RUBELLITE ENERGY CORP. REPORTS FOURTH QUARTER 2024 FINANCIAL AND OPERATING RESULTS, YEAR-END 2024 RESERVES, PROVIDES OPERATIONS UPDATE AND FIRST QUARTER AND FULL YEAR 2025 GUIDANCE
CALGARY, AB, March 10, 2025 /CNW/ - (TSX: RBY) – Rubellite Energy Corp. ("Rubellite" or the "Company"), is pleased to report its fourth quarter 2024 financial and operating results and select information from the Company's independent year-end 2024 reserve report, evaluated by McDaniel and Associates Consultants Ltd. ("McDaniel"), provides an operations update and provides first quarter and full year 2025 guidance. A copy of Rubellite's audited financial statements, Management's Discussion and Analysis ("MD&A") and Annual Information Form for the year ended December 31, 2024 will be 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.
FOURTH QUARTER AND FULL YEAR 2024 HIGHLIGHTS
- On October 31, 2024, the Company, Rubellite Energy Inc., and Perpetual Energy Inc. ("Perpetual") completed the previously announced recombination transaction by way of an arrangement under Section 193 of the Business Corporations Act (Alberta) (the "Recombination Transaction")(1). In accordance with the Recombination Transaction, (i) holders of common shares of Rubellite Energy Inc. received one (1) common share of the Company for every one (1) common share of Rubellite Energy Inc. held, (ii) holders of common shares of Perpetual received one (1) common share of the Company for every five (5) Perpetual common shares held, and (iii) Perpetual's outstanding senior notes ($26.2 million in face value) were converted into 11.6 million common shares of the Company at a conversion price of $2.25 per share. At closing, shareholders of Rubellite Energy Inc. held 67.6 million shares (72.7%), Perpetual shareholders held 13.7 million shares (14.8%) and holders of Perpetual senior notes held the remaining 12.5% of the Company.
- Rubellite delivered record fourth quarter conventional heavy oil sales production of 7,754 bbl/d that exceeded guidance and was 30% higher than the third quarter of 2024 (Q3 2024 - 5,954 bbl/d) and 84% above the fourth quarter of 2023 (Q4 2023 - 4,209 bbl/d). Fourth quarter total sales production of 10,386 boe/d (77% heavy oil and NGL) was up 74% and 147% from the third quarter of 2024 and fourth quarter of 2023. Production growth relative to the third quarter of 2024 was driven by the successful drilling program at Figure Lake, the full quarter impact of the acquisition of Buffalo Mission Energy Corp. (the "BMEC Acquisition") which closed on August 2, 2024, and two months of operations at East Edson following the closing of the Recombination Transaction, which added an average of 2,627 boe/d of sales volumes (14.1 MMcf/d of conventional natural gas and 275 bbl/d of NGL). During the fourth quarter, there were seventeen (14.25 net) wells brought on production from the heavy oil drilling program at both Figure Lake and Frog Lake.
- Rubellite delivered 2024 exit rate sales production for the month of December of 12,027 boe/d (8,083 bbl/d heavy oil), exceeding previous production guidance ranges of 11,300 to 11,800 boe/d of total sales (7,500 to 7,900 bbl/d heavy oil).
- Exploration and development capital expenditures(2) totaled $34.4 million for the fourth quarter bringing expenditures to $101.7 million in 2024. Fourth quarter spending included costs to drill, complete, equip and tie-in nine (9.0 net) multi-lateral horizontal development / step-out delineation wells at Figure Lake, five (3.0 net) multi-lateral horizontal development wells at Frog Lake and one (1.0 net) exploratory horizontal four-leg multi-lateral well at Calling Lake / Nixon. Included in fourth quarter development capital spending was $1.8 million for the Figure Lake gas conservation project, bringing total gas plant and pipeline expenditures to $7.2 million in 2024.
- Adjusted funds flow before transaction costs(2) in the fourth quarter was $35.9 million ($0.41 per share) compared to the third quarter of $25.0 million or $0.37/share (Q4 2023 - $17.1 million or $0.27 per share). Adjusted funds flow after transaction costs(2) for the three and twelve months ended December 31, 2024 were $31.6 and $93.8 million (three and twelve months ended December 31, 2024 - $16.9 and $54.2 million).
- Cash costs(2) were $18.6 million or $19.45/boe in the fourth quarter of 2024 (Q3 2024 - $13.5 million or $24.72/boe; Q4 2023 - $7.9 million or $20.49/boe).
- Net income was $26.7 million in the fourth quarter of 2024 (Q4 2023 - $9.5 million net income).
- As at December 31, 2024, net debt(2) was $154.0 million, an increase from $51.0 million as at December 31, 2023 as a result of the BMEC Acquisition during the third quarter of 2024 and capital expenditures of $108.9 million in 2024 which exceeded adjusted funds flow of $93.8 million. The Recombination Transaction did not have a material impact on net debt as consideration was primarily from the issuance of Rubellite shares with minimal net debt assumed. At December 31, 2024, net debt to Q4 2024 annualized adjusted funds flow before transaction costs(2) was 1.1 times.
- Rubellite had available liquidity(2) at December 31, 2024 of $30.4 million, comprised of the $140.0 million borrowing limit of Rubellite's first lien credit facility, less current bank borrowings of $108.5 million, outstanding letters of credit of $3.6 million offset by cash and cash equivalents of $2.6 million.
(1) |
This news release contains certain information pertaining to the Company before and after giving effect to the Recombination Transaction. Any reference to information prior to October 31, 2024 are references to Rubellite Energy Inc. and any reference to information subsequent to October 31, 2024 are references to the Company. Accordingly, unless the context otherwise requires, references to the Company subsequent to October 31, 2024 shall mean "Rubellite Energy Corp." and references to the Corporation prior to October 31, 2024 shall mean "Rubellite Energy Inc." |
(2) |
Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this news release. |
OPERATIONS UPDATE
In 2024, operational goals were focused on: (1) maximizing the Net Present Value ("NPV") of development locations at Figure Lake through advancements in well design; (2) de-risking the prospective location inventory at Figure Lake through confirmatory step-out drilling; (3) construction and commissioning of the solution gas gathering and natural gas sales infrastructure at Figure Lake; and (4) integration of the Frog Lake assets acquired through the BMEC Acquisition. Positive advancement of these objectives successfully converted the vast majority of Rubellite's ~316 net heavy oil development locations(1) to high confidence locations, solidifying the foundation for Rubellite's longer term organic growth plan.
Operational goals for 2025 include: (1) advancement of enhanced oil recovery opportunities at Figure Lake; (2) ongoing improvement of well designs and development costs across the portfolio; and (3) testing and de-risking of secondary Mannville Stack sands at Frog Lake.
Greater Figure Lake (Figure Lake and Edwand)
Production from the Greater Figure Lake area averaged 5,228 bbl/d (100% heavy oil) in December 2024 and 4,953 bbl/d (100% heavy oil) for the fourth quarter.
In the fourth quarter of 2024, Rubellite operated two rigs to drill and rig release a total of nine (9.0 net) horizontal wells in the Greater Figure Lake area, all targeting the Clearwater formation, bringing the total number of wells drilled in the year to thirty-four (34.0 net) wells. Average results from the 2024 capital program across the Greater Figure Lake field continue to meet or exceed expectations, solidifying confidence in the geologic model and affirming the 243.0 net drilling inventory locations, including 65.6 net proven undeveloped and 30.6 probable undeveloped(1) identified. Under a one-rig program drilling 18 wells per year, the location count at Figure Lake represents over 13 years of economic inventory.
