RUBELLITE ENERGY CORP. REPORTS RECORD PRODUCTION AND ADJUSTED FUNDS FLOW PER SHARE IN SECOND QUARTER 2025 FINANCIAL AND OPERATING RESULTS

Cision Canada

a day ago

CALGARY, AB, Aug. 5, 2025 /CNW/ - (TSX: RBY) - Rubellite Energy Corp. ("Rubellite" or the "Company"), is pleased to report its second quarter 2025 financial and operating results and provide an operations and guidance update.
Select financial and operational information is outlined below and should be read in conjunction with Rubellite's unaudited condensed consolidated interim financial statements and related Management's Discussion and Analysis ("MD&A") for the three and six months ended June 30, 2025, which are available on the Company's website at www.rubelliteenergy.com and SEDAR+ at www.sedarplus.ca.
This news release contains certain specified financial measures that are not recognized by GAAP and used by management to evaluate the performance of the Company and its business. Since certain specified financial measures may not have a standardized meaning, securities regulations require that specified financial measures are clearly defined, qualified and, where required, reconciled with their nearest GAAP measure. See "Non GAAP and Other Financial Measures" in this news release and in the MD&A for further information on the definition, calculation and reconciliation of these measures. This news release also contains forward-looking information. See" Forward-Looking Information". Readers are also referred to the other information under the "Advisories" section in this news release for additional information.
SECOND QUARTER 2025 HIGHLIGHTS
Rubellite delivered record second quarter conventional heavy oil sales production of 8,637 bbl/d that exceeded the high end of guidance and was up 4% relative to the first quarter of 2025 (Q1 2025 - 8,339 bbl/d) and 92% relative to the second quarter of 2024 (Q2 2024 - 4,503 bbl/d). Second quarter total sales production of 12,425 boe/d (72% heavy oil and NGL) also exceeded the high end of guidance. Production growth quarter over quarter was driven by the successful drilling programs at Figure Lake and Frog Lake which brought eleven (10.0 net) new wells on production during the second quarter of 2025. The Figure Lake gas plant that commenced operations on January 23, 2025, added an average of 3.0 MMcf/d of solution gas sales plus associated liquids (17 boe/d) in the second quarter of 2025.
Exploration and development capital expenditures (1) totaled $23.8 million for the second quarter of 2025, to drill, complete, equip and tie-in five (5.0 net) multi-lateral horizontal development wells at Figure Lake and six (4.0 net) multi-lateral horizontal development wells at Frog Lake. Included in second quarter development capital spending was $0.7 million for the Figure Lake gas conservation project and the expansion of the gas gathering system.
Land and other spending totaled $7.3 million in the second quarter of 2025 and included $0.5 million of spending on seismic purchases (Q2 2024 - nominal). An additional $0.1 million (Q2 2024 - nominal) was spent on decommissioning, abandonment and reclamation activities.
Adjusted funds flow (1) in the second quarter of 2025 was $37.3 million ($0.40 per share), up 81% (21% per share) from the second quarter of 2024 (Q2 2024 - $20.7 million or $0.33 per share).
Cash costs (1) were $20.7 million or $18.26/boe in the second quarter of 2025, down 19% on a per boe basis from the second quarter of 2024 (Q2 2024 - $9.3 million or $22.58/boe).
Net income was $16.1 million ($0.17 per share) in the second quarter of 2025 (Q2 2024 - $12.4 million net income and $0.20 per share).
As at June 30, 2025, net debt (1) was $142.4 million, down 8% with the reduction of $11.7 million from $154.0 million as at December 31, 2024 driven by positive free funds flow (1) of $17.1 million in the first half of 2025 which was used to reduce net debt and other balance sheet obligations.
Rubellite had available liquidity (1) at June 30, 2025 of $32.4 million, comprised of the $140.0 million borrowing limit of Rubellite's first lien credit facility, less current bank borrowings of $106.2 million and outstanding letters of credit of $1.4 million.
