CALGARY, AB, May 11, 2026 /CNW/ - (TSX: RBY) – Rubellite Energy Corp. ("Rubellite" or the "Company"), is pleased to report its first quarter 2026 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 consolidated interim financial statements and related Management's Discussion and Analysis ("MD&A") for the three months ended March 31, 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.
FIRST QUARTER 2026 OPERATIONAL AND FINANCIAL HIGHLIGHTS
Operational Highlights
- Heavy oil sales production: Averaged a record 8,641 bbl/d in the first quarter of 2026, an increase of 4% from 8,339 bbl/d in the first quarter of 2025 and a 4% increase from 8,295 bbl/d in the fourth quarter of 2025, exceeding first quarter guidance of 8,300 to 8,400 bbl/d.
- Total sales production: Averaged a record 13,843 boe/d in the first quarter of 2026 (66% heavy oil and natural gas liquids ("NGL")), an increase of 12% from 12,383 boe/d (70% heavy oil and NGL) in the first quarter of 2025 and a 6% increase from 13,042 boe/d in Q4 2025, exceeding first quarter guidance of 13,300 to 13,400 boe/d.
- Heavy oil activity: Brought 10 (9.5 net) heavy oil wells on production at Figure Lake and Frog Lake in the first quarter.
- West Central natural gas activity: Added 2 (1.0 net) liquids-rich conventional natural gas wells to production at East Edson at the end of the fourth quarter of 2025 and 2 (1.0 net) additional wells during the first quarter.
- Exploration and development spending(1): Spent $31.3 million in the first quarter, within the guided range of $30.0 to $32.0 million. First quarter spending included the drilling and completion of 4 (4.0 net) multi-lateral horizontal Clearwater development wells, and 1 (1.0 net) waterflood pilot producer-injector pair at Figure Lake (2.0 net drills); 3 (2.5 net) multi-lateral horizontal Waseca development wells at Frog Lake; 1 (1.0 net) exploration well on a new prospect in Saskatchewan; and the drilling, completion, equipping and tie-in of 2 (1.0 net) liquids-rich conventional natural gas wells at East Edson that commenced drilling late in 2025.
- Land and geological and geophysical spending: Spent $0.9 million on land to capture acreage in core areas and for exploration prospects, and $0.4 million on geological and geophysical activities related to completion of the 3D seismic program at Frog Lake, which commenced in the fourth quarter of 2025.
- Abandonment and reclamation: Spent $0.4 million on decommissioning, abandonment and reclamation activities and received one reclamation certificate from the Alberta Energy Regulator ("AER") (Q1 2025 - one).
Financial Highlights
- Adjusted funds flow(1): $33.4 million ($0.36 per share) in the first quarter of 2026, a decrease of 7% from $35.9 million ($0.39 per share) in the first quarter of 2025.
- Cash costs(1): $19.4 million or $15.57/boe in the first quarter of 2026, representing a 17% decrease on a per boe basis as compared to the first quarter of 2025 (Q1 2025 - $20.9 million or $18.76/boe).
- Net loss: $23.1 million ($0.25 per share) in the first quarter of 2026 (Q1 2025 - $1.2 million net income or $0.01 per share) primarily driven by an unrealized loss on risk management contracts.
- Net debt(1): $148.0 million at March 31, 2026, an increase of 3% from $143.1 million at December 31, 2025. Positive free funds flow(1) of $0.7 million generated during the first quarter was primarily used to reduce other obligations, including a $3.8 million reduction of the other provision, $0.4 million of decommissioning expenditures and $0.7 million of cash-settled share based compensation payments.
- Available liquidity(2): $30.8 million at March 31, 2026, based on a $140.0 million first-lien credit facility borrowing limit, less $107.8 million of bank borrowings and $1.4 million in letters of credit. Subsequent to the end of the quarter, the borrowing limit was increased to $160.0 million, further enhancing available liquidity.
