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CU Inc. Management Reports 2025
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An ATCO Company
CU INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2025
This Management’s Discussion and Analysis (MD&A) is meant to help readers understand key operational and financial events that influenced the results of CU Inc. (our, we, us, or the Company) during the nine months ended September 30, 2025.
This MD&A was prepared as of November 6, 2025, and should be read with the Company’s unaudited interim consolidated financial statements for the nine months ended September 30, 2025. Additional information, including the Company’s previous MD&As, Annual Information Form, and audited consolidated financial statements for the year ended December 31, 2024, is available on SEDAR+ at www.sedarplus.ca. Information contained in the 2024 MD&A is not discussed in this MD&A if it remains substantially unchanged.
The Company is controlled by Canadian Utilities Limited (Canadian Utilities or CU), which in turn is controlled by ATCO Ltd. (ATCO) and its controlling share owner, Sentgraf Enterprises Ltd. and its controlling share owner, the Southern family.
Terms used throughout this MD&A are defined in the Glossary at the end of this document.
TABLE OF CONTENTS
| Page | |
|---|---|
| Utilities Performance | 2 |
| Recent Developments | 3 |
| Regulatory Developments | 4 |
| Policy and Regulatory Updates | 5 |
| Sustainability | 6 |
| Other Expenses and Income | 6 |
| Liquidity and Capital Resources | 7 |
| Share Capital | 9 |
| Quarterly Information | 9 |
| Other Financial and Non-GAAP Measures | 10 |
| Reconciliation of Adjusted Earnings to Earnings for the Period | 11 |
| Other Financial Information | 16 |
| Glossary | 18 |
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
UTILITIES PERFORMANCE
REVENUES
Revenues of $656 million and $2,277 million in the third quarter and first nine months of 2025 were $11 million and $56 million higher compared to the same periods in 2024. Higher revenues were mainly due to growth in rate base. Higher revenues were partially offset by a decrease in return on equity (ROE) following the annual update of the Alberta Utilities Commission (AUC) approved ROE formula which set the 2025 ROE at 8.97 per cent compared to the 2024 rate of 9.28 per cent, and the completion of efficiency carryforward mechanism (ECM) funding of up to 0.5 per cent additional ROE in 2024 for Electricity Distribution and Natural Gas Distribution. Additionally, higher revenues were partially offset by the commencement of refunds of $35 million and $36 million to the customers of Electricity Distribution and Natural Gas Distribution, respectively, over the September 1, 2025 to February 28, 2026 period, resulting from the AUC's Performance Based Regulation (PBR2) re-opener Phase II Decision rendered in the second quarter of 2025. The Company has been granted leave to appeal this decision which will be heard in April 2026.
ADJUSTED EARNINGS
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||
|---|---|---|---|---|---|---|
| ($ millions) | 2025 | 2024 | Change | 2025 | 2024 | Change |
| Electricity | ||||||
| Electricity Distribution (1) | 39 | 36 | 3 | 117 | 104 | 13 |
| Electricity Transmission (1) | 44 | 47 | (3) | 133 | 143 | (10) |
| Total Electricity (1) | 83 | 83 | — | 250 | 247 | 3 |
| Natural Gas | ||||||
| Natural Gas Distribution (1) | (27) | (25) | (2) | 70 | 73 | (3) |
| Natural Gas Transmission (1) | 28 | 21 | 7 | 81 | 67 | 14 |
| Total Natural Gas (1) | 1 | (4) | 5 | 151 | 140 | 11 |
| Financing & Other and Intersegment Eliminations (1) | — | (6) | 6 | (1) | (15) | 14 |
| Total Utilities (2) | 84 | 73 | 11 | 400 | 372 | 28 |
(1) Non-GAAP financial measures (as defined in National Instrument 52-112 - Non GAAP and Other Financial Measures Disclosure (NI 52-112)). The most directly comparable measure reported in accordance with International Financial Reporting Standards (IFRS) is Earnings for the Period. See "Other Financial and Non-GAAP Measures" and "Reconciliation of Adjusted Earnings to Earnings for the Period" in this MD&A.
(2) Total of segments measure (as defined in NI 52-112). The most directly comparable measure reported in accordance with IFRS is Earnings for the Period. See "Other Financial and Non-GAAP Measures" and "Reconciliation of Adjusted Earnings to Earnings for the Period" in this MD&A.
Utilities adjusted earnings of $84 million and $400 million in the third quarter and first nine months of 2025 were $11 million and $28 million higher than the same periods in 2024 mainly due to growth in rate base and cost efficiencies. Higher earnings were partially offset by a decrease in 2025 ROE which is set at 8.97 per cent compared to the 2024 rate of 9.28 per cent, and the completion of ECM funding of up to 0.5 per cent additional ROE in 2024 for Electricity Distribution and Natural Gas Distribution.