OPERATIONS UPDATE
Greater Figure Lake (Figure Lake and Edwand)
Heavy oil sales production from the Greater Figure Lake area averaged 5,544 bbl/d for the second quarter as compared to 5,326 bbl/d for the first quarter of 2025, an increase of 4%. Solution gas sales contributed 3.0 MMcf/d plus associated natural gas liquids of 17 boe/d which brought total sales production at Figure Lake for the second quarter to 6,064 boe/d (92% oil and liquids). Rubellite is currently expanding the Figure Lake 1-13 Gas Plant to manage additional associated solution gas volumes and increase total throughput capacity to approximately 5.9 to 6.4 MMcf/d. Completion of the expansion is expected in August 2025.
During the second quarter of 2025, Rubellite drilled and rig released three (3.0 net) development horizontal wells in the Greater Figure Lake area, all targeting the Wabiskaw Member of the Clearwater Formation, with 33 meter inter-leg spacing and typical 15,000m open hole length per the Figure Lake well design adopted in the latter half of 2024. Results from the 2025 development capital program to date across the Greater Figure Lake field have achieved an average (1) IP30 of 271 bbl/d (7 wells) and IP60 of 267 bbl/d (5 wells), as compared to the McDaniel Tier 1 Type Curve (2) rates for 33 meter inter-leg spacing of 177 bbl/d (IP30) and 169 bbl/d (2) (IP60).
In addition to development drilling, two (2.0 net) step-out delineation wells were drilled in the Greater Figure Lake area with 50m inter-leg spacing and ~10,000m open hole length, to test and confirm productivity from two new pools in the Wabiskaw Member. The first well, 00/01-14-062-18W4 ("1-14 Well"), encountered the down dip limit of the first pool, yielding lower oil saturations and higher water cuts than averaged elsewhere in the field. The second well, 00/04-32-060-17W4 ("4-32 Well") has fully recovered load oil, and with early Initial Production (IP15) of 58 bbl/d is within the range of expected outcomes supporting further development of the pool in accordance with the geological model established for the field.
Rubellite is actively advancing several opportunities to increase the economic recovery factor for heavy oil at Figure Lake beyond the average anticipated primary recovery factor of approximately 4.0 to 5.5 percent of the original oil in place.
A waterflood pilot is currently planned for the fourth quarter of 2025 from a surface location at 9-35-63-18W4 (the "9-35 Pad"). The waterflood pilot pattern will consist of a single horizontal multi-lat well with two sets of four legs each (8 legs in total), with ~150 meters between the four-leg sets. Each 4-leg set will be drilled with 33 meter inter-leg spacing, and the waterflood producer well will have a planned total open hole length for the 8 legs of approximately 10,000 meters. A separate single leg water injection well will be drilled along the center line between the two 4-leg sets, and water injection is expected to commence in early 2026.
The Company is also advancing a novel natural gas-based re-injection pilot at Figure Lake for enhanced oil recovery, with an experimental well now configured at the 01-13-063-18W4 pad (the "1-13 Pad"), on the same site as the Figure Lake 1-13 Gas Plant. Results from the waterflood pilot and gas re-injection experiment will inform future development patterns and enhanced oil recovery techniques to be implemented across the Greater Figure Lake area.
Rubellite will also test larger diameter (200mm) boreholes at the 9-35 Pad in the third quarter of 2025 to determine if incremental economic returns associated with improved inflow and productivity can be realized relative to the robust economics established for the existing 159mm boreholes drilled to date at Figure Lake.
3D seismic acquired in the first quarter of 2025, imaging the northern end of Figure Lake, has now been interpreted and a Sparky exploration well is planned to be drilled in the first quarter of 2026. Separate detailed mapping work has identified an Upper Clearwater prospect in the southern part of the greater Figure Lake area. If associated exploration wells are successful, there are approximately 15.0 net follow-up Sparky locations and up to 10.0 net follow-up Upper Clearwater locations, all of which would be incremental to the existing Clearwater development inventory and secondary targets inventory at Figure Lake.
