RUBELLITE ENERGY CORP. REPORTS THIRD QUARTER FINANCIAL AND OPERATING RESULTS

CALGARY, AB, Nov. 12, 2024 /CNW/ - (TSX: RBY) – Rubellite Energy Corp. ("Rubellite" or the "Company"), is pleased to report its third quarter 2024 financial and operating results.

Select financial and operational information is outlined below and should be read in conjunction with Rubellite's unaudited condensed interim consolidated financial statements and related Management's Discussion and Analysis ("MD&A") for the three and nine months ended September 30, 2024, which are available through 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.

THIRD QUARTER 2024 HIGHLIGHTS

• Third quarter conventional heavy oil sales production of 5,954 bbl/d was 32% higher than the second quarter of 2024 (Q2 2024 - 4,503 bbl/d) and 89% above the third quarter of 2023 (Q3 2023 - 3,154 bbl/d). During the third quarter, the acquisition of Buffalo Mission Energy Corp. (the "BMEC Acquisition") contributed approximately 1,528 bbl/d and there were eleven (10.5 net) wells brought on production from the drilling program.
• Exploration and development capital expenditures⁽¹⁾ totaled $33.7 million for the third quarter to drill, complete, equip and tie-in eleven (11.0 net) multi-lateral horizontal development / step-out delineation wells at Figure Lake and five (2.5 net) multi-lateral horizontal development wells at Frog Lake. Spending on facilities of $2.9 million in the quarter were for the Figure Lake gas conservation project, bringing total gas plant and pipeline expenditures for 2024 to $5.4 million.
• Adjusted funds flow before transaction costs⁽¹⁾ in the third quarter was $25.0 million ($0.37 per share), a 21% increase from the second quarter of 2024 (Q2 2024 - $20.7 million; $0.33/share) and a 60% increase from the third quarter of 2023 (Q3 2023 - $15.6 million; $0.25 per share) driven by the growth in sales production, partially offset by higher cash costs.
• Cash costs⁽¹⁾ were $13.5 million or $24.72/boe in the third quarter of 2024 (Q2 2024 - $9.3 million or $22.58 per boe; Q3 2023 - $5.9 million or $20.27/boe). On a per boe basis, the higher costs were driven by increased royalties and production and operating costs as a result of the BMEC Acquisition and higher G&A costs, partially offset by decreased transportation costs on lower trucking rates.
• Net income was $15.0 million in the third quarter of 2024 (Q3 2023 - $3.9 million net income), driven by higher adjusted funds flow and an $11.4 million unrealized gain on risk management contracts.
• As at September 30, 2024, net debt⁽¹⁾ was $147.9 million, an increase from $51.0 million as at December 31, 2023 as a result of the BMEC Acquisition during the third quarter of 2024.
• Rubellite had available liquidity⁽²⁾ at September 30, 2024 of $25.5 million, comprised of the $100.0 million borrowing limit of Rubellite's first lien credit facility and $20.0 million bank syndicate term loan, less current bank borrowings of $92.2 million and outstanding letters of credit of $2.4 million.
• Subsequent to September 30, 2024, in conjunction with the closing of the recombination transaction with Perpetual Energy Inc. on October 31, 2024, the Company's credit facility has been increased to $140.0 million and the $20.0 million bank syndicate term loan has been repaid. The initial revolving term remains unchanged at May 31, 2025 and may be extended for a further twelve months to May 31, 2026. The next semi-annual borrowing base redetermination is scheduled on or before May 31, 2025.

(1)     Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this news release.

OPERATIONS UPDATE

In the third quarter of 2024, the Company contracted two rigs and drilled and rig released a total of eleven (11.0 net) horizontal wells in the Greater Figure Lake area, all targeting the Clearwater Formation. Production results from the 2024 drilling program have averaged IP(30) 138 bbl/d (21 wells) and IP(60) 111 bbl/d (17 wells) to date, as compared to the McDaniel Type Curve⁽¹⁾ rates of 120 and 112 bbl/d, respectively. Production results at East Edwand were encouraging, where a step-out delineation well at 06-09-062-16W4 was drilled using a conventional 50m inter-leg design, recorded an IP(30) of 172 bbl/d and IP(60) of 140 bbl/d. Repeatable results from the 2024 capital program across the Greater Figure Lake field continue to meet expectations, solidifying confidence in the geologic model and affirming the identified drilling inventory in excess of 243.0 net drilling locations (182.0 net unbooked⁽¹⁾). 

