RUBELLITE ENERGY CORP. REPORTS THIRD QUARTER 2026 FINANCIAL AND OPERATING RESULTS, AND PROVIDES OPERATIONS AND FOURTH QUARTER 2026 GUIDANCE UPDATE

CALGARY, AB, Nov. 9, 2026 /CNW/ -- (TSX: RBY) - Rubellite Energy Corp. ("Rubellite" or the "Company") is pleased to report its third quarter 2026 financial and operating results and provides an operations and fourth quarter 2026 guidance update.

Select financial and operational information is outlined below and should be read in conjunction with Rubellite's unaudited condensed consolidated interim financial statements and related Management's Discussion and Analysis ("MD&A") for the three and nine months ended September 30, 2026, which are available on the Company's website at www.rubelliteenergy.com and SEDAR+ at www.sedarplus.ca.

This news release contains certain specified financial measures that are not recognized by GAAP and used by management to evaluate the performance of the Company and its business. Since certain specified financial measures may not have a standardized meaning, securities regulations require that specified financial measures are clearly defined, qualified and, where required, reconciled with their nearest GAAP measure. See "Non-GAAP and Other Financial Measures" in this news release and in the MD&A for further information on the definition, calculation and reconciliation of these measures. This news release also contains forward-looking information. See "Forward-Looking Information". Readers are also referred to the other information under the "Advisories" section in this news release for additional information.

QUARTERLY OPERATIONAL AND FINANCIAL HIGHLIGHTS

Operational Highlights

• East Edson disposition: On September 8, 2026, the Company completed the sale of its non-operated 50% working interest in the East Edson property in West Central Alberta, (the "East Edson Disposition"). The Company received 2.1 million common shares of Topaz Energy Corp. ("Topaz"), having a deemed value of $67.0 million as consideration for the East Edson Disposition. East Edson averaged approximately 3,460 boe/d of sales production during the 69 days of the third quarter that preceded the East Edson Disposition. Following the East Edson Disposition, Rubellite's sales production is approximately 90% heavy oil, with the remaining production being solution gas and natural gas liquids ("NGL") related to heavy oil production.

• Total sales production: Averaged 12,128 boe/d in the third quarter of 2026 (73% heavy oil and NGL), down 10% from 13,406 boe/d (67% heavy oil and NGL) in the second quarter of 2026, reflecting the East Edson Disposition and natural declines in the West Central area.

• Heavy oil sales production: Averaged 8,542 bbl/d in the third quarter of 2026, consistent with the 8,534 bbl/d of sales production in the second quarter of 2026. During the quarter, 18 (15.5 net) heavy oil wells were brought on production, and the Company established tank inventory at new pads and added to sales volumes at Figure Lake and Frog Lake, with initial production rates varying across the program. An additional 4 (4.0 net) wells were awaiting tie-in, or recovery of drilling fluids, and not yet contributing to sales production.

• Exploration and development spending⁽¹⁾⁽³⁾: Spent $41.3 million in the third quarter, which included the drilling and completion of 8 (8.0 net) primary open hole multi-lateral ("OHML") Clearwater development wells at Figure Lake and 3 (2.5 net) OHML Waseca South development wells, 4 (3.5 net) Sparky and 2 (1.5 net) GP single leg lined circulation string wells ("SLLC") at Frog Lake.

• Land and geological and geophysical spending: Spent $1.6 million on land to capture acreage in core areas and for exploration prospects and $0.4 million on geological and geophysical activities related to core testing to inform enhanced oil recovery pilot work and various seismic data purchases. 

• Abandonment and reclamation: Spent $0.2 million on decommissioning, abandonment and reclamation activities in the third quarter and received one reclamation certificate from the Alberta Energy Regulator ("AER"). Two more certificates were received early in the fourth quarter, bringing the 2026 total to six as of November 6, 2026.