Consistent production results continue to support the geologic model at Figure Lake and affirm the 243.0 net development drilling inventory locations (3) in the Wabiskaw, including 96.2 net proven and probable undeveloped (2)(3) booked locations. Under a one-rig program, which would provide for the drilling of 18 wells per year at Figure Lake, the Clearwater location count at Figure Lake represents over 13 years of low-risk development drilling inventory.
Frog Lake
Production at the Frog Lake property grew 5% to average 2,539 bbl/d (100% heavy oil) for the second quarter, as compared to 2,423 bbl/d (100% heavy oil) for the first quarter of 2025.
Results from the 2025 capital drilling program to date at Frog Lake (all wells drilled using an oil-based mud ("OBM") drilling system and targeting the north Waseca sand) achieved an average (1) IP30 and IP60 of 140 bbl/d (9 wells) and 128 bbl/d (7 wells) respectively, as compared to the McDaniel Waseca North Type Curve (2) IP30 and IP60 of 107 bbl/d and 104 bbl/d established by McDaniel at year-end 2024 using historical data obtained from wells drilled with water-based mud systems.
Rubellite switched its drilling operations at Frog Lake in December 2024 to utilize OBM. The OBM trial at Frog Lake has confirmed the benefits of using OBM fluid consistent with Rubellite's operations at Figure Lake, where the use of OBM has improved hole cleaning and stability, accelerated the time to stabilized reservoir production, and reduced drill pipe wear, water handling and disposal costs as compared to conventional water-based mud systems. The Company is continuing to utilize OBM in its ongoing drilling operations at Frog Lake as it evaluates the effects on long term production performance in different parts of the Waseca reservoir across the Frog Lake field.
In addition to continued drilling of the Waseca sand as the primary development zone at Frog Lake, the Company is planning two exploration wells in the third quarter of 2025, targeting the General Petroleum ("GP") sand. The first well will be drilled using a single leg lined horizontal lateral design and the second well will be drilled using an alternative lined "fish bone" well design. Learnings from these two wells will confirm type curve assumptions, and inform mapping parameters, appropriate geological cutoffs, and the future well design for optimum economic development of both the GP and Sparky sands in the Mannville Stack at Frog Lake.
The Company commenced a "bottoms up" waterflood at Marten Hills during the second quarter of 2025, with water injection initiated at its first injection well in April. Value is expected to be realized through reduced water handling costs, reduced production declines and enhanced reserve recoveries.
East Edson
Non-operated drilling planned at East Edson for late in the second quarter was delayed due to wet weather, shifting $3.0 million of capital from Q2 to Q3. Subsequent to the end of the second quarter, the first of four gross (2.0 net) wells was spud in early July, and drilling of the second well is now underway.
A turnaround lasting 5.5 days was completed in June 2025 at the Company's primary gas processing facility at East Edson, reducing average sales by 77 boe/d during the second quarter.
Other Exploration
In addition to exploration activities in the General Petroleum and Sparky zones at Frog Lake and the Sparky prospect at Figure Lake, the Company is continuing to advance multiple additional new venture exploration prospects, pursuing both land capture and play concept de-risking activities while minimizing its risked capital exposure. A total of $3.4 million was invested in the second quarter of 2025 to acquire mineral rights and seismic for exploratory prospects that are expected to be evaluated in 2026.
(1)
No wells were excluded from the calculation of average results except the criteria for producing days.
(2)
Type curve assumptions for the 33m spacing well design are based on the Total Proved plus Probable Undeveloped reserves contained in the 2024 McDaniel Reserve Report as disclosed in the Company's 2024 Annual Information Form available under the Company's profile on SEDAR+ at www.sedarplus.ca. "McDaniel" means McDaniel & Associates Consultants Ltd. independent qualified reserves evaluators. "McDaniel Reserve Report" means the independent engineering evaluation of the heavy crude oil and conventional natural gas and NGL reserves, prepared by McDaniel with an effective date of December 31, 2024 and a preparation date of March 10, 2025. See "Estimated Drilling Locations.