During the second and third quarters of 2024, the Company executed pilot drilling at the 6-19-62-18W4 Pad (the "6-19 Pad") to validate the predicted economic advantage of implementing tighter inter-leg spacing at Figure Lake. Specifically, the Company reduced the distance between laterals from 50m to approximately 33m, and commensurately increased the number of legs and therefore also increased the open hole lateral length per well to greater than 14,000 meters while maintaining the same approximate areal coverage per well. Four (4.0 net) wells were drilled with the tighter inter-leg spacing prior to the end of the third quarter at the 6-19 Pad.  Early productivity data from the tighter spacing design is encouraging, both on a per meter and total production per well basis.  The 00/08-23-062-19W4 was drilled with a 33m inter-leg spacing to a total lateral measured depth of 14,500 meters and achieved an IP(30) of 304 bbl/d. The offsetting 02/08-23-062-19W4 was drilled to a total lateral length of 18,600m using a hybrid multi-lateral / "fan" design and is on production at similar rates, recording an IP(24) of 362 bbl/d post load oil recovery. While productivity per meter of open reservoir varies with reservoir quality, the preliminary pilot results suggest that productivity per meter of open reservoir for the wells with tighter inter-leg spacing is statistically similar to the closest neighboring wells, supporting the expectation of economic production acceleration. Incremental drilling time and costs for the wells with tighter inter-leg spacing are also encouraging and in line with modeled assumptions, and in combination with early production data suggest that an increase in net asset value per unit area of land will be realized. Based on these initial results, four (4.0 net) additional 33m down-spaced wells are planned at the offsetting 1-25-62-19W4 Pad (the "1-25 Pad") in the fourth quarter to further confirm accelerated production and increased capital efficiencies, and to facilitate statistical assessment of the technically anticipated increase in ultimate oil recovery factors. Production results will continue to be carefully analyzed over the remainder of the year and will inform the well design to be implemented in the future for economically optimized exploitation. 

To advance solution gas conservation at Figure Lake, construction and installation of natural gas compression, dehydration, and associated facilities have progressed and are now substantially complete in advance of the expected re-activation of the gas sales meter by others in Q1 2025. Tie-in of solution gas at Figure Lake will significantly reduce emissions, and is forecast to deliver a rate of return in excess of 75%, enhanced by the re-activation of existing gas gathering pipelines and a forecasted reduction in carbon taxes related to elimination of flaring and incineration at multiple pad sites. Once operational, approximately 3 to 4 MMcf/d of natural gas sales is forecast at Figure Lake. The Company is also advancing a novel natural gas re-injection pilot at Figure Lake for enhanced oil recovery. Preliminary results of the gas re-injection pilot are expected by mid-2025.

At Frog Lake, the Company assumed operations after closing the BMEC Acquisition on August 2, 2024, and subsequently drilled and rig released five (2.5 net) horizontal wells in the third quarter of 2024. The wells, all targeting the Waseca Sand of the Mannville Stack, are currently recovering load fluid and beginning to cut oil as they clean up over a typical 60-90 day period. The Waseca Sand is the primary zone of development, but several wells are being planned to additionally test the General Petroleum and Sparky Sands in 2025, evaluate suitable well designs, confirm type curve assumptions, and extend known pool limits.

As at the end of the third quarter of 2024, the total number of new horizontal wells rig-released by the Company in 2024 is thirty (25.5 net).

Subsequent to the end of the quarter, the Company spud an exploratory four-leg multi-lateral horizontal well approximately 90km north of Figure Lake in the Nixon/Calling Lake area to test a new play for which the Company currently holds 108.0 net sections of land. Preliminary stabilized production results post load fluid recovery are expected in the first quarter of 2025.