Well Design Pilot
During the second half of 2024, the Company executed a pilot drilling project at the 6-19-62-18W4 Pad (the "6-19 Pad") and 1-25-62-19W4 Pad (the "1-25" Pad) to validate the predicted economic advantage of implementing tighter inter-leg spacing in the Clearwater formation at Figure Lake. Specifically, the Company reduced the distance between laterals from 50m to approximately 33m, and commensurately increased the number of legs from eight to twelve, thereby also increasing the open hole lateral length per well from ~10,000 meters to ~15,000 meters while maintaining the same approximate area coverage per well. Early productivity data from the tighter spacing design is encouraging, both on a per meter and total production per well basis. A total of eight (8.0 net) horizontal wells were drilled with a tighter 33 meter inter-leg spacing which were compared to four (4.0 net) wells drilled with a wider 50 meter inter-leg spacing within the pilot project area. While productivity per meter of open reservoir varies with reservoir quality, the preliminary pilot results suggest that productivity per meter of open reservoir for the wells with tighter inter-leg spacing is statistically similar to the closest neighboring wells, supporting the expectation of economic production acceleration. Incremental drilling time and costs savings per meter drilled for the wells with tighter inter-leg spacing are also encouraging and in line with modeled assumptions, and in combination with early production data suggest that an increase in net asset value per unit area of land will be realized. The 00/08-23-062-19W4 was drilled with a 33 meter inter-leg spacing to a total lateral measured depth of 14,500 meters and achieved an IP30 and IP60 of 304 bbl/d and 266 bbl/d, respectively. The offsetting 02/08-23-062-19W4 was drilled to a total lateral measured depth of 18,600 meters using a hybrid multi-lateral / "fan" design and is on production at similar rates, recording an IP30 and IP60 of 360 bbl/d and 330 bbl/d, respectively.
In view of the positive pilot program results at Figure Lake, the tighter inter-leg spacing drilling design was subsequently implemented at South Edwand at the 7-5-61-17W4 Pad (the "7-5 Pad"), where the 02/06-08-61-17W4 well was drilled to a total lateral measured depth of ~16,960 meters and achieved an IP30 of 378 bbl/d and the 00/07-08-61-17W4 well was drilled to a total lateral measured depth of ~17,125 meters and achieved an IP30 of 264 bbl/d. The Company now intends to develop the remaining Greater Figure Lake area using the 33 meter inter-leg well design to maximize the net present value realized from the field.
Production results from the 2024 drilling program with a 50 meter inter-leg spacing well design averaged IP30 of 156 bbl/d (24 wells) and IP60 of 141 bbl/d (24 wells) to date, as compared to the McDaniel Type Curve(1) for the 8 leg 50 meter well design of 120 bbl/d and 112 bbl/d, respectively. Production results from the pilot program wells with a 33 meter inter-leg spacing averaged IP30 217 bbl/d (9 wells) and IP60 168 bbl/d (6 wells) to date, as compared to the McDaniel Tier 1 Type Curve(1) for the 33 meter spacing well design of IP30 177 bbl/d and IP60 169 bbl/d. Only 2024 drills that have at least 30 or 60 days of production have been included in the averages stated. Other than the producing day criteria, no wells have been excluded in the calculation of the average rate.
Inventory Conversion to Development
Of the thirty four (34.0 net) wells drilled during the year in the Greater Figure Lake area, six (6.0 net) were internally categorized as "step-out delineation" wells and were drilled to confirm new pools or pool extensions. All of the step-out delineation wells were drilled at 50 meter inter-leg spacing with a 100% success rate, with an average IP30 and IP60 of 195 bbl/d and 186 bbl/d, respectively. The success of the step-out drilling program affirms the geologic model and further supports the location inventory identified for future development.
Solution Gas Gathering and Conservation
Subsequent to the end of the fourth quarter, construction, start-up and commissioning of the new Figure Lake gas plant located at 01-13-063-18W4 was completed, and solution gas sales commenced on January 23, 2025. Sales gas production will progressively increase through the first quarter of 2025 to the designed plant capacity of approximately 4 MMcf/d.
The tie-in and sale of solution gas at Figure Lake is forecast to deliver a rate of return in excess of 75%, enhanced by the re-activation of previously decommissioned gas gathering pipelines in the area, and a forecast reduction in carbon taxes related to reduced emissions resulting from the elimination of flaring and incineration at multiple pad sites. With expected ongoing growth in heavy oil volumes, Rubellite is evaluating options to manage additional gas volumes, including expansion of the gas plant for increased sales volumes and temporary gas storage into a depleted reservoir. The Company is also advancing a novel natural gas re-injection pilot at Figure Lake for enhanced oil recovery.
Frog Lake
Production at the Frog Lake property averaged 2,223 bbl/d (100% heavy oil) net to Rubellite in December 2024 and 2,210 bbl/d (100% heavy oil) for the fourth quarter.
Following the closing of the BMEC Acquisition on August 2, 2024, the Company drilled and rig released five (2.5 net) horizontal wells in the third quarter and five (3.0 net) horizontal wells in the fourth quarter.
The wells in 2024 were all drilled with water-based mud. Following drilling with water-based mud, the wells initially produce 100% water, and oil cuts then progressively increase through time as the wells "clean up" and recover the fluid lost to the reservoir during drilling operations. 2024 well results have been in line with expectations, excluding three (1.5 net) wells drilled in a localized structurally low area of the Waseca reservoir having higher than expected water saturations. The peak trailing 30-day average oil production, which management considers indicative of performance for wells drilled with water-based mud, was 119 bbl/d for all wells and 153 bbl/d excluding the subset of three structurally low wells.
Rubellite recently initiated a pilot project at Frog Lake to evaluate the use of oil-based mud ("OBM") as the drilling fluid, consistent with Rubellite's operations at Figure Lake where the use of OBM has demonstrated improved hole cleaning and stability, accelerated clean up, and operational improvements including reduced water handling and disposal costs as compared to conventional water-based mud systems. Definitive results from the pilot project at Frog Lake are expected by the end of the first quarter of 2025; however, drilling costs, initial oil-based mud recovery for re-use, and preliminary well performance has been encouraging, and the Company is continuing to utilize oil-based mud in its ongoing drilling operations.
While the Waseca sand is the primary zone of development at Frog Lake, several wells are being planned to additionally test the less consolidated General Petroleum and Sparky sands in 2025 and 2026, to confirm type curve assumptions and extend known pool limits. Corresponding well design work is currently underway.
Exploration
In the fourth quarter, the Company spud an exploratory four-leg open hole multi-lateral horizontal well approximately 90km north of Figure Lake in the Calling Lake / Nixon area to test a new play concept for which Rubellite currently holds 108 net sections of land. While the Company is encouraged by the quality of the oil recovered to date, significant solids production and low total production rates suggest a lack of consolidation in the reservoir, and possible collapse of the open hole laterals. Planning is underway to run a liner or drill a modified lined fishbone design later in 2025 to further evaluate the economic viability of the play.
Rubellite is continuing to advance additional exploration prospects, pursuing both land capture and play concept de-risking activities, and will report further on those activities in due course.