(3)
Assuming a January 1, 2025, reference date, of the 243.0 net locations described in the greater Figure Lake area, 65.6 net locations are recognized in the McDaniel Report as proved undeveloped and an additional 30.6 net locations are classified as probable undeveloped. The Company recognizes a total of 316.2 net heavy oil development locations, 93.1 of which are net proved and 45.6 are net probable and included in the McDaniel Reserve Report.
OUTLOOK AND GUIDANCE
For the second half of 2025, Rubellite has budgeted to spend a total of $54.0 to $64.0 million on its exploration and development drilling program, excluding expenditures on land and abandonment and reclamation activities, bringing the total for the year to a range of $100 to $110 million which compares to previous guidance of $95 to $110 million.
The increase in the low end of the guidance range reflects the following drilling program changes:
At Figure Lake:
One (1.0 net) Clearwater waterflood injection well is now planned;
Offset somewhat by lower per well costs forecast on the eleven (11.0 net) wells scheduled for H2/25.
At Frog Lake:
Four Waseca wells are now forecast to be at 100% working interest as Frog Lake Energy Resources Corp. ("FLERC") has elected to be in a gross overriding royalty position on these wells;
A second 100% working interest exploratory GP well is now planned;
Offset by one (0.5 net) fewer Waseca development well now planned for H2/25.
Planned capital activity in the second half of 2025 includes:
At Figure Lake:
Drilling ten (10.0 net) multi-lateral development wells;
Drilling and equipping one (1.0 net) waterflood injection well;
Spending to cut a core and conduct several lab experiments to progress enhanced oil recovery technology ideas; and
Capital to expand the Figure Lake gas conservation project, including additional plant optimization and pipeline tie-ins.
At Frog Lake:
Drilling eleven (7.0 net) Waseca multi-lateral development wells; and
Drilling one single leg lined lateral well and one lined fish bone well (1.5 net wells) to evaluate the exploratory General Petroleum zone in the Mannville Stack.
At East Edson, participation in the drilling of four (2.0 net) Wilrich development wells.
Additional spending is planned to continue to advance the evaluation of several heavy oil exploration prospects, to increase gas conservation and usage at Ukalta, and to advance enhanced oil recovery in other areas.
With the ongoing volatility in oil prices, the Company is currently planning to maintain its one rig drilling program at each of Figure Lake and Frog Lake for the second half of 2025. The Company will continue to strive for meaningful per well capital cost reductions to maintain attractive rates of return and payout periods, and will manage its capital spending to prioritize free funds flow generation over production growth in this current weaker oil price environment.
Heavy oil sales volumes based on the current budget are expected to grow 44% to 48% year-over-year to average between 8,200 - 8,400 bbl/d in 2025, unchanged from previous guidance. 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, unchanged from previous guidance.
Capital spending activity will be funded from adjusted funds flow (1), with excess free funds flow (1) applied to reduce net debt (1) and other balance sheet obligations. Aided by Rubellite's extensive commodity price risk management positions, the Company continues to forecast strong adjusted funds flow and free funds flow through the third quarter of 2025 based on the forward market for commodity prices as at August 5, 2025.
Rubellite's Clearwater production continues to realize an attractive offset to WCS benchmark pricing, resulting in an improvement in our heavy oil wellhead differential guidance to a range of $4.00 to $4.50 per barrel vs $5.00 to $5.50 per barrel previously. Additionally, initiatives to improve field operating costs have improved our operating cost guidance to a range of $6.50 to $7.25 per boe versus $7.00 to $7.75 per boe previously.
Rubellite will continue to address end of life ARO, with total abandonment and reclamation expenditures of approximately $0.8 million planned for the second half of 2025. In combination with the $0.9 million of asset retirement obligation spending in the first half of the year, the Company is on track to exceed its area-based mandatory spending requirement for 2025 of $1.7 million, as calculated by the Alberta Energy Regulator ("AER").