Financial Highlights

• Adjusted funds flow before transaction costs⁽¹⁾: $35.8 million ($0.38 per share) in the third quarter of 2026, an increase from the second quarter of 2026 (Q2 2026 - $35.2 million or $0.38 per share). Lower natural gas and NGL sales volumes and higher royalties and net operating costs were largely offset by lower realized losses on risk management contracts and lower G&A expenses.

• Cash costs⁽¹⁾: $22.3 million or $19.97/boe in the third quarter of 2026, representing a 4% increase on a per boe basis as compared to the second quarter of 2026 (Q2 2026 - $23.5 million or $19.29/boe). The increase was driven by higher net operating and transportation costs due to poor weather-related lease and road conditions at Figure Lake and Frog Lake that continued into the third quarter and the disposition of the lower per unit cost East Edson assets, partially offset by lower G&A and finance expenses.

• Net loss: $27.1 million ($0.29 loss per share) in the third quarter of 2026, primarily driven by a $43.7 million unrealized loss on risk management contracts as forward commodity prices increased, partially offset by a $20.8 million deferred tax recovery, of which $13.0 million related to the East Edson Disposition.

• Net debt⁽¹⁾: $109.0 million at September 30, 2026, down from $158.1 million at June 30, 2026, mainly due to the receipt of Topaz shares, valued at $59.7 million at September 30, 2026, as consideration for the East Edson Disposition. This was partially offset by negative free funds flow of $7.9 million in the third quarter, as capital spending of $43.4 million exceeded adjusted funds flow, after transaction costs, of $35.4 million. Since December 31, 2025, net debt has decreased 24% from $143.1 million at December 31, 2025, with the East Edson Disposition proceeds partially offset by negative free funds flow of $15.9 million, as capital expenditures of $119.9 million exceeded adjusted funds flow, after transaction costs, of $104.1 million in the first nine months of 2026, and $9.6 million of payments for other obligations.

• Available liquidity⁽²⁾: Following the East Edson Disposition, the first-lien credit facility borrowing limit was reconfirmed at $160.0 million. As at September 30, 2026, available liquidity was $40.6 million, based on the $160.0 million borrowing limit, less $118.0 million of bank borrowings and $1.4 million in letters of credit.

OPERATIONS UPDATE

Figure Lake

Primary Development Update:

In the third quarter, Rubellite drilled and rig released 8 (8.0 net) primary OHML development wells targeting the Wabiskaw Member of the Clearwater Formation:

• 3 (3.0 net) at the 12-28-62-18W4 surface pad (the "12-28 Pad")
• 4 (4.0 net) at the 14-22-63-18W4 surface pad (the "14-22 Pad")
• 1 (1.0 net) at the 13-26-61-16W4 surface pad (the "13-26 Pad")

Production results for primary wells drilled to date in 2026 averaged⁽¹⁾ IP30/60 rates of 150 bbl/d (16 wells)/128 bbl/d (14 wells), as compared to the 2025 McDaniel Tier 1 type curve⁽²⁾ of IP30/60 of 201/193 bbl/d⁽²⁾ and Tier 2 type curve⁽²⁾ of IP30/60 of 144/138 bbl/d⁽²⁾. Five (5.0 net) wells drilled from the 14-22 Pad were classified by McDaniel⁽²⁾ as Tier 2 and the results are reflected in the average results obtained. Currently one rig is contracted to continue drilling operations at Figure Lake through the remainder of the year.

Wet weather conditions persisted through the third quarter, negatively impacting operating costs. To mitigate increased operating costs, capital costs, well downtime and oil sales trucking disruptions related to weather events such as the unseasonably wet weather experienced during the second and third quarters this year, Rubellite spent $1.1 million during the third quarter to successfully apply several technical solutions to improve existing all-weather road and pad infrastructure. Based on the cost/benefit analysis to date, future lease construction of new pads will include the application of soil cement in preparation for drilling operations and long-term production, offsetting costs historically incurred in the drilling operation to maintain lease conditions while drilling, and at the same time reducing future maintenance costs and operations downtime.