(1) |
Type curve assumptions are based on the Total Proved plus Probable Undeveloped reserves contained in the McDaniel Reserve Report as disclosed in the Company's Annual Information Form which will be 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. Type curve assumptions for the 50 meter spacing well design are based on the Total Proved plus Probable Undeveloped reserves contained in the 2023 McDaniel Reserve Report as disclosed in the Company's 2023 Annual Information Form. |
OUTLOOK AND GUIDANCE
Rubellite plans to operate one rig drilling continuously in the Greater Figure Lake area and a second rig drilling continuously at Frog Lake, throughout 2025. Exploration and development capital spending for the first quarter of 2025 is expected to be approximately $22 to $24 million, including the drilling, completion, equipping and tie-in of: four (4.0 net) multi-lateral horizontal Clearwater development wells at Figure Lake / Edwand; six (4.5 net) multi-lateral horizontal development wells in the Waseca formation at Frog Lake (three upcoming Q1 drills and one upcoming Q2 well will be at 100% working interest as Frog Lake Energy Resources Corp. ("FLERC") has elected gross overriding royalty positions on those wells); one (0.3 net) well at Marten Hills to initiate waterflood; and one (1.0 net) exploration evaluation well. First quarter 2025 capital spending will further include approximately $1.5 million to complete the initial phase of the gas conservation project at Figure Lake and expand the gas gathering system. In West Central Alberta, $0.9 million is forecast to participate with its joint venture partner at East Edson in preparatory surface work for a four (2.0 net) well drilling program in the second half of 2025 to offset natural declines in the Company's liquids-rich natural gas production.
Factoring in recent drilling performance and type curve expectations at Figure Lake/Edwand and at Frog Lake, heavy oil sales volumes are expected to grow approximately 3% to 6% from the fourth quarter of 2024 to average between 8,000 - 8,200 bbl/d in Q1 2025. Total production sales volumes for the first quarter of 2025 are expected to be 12,000 to 12,200 boe/d (70% heavy oil and NGL).
For full year 2025, Rubellite expects to spend a total of $95 to $110 million. Planned capital activity at the low end of the spending guidance range includes: drilling eighteen (18.0 net) multi-lateral development / step-out wells in the Greater Figure Lake area; drilling twenty-four (14.0 net) multi-lateral development / step-out wells in the Frog Lake area; approximately $2.6 million to expand the Figure Lake gas conservation project including additional plant optimization and pipeline tie-ins; drilling one (0.3 net) well at Marten Hills to initiate waterflood; participation in the drilling of four (2.0 net) wells at East Edson; and spending to continue to evaluate additional heavy oil exploration prospects, and to advance enhanced oil recovery ideas in the Clearwater. If market conditions warrant, the Company would look to expand its planned activity levels to the high end of the spending guidance range which would further grow production levels into 2026.
Corresponding heavy oil sales volumes are expected to grow 44% to 48% year-over-year to average between 8,200 - 8,400 bbl/d in 2025. Total production sales volumes, including natural gas and NGL volumes at East Edson and solution gas sales at Figure Lake, are forecast to average 12,200 - 12,400 boe/d in 2025.
Forecast activity will be funded from adjusted funds flow(1), with excess free funds flow applied to reduce net debt(1).
Rubellite has made provisions to potentially add a second drilling rig to the Greater Figure Lake Clearwater drilling program early in the third quarter of 2025, subject to a favorable commodity price outlook in the second quarter of 2025.
Rubellite will continue to address end of life ARO, with total abandonment and reclamation expenditures of approximately $1.9 million planned for 2025. The Company's area-based mandatory spending requirement for 2025 is $1.7 million, as calculated by the Alberta Energy Regulator ("AER").
(1) |
Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures" |
Capital spending and drilling activity for the first quarter and full year 2025 is summarized in the table below:
Q1 2025(1) |
# of wells |
2025(1) |
# of wells |
|
($ millions) |
(gross/net) |
($ millions) |
(gross/net) |
|
Figure Lake |
4 / 4.0 |
18 / 18.0 |
||
Frog Lake |
6 / 4.5 |
24 / 14.0 |
||
Marten Hills |
1 / 0.3 |
1 / 0.3 |
||
East Edson |
0 / 0.0 |
4 / 2.0 |
||
Exploration(2) |
1 / 1.0 |
4 / 3.5 |
||
Total(1) |
$22 - $24 million |
12 /9.8 |
$95 - $110 million |
51 / 37.8 |
(1) |
Excludes abandonment and reclamation spending and acquisitions or land expenditures, if any. |
(2) |
Includes wells at Figure Lake and Frog Lake targeting secondary exploratory zones. |
Rubellite's guidance for first quarter and full year 2025 is presented in the table below:
Q1 2025 Guidance |
2025 Guidance |
|
Sales Production (boe/d) |
12,000 -12,200 |
12,200 - 12,400 |
Production mix (% oil and liquids)(1) |
70 % |
70 % |
Heavy Oil Production (bbl/d) |
8,000 - 8,200 |
8,200 - 8,400 |
Exploration and Development spending ($ millions)(2)(3) |
$22 - $24 |
$95 - $110 |
Multi-lateral development / step-out wells (net)(4) |
11 (8.8) |
47 (34.3) |
Exploration wells (net)(5) |
1 (1.0) |
4 (3.5) |
Heavy oil wellhead differential ($/bbl)(2) |
$5.00 - $5.50 |
$5.00 - $5.50 |
Royalties (% of revenue)(2) |
13% - 14% |
13% - 14% |
Production and operating costs ($/boe)(2) |
$7.00 - $7.75 |
$7.00 - $7.75 |
Transportation costs ($/boe)(2) |
$5.50 - $6.00 |
$5.50 - $6.00 |
General and administrative costs ($/boe)(2) |
$3.00 - $3.50 |
$3.00 - $3.50 |
(1) |
Liquids means oil, condensate, ethane, propane and butane. |
(2) |
Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures". |
(3) |
Excludes land and acquisition spending, if any. |
(4) |
Includes three step-out delineation wells at Figure Lake. |
(5) |
Includes wells at Figure Lake and Frog Lake targeting secondary exploratory zones. |
YEAR-END 2024 RESERVES HIGHLIGHTS
As presented in the McDaniel Report(1), Rubellite's proved plus probable reserves(1) at year-end 2024 are 53.0 MMboe, comprised of 51% heavy crude oil (2023 – 16.0 MMboe, 93% heavy crude oil). The Company's proved plus probable reserves grew by 37.0 MMboe (231%) year-over-year, replacing production of 2.3 MMboe by 17 times.
Growth in year-end 2024 reserves is attributed to the successful drilling program at Figure Lake and Edwand and to acquisitions which added 32.0 MMboe to the year end proved plus probable reserves balance. Acquisitions included the heavy oil producing property at Frog Lake, prospective land in Ukalta and Figure Lake, and the addition of assets in West Central Alberta through the Recombination Transaction with Perpetual which accounted for 25.0 MMboe of the proved plus probable reserve acquisition volumes. Organic growth through drilling in the Clearwater play alone added 8.2 MMboe, replacing production by 3.5 times.
Other highlights from the McDaniel Report(1) include:
- Total proved reserves were 32.7 MMboe at year-end 2024, representing 62% of the Company's proved plus probable reserves (2023 – 62%) and a 228% increase over 2023 (10.0 MMboe).