Capital spending and drilling activity for 2025 is summarized in the table below:
(1)
Includes one waterflood injection well.
(2)
Includes two (1.5 net) wells at Frog Lake targeting secondary exploration zones.
(3)
Excludes abandonment and reclamation spending, acquisitions and land expenditures, if any.
Rubellite's capital spending, drilling and operational guidance for 2025 are presented in the table below:
(1)
Previous full year 2025 guidance dated May 7, 2025.
(2)
Liquids means oil, condensate, ethane, propane and butane.
(3)
Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures".
(4)
Excludes land and acquisition spending, if any.
Three months ended June 30,
Six months ended June 30,
2025
2024
2025
2024
Financial
Oil revenue
60,542
35,798
127,149
65,621
Net income and comprehensive income
16,051
12,368
17,211
8,215
Per share – basic (1)
0.17
0.20
0.18
0.13
Per share – diluted (1)
0.17
0.19
0.18
0.13
Total Assets
561,545
281,549
561,545
281,549
Cash flow from operating activities
35,808
19,916
62,943
36,413
Adjusted funds flow (2)
37,311
20,664
73,245
39,116
Per share – basic (1)(2)
0.40
0.33
0.79
0.63
Per share – diluted (1)(2)
0.39
0.33
0.77
0.62
Q2 annualized adjusted funds flow (2)(7)
149,244
82,656
149,244
82,656
Net debt to Q2 annualized adjusted funds flow ratio (2)(7)
1.0
0.6
1.0
0.6
Net debt (2)
142,353
49,083
142,353
49,083
Capital expenditures (2)
Capital expenditures, including land, corporate and other (2)
31,168
23,927
56,100
36,719
Wells Drilled (3) – gross (net)
11 / 9.0
8 / 8.0
23 / 18.8
15 / 15.0
Common shares outstanding (1) (thousands)
Weighted average – basic
93,279
62,494
93,120
62,476
Weighted average – diluted
95,074
63,446
95,426
63,446
End of period
93,395
62,593
93,395
62,593
Operating
Heavy Oil (bbl/d) (4)
8,637
4,503
8,489
4,509
Natural gas (Mcf/d)
20,522
—
21,276
—
NGLs (bbl/d) (5)
368
—
370
—
Daily average sales production (boe/d)
12,425
4,503
12,405
4,509
Average prices
West Texas Intermediate ("WTI") ($US/bbl)
63.74
80.57
67.58
78.77
Western Canadian Select ("WCS") ($CAD/bbl)
73.96
91.63
79.13
84.70
AECO 5A Daily Index ($CAD/Mcf)
1.69
1.18
1.93
1.84
Rubellite average realized prices (2)(6)
Oil ($/bbl)
69.98
87.35
74.89
79.97
Natural gas ($/Mcf)
1.93
—
2.05
—
NGL ($/bbl)
57.92
—
62.72
—
Average realized price (2) ($/boe)
53.54
87.35
56.63
79.97
Average realized price, after risk management contracts (2) ($/boe)
57.81
82.99
58.69
79.06
(1)
Per share amounts are calculated using the weighted average number of basic or diluted common shares.
(2)
Non-GAAP measure or ratio. See "Non-GAAP and other Financial Measures" contained in this news release.
(3)
Well count reflects wells rig released during the period.
(4)
Conventional heavy oil sales production excludes tank inventory volumes.
(5)
Liquids means oil, condensate, ethane and butane.
(6)
Before risk management contracts; supplementary financial measure. See "Non-GAAP and Other Financial Measures".
(7)
Based on Q2 2025 and Q2 2024 annualized adjusted funds flow before transaction costs relative to period end net debt. Non-GAAP financial measure and ratio.