In total in 2024, the Company expects to drill thirty-four (34.0 net) Clearwater multi-lateral wells at Figure Lake, eleven gross (5.75 net) wells on the acquired Mannville Stack assets at Frog Lake in connection with the BMEC Acquisition, and one (1.0 net) exploration horizontal well at Calling Lake. The Company is also continuing to advance additional exploration activities, pursuing additional land capture and play concept de-risking activities.

(1)

Type curve assumptions are based on the Total Proved plus Probable Undeveloped reserves contained in the McDaniel Reserve Report as disclosed in the Company's Annual Information Form which is available under the Company's profile on SEDAR+ at 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 reserves, prepared by McDaniel with an effective date of December 31, 2023 and a preparation date of March 14, 2024. See "Estimated Drilling Locations.

OUTLOOK AND GUIDANCE

Production sales volumes for the fourth quarter of 2024 are expected to average 9,900 to 10,400 boe/d, 77% oil and liquids, and exit the year at 11,300 to 11,800 boe/d unchanged from previous guidance. Relative to the pro forma recombination transaction 2024 guidance contained in the September 17, 2024 news release, refinements to Q4 2024 guidance assumptions are outlined in the table below. Guidance assumptions on the Q4 2024 exit rate are largely unchanged outside of a $0.50 per boe reduction to general and administrative cost assumptions and a $0.50 per bbl reduction to the heavy oil wellhead differential. Heavy oil production is expected to average 7,400 to 7,800 bbl/d and exit the year at 7,500 to 7,900 bbl/d, unchanged from the heavy oil production guidance contained in our August 8th press release.

Growth is expected to continue into 2025 with the return of the second drilling rig to Figure Lake after completion of the horizontal exploratory test well at Calling Lake for the drilling of four (4.0 net) additional planned development / step out wells. Thereafter, drilling operations will continue with one rig at Figure Lake and one rig at Frog Lake through to winter break up. Given the preliminary results of the down-space pilot at the 6-19 Pad at Figure Lake, six (6.0 net) of the wells planned for the fourth quarter at Figure Lake, including four (4.0 net) of the five (5.0 net) wells planned for the 1-25 Pad and two (2.0 net) wells on a pad at South Edwand are now designed with tighter inter-leg spacing, resulting in incremental capital spending in the fourth quarter relative to previous guidance. Capital spending for the Calling Lake exploration well was also moved forward into the fourth quarter of 2024 and one additional well at Frog Lake (capital carried at 100%) is now being planned. A combination of these items resulted in the increase to Q4 2024 capital spending guidance by $5 to $6 million and the well count from 12.0 to 13.25 net wells. The change to the Q4 2024 royalty guidance is related to several wells achieving C* payout earlier than previously expected and the increase to the Q4 2024 operating costs relates to Frog Lake as expected optimizations are still being integrated into ongoing operations.

Rubellite's guidance for Q4 2024 is presented in the table below:

	Previous Q4 2024 Guidance^(1)	Previous Q4 2024 Exit Rate^(1)	Revised Q4 2024 Guidance	Revised Q4 2024 Exit Rate
Sales Production (boe/d)	9,900 - 10,400	11,300 - 11,800	9,900 - 10,400	11,300 - 11,800
Production mix (% oil and liquids)^(4)	77 %	70 %	77 %	70 %
Heavy Oil Production (bbl/d)	7,400 - 7,800	7,500 - 7,900	7,400 - 7,800	7,500 - 7,900
Exploration and Development spending ($ millions)^(2)(3)	$21 - $23	-	$26 - $29	-
Multi-lateral development / step-out wells (net)^(5)	12.0	N/A	13.25	N/A
Heavy oil wellhead differential ($/bbl)^(2)	$5.50 - $6.00	$5.50 - $6.00	$5.00 - $5.50	$5.00 - $5.50
Royalties (% of revenue)^(2)	11.5% - 12.5%	12% - 13%	12% - 13%	12% - 13%
Production and operating costs ($/boe)^(2)	$6.50 - $7.00	$6.50 - $7.00	$6.75 - $7.25	$6.50 - $7.00
Transportation costs ($/boe)^(2)	$6.00 - $6.50	$5.50 - $6.00	$6.00 - $6.50	$5.50 - $6.00
General and administrative costs ($/boe)^(2)	$3.50 - $4.00	$3.50 - $4.00	$3.00 - $3.50	$3.00 - $3.50