Detailed information about the activities and financial results of the Utilities business segments is provided in the following sections.
Electricity Distribution
Electricity Distribution provides regulated electricity distribution and distributed generation mainly in Northern and Central East Alberta, the Yukon, the Northwest Territories, and in the Lloydminster area of Saskatchewan.
Electricity Distribution adjusted earnings of $39 million and $117 million in the third quarter and first nine months of 2025 were $3 million and $13 million higher than the same periods in 2024 mainly due to growth in rate base, and the timing of cost efficiencies and tax adjustments recorded throughout 2024 and 2025, partially offset by the completion of ECM funding in 2024 and lower ROE in 2025.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
3
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
Electricity Transmission
Electricity Transmission provides electricity transmission mainly in Northern and Central East Alberta, and in the Lloydminster area of Saskatchewan. Electricity Transmission has a 35-year contract to be the operator of Alberta PowerLine, a 500-km electricity transmission line between Wabamun, near Edmonton, and Fort McMurray, Alberta.
Electricity Transmission adjusted earnings of $44 million and $133 million in the third quarter and first nine months of 2025 were $3 million and $10 million lower than the same periods in 2024 mainly due to lower ROE in 2025.
Natural Gas Distribution
Natural Gas Distribution serves municipal, residential, commercial, and industrial customers throughout Alberta and in the Lloydminster area of Saskatchewan.
Natural Gas Distribution adjusted earnings in the third quarter and first nine months of 2025 were $2 million and $3 million lower than the same periods in 2024 mainly due to the completion of ECM funding in 2024 and lower ROE in 2025, partially offset by growth in rate base and cost efficiencies.
Natural Gas Transmission
Natural Gas Transmission receives natural gas on its pipeline system from various gas processing plants as well as from other natural gas transmission systems and transports it to end users within the province of Alberta or to other pipeline systems.
Natural Gas Transmission adjusted earnings of $28 million and $81 million in the third quarter and first nine months of 2025 were $7 million and $14 million higher than the same periods in 2024 mainly due to growth in rate base and cost efficiencies, partially offset by lower ROE in 2025.
FINANCING & OTHER AND INTERSEGMENT ELIMINATIONS
Including intersegment eliminations, Financing & Other adjusted earnings in the third quarter and first nine months of 2025 were $6 million and $14 million higher than the same periods in 2024 mainly due to higher interest income from cash investments.
RECENT DEVELOPMENTS
Utility Infrastructure Projects
ATCO Energy Systems continues work on its two large utility infrastructure projects: the Yellowhead Pipeline Project (Yellowhead) in Natural Gas Transmission and the Central East Transfer-Out Project (CETO) in Electricity Transmission.
- Yellowhead consists of approximately 235 kilometres of high-pressure natural gas pipeline with the projected spend estimated at $2.9 billion, a Class III estimate with an expected accuracy of +/-20 per cent, and is on track for construction to commence in 2026, subject to both AUC and corporate approvals. In the third quarter of 2025, the AUC approved the Need Assessment Application for the project. As one of two key regulatory filings that require approval from the AUC to advance, this approval marks a major milestone in the development of Alberta's energy infrastructure. ATCO Energy Systems filed a separate facility application on November 4, 2025 to seek AUC approval for construction and operation of the physical infrastructure.
The Company expects to fund Yellowhead's development according to their regulated capital structure, which is 63 per cent regulated debt and 37 per cent equity. We continue to pursue partnership arrangements with Indigenous partners that may contribute up to 30 per cent.
- CETO consists of a 135-km 240kV transmission line, of which Electricity Transmission is building 85-km of the transmission line and AltaLink LP is constructing the remaining 50-km. Electricity Transmission completed the winter season construction in the first quarter of 2025, and has progressed substation tendering for civil, structural and electrical works and began fall season construction in the third quarter of 2025. Electricity Transmission's 85-km of the transmission line is on track to be energized by June 2026 with an approximate $255 million project spend. CETO will support renewable energy integration in Alberta and transport electricity in the counties of Red Deer, Lacombe and Stettler, supplying more than 1,500 megawatts of electricity to Alberta's grid.
REGULATORY DEVELOPMENTS
COMMON MATTERS
Second Generation Performance Based Regulation (PBR2) Re-openers
In June 2023, the AUC initiated a proceeding for Electricity Distribution and Natural Gas Distribution as the re-opener clause was triggered by both utilities' earnings in 2022, the final year of PBR2. The PBR2 re-opener thresholds were triggered as a result of both utilities' earnings being either +/- 500 basis points from the approved ROE in one year or +/- 300 basis points from the approved ROE in two consecutive years.
On May 22, 2024, the AUC issued a decision to re-open the PBR2 plan and advanced to the second phase of the proceeding (Phase I Decision). The AUC claimed that the distribution businesses failed to quantify or attribute all efficiency gains under PBR2 to specific programs or initiatives. An appeal with the Alberta Court of Appeal (ACA) was filed on the Phase I Decision of the proceeding.