- Total proved developed producing reserves were 17.7 MMboe at year-end 2024, an increase of 230% over year-end 2023 and representing 33% of the Company's proved plus probable reserves (2023 - 5.3 MMboe; 33% of proved plus probable reserves).
- Proved plus probable producing reserves were 23.0 MMboe at December 31, 2024, representing 43% of total proved plus probable reserves (2023 – 7.1 MMboe; 44% of proved plus probable reserves).
- Rubellite's total exploration, development and acquisition capital spending of $285.1 million (excluding $3.1 million of corporate capital) resulted in total proved plus probable additions of 39.3 MMboe and including a change in future development capital of $291.2 million results in Finding Development and Acquisition ("FD&A") costs of $14.66/boe.
- Strong annual operating netback(4) of $49.60/boe and relatively low cost reserve additions delivered a total proved plus probable recycle ratio of 3.4 times.
- The McDaniel Report includes a total of 200 gross (152.7 net) booked undeveloped drilling locations, which are comprised of 131 (102.6 net) proved undeveloped and 69 (50.1 net) probable undeveloped locations. Of these, 99 gross (96.2 net) are in the greater Figure Lake area with 66 (65.6 net) that are proved undeveloped and 33 (30.6 net) probable undeveloped.
- Rubellite has made advances in optimizing well configuration throughout 2024 to maximize net present value and better exploit the Clearwater formation in Figure Lake and Edwand. Nine gross (9.0 net) 33 meter inter-leg spaced pilot wells ("33m wells") were drilled in 2024 to assess this exploitation technique (compared to typical 50 meter inter-leg spaced wells ("50m wells"). Results to date (3-4 months of production history) indicate a 1:1 scaling for rate on the additional meters drilled, while maintaining the same areal footprint of a 50 meter well. This exploitation strategy maintains future well placement and location count, while increasing rates, reserves and net present values. All future Figure Lake development locations reflected in the McDaniel Report are booked as 33 meter wells and McDaniel has made adjustments to the year-end 2024 type curve to reflect this well design change.
- The Figure Lake Tier 1 type curve(2) total proved plus probable reserves increased 7.7% to 140 Mboe per well (2023 - 130 Mboe per 50m well) with future development costs of $2.5 million per 33m well (2023 - $1.9 million per 50m well). The Figure Lake type curve IP30 rate increased to 177 bbl/d from the year end 2023 Tier 1 50m type curve IP30 of 119 bbl/d due to the positive performance from 2024 wells including results from both the 50m and 33m inter-leg spacing wells.
- All abandonment, decommissioning and reclamation obligations are included in the McDaniel Report, consistent with year-end 2023. Decommissioning obligations for wells assigned reserves are forecast to occur at end of life while the additional costs expected to be incurred to abandon and reclaim non-reserve wells, facilities and pipelines are forecast in accordance with regulatory asset retirement obligation spending requirements for inactive wells.
- Based on the three consultant average price (McDaniel, GLJ, Sproule) forecasts (the "Consultant Average Price Forecast") used by McDaniel, the net present value ("NPV") of Rubellite's total proved plus probable reserves (discounted at 10%) before income tax, was $721.5 million (2023 – $322.1 million). The 124% NPV10 increase is related primarily to acquisitions, as well as organic growth in Figure Lake.
- Rubellite's undeveloped land at year-end 2024, was independently assessed in the Seaton-Jordan Report(3), at $48.8 million, an increase of 19.9% from $40.7 million at year-end 2023.
- Based on the Consultant Average Price Forecast, Rubellite's reserve-based net asset value ("NAV")(4) (discounted at 10%) at year-end 2024, inclusive of the independent assessment of undeveloped land and net of the Company's year-end 2024 total net debt(4) and other obligations, which includes $154.0 million of net debt, $19.9 million of other obligations and an estimated mark-to-market value of financial hedges relative to the Consultant Average Price Forecast as of January 1, 2025 of $4.7 million, is estimated at $601.1 million ($6.47 per share) as compared to $321.3 million ($5.14 per share) at year-end 2023.
(1) |
"McDaniel Report" means the independent engineering evaluation of the Company's heavy crude oil, conventional natural gas and NGL reserves, prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") with an effective date of December 31, 2024 and a preparation date of March 10, 2025. |
(2) |
Type curve assumptions are based on the Total Proved plus Probable Undeveloped reserves contained in the McDaniel Report as disclosed in the Company's Annual Information Form which will be available under the Company's profile on SEDAR+ at www.sedarplus.ca. |
(3) |
The value of Rubellite's undeveloped land was assessed by an independent third party, Seaton-Jordan & Associates Ltd., as at December 31, 2024 in a report dated February 20, 2025 (the "Seaton-Jordan Report"). Estimates of the value of Rubellite's undeveloped acreage was prepared in accordance with NI 51-101 5.9(1)(e) for purposes of the net asset value calculation and is based on past Crown land sale activity, adjusted for tenure and other considerations. No undeveloped land value is assigned where proved and/or probable undeveloped reserves have been booked. |
(4) |
Non-GAAP financial measure or non-GAAP ratio. See "Non-GAAP and Other Financial Measures" in this news release. |
YEAR-END 2024 RESERVES DATA
The reserves data set forth below is based upon the report of McDaniel & Associates Consultants Ltd. ("McDaniel") dated effective December 31, 2024, with a preparation date of March 10, 2025 (the "McDaniel Report"). The following presentation summarizes the Company's crude oil, natural gas liquids and conventional natural gas reserves and the net present values before income tax of future net revenue for the Company's reserves using the forecast prices and costs reflected in the McDaniel Report. The McDaniel Report has been prepared in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). McDaniel prepared the McDaniel Report using their own technical assumptions and interpretations, methodologies and cost assumptions and the equal weighting of the three consultant (McDaniel, GLJ Ltd., Sproule Associates Limited) average price forecasts (the "Consultant Average Price Forecast") as outlined in the table below entitled "Price Forecast". See "Reserves Data and Other Metrics" for additional cautionary language, explanations and discussion and "Forward Looking Information and Statements" for principal assumptions and risks that may apply.