Enhanced Oil Recovery ("EOR") Update:

Water injection commenced in March 2026 at the first Figure Lake waterflood pilot producer-injector pair drilled in the fourth quarter of 2025 on the 9-35-63-18W4 Pad (the "9-35 Pad"). Results continue to be encouraging with positive water injection performance to date and production rates meeting McDaniel's waterflood response forecast from the year end 2025 reserve evaluation⁽³⁾.

The second and third EOR pilots at Figure Lake are both located at the 8-26-61-16W4 surface pad (the "8-26 Pad"), where 2 (2.0 net) 8-leg OHML producers are paired with dedicated injectors. Water injection commenced in both injectors in late September.

In addition to the dedicated line drive injector pilots, two multi-lateral horizontal producer-to-injector conversions were advanced on two separate pads at Figure Lake and water injection rates have continued to ramp up late in the third quarter following surface equipment modifications. These producer-to-injector conversion pilots will assist in evaluating the effectiveness of repressurization through waterflood where primary-focused multi-lateral drilling development has already occurred.

Lab testing for the selection of an appropriate polymer for a polymer flood pilot was advanced during the third quarter, with field trials expected to begin in 2027 after installation of dedicated blending equipment.

Up to five (5.0 net) producer / injector pairs and a dedicated source well are planned for a waterflood Commercial Demonstration Pad at 7-8-63-17W4 (the "7-8 Pad") beginning late in the first quarter of 2027. The intent of the commercial demonstration pad is to verify source water deliverability and quality, to evaluate the effectiveness of several waterflood well pair configuration designs, and to pilot water injection for repressurization in proximity to an existing primary well. The Commercial Demonstration Pad is an important next step to refine and optimize the full scale development plan for the Clearwater at Figure Lake.

Figure Lake Sparky

The exploration well (1.0 net) targeting the Sparky Formation drilled in the fourth quarter of 2025 was suspended in August due to wet road conditions. Continuous production from the discovery well requires the construction of an all-season road and associated bridge improvements, which are partially scheduled for the fourth quarter of 2026 and expected to be completed following spring break up. Follow up development drilling, with the potential to pilot waterflood in the Sparky pool, is planned for the summer of 2027.

Frog Lake⁽⁴⁾

Waseca Update - Open Hole Multi-lateral Horizontals:

During the third quarter, Rubellite drilled and rig released 3 (recorded and forecast at 2.5 net) OHML wells targeting the Waseca Formation. Results to date of Waseca wells drilled at Frog Lake in 2026 are:

• Waseca North: Average⁽¹⁾ IP30/IP60 rates obtained for Waseca North wells drilled to date in 2026 are 118 bbl/d (5 wells)/106 bbl/d (5 wells), as compared to the 2025 McDaniel type curve⁽²⁾ of 122/117 bbl/d.

• Waseca South: Average⁽¹⁾ IP30/IP60 rates obtained for Waseca South wells drilled to date in 2026 are 98 bbl/d (3 wells)/81 bbl/d (3 wells), as compared to the 2025 McDaniel type curve⁽²⁾ of 145/145 bbl/d.

Two (forecast at 2.0 net) 20,000m OHML Waseca North wells are planned for the fourth quarter of 2026. Working interest elections by Frog Lake Energy Resources Corp. ("FLERC") are expected to be received in January 2027.

GP and Sparky Update - Single Leg Lined Laterals with Circulation Strings:

Rubellite has continued to positively advance the use of single leg lined lateral horizontal wells equipped with high velocity circulation strings ("SLLC wells") to enable consistent production of heavy oil with solids from the less consolidated GP and Sparky sands of the Mannville Stack.  Through the third quarter of 2026, Rubellite has drilled and placed on production 4 (recorded and forecast at 3.0 net) GP wells and 3 (recorded and forecast at 2.5 net) Sparky wells. Results to date from both zones have been encouraging. The GP wells averaged⁽¹⁾ IP30 rates of 101 bbl/d (three wells) vs. the McDaniel type curve⁽²⁾ for the GP of 73 bbl/d. Sparky wells drilled in 2026 and on production to date averaged⁽¹⁾ IP30 rates of 118 bbl/d (three wells). Heavy oil production rates from the SLLC wells have improved on average ~30% through their second months of production as operations are optimized and wormholes are postulated to be developing in the unconsolidated sand reservoirs.