(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 MD&A. |
Q1 2026 GUIDANCE RECONCILIATION
During the first quarter of 2026, Rubellite recorded strong growth from a successful drilling program, which saw both heavy oil and total sales production exceed the high end of the Q1 2026 guidance range. Rubellite's heavy oil wellhead differential of $4.81/bbl in Q1/26 exceeded the guided range $3.50 to $4.00/bbl due to higher than expected diluent costs. A comparison of the Company's most recent Q1 2026 guidance metrics to actual results is provided below.
| Q1 2026 Guidance(1) | Q1 2026 Actuals |
Sales Production (boe/d) | 13,300 - 13,400 | 13,843 |
Production mix (% oil and NGL) | 67 % | 66 % |
Heavy oil sales production (bbl/d) | 8,300 - 8,400 | 8,641 |
Exploration and development spending ($ millions)(2)(3) | $30 - $32 | $31.3 |
Heavy oil wellhead differential ($/bbl)(2) | $3.50 - $4.00 | $4.81 |
Royalties (% of revenue)(2) | 13% - 14% | 13 % |
Production and operating costs ($/boe)(2) | $6.50 - $7.25 | $5.89 |
Transportation costs ($/boe)(2) | $4.50 - $5.00 | $4.52 |
General and administrative costs ($/boe)(2) | $3.00 - $3.50 | $3.48 |
(1) | Q1 2026 guidance dated March 10, 2026. |
(2) | Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures". |
(3) | Excludes abandonment and reclamation spending, land and geological expenditures. |
OPERATIONS UPDATE
Figure Lake
Primary Development Update:
In the first quarter, Rubellite drilled and rig released 4 (4.0 net) Clearwater primary development multi-lateral horizontal wells targeting the Wabiskaw Member of the Clearwater Formation, using the optimized 33 meter inter-leg spacing and 15,000 meters open hole length at the 8-26-61-16W4 Surface Pad (the "8-26 Pad"). Initial well performance continues to exceed expectations, with average(1) IP30/60 rates of 303 bbl/d (3 wells)/300 bbl/d (2 wells), compared to the 2025 McDaniel Tier 1 type curve(2) of IP30/60 of 201/193 bbl/d(2).
Drilling operations continued at the 8-26 Pad into the second quarter. In early April, a second drilling rig was added to supplement the one‑rig program and is expected to drill a minimum of 8.0 and up to 13.0 net additional Clearwater multi-lateral horizontal wells to grow heavy oil production in this stronger commodity price environment. Continuation of the second rig into the fourth quarter is contingent upon future heavy oil prices.
A well targeting the Sparky Formation (1.0 net) drilled in the fourth quarter of 2025 continues to deliver encouraging results, with an IP30/60 rate of 286 bbl/d/259 bbl/d and water cut averaging 10%. The well has 6 legs and approximately 7,750 meters of horizontal length. Continuous production from the initial well and further development of the Sparky discovery pool will require construction of a permanent all season access road and pad expansion, which are currently planned for the second half of 2026. The well was temporarily shut in during spring breakup and will be restarted later in the second quarter following completion of interim access upgrades. Two (2.0 net) additional Sparky wells are planned for the fourth quarter of 2026.
Enhanced Oil Recovery ("EOR") Update:
Water injection commenced in March 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").
A second waterflood pilot at Figure Lake was advanced in the first quarter of 2026, with the drilling of an 8‑leg horizontal multi‑lateral producer (1.0 net) on the 8-26 Pad, straddling a dedicated single‑leg injection well (1.0 net). The 4-leg sets on each side of the injector were drilled with 25 meter inter-leg spacing, and offset from the injector by 75 meters. Total open hole length for the 8 legs is approximately 9,900 meters. Initial well performance for the 8 leg producer exceeded expectations with an average IP30 rate of 283 bbl/d. Water injection for this pilot is expected to commence late in the second quarter.
Subsequent to the end of the quarter, a third dedicated producer (1.0 net) and injector (1.0 net) pair were drilled on the 08-26 Pad to evaluate the utility and effectiveness of polymer injection on oil recovery. The 8 leg producer recovered oil based mud ("OBM") on April 20th and achieved an IP(15) of 185 bbl/d. Polymer injection is expected to commence in the fourth quarter.
In addition, two multi-lateral horizontal producer-to-injector conversions on two separate pads at Figure Lake were advanced, with water injection initiated on the 1-3 Pad in March 2026, and water injection expected to be initiated on the 1-13 Pad in the second quarter. These producer-to-injector conversion pilots will evaluate the effectiveness of waterflood where primary production has already occurred through multi-lateral drilling development.