Corporate Reserves
Light & Medium |
Natural Gas |
Conventional |
Barrels of oil |
|
(Mbbl) |
(Mbbl) |
(MMcf) |
(Mboe) |
|
Proved |
||||
Developed Producing |
7,932 |
889 |
53,021 |
17,659 |
Developed Non-producing |
110 |
2 |
176 |
141 |
Undeveloped |
7,836 |
684 |
38,222 |
14,890 |
Total Proved ("1P")(1) |
15,878 |
1,576 |
91,419 |
32,690 |
Total Probable |
10,976 |
884 |
50,749 |
20,318 |
Total Proved plus Probable ("2P")(1) |
26,854 |
2,460 |
142,167 |
53,009 |
(1) |
May not add due to rounding. |
Reserves Value
The estimated before tax net present value ("NPV") of future net revenues associated with Rubellite's reserves effective December 31, 2024, and based on the McDaniel Report and the Consultant Average Price Forecast, are summarized in the following table:
($ thousands) |
0 % |
5 % |
10 % |
15 % |
20 % |
Proved |
|||||
Developed Producing |
376,886 |
339,307 |
303,259 |
274,457 |
251,722 |
Developed Non-producing |
4,147 |
3,887 |
3,623 |
3,383 |
3,171 |
Undeveloped |
260,496 |
184,411 |
133,496 |
97,998 |
72,317 |
Total Proved(1) |
641,529 |
527,604 |
440,378 |
375,838 |
327,211 |
Total Probable |
568,898 |
387,221 |
281,160 |
214,595 |
170,200 |
Total Proved plus Probable(1) |
1,210,427 |
914,825 |
721,538 |
590,433 |
497,411 |
(1) |
May not add due to rounding. |
Price Forecast
The Consultant Average Price Forecast December 31, 2024, price forecast used for the purposes of preparing the McDaniel Report is summarized as follows:
Year |
WTI @ Cushing |
WCS @ Hardisty |
AECO/NIT spot |
Exchange Rate |
(US$/bbl) |
(C$/bbl) |
(C$/MMbtu) |
($US/$CDN) |
|
2025 |
71.58 |
82.69 |
2.36 |
0.712 |
2026 |
74.48 |
84.27 |
3.33 |
0.728 |
2027 |
75.81 |
83.81 |
3.48 |
0.743 |
2028 |
77.66 |
85.70 |
3.69 |
0.743 |
2029 |
79.22 |
87.45 |
3.76 |
0.743 |
2030 |
80.80 |
89.25 |
3.83 |
0.743 |
2031 |
82.42 |
91.04 |
3.91 |
0.743 |
2032 |
84.06 |
92.85 |
3.99 |
0.743 |
2033 |
85.74 |
94.71 |
4.07 |
0.743 |
2034 |
87.46 |
96.61 |
4.15 |
0.743 |
2035+ |
+2 % |
+2 % |
+2 % |
constant |
Reserves Reconciliation
The following reconciliation of Rubellite's gross reserves compares changes in the Company's independently evaluated reserves as at December 31, 2024, relative to the reserves as at December 31, 2023:
Mboe |
|||
Total Proved |
Total Probable |
Total Proved+Probable |
|
December 31, 2023 |
9,957 |
6,058 |
16,014 |
Extensions and Improved Recoveries |
4,823 |
3,381 |
8,204 |
Discoveries |
— |
— |
— |
Technical Revisions |
27 |
(999) |
(972) |
Acquisitions |
20,180 |
11,867 |
32,047 |
Dispositions |
— |
— |
— |
Production |
(2,324) |
— |
(2,324) |
Economic Factors |
27 |
12 |
39 |
December 31, 2024(1) |
32,690 |
20,318 |
53,009 |
(1) |
May not add due to rounding. |
The 2024 drilling program resulted in proved plus probable producing extensions of 2,532 Mboe and proved plus probable undeveloped extensions of 5,672 Mboe attributed to the addition 50 (48.2 net) undeveloped locations.
Forty percent of the technical revisions in proved plus probable reserves were driven by changes to the corporate development plan. With a strategic focus to develop the core properties of Figure Lake, and the recently acquired Frog Lake asset, several lower tier locations in Ukalta and Marten Hills were removed from reserves. The remaining technical revisions (representing a minor reduction of 3.5% on the opening balance) are a result of the aggregate changes to all base producing wells and some non-producing re-activations that were removed from proved plus probable reserves.
Material changes in reserves in all categories resulted from three acquisitions: Assets acquired in Frog Lake through the BMEC Acquisition added 5,925 Mboe; the Recombination Transaction with Perpetual added 24,964 Mboe; and a land acquisition in the Figure Lake and Ukalta properties added 1,158 Mboe.
Finding & Development Costs
2024 |
2023 |
|||||
($ thousands, except as noted) |
PDP |
1P |
2P |
PDP |
1P |
2P |
Exploration and Development Expenditures |
95,373 |
95,373 |
95,373 |
71,530 |
71,530 |
71,530 |
Acquisitions (net of Dispositions) |
189,683 |
189,683 |
189,683 |
25,184 |
25,184 |
25,184 |
Change in Future Development Capital ("FDC") |
— |
187,586 |
291,180 |
— |
32,390 |
39,613 |
Exploration and Development |
— |
77,762 |
121,363 |
— |
17,091 |
18,947 |
Acquisitions (net of Dispositions) |
— |
109,824 |
169,817 |
— |
15,299 |
20,666 |
Reserves Additions with Revisions and Economic Factors (Mboe) |
14,636 |
25,058 |
39,319 |
3,552 |
5,082 |
6,943 |
Exploration and Development (Mboe) |
3,231 |
4,877 |
7,271 |
2,954 |
3,890 |
5,018 |
Acquisitions (net of Dispositions) (Mboe) |
11,405 |
20,180 |
32,047 |
598 |
1,192 |
1,925 |
2024 |
2023 |
|||||
PDP |
1P |
2P |
PDP |
1P |
2P |
|
Finding & Development Costs(1) ("F&D")($ per boe) |
29.52 |
35.50 |
29.81 |
24.22 |
22.78 |
18.03 |
Finding, Development & Acquisition Costs(1) ("FD&A")($ per boe) |
19.48 |
18.86 |
14.66 |
27.23 |
25.40 |
19.63 |
Recycle Ratio (FD&A) |
2.5 |
2.6 |
3.4 |
2.0 |
2.1 |
2.7 |
Reserve Replacement |
6.3 |
10.8 |
16.9 |
2.9 |
4.2 |
5.8 |
(1) |
Includes change in future development capital ("FDC") for 1P and 2P. |
Rubellite's total 2024 exploration and development capital spending was $105.8 million of which $10.4 million was spent at Frog Lake following the closing of the Frog Lake acquisition. Rubellite's 2024 acquisitions expenditure was $179.2 million. All Frog Lake reserve changes, including results of the post acquisition drilling program are included as acquisition additions; therefore, to align capital and reserves for the purposes of F&D calculations, capital spent at Frog Lake post acquisition has been included with acquisition expenditures, resulting in adjusted exploration and development expenditures of $95.4 million and adjusted acquisition expenditures of $189.7 million.
Exploration and development expenditures of $95.4 million, including a change in FDC of $121.4 million for newly recognized drilling locations that includes $0.5 million per proved and probable undeveloped location to reflect the development plan change to the 33 meter inter-leg spacing well design for all future drilling locations at Figure Lake, resulted in total proved plus probable additions of 7.3 MMboe for year end 2024.
Acquisition expenditures of $189.7 million and the change in FDC related to acquisitions of $169.8 million resulted in total proved plus probable additions of 32.0 MMboe.
Combined, total proved plus probable additions of 39.3 MMboe and total capital of $576.2 million result finding, development and acquisition costs, including changes in FDC, of $14.66/boe. Based on 2024 operating netbacks of $49.60/boe, the total proved plus probable recycle ratio is 3.4 times.
As a result of the well design change and positive results from the 2024 drilling program (on both 33m and 50m inter-leg spaced wells), the McDaniel 33m Tier 1 Type Curve(1) 2P reserves increased by 8% and the IP30 rate was increased by 48% relative to the McDaniel 50m Type Curve(1) in the 2023 McDaniel Report. Capital per location was increased by $0.5 million (~27%) per proved and probable undeveloped location relative to the 50 meter spacing well design in the 2023 McDaniel Report, as the new well design has 5,000m additional horizontal length.