ABOUT RUBELLITE
The Company is a Canadian energy company headquartered in Calgary, Alberta which, through its operating subsidiary, Rubellite Energy Inc. is engaged in the exploration, development, production and marketing of its diversified asset portfolio which includes heavy crude oil from the Clearwater and Mannville Stack Formations in Eastern Alberta utilizing multi-lateral drilling technology, liquids-rich conventional natural gas assets in the deep basin of West Central Alberta, and undeveloped bitumen leases in Northern Alberta. The Company is pursuing a robust organic growth plan focused on superior corporate returns and funds flow generation while maintaining a conservative capital structure and prioritizing operational excellence. Additional information on the Company can be accessed on the Company's website at www.rubelliteenergy.com or on SEDAR+ at www.sedarplus.ca.
The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.
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.
The following abbreviations used in this news release have the meanings set forth below:
INDUSTRY METRICS
This news release contains certain industry metrics which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this document to provide readers with additional measures to evaluate Rubellite's performance; however, such measures are not reliable indicators of Rubellite's future performance and future performance may not compare to Rubellite's performance in previous periods and therefore such metrics should not be unduly relied upon.
INITIAL PRODUCTION RATES
Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinate of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time.
ESTIMATED DRILLING LOCATIONS
Assuming a January 1, 2025 reference date, of the 316.2 net heavy oil drilling development locations disclosed in this news release, 93.1 net are proved and 45.6 net are probable undeveloped locations in the McDaniel year-end 2024 reserve report. There are 9.5 net proven natural gas locations and 4.4 net probable natural gas locations in the McDaniel year-end 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:
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.
Six Months Ended June 30,
($ thousands, except per boe amounts)
$/boe
2025
$/boe
2024
Net operating costs
6.85
15,387
6.51
5,344
Transportation
5.76
12,938
7.77
6,379
General and administrative
3.75
8,429
5.39
4,426
Cash finance expense
2.14
4,798
2.55
2,087
Cash costs
18.50
41,552
22.22
18,236
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).
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:
(1)
Calculation of current assets less current liabilities has been adjusted for the removal of the current portion of risk management contracts, decommissioning liabilities, lease liabilities, share-based compensation and other provisions.
(2)
Excludes decommissioning liabilities and other provisions.
Adjusted funds flow: Adjusted funds flow is calculated based on net cash flows from operating activities, excluding changes in non-cash working capital and expenditures on decommissioning obligations, other provisions and share-based compensation since the Company believes the timing of collection, payment or incurrence of these items is variable. Expenditures on decommissioning and share based compensation obligations may vary from period to period and are managed as expenditures through the corporate budgeting process which considers available adjusted funds flow. Management uses adjusted funds flow and adjusted funds flow per boe as key measures to assess the ability of the Company to generate the funds necessary to finance capital expenditures, expenditures on decommissioning obligations, expenditures on share based compensation and meet its financial obligations.
Adjusted funds flow is not intended to represent net cash flows from operating activities calculated in accordance with IFRS.
The following table reconciles net cash flows from operating activities, as reported in the Company's statements of cash flows, to adjusted funds flow:
Free funds flow: Free funds flow is an important measure that informs efficiency of capital spent and liquidity. Free funds flow is calculated as adjusted funds flow generated during the period less capital expenditures. Rubellite's capital expenditures excluded non cash items and acquisitions and dispositions. Adjusted funds flow and capital expenditures are non-GAAP financial measures which have been reconciled to its most directly comparable GAAP measure previously in this document. By removing the impact of current period capital expenditures from adjusted funds flow, Rubellite monitors its free funds flow to inform decisions such as capital allocation and debt repayment.
The following table shows the calculation of the removal of capital expenditures from adjusted funds flows pre transaction costs:
Available Liquidity: Available liquidity is defined as the borrowing limit under the Company's credit facility, plus any cash and cash equivalents, less any borrowings and letters of credit issued under the credit facility. Management uses available liquidity to assess the ability of the Company to finance capital expenditures, expenditures on decommissioning obligations and to meet its financial obligations.