Information from the multiple EOR pilot schemes are being evaluated and will inform future development plans.
Frog Lake
Waseca Update - Open Hole Horizontal Multi-laterals:
During the first quarter, Rubellite drilled and rig released 3 (2.5 net) open hole multi-lateral wells targeting the Waseca Formation.
- Waseca North: 2 (2.0 net) wells achieved average(1) IP30/IP60 rates of 130 bbl/d (2 wells)/134 bbl/d (1 well), exceeding the 2025 McDaniel type curve(2) of 122/117 bbl/d.
- Waseca South: 1 (0.5 net) well achieved an average IP30/IP60 rate of 68 bbl/d, below the 2025 McDaniel type curve(2) of 145 bbl/d due to a combination of thinning reservoir and higher shale content encountered at the toe of the well.
Rubellite suspended drilling operations at Frog Lake on February 5, 2026 to allow the drilling rig, which operated continuously for several years, to undergo servicing and recertification. Drilling recommenced at Frog Lake on April 19, 2026, with the spud of an extended reach Waseca North well (1.0 net). The well is targeting up to 20,000m of open hole, as compared to historical 15,000m of open hole, and using a new water-based amine mud system to reduce costs, improve hole cleaning, and limit fluid losses to the formation while drilling.
GP and Sparky Update - Single Leg Lined Laterals with Recycle Strings:
Rubellite has continued to positively advance the use of single leg lined lateral horizontal wells equipped with high velocity recycle strings to enable consistent production of heavy oil with solids from the less consolidated GP and Sparky Sands of the Mannville Stack. Four (3.0 net) GP wells have been drilled to date using both single‑leg and fishbone designs, of which three were completed with recycle strings. Early IP30(1) performance across the three wells completed with recycle strings ranged from 44–134 bbl/d, with an average of 78 bbl/d. The most recent of those three wells, 00/09-23-056-03W4 (50% working interest), has been on production since December 19, 2025, and following startup and tubing string optimization, is currently producing at an average of 145 bbl/d gross. For reference, the McDaniel year-end 2025 type curve(2) for the GP formation assumes an IP30/IP60 of 73/72 bbl/d.
Other Operational Updates:
Approximately 26 km2 of new 3D seismic was acquired in late 2025 and early 2026 to support future drilling plans at Frog Lake.
A continuous one-rig drilling program is planned for the remainder of the year, targeting the Waseca North and Waseca South sands with open hole multilateral horizontal wells, and the GP and Sparky zones within the Mannville Stack with horizontal wells equipped with recycle strings.
East Edson
Two (1.0 net) Wilrich development wells were rig released, fracture stimulated, equipped, and tied-in following drilling that commenced in late 2025, with both wells brought on production in February.
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 multiple early stage exploration prospects including land capture and play concept de-risking, while maintaining a disciplined approach to risked capital exposure. One (1.0 net) exploration well was drilled at Bayhurst, Saskatchewan in the first quarter and placed on a limited production trial until spring breakup, at which time the well was temporarily shut in. An extended production evaluation period is planned once road restrictions are lifted.
(1) | No development wells were excluded from the calculation of average results except by the criteria for producing days. |
(2) | Type curve assumptions are based on the total proved plus probable undeveloped reserves contained in the McDaniel Report as disclosed in the most recent AIF available under the Company's profile on SEDAR+ at www.sedarplus.ca. "McDaniel Report" means the independent engineering evaluation of the heavy crude oil and conventional natural gas and NGL reserves, prepared by McDaniel with an effective date of December 31, 2025 and a preparation date of March 10, 2026. |
OUTLOOK AND GUIDANCE
For 2026, Rubellite forecasts total exploration and development spending(1) of $125 to $135 million, with the range reflecting the expected duration of a second drilling rig at Figure Lake. In addition to development drilling in its core heavy oil operating areas, 2026 capital spending will support longer term strategic initiatives including: (1) advancing multiple EOR pilots in the Clearwater, with water injection expected to have commenced at six waterflood pilots by mid‑2026; (2) initiating polymer injection on the producer‑injector pair drilled for a polymer flood pilot, with injection planned to commence in Q4 2026; (3) additional injection and production cycles under the novel gas injection EOR pilot at Figure Lake; and (4) ongoing exploration activities across the Company's land base.