(1)	Previous Q4 2024 guidance and Q4 2024 exit rate guidance dated September 17, 2024. Previous Heavy Oil Production guidance dated August 8, 2024.
(2)	Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures".
(3)	Excludes land and acquisition spending.
(4)	Liquids means oil, condensate, ethane, propane and butane.
(5)	Includes the drilling of 1 (1.0 net) horizontal exploration well at Calling Lake.

SUMMARY OF QUARTERLY RESULTS

	Three months ended September 30,		Nine months ended September 30,
($ thousands, except as noted)	2024	2023	2024	2023
Financial
Oil revenue	43,682	25,777	109,303	61,744
Net income (loss) and comprehensive income (loss)	15,010	3,942	23,225	9,038
Per share – basic^(1)	0.23	0.06	0.37	0.15
Per share – diluted^(1)	0.23	0.06	0.36	0.15
Cash flow from operating activities	19,973	14,957	56,386	36,428
Adjusted funds flow^(2)	23,029	15,554	62,145	37,234
Per share – basic^(1)(2)	0.35	0.25	0.98	0.60
Per share – diluted^(1)(2)	0.35	0.25	0.96	0.62
Net debt (asset)	147,939	20,676	147,939	20,676
Capital expenditures^(2)
Capital expenditures, including land and other^(2)	36,650	11,330	73,369	45,211
Acquisition	62,732	—	62,732	—
Wells Drilled^(3)– gross (net)	16 / 13.5	6 / 6.0	31 / 28.5	19 / 18.5
Common shares outstanding^(1) (thousands)
Weighted average – basic	65,834	61,956	63,592	59,640
Weighted average – diluted	66,571	62,597	64,599	60,325
End of period	67,593	61,839	67,593	61,839
Operating
Daily average oil sales production^(4) (bbl/d)	5,954	3,154	4,994	2,997
Average prices
West Texas Intermediate ("WTI") ($US/bbl)	75.09	82.18	77.54	77.37
Western Canadian Select ("WCS") ($CAD/bbl)	83.95	92.97	84.45	80.42
Average realized oil price^(2) ($/bbl)	79.75	88.85	79.88	75.47
Average realized oil price after risk management contracts^(2) ($/bbl)	80.06	82.15	79.46	74.23

(1)	Per share amounts are calculated using the weighted average number of basic or diluted common shares.
(2)	Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this news release.
(3)	Well count reflects wells rig released during the period.
(4)	Heavy crude oil sales production excludes tank inventory volumes.

ABOUT RUBELLITE

The Company is a Canadian energy company headquartered in Calgary, Alberta which, through its operating subsidiaries, Rubellite Energy Inc. and Perpetual Energy Inc., are engaged in the exploration, development, production and marketing of its diversified asset portfolio which includes heavy crude oil from the Clearwater and Mannville Stack Formations in Eastern Alberta, utilizing multi-lateral drilling technology and 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 organic growth plan focused on superior corporate returns and 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

BOE 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.

ABBREVIATIONS

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

bbl	barrels
bbl/d	barrels per day
boe	barrels of oil equivalent
MMboe	millions of barrels of oil equivalent
WCS	Western Canadian select, the benchmark price for conventional produced crude oil in Western Canada

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.

ESTIMATED DRILLING LOCATIONS

Of the 243 net future drilling locations disclosed in this news release 182 net are unbooked drilling locations. 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.

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.

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,
	2024	2023	2024	2023
Net cash flows used in investing activities	(86,044)	(12,129)	(123,397)	(55,541)
Acquisitions	(62,732)	—	(62,732)	—
Change in non-cash working capital	13,338	(799)	12,704	(10,330)
Capital expenditures	(36,650)	(11,330)	(73,369)	(45,211)
Property, plant and equipment expenditures	(28,348)	(11,177)	(58,115)	(30,429)
Exploration and evaluation expenditures	(8,250)	(153)	(12,285)	(14,782)
Corporate additions	(52)	—	(2,969)	—
Capital expenditures	(36,650)	(11,330)	(73,369)	(45,211)

Cash costs: Cash costs are comprised of production and operating, 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.