Excluding the change in FDC, the finding and development costs in 2024 for Clearwater heavy oil were $29.52/boe on a PDP basis, $25.62/boe on a P+PDP basis, and $19.45/boe on a P+PDP basis using drill bit capital and reserves only (all capital and reserves related to wells drilled in 2024 including drilling, completions, pad-site construction, and associated facilities). Based on 2024 heavy oil netbacks of $54.44/boe, the PDP, P+PDP and P+PDP (using drill bit capital and reserves only) recycle ratios are 1.8 times, 2.1 times and 2.8 times respectively.
(1) |
Type curve assumptions are based on the Total Proved plus Probable Undeveloped reserves contained in the McDaniel Reserve Report as disclosed in the Company's Annual Information Form which will be available under the Company's profile on SEDAR+ at www.sedarplus.ca. "McDaniel" means McDaniel & Associates Consultants Ltd. independent qualified reserves evaluators. "McDaniel Reserve Report" means the independent engineering evaluation of the heavy crude oil and conventional natural gas and NGL reserves, prepared by McDaniel with an effective date of December 31, 2024 and a preparation date of March 10, 2025. See "Estimated Drilling Locations. Type curve assumptions for the 50 meter spacing well design are based on the Total Proved plus Probable Undeveloped reserves contained in the 2023 McDaniel Reserve Report as disclosed in the Company's 2023 Annual Information Form. |
NET ASSET VALUE ("NAV")
The following reserve-based NAV(1) table shows what is referred to as a "produce-out" NAV calculation under which the Company's proved plus probable reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of Rubellite's shares. The calculations below do not reflect the value of the Company's prospect inventory to the extent that the prospects are not recognized within the NI 51-101 compliant reserve assessment, except as they are valued through the estimate of the fair market value of undeveloped land.
Pre-tax NAV(1) at December 31, 2024(2) |
||||
Discounted at |
||||
($ millions, except as noted) |
Undiscounted |
5 % |
10 % |
15 % |
Developed reserves(3) |
549.4 |
466.0 |
402.5 |
356.2 |
Undeveloped reserves(3) |
665.7 |
453.5 |
323.7 |
238.9 |
Fair market value of undeveloped land(4) |
48.8 |
48.8 |
48.8 |
48.8 |
Net debt(1)(2) |
(154.0) |
(154.0) |
(154.0) |
(154.0) |
Other provision(2) |
(19.9) |
(19.9) |
(19.9) |
(19.9) |
NAV(1) |
1,090.0 |
794.4 |
601.1 |
470.0 |
Common shares outstanding (million)(5) |
92.9 |
92.9 |
92.9 |
92.9 |
NAV per share ($/share)(1)(5)(6) |
$ 11.73 |
$ 8.55 |
$ 6.47 |
$ 5.06 |
(1) |
Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures". |
(2) |
Financial information is per Rubellite's 2024 audited consolidated financial statements. |
(3) |
Proved plus Probable developed and proved plus probable undeveloped reserve values per the McDaniel Report dated December 31, 2024 with a preparation date of March 10, 2025, including adjustments for risk management contracts. All abandonment and reclamation obligations, including future abandonment and reclamation costs for pipelines and facilities and non-reserve wells, are included in the McDaniel Report. |
(4) |
Independent third-party estimate as per the Seaton-Jordan Report; excludes undeveloped lands where reserves are assigned. |
(5) |
Common shares outstanding are net of shares held in trust. |
(6) |
NAV per share is calculated by dividing the NAV by the number of issued and outstanding common shares, net of shares held in trust, at December 31, 2024. |
SUMMARY OF ANNUAL RESULTS
($ thousands, except as noted) |
2024 |
2023 |
2022 |
Financial |
|||
Oil revenue |
168,384 |
88,968 |
54,491 |
Net income and comprehensive income |
49,973 |
18,561 |
24,605 |
Per share – basic(1) |
0.73 |
0.31 |
0.47 |
Per share – diluted(1) |
0.72 |
0.30 |
0.47 |
Total Assets |
562,612 |
271,153 |
204,030 |
Cash flow from operating activities |
95,788 |
55,391 |
23,870 |
Adjusted funds flow, including transaction costs(2)(6) |
93,777 |
54,156 |
23,036 |
Per share – basic(1)(2) |
1.37 |
0.90 |
0.44 |
Per share – diluted(1)(2) |
1.35 |
0.89 |
0.44 |
Adjusted funds flow, before transaction costs(2)(6) |
100,010 |
54,304 |
23,036 |
Per share – basic(1)(2) |
1.46 |
0.90 |
0.44 |
Per share – diluted(1)(2) |
1.43 |
0.89 |
0.44 |
Q4 annualized adjusted funds flow(2)(11) |
143,420 |
68,280 |
32,580 |
Net debt to Q4 annualized adjusted funds flow ratio(2)(11) |
1.1 |
0.7 |
0.9 |
Net debt (asset)(2) |
154,020 |
50,984 |
28,228 |
Capital expenditures(2) |
|||
Capital expenditures, including land, corporate and other(2) |
108,906 |
71,530 |
94,207 |
Acquisitions(8)(9) |
179,247 |
33,173 |
— |
Proceeds on dispositions(10) |
— |
(7,990) |
— |
Capital expenditures, after acquisition and dispositions(2) |
288,153 |
96,713 |
94,207 |
Wells Drilled(3) – gross (net) |
46 / 41.5 |
30 / 29.5 |
45 / 39.5 |
Common shares outstanding(1) (thousands) |
|||
Weighted average – basic |
68,667 |
60,346 |
52,093 |
Weighted average – diluted |
69,716 |
61,075 |
52,471 |
End of period |
93,044 |
62,456 |
54,826 |
Operating |
|||
Heavy oil (bbl/d)(4) |
5,685 |
3,302 |
1,670 |
Natural gas (MMcf/d) |
3.6 |
— |
— |
NGL (bbl/d)(5) |
69 |
— |
— |
Daily average sales production (boe/d) |
6,349 |
3,302 |
1,670 |
Average prices |
|||
West Texas Intermediate ("WTI") ($US/bbl) |
75.72 |
77.62 |
94.22 |
Western Canadian Select ("WCS") ($CAD/bbl) |
83.52 |
79.46 |
98.49 |
AECO 5A Daily Index ($CAD/Mcf) |
1.46 |
2.64 |
5.34 |
Rubellite average realized prices(2)(7) |
|||
Oil ($/bbl) |
78.92 |
73.82 |
89.38 |
Natural gas ($/Mcf) |
2.01 |
— |
— |
NGL ($/bbl) |
61.32 |
— |
— |
Average realized price(2) ($/boe) |
72.46 |
73.82 |
89.38 |
Average realized price, after risk management contracts(2) ($/boe) |
73.57 |
73.56 |
67.82 |
(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) |
2024 includes $6.2 million in transaction costs related to the BMEC Acquisition and the Recombination Transaction with Perpetual. 2023 includes $0.1 million in transaction costs related to a Clearwater Acquisition. |
(7) |
Before risk management contracts; supplementary financial measure. See "Non-GAAP and Other Financial Measures". |
(8) |
The Recombination Transaction with Perpetual closed on October 31, 2024 for share consideration of $51.7 million. The BMEC Acquisition closed on August 2, 2024 for total consideration of $73.1 million, prior to purchase price adjustments. |
(9) |
Clearwater acquisition closing on November 8, 2023 for cash consideration of $34.0 million, prior to purchase price adjustments. |
(10) |
Royalty sale closed on December 8, 2023 for cash consideration of $8.0 million, prior to purchase price adjustments. |
(11) |
Based on fourth quarter annualized adjusted funds flow before transaction costs relative to year-end net debt. |
SUMMARY OF QUARTERLY RESULTS
Three months ended |
Twelve months ended |
|||
($ thousands, except as noted) |
2024 |
2023 |
2024 |
2023 |
Financial |
||||
Oil revenue |
59,081 |
27,224 |
168,384 |
88,968 |
Net income and comprehensive income |
26,747 |
9,523 |
49,973 |
18,561 |