Capital Program - Q1 2026:
Figure Lake:
- Drilled and completed 4 (4.0 net) 15,000m, 12 leg, Clearwater primary development wells; and
- Drilled and completed 1 (1.0 net) 10,000m, 8 leg, waterflood pilot producer and 1.0 (1.0 net) injector on the 8-26 Pad.
Frog Lake:
- Drilled and completed 1 (0.5 net) Waseca South development wells; and
- Drilled and completed 2 (2.0 net) Waseca North development wells.
East Edson:
- Drilled, fracture stimulated, equipped, and tied-in 2 (1.0 net) Wilrich natural gas development wells.
Exploration:
- Drilled and completed 1 (1.0 net) exploration well at Bayhurst, Saskatchewan.
Capital Program - Remainder of 2026:
At Figure Lake:
- Drilling and completion of 17 (17.0 net) to 22 (22.0 net) 15,000m, 12 leg, Clearwater primary development wells;
- Drilling and completion of 2 (2.0 net) 10,000m, 10 leg, Clearwater step-out wells;
- Drilling and completion of 2 (2.0 net) 10-15,000m, 12 leg, Sparky wells;
- Drilling and completion of 1 (1.0 net) 10,000m, 8 leg, polymer flood pilot producer and 1 (1.0 net) injector on the '8-26 Pad';
- Surface and downhole equipping activities related to two mature multi-lateral producer to waterflood injector conversions; and
- Additional core testing to continue informing EOR initiatives.
At Ukalta:
- Conversion of an existing mature multi-lateral producer to waterflood injector, with water injection expected to commence in the second quarter.
At Frog Lake:
- Drilling and completion of 24 (13.0 net) wells targeting the Waseca North, Waseca South, GP and Sparky zones;
- Drilling and completion of 1 (0.5 net) water disposal well; and
- Core testing to inform EOR initiatives.
Additional capital spending is anticipated for land and seismic purchases and other exploration activities. Capital activity is expected to be funded from adjusted funds flow(1), with any excess free funds flow(1) applied to net debt(1) reduction and other balance sheet obligations.
For 2026, heavy oil sales volumes are forecast to average 8,800 to 9,200 bbl/d, while total production sales volumes, including natural gas and NGL volumes, are forecast to average 13,300 to 13,800 boe/d, representing 7% to 10% growth relative to 2025.
Building on continued efficiency gains, operating costs are forecast to average $6.50 to $7.00/boe for 2026, and transportation costs are forecast to average $4.75 to $5.25/boe, reflecting anticipated increased fuel surcharges for trucked oil. Heavy oil wellhead differentials are forecast to average $4.50 to $5.50/bbl, assuming diluent pricing consistent with the current forward curve. Royalties are expected to increase as a percentage of revenue, averaging 14.5% to 15.5%, given the higher forecast reference oil prices.
Rubellite will continue to address end of life asset retirement obligations ("ARO"), with $1.4 million of abandonment and reclamation expenditures planned for the remainder of 2026, satisfying the Company's AER area-based mandatory 2026 spending requirement of $1.4 million.
