CALGARY, AB, Nov. 5, 2025 /CNW/ - (TSX: RBY) -- Rubellite Energy Corp. ("Rubellite" or the "Company"), is pleased to report its third quarter 2025 financial and operating results and provide an operations and guidance update.
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, 2025, 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.
THIRD QUARTER 2025 OPERATIONAL AND FINANCIAL HIGHLIGHTS
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 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 news release.
(2) See "Liquidity, Capitalization and Financial
Resources - Capital Management" in the Q3 2025 MD&A.
OPERATIONS UPDATE
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 175 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 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 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:
Q1 - Q3 2025 Q4 2025 Full year 2025
Capital # of wells Capital # of wells Capital # of wells
Expenditures Expenditures Expenditures
(millions)
(millions) (millions)
(gross/net) (gross/net) (gross/net)
Figure
Lake(1) 14 / 14.0 6 / 6.0 20 / 20.0
Frog Lake(2) 19 / 14.0 7 / 3.5 26 / 17.5
Marten Hills 1 / 0.3 - / - 1 / 0.3
East Edson 2 / 1.0 2 / 1.0 4 / 2.0
Exploration 1 / 1.0 - / - 1 / 1.0
Total(3) $80.0 37 / 30.3 $30 - $35 15 / 10.5 $110 - $115 52 / 40.8
(1) Includes one waterflood injection well.
(2) Includes 5 gross (3.0 net) wells at Frog Lake
targeting secondary exploration zones.
(3) Excludes abandonment and reclamation spending,
acquisitions and land expenditures, if any.
Rubellite's capital spending, drilling and operational guidance for 2025 are presented in the table below:
Previous Full Year Full Year 2025
2025 Guidance(1) Guidance
Sales Production (boe/d) 12,200 - 12,400 12,325 - 12,400
Production mix (% oil and liquids)(2) 70 % 70 %
Heavy Oil Production (bbl/d) 8,200 - 8,400 8,325 - 8,400
Exploration and Development spending ($
millions)(3)(4) $100 - $110 $110 - $115
Heavy oil wellhead differential $4.00 - $4.50 $3.75 - $4.00
($/bbl)(3)
Royalties (% of revenue)(3) 13% - 14% 13% - 14%
Production and operating costs ($/boe)(3) $6.50 - $7.25 $6.50 - $7.00
Transportation costs ($/boe)(3) $5.50 - $6.00 $5.25 - $5.50
General and administrative costs $3.00 - $3.50 $3.00 - $3.50
($/boe)(3)
(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.
SUMMARY OF QUARTERLY RESULTS
Three months ended September Nine months ended September
30, 30,
($ thousands,
except as noted) 2025 2024 2025 2024
Financial
Oil revenue 58,290 43,682 185,439 109,303
Net income and
comprehensive
income 5,646 15,010 22,857 23,225
Per share --
basic(1) 0.06 0.23 0.25 0.37
Per share --
diluted(1) 0.06 0.23 0.24 0.36
Total Assets 558,709 432,836 558,709 432,836
Cash flow from
operating
activities 34,953 19,973 97,896 56,386
Adjusted funds
flow(2) 35,663 23,029 108,908 62,145
Per share --
basic(1)(2) 0.38 0.35 1.17 0.98
Per share --
diluted(1)(2) 0.37 0.35 1.14 0.96
Adjusted funds
flow, before
transaction
costs(2)(6) 35,663 25,039 108,908 64,155
Per share --
basic(1)(2) 0.38 0.37 1.17 1.00
Per share --
diluted(1)(2) 0.37 0.37 1.14 0.99
Q3 annualized
adjusted funds
flow(2)(7) 142,652 100,156 142,652 100,156
Net debt to Q3
annualized
adjusted funds
flow ratio(2)(7) 1.0 1.5 1.0 1.5
Net debt(2) 138,354 147,939 138,354 147,939
Capital
expenditures (2)
Capital
expenditures,
including land,
corporate and
other(2) 35,365 36,650 91,465 73,369
Acquisition(8)(9) -- 62,732 -- 62,732
Proceeds on
disposition(10) (5,500) -- (5,500) --
Capital
expenditures,
after acquisition
and
dispositions(2) 29,865 99,382 85,965 136,101
Wells Drilled(3)
-- gross (net) 14 / 11.5 16 / 13.5 37 / 30.3 31 / 28.5
Common shares
outstanding(1)
(thousands)
Weighted average
-- basic 93,700 65,834 93,211 63,592
Weighted average
-- diluted 96,311 66,571 95,838 64,599
End of period 93,670 67,593 93,670 67,593
Operating
Heavy Oil
(bbl/d)(4) 8,338 5,954 8,438 4,994
Natural gas
(Mcf/d) 20,975 -- 21,174 --
NGL (bbl/d)(5) 288 -- 342 --
Daily average
sales production
(boe/d) 12,122 5,954 12,309 4,994
Average prices
West Texas
Intermediate
("WTI")
($US/bbl) 64.93 75.09 66.70 77.54
Western Canadian
Select ("WCS")
($CAD/bbl) 75.10 83.95 77.88 84.45
AECO 5A Daily
Index ($CAD/Mcf) 0.63 0.69 1.50 1.45
Rubellite average
realized
prices(2)(6)
Oil ($/bbl) 72.40 79.75 74.06 79.88
Natural gas
($/Mcf) 0.66 -- 1.58 --
NGL ($/bbl) 56.12 -- 60.85 --
Average realized
price(2) ($/boe) 52.27 79.75 55.18 79.88
Average realized
price, after risk
management
contracts(2)
($/boe) 55.83 80.06 57.74 79.46
(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 news release.