With the ongoing one rig delineation drilling program that spans across Rubellite's land base at Frog Lake, an additional 6 (forecast at 5.0 net) GP and 3 (forecast at 1.5 net) Sparky SLLC wells will be drilled and on production in the fourth quarter, for a total of 16 (forecast at 12.0 net) SLLC wells in 2026. A number of these working interest elections will be received from FLERC in January and through March 2027.

Marten Hills

Following the acquisition of an additional 30% working interest at Marten Hills which closed on June 30, 2026, 1 (0.6 net) injection well and 1 (0.6 net) water source well are scheduled to be drilled in the fourth quarter of 2026 to expand the existing waterflood to all four wells on the 12-35 Pad at Marten Hills. Additional water injection to provide pressure support for Rubellite's remaining 7 (4.2 net) primary producers is anticipated for 2027.

Ukalta

Source water management and modification of surface facilities is underway to increase the volume of water available for injection in the converted multi-lateral waterflood injector that commenced injection in the second quarter of 2026.

Other Exploration

In addition to ongoing zonal delineation activity in the GP and Sparky zones at Frog Lake and the Sparky zone at Figure Lake, Rubellite continued to advance several early-stage exploration prospects including land capture and play concept de-risking, while maintaining a disciplined approach to risked capital exposure.

Bayhurst

One (1.0 net) exploration OHML well with ~2,750m of measured depth open hole was drilled at Bayhurst, Saskatchewan in the first quarter of 2026 and has been on an extended production test for several months at 30 bbl/d. Two additional follow up wells at Bayhurst (2.0 net) are planned for the fourth quarter of 2026 to further delineate the reservoir, confirm the optimal well design and secure land tenure.

Calling Lake

As previously disclosed, the 4 leg OHML horizontal exploration well drilled in 2024 has underperformed expectations due to what is suspected to be a collapsed wellbore. A resumption of drilling operations is planned for the fourth quarter where a single lined lateral will be drilled from the existing well and equipped with the SLLC design to lift solids, similar to the well configuration used in the Mannville Stack at Frog Lake.

OUTLOOK AND GUIDANCE

With the increased liquidity as a result of the East Edson Disposition, the closing of the swap transaction to increase its working interest at Marten Hills, and higher anticipated average working interest in the ongoing Frog Lake drilling program, Rubellite has increased its capital spending forecast for the fourth quarter of 2026 to $31 to $41 million, bringing the total exploration and development spending⁽¹⁾ forecast for 2026 to $145 to $155 million, up from previous guidance of $125 to $135 million. Total capital spending can vary by up to approximately $10 million depending on partner elections at Frog Lake.

In addition to development drilling in its core heavy oil operating areas, Rubellite's remaining 2026 capital spending will support longer term EOR and exploration initiatives, including: (1) drilling a waterflood injector and a water source well at Marten Hills to expand the waterflood on the 12-35 Pad; (2) one or more waterflood repressurization pilots at pads in Figure Lake that were originally developed for primary production only; (3) preparation for a new Commercial Waterflood Demonstration Pad at Figure Lake; (4) advancing polymer testing and polymer injection plans at Figure Lake and Frog Lake; and (5) activities to advance the evaluation of two exploration plays where Rubellite has material land capture.

Forecast core development property capital activity for the fourth quarter of 2026 is detailed below:

At Figure Lake:

• Drilling and completion of 5 (5.0 net) 15,000m, Clearwater primary development wells;
• Installation of a permanent bridge and a portion of required all-weather road upgrades to establish year-round production for the Sparky pool discovery;
• Pad preparation for the Commercial Waterflood Demonstration Pad at 7-8-63-17W4 to evaluate waterflood implementation at scale;
• Surface and downhole equipping activities related to one mature multi-lateral producer to waterflood injector conversion; and
• Additional core testing to continue to inform EOR initiatives.