(1) | Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures". |
Planned exploration and development spending and drilling activity for 2026 is summarized in the table below:
| Q1 2026 | Q2 - Q4 2026 | Full year 2026 |
| Capital
Expenditures
(millions)(1) | # of wells | Capital
Expenditures
(millions)(1) | # of wells | Capital
Expenditures
(millions)(1) | # of wells |
| (gross/net) | (gross/net) | (gross/net) |
Figure Lake(1) |
| 6 / 6.0 |
| 23 - 28 / 23.0 - 28.0 |
| 29 - 34 / 29.0 - 34.0 |
Frog Lake |
| 3 / 2.5 |
| 25 / 13.5 |
| 28 / 16.0 |
Marten Hills |
| - / - |
| - / - |
| -/- |
East Edson |
| 2 / 1.0 |
| - / - |
| 2 / 1.0 |
Exploration |
| 1 / 1.0 |
| - / - |
| 1 / 1.0 |
Total | $31.3 | 12 / 10.5 | $94 - $104 | 48 - 53 / 36.5 - 41.5 | $125 - $135 | 60 - 65 / 47.0 - 52.0 |
(1) | Excludes corporate expenditures, abandonment and reclamation spending, land and geological expenditures, if any. |
(2) | 2 (2.0 net) wells drilled in Q1 2026 were the waterflood pilot producer-injector pair and 2 (2.0 net) wells drilled in Q2 2026 will be the polymer pilot producer-injector pair on the 8-26 Pad at Figure Lake. |
Rubellite's financial and operational guidance for the second quarter and full year 2026 is presented in the table below:
| Q2 2026 Guidance | Full year 2026 Guidance |
Sales Production (boe/d) | 13,300 - 13,400 | 13,300 - 13,800 |
Production mix (% oil and NGL) | 68 % | 69 % |
Heavy oil sales production (bbl/d) | 8,550 - 8,650 | 8,800 - 9,200 |
Exploration and development spending ($ millions)(1)(2) | $39 - $41 | $125 - $135 |
Heavy oil wellhead differential ($/bbl)(1) | $5.50 - $6.00 | $4.50 - $5.50 |
Royalties (% of revenue)(1) | 15.5% - 16.5% | 14.5% - 15.5% |
Production and operating costs ($/boe)(1) | $6.50 - $7.25 | $6.50 - $7.00 |
Transportation costs ($/boe)(1) | $4.75 - $5.25 | $4.75 - $5.25 |
General and administrative costs ($/boe)(1) | $3.00 - $3.50 | $3.00 - $3.50 |
(1) | Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures". |
(2) | Excludes abandonment and reclamation spending, land and geological expenditures, if any. |
SUMMARY OF QUARTERLY RESULTS
| Three months ended March 31, |
($ thousands, except as noted) | 2026 | 2025 |
Financial |
|
|
Oil and natural gas revenue | 66,243 | 66,607 |
Net income and comprehensive income | (23,071) | 1,160 |
Per share – basic(1) | (0.25) | 0.01 |
Per share – diluted(1) | (0.25) | 0.01 |
Total Assets | 597,152 | 551,889 |
Cash flow from operating activities | 24,579 | 27,135 |
Adjusted funds flow(2) | 33,367 | 35,934 |
Per share – basic(1)(2) | 0.36 | 0.39 |
Per share – diluted(1)(2) | 0.36 | 0.38 |
Q1 annualized adjusted funds flow(2)(7) | 133,468 | 143,736 |
Net debt to Q3 annualized adjusted funds flow ratio(2)(7) | 1.1 | 1.0 |
Net debt(2) | 148,006 | 147,688 |
Capital expenditures(2) |
|
|
Total capital expenditures(2) | 32,664 | 24,932 |
Wells Drilled(3) – gross (net) | 12 / 10.5 | 12 / 9.8 |
Common shares outstanding(1)(thousands) |
|
|
Weighted average – basic | 93,590 | 92,930 |
Weighted average – diluted | 93,590 | 95,068 |
End of period | 93,774 | 93,387 |
Sales Production |
|
|
Heavy Oil (bbl/d)(4) | 8,641 | 8,339 |
Natural gas (Mcf/d) | 28,532 | 22,038 |
NGL (bbl/d)(5) | 447 | 371 |
Daily average sales production (boe/d) | 13,843 | 12,383 |
Average prices |
|
|
West Texas Intermediate ("WTI") ($US/bbl) | 71.93 | 71.42 |
Western Canadian Select ("WCS") ($CAD/bbl) | 79.23 | 84.30 |
AECO 5A Daily Index ($CAD/Mcf) | 1.82 | 2.16 |
Rubellite average realized prices(2)(6) |
|
|
Oil ($/bbl) | 74.42 | 80.03 |
Natural gas ($/Mcf) | 2.27 | 2.16 |
NGL ($/bbl) | 63.10 | 67.54 |
Average realized price(2) ($/boe) | 53.17 | 59.77 |
Average realized price, after risk management contracts(2) ($/boe) | 49.37 | 59.60 |
Operating netback ($/boe) |
|
|
Revenue | 53.17 | 59.77 |
Royalties | (7.02) | (8.48) |
Net operating costs(2) | (5.89) | (7.00) |
Transportation costs | (4.52) | (5.59) |
Operating netback(2) | 35.74 | 38.70 |
Realized gain on risk management contracts | (3.80) | (0.17) |
Total operating netback, after risk management contracts(2) | 31.94 | 38.53 |
(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) | 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 Q1 2026 and Q1 2025 annualized adjusted funds flow before transaction costs relative to period end net debt. |
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.