Per share – basic(1) |
0.31 |
0.15 |
0.73 |
0.31 |
Per share – diluted(1) |
0.30 |
0.15 |
0.72 |
0.30 |
Total Assets |
562,612 |
271,153 |
562,612 |
271,153 |
Cash flow from operating activities |
39,402 |
18,963 |
95,788 |
55,391 |
Adjusted funds flow, after transaction costs(2)(6) |
31,632 |
16,923 |
93,777 |
54,156 |
Per share – basic(1)(2) |
0.36 |
0.27 |
1.37 |
0.90 |
Per share – diluted(1)(2) |
0.36 |
0.27 |
1.35 |
0.89 |
Adjusted funds flow, before transaction costs(2)(6) |
35,855 |
17,070 |
100,010 |
54,304 |
Per share – basic(1)(2) |
0.41 |
0.27 |
1.46 |
0.90 |
Per share – diluted(1)(2) |
0.40 |
0.27 |
1.43 |
0.89 |
Q4 annualized adjusted funds flow(2)(11) |
143,420 |
68,280 |
143,420 |
68,280 |
Net debt to Q4 annualized adjusted funds flow ratio(2)(11) |
1.1 |
0.7 |
1.1 |
0.7 |
Net debt (asset)(2) |
154,020 |
50,984 |
154,020 |
50,984 |
Capital expenditures(2) |
||||
Capital expenditures, including land, corporate and other(2) |
35,537 |
26,320 |
108,906 |
71,530 |
Acquisition(8)(9) |
68,467 |
33,173 |
179,247 |
33,173 |
Proceeds on disposition(10) |
— |
(7,990) |
— |
(7,990) |
Capital expenditures, after acquisition and dispositions(2) |
104,004 |
51,503 |
288,153 |
96,713 |
Wells Drilled(3) – gross (net) |
15 / 13.0 |
11 / 11.0 |
46 / 41.5 |
30 / 29.5 |
Common shares outstanding(1) (thousands) |
||||
Weighted average – basic |
87,655 |
62,440 |
68,667 |
60,346 |
Weighted average – diluted |
88,546 |
62,958 |
69,716 |
61,075 |
End of period |
93,044 |
62,456 |
93,044 |
62,456 |
Operating |
||||
Heavy Oil (bbl/d)(4) |
7,754 |
4,209 |
5,685 |
3,302 |
Natural gas (Mcf/d) |
14,140 |
— |
3,570 |
— |
NGLs (bbl/d)(5) |
275 |
— |
69 |
— |
Daily average sales production (boe/d) |
10,386 |
4,209 |
6,349 |
3,302 |
Average prices |
||||
West Texas Intermediate ("WTI") ($US/bbl) |
70.27 |
78.32 |
75.72 |
77.62 |
Western Canadian Select ("WCS") ($CAD/bbl) |
80.74 |
76.84 |
83.52 |
79.46 |
AECO 5A Daily Index ($CAD/Mcf) |
1.48 |
2.30 |
1.46 |
2.64 |
Rubellite average realized prices(2)(7) |
||||
Oil ($/bbl) |
76.97 |
70.31 |
78.92 |
73.82 |
Natural gas ($/Mcf) |
2.01 |
— |
2.01 |
— |
NGL ($/bbl) |
61.32 |
— |
61.32 |
— |
Average realized price(2) ($/boe) |
61.83 |
70.31 |
72.46 |
73.82 |
Average realized price, after risk management contracts(2) ($/boe) |
65.14 |
72.12 |
73.57 |
73.56 |
(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) |
2024 includes $6.2 million in transaction costs related to the BMEC Acquisition and the Recombination Transaction with Perpetual. 2023 includes $0.1 million in transaction costs related to a Clearwater Acquisition. |
(7) |
Before risk management contracts; supplementary financial measure. See "Non-GAAP and Other Financial Measures". |
(8) |
The Recombination Transaction with Perpetual closed on October 31, 2024 for share consideration of $51.7 million. The BMEC acquisition closed on August 2, 2024 for total consideration of $73.1 million, prior to purchase price adjustments. |
(9) |
Clearwater acquisition closing on November 8, 2023 for cash consideration of $34.0 million, prior to purchase price adjustments. |
(10) |
Royalty sale closed on December 8, 2023 for cash consideration of $8.0 million, prior to purchase price adjustments. |
(11) |
Based on fourth quarter annualized adjusted funds flow before transaction costs relative to year-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 and liquids-rich conventional natural gas assets in the deep basin of West Central Alberta and undeveloped bitumen leases in Northern Alberta. The Company is pursuing a robust organic growth plan focused on superior corporate returns and funds flow generation while maintaining a conservative capital structure and prioritizing operational excellence. Additional information on the Company can be accessed on the Company's website at www.rubelliteenergy.com or on SEDAR+ at www.sedarplus.ca.
The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.
ADVISORIES
RESERVE DATA AND OTHER METRICS
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and natural gas liquids ("NGL") reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only and there is no guarantee that the estimated reserves will be recovered. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The after-tax net present value of the Company's oil and gas properties reflects the tax burden on the properties on a stand-alone basis and utilizes the Company's tax pools. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the after-tax value of the Company, which may be significantly different. The Company's financial statements and the MD&A should be consulted for information at the level of the Company.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregations. The estimated values of future net revenue disclosed in this news release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.
This news release contains metrics commonly used in the oil and gas industry, such as; FDC, F&D, FD&A costs and recycle ratio. These terms have been calculated by management and do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included in this news release 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.
Future Development Capital ("FDC") means the aggregate exploration and development costs incurred on reserves that are categorized as development reserves. Development capital presented herein includes land expenditures and excludes capitalized administrations costs and the cost of acquisitions.
Finding and development ("F&D") costs are calculated as the sum of field capital plus the change in FDC for the period divided by the change in reserves that are characterized as development for the period and takes into account reserve revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
Finding, development and acquisition ("FD&A") costs are calculated as the sum of development costs, acquisition and disposition costs and the change in FDC for the period, divided by the reserves within the applicable reserves category, including changes due to acquisitions and dispositions.
Recycle ratio is measured by dividing the operating netback for the applicable period by F&D costs per boe for the year. The recycle ratio compares the netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are equivalent quality as the produced reserves.
The reserve data provided in this news release presents only a portion of the disclosure required under NI 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2024, which will be filed on SEDAR+ (accessible at www.sedarplus.ca) on or before March 31, 2025.
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 |
WCS |
Western Canadian select, the benchmark price for conventional produced crude oil in Western Canada |
OIL AND GAS RESERVE DEFINITIONS
Reserves: are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of capital assumptions, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows.
Proved Reserves: are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable Reserves: are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the estimated proved plus probable reserves.