At Frog Lake:

• Drilling and completion of 11 (forecast 8.5 net) wells: 6 (forecast 5.0 net) targeting the GP, 3 (forecast 1.5 net) targeting the Sparky and 2 (forecast 2.0 net) targeting the Waseca North; and
• Special core testing on the core cut during the third quarter, to inform EOR initiatives.

At Marten Hills:

• Drilling of 1 (0.6 net) waterflood injector and 1 (0.6 net) water source well to expand the 12-35 Pad waterflood, and construction to expand the other two Marten Hills pads ahead of 2027 waterflood expansion drilling.

The increased spending forecast relative to prior guidance is related to (1) known and forecast lower partner working interest participation elections at Frog Lake; (2) acceleration of waterflood expansion to the fourth quarter at Marten Hills; (3) accelerated exploration activity to the fourth quarter; (4) all-season pad and road infrastructure upgrades for existing pads during the third quarter and enhanced construction of new pads during the fourth quarter for the 2027 drilling program; and (5) bespoke capital activity overages in the third quarter, a portion of which compensation from the contractor is being sought.

At Frog Lake, Rubellite's 50% working interest partner ("FLERC" or "the Partner") can elect, on a well by well basis, to participate in a 50% working interest position, or not to participate and revert to an overriding royalty position. Wells drilled but still pending an election are accounted for at 100% WI until the election is received, including three wells with Q3 capital activity (two wells drilled in Q3 and one well rig released on October 3rd) with elections due later in November. If adjustments are required when the elections are received they will be made at that time. FLERC elections added a net $2.7 million to Q3 capital relative to prior guidance assumptions: $1.7 million on two wells where the Partner elected not to participate, $2.2 million on wells held at 100% pending elections due November 23, 2026, less $1.2 million adjusted for wells drilled in Q2 and recorded at 100% and the Partner made its election to participate during Q3. Historic guidance was predicated on FLERC participating at 50% working interest. Since Rubellite acquired the property in 2024, the Partner has historically participated in 57% of the wells elected to date, resulting in Rubellite having a 72% average working interest in drilling operations. On a prospective basis, guidance will assume a 75% average working interest (the Partner participating in half the wells). Depending on the Partner's elections due before year-end reporting, Frog Lake capital could vary by up to approximately $10 million, from FLERC participating in all of these wells to participating in none.

Proactively, in its core operating areas, Rubellite is investing to upgrade select road and pad infrastructure to ensure all-season access and continued operations, mitigating increased operating costs, capital costs and well downtime due to future weather events. Rubellite had three bespoke well events that increased Q3 capital by approximately $2.8 million in aggregate. At Frog Lake, a SLLC well had to be junked, abandoned and redrilled in the quarter. At Figure Lake, mechanical drilling challenges on an OHML well resulted in multiple fishing attempts and ultimately lost tools downhole, and a geologic anomaly at the toe of one of the legs in an OHML well resulted in significant OBM losses.

Exploration activity is being accelerated into Q4/26, adding $2.8 million to forecast capital with two Bayhurst exploration wells (up from one well in the prior forecast) and a lined lateral circulation string well at Calling Lake now planned in the fourth quarter.

Additional capital spending is anticipated for land capture and seismic purchases.

For 2026, heavy oil sales volumes are forecast to average 8,630 to 8,730 bbl/d, 2% to 4% higher than 2025, while total production sales volumes, including natural gas and NGL volumes, are forecast to average 12,230 to 12,330 boe/d, reflecting the East Edson Disposition on September 8, 2026. Fourth quarter heavy oil sales are forecast to average a record 8,800 to 9,200 bbl/d, while total sales volumes are expected to average 9,700 to 10,100 boe/d, including natural gas production conserved and sold at Figure Lake.