For additional information please contact: Rubellite Energy Corp. Suite 3200, 605 - 5 Avenue SW Calgary, Alberta, Canada T2P 3H5 Telephone: 403 269-4400 Fax: 403 269-4444 Email: info@rubelliteenergy.com |
Susan L. Riddell Rose Ryan A. Shay | President and Chief Executive Officer Vice President Finance and Chief Financial Officer |
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.
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 |
boe/d | barrels of oil equivalent per day |
Mboe | thousands of 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 |
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:
| Three months ended March 31, |
($ thousands) | 2026 | 2025 |
Net cash flows used in investing activities | (39,197) | (24,383) |
Change in non-cash working capital | (6,533) | 549 |
Total capital expenditures | (32,664) | (24,932) |
|
|
|
Property, plant and equipment expenditures | (28,600) | (21,858) |
Exploration and evaluation expenditures | (3,971) | (2,933) |
Corporate expenditures | (93) | (141) |
Total capital expenditures | (32,664) | (24,932) |
Add back: |
|
|
Corporate | 93 | 141 |
Geological and geophysical | 370 | 405 |
Land and other | 875 | 2,102 |
Exploration and development spending(1) | (31,326) | (22,284) |
(1) | Non-GAAP supplementary measure. See "Supplementary Measures" contained in this news release. |
Presented below are capital expenditures by CGU:
| Three months ended March 31, |
($ thousands) | 2026 | 2025 |
Total capital expenditures: |
|
|
Eastern Heavy Oil | 27,393 | 24,223 |
West Central | 5,178 | 581 |
Corporate | 93 | 128 |
Total capital expenditures | 32,664 | 24,932 |
|
|
|
Exploration and development spending: |
|
|
Eastern Heavy Oil | 26,148 | 21,703 |
West Central | 5,178 | 581 |
Exploration and development spending: | 31,326 | 22,284 |
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 March 31, |
($ thousands, except per boe amounts) | $/boe | 2026 | $/boe | 2025 |
Net operating costs | 5.89 | 7,335 | 7.00 | 7,796 |
Transportation | 4.52 | 5,630 | 5.59 | 6,231 |
General and administrative | 3.48 | 4,333 | 3.96 | 4,414 |
Cash finance expense | 1.68 | 2,088 | 2.21 | 2,459 |
Cash costs | 15.57 | 19,386 | 18.76 | 20,900 |
Operating netbacks and total operating netbacks, after risk management contracts: Operating netback is calculated by deducting royalties, net operating expenses, and transportation costs from oil and natural gas revenue. Operating netback is also calculated on a per boe basis using total production sold in the period. Total operating netbacks, after risk management contracts, is presented after adjusting for realized gains or losses from risk management contracts. Rubellite considers operating netback and operating netback after risk management contracts to be key industry performance indicators that provides investors with information that is also commonly presented by other oil and natural gas producers. Rubellite presents the operating netback at a CGU level as it provides investors with key information related to the Eastern Heavy Oil CGU which is the area where growth capital investment is focused. Operating netback and operating netback, after risk management contracts, evaluate operational performance as it demonstrates its profitability relative to realized and current commodity prices.
Net operating costs: Net operating costs equals operating expenses net of other income, which is made up of processing revenue and other one time items from time to time. Management views net operating costs as an important measure to evaluate its operational performance. The most directly comparable IFRS measure for net operating costs is production and operating expenses.
The following table reconciles net operating costs from production and operating expenses and other income in the Company's consolidated statement of income (loss) and comprehensive income (loss).
| Three months ended March 31, |
($ thousands, except per boe amounts) | 2026 | 2025 |
Other income | 133 | 102 |
|
|
|
Production and operating | 7,468 | 7,898 |
Less: processing income | (133) | (102) |
Net operating costs | 7,335 | 7,796 |
$/boe | 5.89 | 7.00 |
Net Debt and Adjusted Working Capital Deficit: Rubellite uses net debt as an alternative measure of outstanding debt and is calculated by adding borrowings under the credit facility and term loan debt less adjusted working capital. Adjusted working capital is calculated by adding cash, accounts receivable, prepaid expenses and deposits and product inventory less accounts payable and accrued liabilities. Management considers net debt as an important measure in assessing the liquidity of the Company. Net debt is used by management to assess the Company's overall debt position and borrowing capacity. Net debt is not a standardized measure and therefore may not be comparable to similar measures presented by other entities.