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 414 net drilling locations disclosed in this news release 152.7 net are booked proved and probable undeveloped locations in the reserve report. 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 December 31, |
Twelve months ended December 31, |
|||
2024 |
2023 |
2024 |
2023 |
|
Net cash flows used in investing activities |
(49,633) |
(38,813) |
(173,030) |
(94,354) |
Acquisitions |
— |
(33,173) |
(62,732) |
(33,173) |
Dispositions |
— |
7,990 |
— |
7,990 |
Change in non-cash working capital |
(14,096) |
12,689 |
(1,392) |
2,359 |
Capital expenditures |
(35,537) |
(26,319) |
(108,906) |
(71,530) |
Property, plant and equipment expenditures |
(32,565) |
(13,231) |
(90,680) |
(43,660) |
Exploration and evaluation expenditures |
(2,844) |
(13,088) |
(15,129) |
(27,870) |
Corporate additions |
(128) |
— |
(3,097) |
— |
Capital expenditures |
(35,537) |
(26,319) |
(108,906) |
(71,530) |
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 December 31, |
Twelve months ended December 31, |
|||||||
($ thousands, except per boe amounts) |
2024 |
2023 |
2024 |
2023 |
||||
Net operating costs |
6.84 |
6,536 |
5.66 |
2,191 |
7.11 |
16,514 |
6.12 |
7,371 |
Transportation |
6.01 |
5,747 |
6.68 |
2,588 |
7.03 |
16,328 |
7.50 |
9,045 |
General and administrative |
3.69 |
3,522 |
6.00 |
2,323 |
4.57 |
10,616 |
6.07 |
7,318 |
Cash finance expense |
2.91 |
2,784 |
2.15 |
831 |
2.97 |
6,904 |
1.60 |
1,923 |
Cash costs |
19.45 |
18,589 |
20.49 |
7,933 |
21.68 |
50,362 |
21.29 |
25,657 |
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 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 December 31, |
Twelve months ended December 31, |
|||
($ thousands, except per share and per boe amounts) |
2024 |
2023 |
2024 |
2023 |
Production and operating |
6,714 |
2,191 |
16,692 |
7,371 |
Less: Other income |
178 |
— |
178 |
— |
Net operating costs |
6,536 |
2,191 |
16,514 |
7,371 |
Per boe |
6.84 |
5.66 |
7.11 |
6.12 |
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:
As of December 31, 2024 |
As of December 31, 2023 |
|
Current assets |
44,714 |
21,061 |
Current liabilities |
(74,680) |
(34,009) |
Working capital deficit |
29,966 |
12,948 |
Risk management contracts – current asset |
9,783 |
8,796 |
Risk management contracts – current liability |
(2,765) |
— |
Right of use liability - current liability |
(357) |
— |
Share-based compensation liability - current liability |
(5,357) |
— |
Decommissioning obligations – current liability |
(2,000) |
(77) |
Other provision - current liability |
(3,750) |
— |
Adjusted working capital deficit |
25,520 |
21,667 |
Bank indebtedness |
108,500 |
29,317 |
Term loan (principal) |
20,000 |
— |
Net debt (1) |
154,020 |
50,984 |
(1) |
Excludes 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 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 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 December 31, |
Twelve months ended December 31, |
|||
($ thousands, except as noted) |
2024 |
2023 |
2024 |
2023 |
Net cash flows from operating activities |
39,402 |
18,963 |
95,788 |
55,391 |
Change in non-cash working capital |
(8,582) |
(2,040) |
(3,093) |
(1,237) |
Cash-settled share-based compensation |
631 |
— |
631 |
— |
Decommissioning obligations settled |
181 |
— |
451 |
3 |
Adjusted funds flow, after transaction costs |
31,632 |
16,923 |
93,777 |
54,157 |
Transaction Costs |
4,223 |
147 |
6,233 |
147 |
Adjusted funds flow - before transaction costs |
35,855 |
17,070 |
100,010 |
54,304 |
Adjusted funds flow per share - basic |
0.36 |
0.27 |
1.37 |
0.90 |
Adjusted funds flow per share - diluted |
0.36 |
0.27 |
1.35 |
0.89 |
Adjusted funds flow per boe |
33.10 |
43.71 |
40.35 |
44.93 |
Adjusted funds flow per share - before transaction costs - basic |
0.41 |
0.27 |
1.46 |
0.90 |
Adjusted funds flow per share - before transaction costs - diluted |
0.40 |
0.27 |
1.43 |
0.89 |
Adjusted funds flow per boe - before transaction costs |
37.52 |
44.09 |
43.04 |
45.06 |
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.
Net Asset Value ("NAV"): Total proved plus probable reserves as per the McDaniel reserves report as at December 31, 2024, plus independently verified third party valuation of undeveloped lands, less net debt. This measure is used to show the net asset value of the Company at a point in time under which the reserves are produced at forecast future prices and costs.
Non-GAAP Financial Ratios
Rubellite calculates certain non-GAAP measures per boe as the measure divided by weighted average daily production. Management believes that per boe ratios are a key industry performance measure of operational efficiency and one that provides investors with information that is also commonly presented by other crude oil and natural gas producers. Rubellite also calculates certain non-GAAP measures per share as the measure divided by outstanding common shares.
Average realized oil price after risk management contracts: are calculated as the average realized price less the realized gain or loss on risk management contracts.
Adjusted funds flow per share: adjusted funds flow per share is calculated using the weighted average number of basic and diluted shares outstanding used in calculating net income (loss) per share.
Adjusted funds flow per boe: Adjusted funds flow per boe is calculated as adjusted funds flow divided by total production sold in the period.
Supplementary Financial Measures
"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; Rubellite's business plan; and including the information and statements contained under the heading "Outlook and Guidance" and "About Rubellite".
Forward-looking information is based on current expectations, estimates and projections that involve a number of known and unknown risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Rubellite and described in the forward-looking information contained in this news release. In particular and without limitation of the foregoing, material factors or assumptions on which the forward-looking information in this news release is based include: the successful operation of the Company's assets, forecast commodity prices and other pricing assumptions; forecast production volumes based on business and market conditions; foreign exchange and interest rates; near-term pricing and continued volatility of the market; accounting estimates and judgments; future use and development of technology and associated expected future results; the ability to obtain regulatory approvals; the successful and timely implementation of capital projects; ability to generate sufficient cash flow to meet current and future obligations and future capital funding requirements (equity or debt); the ability of Rubellite to obtain and retain qualified staff and equipment in a timely and cost-efficient manner, as applicable; the retention of key properties; forecast inflation, supply chain access and other assumptions inherent in Rubellite's current guidance and estimates; climate change; severe weather events (including wildfires and drought); the continuance of existing tax, royalty, and regulatory regimes; the accuracy of the estimates of reserves volumes; ability to access and implement technology necessary to efficiently and effectively operate assets; risk of wars or other hostilities or geopolitical events (including the ongoing war in Ukraine and conflicts in the Middle East), civil insurrection and 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 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 Rubellite Energy Inc. and Perpetual Energy Inc.'s Annual Information Form and MD&A for the year ended December 31, 2023 (and once filed under "Risk Factors" in Rubellite'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.
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: [email protected]; Susan L. Riddell Rose, President and Chief Executive Officer; Ryan A. Shay, Vice President Finance and Chief Financial Officer
Share this article