(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.
ABOUT RUBELLITE
The Company is a Canadian energy company headquartered in Calgary, Alberta which, through its operating subsidiary, Rubellite Energy Inc. is 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, 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 Mcf thousand cubic feet MMcf million cubic feet MMcf/d million cubic feet per day
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.
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 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.
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 Nine months ended September
30, 30,
($ thousands) 2025 2024 2025 2024
Net cash flows
used in
investing
activities (19,291) (86,044) (82,304) (123,397)
Acquisitions -- (62,732) -- (62,732)
Dispositions 5,500 -- 5,500 --
Change in
non-cash
working
capital 10,574 13,338 3,661 12,704
Capital
expenditures (35,365) (36,650) (91,465) (73,369)
Property,
plant and
equipment
expenditures (34,854) (28,348) (84,407) (58,115)
Exploration
and
evaluation
expenditures (312) (8,250) (6,662) (12,285)
Corporate
additions (199) (52) (396) (2,969)
Capital
expenditures (35,365) (36,650) (91,465) (73,369)
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.
Three months ended September 30,
($ thousands, except per boe amounts) $/boe 2025 $/boe 2024
Net operating costs 6.46 7,206 8.46 4,634
Transportation 4.66 5,201 7.67 4,202
General and administrative 3.24 3,615 4.87 2,668
Cash finance expense 2.30 2,568 3.72 2,035
Cash costs 16.66 18,590 24.72 13,539
Nine Months Ended September 30,
($ thousands, except per boe amounts) $/boe 2025 $/boe 2024
Net operating costs 6.72 22,593 7.29 9,978
Transportation 5.40 18,139 7.73 10,581
General and administrative 3.58 12,044 5.18 7,094
Cash finance expense 2.19 7,366 3.02 4,122
Cash costs 17.89 60,142 23.22 31,775
Operating netbacks and total operating netbacks, after risk management contracts: Operating netback is calculated by deducting royalties, net operating expenses, and transportation costs from oil and natural gas revenue. Operating netback is also calculated on a per boe basis using total production sold in the period. Total operating netbacks, after risk management contracts, is presented after adjusting for realized gains or losses from risk management contracts. Rubellite considers operating netback and operating netback after risk management contracts to be key industry performance indicators that provides investors with information that is also commonly presented by other oil and natural gas producers. Rubellite presents the operating netback at a CGU level as it provides investors with key information related to the Eastern Heavy Oil CGU which is the area where growth capital investment is focused. Operating netback and operating netback, after risk management contracts, evaluate operational performance as it demonstrates its profitability relative to realized and current commodity prices.
Net operating costs: Net operating costs equals operating expenses net of other income, which is made up of processing revenue and other one time items from time to time. Management views net operating costs as an important measure to evaluate its operational performance. The most directly comparable IFRS measure for net operating costs is production and operating expenses.
The following table reconciles net operating costs from production and operating expenses and other income in the Company's consolidated statement of income (loss) and comprehensive income (loss).