Non-GAAP Financial Ratios
Rubellite calculates certain non-GAAP measures per boe as the measure divided by weighted average daily production. Management believes that per boe ratios are a key industry performance measure of operational efficiency and one that provides investors with information that is also commonly presented by other crude oil and natural gas producers. Rubellite also calculates certain non-GAAP measures per share as the measure divided by outstanding common shares.
Average realized oil price after risk management contracts: are calculated as the average realized price less the realized gain or loss on risk management contracts.
Adjusted funds flow per share: adjusted funds flow per share is calculated using the weighted average number of basic and diluted shares outstanding used in calculating net income (loss) per share.
Adjusted funds flow per boe: Adjusted funds flow per boe is calculated as adjusted funds flow divided by total production sold in the period.
Net debt to adjusted funds flow ratio: Net debt to adjusted funds flow ratios are calculated on a trailing twelve-month basis.
Net debt to annualized adjusted funds flow ratio: Net debt to annualized adjusted funds flow ratios are calculated by annualizing the current quarter adjusted funds flow after transaction costs.
Supplementary Financial Measures
"Realized oil price" is comprised of total oil revenue, as determined in accordance with IFRS, divided by the Company's total sales oil production on a per barrel basis.
"Realized natural gas price" is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company's natural gas sales production.
"Realized NGL price" is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company's NGL sales production.
"Royalties as a percentage of revenue" is comprised of royalties, as determined in accordance with IFRS, divided by oil revenue from sales oil production as determined in accordance with IFRS.
"Net operating expense per boe" is comprised of net operating expense, divided by the Company's total sales production.
"Transportation cost ($/boe)" is comprised of transportation cost, as determined in accordance with IFRS, divided by the Company's total sales oil production.
"General & administrative costs ($/boe)" is comprised of G&A expense, as determined in accordance with IFRS, divided by the Company's total sales oil production.
"Heavy oil wellhead differential ($/bbl)" represents the differential the Company receives for selling its heavy crude oil production relative to the Western Canadian Select reference price (Cdn$/bbl) prior to any price or risk management activities.
FORWARD-LOOKING INFORMATION
Certain information in this news release including management's assessment of future plans and operations, and including the information contained under the headings "Operations Update" and "Outlook and Guidance" may constitute forward-looking information or statements (together "forward-looking information") under applicable securities laws. The forward-looking information includes, without limitation, statements with respect to: future capital expenditures, production and various cost forecasts; the anticipated sources of funds to be used for capital spending; expectations as to future exploration, development and drilling activity, and the benefits to be derived from such drilling including drilling techniques and production growth; the timing for the completion of certain facilities; Rubellite's business plan; and including the forward-looking information 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, floods and drought); the continuance of existing tax, royalty, and regulatory regimes; the accuracy of the estimates of reserves volumes; ability to access and implement technology necessary to efficiently and effectively operate assets; risk of wars or other hostilities or geopolitical events (including the ongoing war in Ukraine and conflicts in the Middle East), civil insurrection and pandemics; risks relating to Indigenous land claims and duty to consult; data breaches and cyber attacks; risks relating to the use of artificial intelligence; changes in laws and regulations, including but not limited to tax laws, royalties and environmental regulations (including greenhouse gas emission reduction requirements and other decarbonization or social policies) and including uncertainty with respect to the interpretation and impact of omnibus Bill C-59 and the related amendments to the Competition Act (Canada), and the interpretation of such changes to the Company's business); political, geopolitical and economic instability; trade policy, barriers, disputes or wars (including new tariffs or changes to existing international trade requirements and general economic and business conditions and markets, among others.
Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described herein and under "Risk Factors" in the Company's Annual Information Form and MD&A for the year ended December 31, 2024 and in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR+ website www.sedarplus.ca and at Rubellite's website www.rubelliteenergy.com. Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Rubellite's management at the time the information is released, and Rubellite disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.
SOURCE Rubellite Energy Corp.