The following table reconciles working capital and net debt as reported in the Company's statements of financial position:
($ thousands) | As of March 31, 2026 | As of December 31, 2025 |
Current assets | 37,432 | 35,181 |
Current liabilities | (97,311) | (70,413) |
Working capital deficit | 59,879 | 35,232 |
Risk management contracts – current asset | 1,110 | 5,828 |
Risk management contracts – current liability | (27,915) | (327) |
Right of use liability - current liability | (385) | (389) |
Share-based compensation liability - current liability | (7,430) | (4,694) |
Decommissioning obligations – current liability | (1,340) | (1,340) |
Other provision - current liability | (3,750) | (3,750) |
Adjusted working capital deficit(1) | 20,169 | 30,560 |
Bank indebtedness | 107,837 | 92,583 |
Term loan (principal) | 20,000 | 20,000 |
Net debt(2) | 148,006 | 143,143 |
|
|
|
Other provision (undiscounted obligation)(3) | 12,441 | 16,191 |
(1) | Calculation of current assets less current liabilities has been adjusted for the removal of the current portion of risk management contracts, decommissioning liabilities, lease liabilities, share-based compensation and other provisions. |
(2) | Excludes other non-current liabilities. |
(3) | Other provision at the undiscounted obligation is presented in the financial statements and used in the NAV calculation in this news release. |
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 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 March 31, |
($ thousands, except as noted) | 2026 | 2025 |
Net cash flows from operating activities | 24,579 | 27,135 |
Change in non-cash working capital | 3,866 | 4,080 |
Cash-settled share-based compensation | 729 | 196 |
Other provision settled | 3,750 | 3,750 |
Decommissioning obligations settled | 443 | 773 |
Adjusted funds flow | 33,367 | 35,934 |
|
|
|
Adjusted funds flow per share - basic | 0.36 | 0.39 |
Adjusted funds flow per share - diluted | 0.36 | 0.38 |
Adjusted funds flow per boe | 26.78 | 32.24 |
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 its most directly comparable GAAP measure 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:
| Three months ended March 31, |
($ thousands, except per share and per boe amounts) | 2026 | 2025 |
Adjusted funds flow | 33,367 | 35,934 |
Capital expenditures, including land, corporate and other | (32,664) | (24,932) |
Free funds flow | 703 | 11,002 |
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: calculated as the average realized price less the realized gain or loss on risk management contracts.
Adjusted funds flow per share: 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: calculated as adjusted funds flow divided by total average daily production sold in the period.
Net debt to adjusted funds flow ratio: net debt to adjusted funds flow ratios is adjusted to calculate adjusted funds flow 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
"Exploration and development spending" is comprised of the non-GAAP measure total capital expenditures (as calculated above), less land and other, geological and geophysical and corporate spending.
"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$/bbl) prior to any price or risk management activities.
"Realized oil price" is comprised of total oil revenue, as determined in accordance with IFRS, divided by the Company's total sales oil production on a per barrel basis.
"Realized natural gas price" is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company's natural gas sales production.
"Realized NGL price" is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company's NGL sales production.
"Royalties as a percentage of revenue" is comprised of royalties, as determined in accordance with IFRS, divided by oil revenue from sales oil production as determined in accordance with IFRS.
"Net operating expense per boe" is comprised of net operating expense, divided by the Company's total sales production.
"Transportation cost ($/boe)" is comprised of transportation cost, as determined in accordance with IFRS, divided by the Company's total sales oil production.
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 in the Company's core properties at Figure Lake, Frog Lake and East Edson, anticipated average heavy oil sales volumes and total production sales volumes in 2026; the expectation that capital spending activity will be funded from adjusted funds flow, with excess free funds flow to reduce net debt and for other balance sheet obligations; 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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