Operating costs are forecast to average $8.00 to $8.50/boe for the fourth quarter of 2026, and transportation costs are forecast to average $6.25 to $6.75/boe, reflecting increased fuel surcharges for trucked oil and the sale of East Edson where operating and transportation costs for natural gas are significantly lower than Rubellite's heavy oil properties. Heavy oil wellhead differentials are forecast to average $6.50 to $7.50/bbl, assuming diluent pricing consistent with the current forward curve. Royalties are expected to increase as a percentage of revenue, averaging 16.0% to 16.5%, given the higher forecast reference oil prices.

Rubellite will continue to address end of life asset retirement obligations ("ARO"), with $0.7 million of operated abandonment and reclamation expenditures planned for the remainder of 2026. Total forecast abandonment and reclamation spending for 2026 of $1.4 million exceeds the Company's AER area-based mandatory 2026 spending requirement of $1.3 million.

Planned exploration and development spending and drilling activity for 2026 is summarized in the table below:

Rubellite's financial and operational guidance for full year 2026 is presented in the table below:

SUMMARY OF QUARTERLY RESULTS

ABOUT RUBELLITE

The Company is a Canadian energy company headquartered in Calgary, Alberta engaged in the exploration, development, production and marketing of heavy crude oil from the Clearwater and Mannville Stack Formations in Eastern 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 www.rubelliteenergy.com or on SEDAR+ at www.sedarplus.ca.

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.

ADVISORIES

INDUSTRY METRICS

This news release 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. See "Non-GAAP and Other Financial Measures" in this news release for a description of these industry metrics.

VOLUME CONVERSIONS

Barrel of oil equivalent ("boe") may be misleading, particularly if used in isolation. In accordance with 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 news release.

ABBREVIATIONS

The following abbreviations used in this news release have the meanings set forth below:

INITIAL PRODUCTION RATES

Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinate 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.

NON-GAAP AND OTHER FINANCIAL MEASURES

Throughout this news release 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.

Non-GAAP Financial Measures

Capital Expenditures: Rubellite uses capital expenditures related to exploration and development to measure its capital investments compared to the Company's annual capital budgeted expenditures. Rubellite's capital budget excludes acquisition and disposition activities. Total capital expenditures includes exploration and development, land, geological and geophysical and corporate spending.

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:

Presented below are capital expenditures by CGU:

Cash costs: Cash costs are comprised of net operating costs, transportation, general and administrative, and cash finance expense as detailed below. Cash costs per boe is calculated by dividing cash costs by total production sold in the period. Management believes that cash costs assist management and investors in assessing Rubellite's efficiency and overall cost structure. 

Operating netbacks and total operating netback, after risk management contracts: Operating netback is calculated by deducting royalties, net operating costs, and transportation costs from oil and natural gas revenue. Operating netback is also calculated on a per boe basis using total production sold in the period. Total operating netback, after risk management contracts, is presented after adjusting for realized gains or losses from risk management contracts. Rubellite considers operating netback and total operating netback, after risk management contracts to be key industry performance indicators that provide investors with information that is also commonly presented by other oil and natural gas producers. Rubellite presents the operating netback at a CGU level as it provides investors with key information related to the Eastern Heavy Oil CGU which is the area where growth capital investment is focused. Operating netback and total operating netback, after risk management contracts, are used to evaluate operational performance as they demonstrate profitability relative to realized and current commodity prices.

Net operating costs: Net operating costs equals operating expenses net of processing income, which is made up of processing revenue and other one time items from time to time. Management views net operating costs as an important measure to evaluate its operational performance. The most directly comparable IFRS measure for net operating costs is production and operating expenses.

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).

Net Debt and Adjusted Working Capital: Rubellite uses net debt as an alternative measure of outstanding debt and is calculated by adding borrowings under the credit facility plus the principal amount of term loan debt, less marketable securities and adjusted working capital. Adjusted working capital is calculated by adding cash, accounts receivable, prepaid expenses and deposits and product inventory less accounts payable and accrued liabilities. Management considers net debt as an important measure in assessing the liquidity of the Company. Net debt is used by management to assess the Company's overall debt position and borrowing capacity. Net debt is not a standardized measure and therefore may not be comparable to similar measures presented by other entities.