	Three months ended September 30,		Nine months ended September 30,
($ thousands, except per boe amounts)	2024	2023	2024	2023
Production and operating	4,634	1,670	9,978	5,180
Transportation	4,202	2,284	10,581	6,457
General and administrative	2,668	1,634	7,094	4,995
Cash finance expense	2,035	292	4,122	1,092
Cash costs	13,539	5,880	31,775	17,724
Cash costs per boe	24.72	20.27	23.22	21.67

Net Debt and Adjusted Working Capital Deficit: Rubellite uses net debt as an alternative measure of outstanding debt. 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 or asset 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:

	As of September 30, 2024	As of December 31, 2023
Current assets	39,947	21,061
Current liabilities	(86,123)	(34,009)
Working capital (surplus) deficiency	46,176	12,948
Risk management contracts – current asset	9,895	8,796
Bank syndicate term loan	(20,000)	—
Decommissioning obligations - current liability	(285)	(77)
Adjusted working capital (surplus) deficiency	35,786	21,667
Bank indebtedness	72,153	29,317
Bank syndicate term loan	20,000	—
Term loan (principal)	20,000	—
Net debt	147,939	50,984

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 since the Company believes the timing of collection, payment or incurrence of these items is variable. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of Rubellite's operating areas. Expenditures on decommissioning obligations are managed through the capital 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 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,
($ thousands, except as noted)	2024	2023	2024	2023
Net cash flows from operating activities	19,973	14,957	56,386	36,428
Change in non-cash working capital	2,934	594	5,489	803
Decommissioning obligations settled	122	3	270	3
Adjusted funds flow	23,029	15,554	62,145	37,234
Transaction Costs	2,010	—	2,010	—
Adjusted funds flow - pre transaction costs	25,039	15,554	64,155	37,234
Adjusted funds flow per share - basic	0.35	0.25	0.98	0.60
Adjusted funds flow per share - diluted	0.35	0.25	0.96	0.62
Adjusted funds flow per boe	42.04	53.61	45.42	45.51
Adjusted funds flow per share - pre transaction costs - basic	0.37	—	1.00	—
Adjusted funds flow per share - pre transaction costs - diluted	0.37	—	0.99	—
Adjusted funds flow per boe - pre transaction costs	45.04	—	46.62	—

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 crude oil and natural gas producers. Rubellite also calculates certain non-GAAP measures per share as the measure divided by outstanding common shares.

Average realized oil price after risk management contracts: are calculated as the average realized price less the realized gain or loss on risk management contracts.

Adjusted funds flow per share: adjusted funds flow per share is calculated using the weighted average number of basic and diluted shares outstanding used in calculating net income (loss) per share.

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

Supplementary Financial Measures

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

"Royalties (percentage of revenue)" is comprised of royalties, as determined in accordance with IFRS, divided by oil revenue from sales oil production as determined in accordance with IFRS.

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

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

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

"Heavy oil wellhead differential ($/bbl)" represents the differential the Company receives for selling its heavy crude oil production relative to the Western Canadian Select reference price (Cdn$/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, regulatory application and the benefits to be derived from such drilling including production growth; Rubellite's business plan; and including the information and statements contained under the heading "Outlook and Guidance" 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 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 pandemic; 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 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); 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 Rubellite Energy Inc. and Perpetual Energy Inc.'s Annual Information Form and MD&A for the year ended December 31, 2023 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 Inc.

For additional information please contact: Rubellite Energy Corp., Suite 3200, 605 - 5 Avenue SW Calgary, Alberta, Canada T2P 3H5, Telephone: [phone], Fax: [phone], Email: [email protected]; Susan L. Riddell Rose, President and Chief Executive Officer; Ryan A. Shay, Vice President Finance and Chief Financial Officer