Three months ended September Nine months ended September
30, 30,
($ thousands,
except per
boe amounts) 2025 2024 2025 2024
Other income 75 -- 580 --
Less: Non -- -- (343) --
processing
income
Processing
income 75 -- 237 --
Production and
operating 7,281 4,634 22,830 9,978
Less:
processing
income (75) -- (237) --
Net operating
costs 7,206 4,634 22,593 9,978
$/boe 6.46 8.46 6.72 7.29
Net Debt and Adjusted Working Capital Deficit: Rubellite uses net debt as an alternative measure of outstanding debt and is calculated by adding borrowings under the credit facility and term loan debt less adjusted working capital. Adjusted working capital is calculated by adding cash, accounts receivable, prepaid expenses and deposits and product inventory less accounts payable and accrued liabilities. Management considers net debt as an important measure in assessing the liquidity of the Company. Net debt is used by management to assess the Company's overall debt position and borrowing capacity. Net debt is not a standardized measure and therefore may not be comparable to similar measures presented by other entities.
The following table reconciles working capital and net debt as reported in the Company's statements of financial position:
($ thousands) As of September 30, 2025 As of December 31, 2024
Current assets 31,631 44,714
Current liabilities (66,366) (74,680)
Working capital deficit 34,735 29,966
Risk management contracts
-- current asset 4,690 9,783
Risk management contracts
-- current liability (812) (2,765)
Right of use liability -
current liability (387) (357)
Share-based compensation
liability - current
liability (5,346) (5,357)
Decommissioning obligations
-- current liability (1,415) (2,000)
Other provision - current
liability (3,750) (3,750)
Adjusted working capital
deficit(1) 27,715 25,520
Bank indebtedness 90,639 108,500
Term loan (principal) 20,000 20,000
Net debt(2) 138,354 154,020
(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 decommissioning liabilities and other provisions.
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 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 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 Nine months ended September
30, 30,
($ thousands,
except as
noted) 2025 2024 2025 2024
Net cash flows
from operating
activities 34,953 19,973 97,896 56,386
Change in
non-cash
working capital (1,223) 2,934 3,352 5,489
Cash-settled
share-based
compensation 1,539 -- 2,624 --
Other provision -- -- 3,750 --
settled
Decommissioning
obligations
settled 394 122 1,286 270
Adjusted funds
flow 35,663 23,029 108,908 62,145
Transaction
Costs -- 2,010 -- 2,010
Adjusted funds
flow - before
transaction
costs 35,663 25,039 108,908 64,155
Adjusted funds
flow per share
- basic 0.38 0.35 1.17 0.98
Adjusted funds
flow per share
- diluted 0.37 0.35 1.14 0.96
Adjusted funds
flow per boe 31.98 42.04 32.41 45.42
Adjusted funds
flow per share
- before
transaction
costs - basic 0.38 0.37 1.17 1.00
Adjusted funds
flow per share
- before
transaction
costs - diluted 0.37 0.37 1.14 0.99
Adjusted funds
flow per boe -
before
transaction
costs 31.98 45.04 32.41 46.62
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. Rubellite's capital expenditures excluded non cash items and acquisitions and dispositions. Adjusted funds flow and capital expenditures are non-GAAP financial measures which have been reconciled to its most directly comparable GAAP measure previously in this document. By removing the impact of current period capital expenditures from adjusted funds flow, Rubellite monitors its free funds flow to inform decisions such as capital allocation and debt repayment.
The following table shows the calculation of the removal of capital expenditures from adjusted funds flows pre transaction costs:
Three months ended September Nine months ended September
30, 30,
($ thousands,
except per
share and per
boe amounts) 2025 2024 2025 2024
Adjusted funds
flow 35,663 23,029 108,908 62,145
Capital
expenditures,
including
land,
corporate and
other (35,365) (36,650) (91,465) (73,369)
Free funds
flow 298 (13,621) 17,443 (11,224)
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.
Net debt to adjusted funds flow ratio: Net debt to adjusted funds flow ratios are calculated on a trailing twelve-month basis.
Net debt to annualized adjusted funds flow ratio: Net debt to annualized adjusted funds flow ratios are calculated by annualizing the current quarter adjusted funds flow after transaction costs.
Supplementary Financial Measures
"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.
"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.
"Royalties as a 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.
"Net operating expense per boe" is comprised of net operating expense, divided by the Company's total sales production.
"Transportation cost ($/boe)" is comprised of transportation cost, as determined in accordance with IFRS, divided by the Company's total sales oil production.
"General & administrative costs ($/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, and the benefits to be derived from such drilling including drilling techniques and 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 "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), 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 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.
/CONTACT:
Copyright CNW Group 2025
(END) Dow Jones Newswires
November 05, 2025 17:35 ET (22:35 GMT)