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

Adjusted funds flow: Adjusted funds flow is calculated based on net cash flows from operating activities, excluding changes in non-cash working capital and expenditures on decommissioning obligations, other provisions and cash-settled share based compensation since the Company believes the timing of collection, payment or incurrence of these items is variable. Expenditures on decommissioning and share based compensation obligations may vary from period to period and are managed as expenditures through the corporate budgeting process which considers available adjusted funds flow. Management uses adjusted funds flow and adjusted funds flow per boe as key measures to assess 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 before transaction costs: Adjusted funds flow before transaction costs is calculated as adjusted funds flow plus transaction costs incurred in connection with acquisitions, dispositions and other corporate transactions. Management believes that excluding transaction costs, which relate to specific corporate transactions and are not indicative of the Company's ongoing operations, provides a more comparable measure of the funds generated by the Company's ongoing operations between periods. The most directly comparable IFRS measure is net cash flows from operating activities. Adjusted funds flow before transaction costs is not a standardized measure and may not be comparable to similar measures presented by other entities.

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:

Free funds flow: Free funds flow is an important measure that informs efficiency of capital spent and liquidity. Free funds flow is calculated as adjusted funds flow generated during the period less capital expenditures, excluding non-cash items and acquisitions and dispositions. Adjusted funds flow and capital expenditures are non-GAAP financial measures which have been reconciled to their most directly comparable GAAP measures previously in this document. By comparing current period capital expenditures relative to adjusted funds flow, Rubellite monitors its free funds flow to inform decisions such as capital allocation, debt repayment and liquidity.

The following table shows the calculation of the removal of capital expenditures from adjusted funds flow:

Available Liquidity: Available liquidity is defined as the borrowing limit under the Company's credit facility, plus any cash and cash equivalents, less any borrowings and letters of credit issued under the credit facility. Management uses available liquidity to assess the ability of the Company to finance capital expenditures, expenditures on decommissioning obligations and to meet its financial obligations.

Non-GAAP Financial Ratios

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 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 prices after risk management contracts: calculated as the average realized price by product type less the realized gain or loss on risk management contracts by product type.

Adjusted funds flow per share: calculated as adjusted funds flow divided by the basic or diluted weighted average number of common shares outstanding for the period, consistent with the share amounts used to calculate net income (loss) per share in the Company's interim consolidated financial statements. In periods of net loss, diluted weighted average shares equal basic weighted average shares, as potentially dilutive instruments are anti-dilutive. Adjusted funds flow per share before transaction costs is calculated on the same basis.

Adjusted funds flow per boe: calculated as adjusted funds flow divided by total production sold in the period.

Net debt to adjusted funds flow ratio: calculated on a trailing twelve-month basis.

Net debt to annualized adjusted funds flow ratio: calculated by annualizing the current quarter adjusted funds flow.

Supplementary Financial Measures

"Exploration and development spending" is comprised of the non-GAAP measure total capital expenditures (as calculated above), less land, geological and geophysical and corporate and other spending.

"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.

"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 boe basis.

"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 total oil and natural gas revenue, 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 cost per boe" is comprised of net operating cost (as calculated above), divided by the Company's total sales production.

"Transportation cost ($/boe)" is comprised of transportation, 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.

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

FORWARD-LOOKING INFORMATION

Certain information in this news release 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, and the benefits to be derived from such drilling including drilling techniques, pilot projects and production growth including the timing for and benefits of EOR initiatives; the plan to advance strategic initiatives including multiple enhanced oil recovery pilots, exploration activities, new land capture, capital spending activities, anticipated average heavy oil sales volumes and total production sales volumes in 2026; operating and transportation cost forecasts for 2026; planned ARO spending; Rubellite's business plan; and including the forward-looking information contained under the headings "Operations Update" and "About Rubellite".

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 news release. In particular and without limitation of the foregoing, material factors or assumptions on which the forward-looking information in this news release 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, South America and elsewhere), 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, 2025 and in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR+ website www.sedarplus.ca and at Rubellite's website 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.

SOURCE Rubellite Energy Corp.

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