On May 28, 2025, the AUC issued its Phase II Decision related to the PBR2 re-opener proceeding to refund $35 million to the customers of Electricity Distribution and $36 million to the customers of Natural Gas Distribution over a six-month period, from September 1, 2025 to February 28, 2026. In regard to the Phase II Decision, a Review and Variance (R&V) and a Permission to Appeal (PTA) were filed with the AUC and the ACA, respectively, on June 27, 2025. On September 22, 2025, the PTA of the Phase II Decision was granted by the ACA. The Phase I and Phase II appeals have been combined into a single proceeding before the ACA and will be heard in April 2026. On October 6, 2025, the AUC denied the application to review and vary the Phase II Decision.
Electricity Distribution and Natural Gas Distribution were the only utilities in Alberta to lower rates in 2023 due to efficiencies being passed onto customers. The after-the-fact requirement to track cost efficiencies at a granular level is inconsistent with PBR regulatory principles and past AUC positions. As Electricity Distribution and Natural Gas Distribution are appealing both the Phase I and Phase II Decisions of the PBR2 re-opener proceeding with the ACA, and the Company believes it will more likely than not succeed on appeal, no impact to Adjusted Earnings has been recognized in 2025 related to the PBR2 re-opener decisions.
Natural Gas Transmission
2026-2028 General Rate Application (GRA)
On September 22, 2025, ATCO Pipelines filed its GRA with the AUC to establish its revenue requirement for the 2026-2028 Test Period. The application seeks approval for revenue requirements of $381 million, $489 million and $680 million for the years 2026, 2027 and 2028, respectively. Increases over the test period are largely related to Yellowhead. ATCO Pipelines is requesting a deferral account to manage uncertainties for Yellowhead and measures to provide credit relief during the construction. The temporary credit relief includes three options to be considered: a temporary ROE adder of 1 per cent for 2026 and 2027, a temporary deemed equity thickness adder of 2 per cent for 2026 and 2027, and Construction Work in Progress to be included in rate base.
Yellowhead Pipeline Project
On August 21, 2025, the AUC issued a decision approving ATCO Pipelines' Need Assessment Application for Yellowhead. The decision confirms the requirement for approximately 235-kilometers of high-pressure pipeline from the Peers area to Fort Saskatchewan, with an expected in-service date in the fourth quarter of 2027. The selected alternative carries a current forecast capital cost of approximately $2.9 billion, a Class III estimate with an expected accuracy of +/-20 per cent, with costs and revenue requirements impact to be reviewed through the 2026-2028 GRA. A separate facility application was filed with the AUC on November 4, 2025, to address routing and environmental considerations prior to construction. In addition, we continue to pursue equity partnership arrangements with Indigenous partners.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
POLICY AND REGULATORY UPDATES
We constructively work with all levels of government to advocate for enabling policy and regulation, and to identify barriers that impede cost-effective, economy-wide solutions. We participate in a wide number of discussions, and the following are examples of where we focus our efforts on policies or regulations most relevant to our existing or planned projects.
CANADA
Major Projects Office
On August 29, 2025, the Federal government announced the launch of the Major Projects Office (MPO). Established through the Building Canada Act, which came into force on June 26, 2025, the MPO is expected to support the advancement of the federal government's nation-building projects. The MPO will be headquartered in Calgary with offices expected to be opened in other major Canadian cities. Its mandate will include streamlining and accelerating regulatory approval processes to ensure projects are approved within a two-year time frame, as well as helping to structure and coordinate financing of these projects as needed. The MPO will work to attract domestic and global capital to these major projects by helping coordinate financing from the private sector, provincial and territorial partners, and government initiatives, including the Canada Infrastructure Bank, the Canada Growth Fund, and the Indigenous Loan Guarantee Program. Dawn Farrell was appointed as Chief Executive Officer of the MPO.
On September 11, 2025, the first tranche of projects (five projects) was announced by the MPO. These five nation-building projects are meant to be fast-tracked through the regulatory process. A second tranche of projects is also currently under consideration by the MPO and is expected to be announced later this year.
ALBERTA
Final Restructured Energy Market (REM) Design
On August 27, 2025, the Alberta Electric System Operator (AESO) published the complete REM framework after two years of stakeholder engagement and government direction (summer 2023–2025). This final redesign impacts Alberta's existing energy-only electricity market and includes locational marginal pricing, ramping reserves, scarcity pricing, and cost-sharing for system needs. Stakeholder consultations on Independent System Operator rules and implementation begin fall 2025, targeting a mid-2027 rollout.
Technology Innovation and Emissions Reduction (TIER) System Amendments
On September 16, 2025, the Alberta Ministry of Environment and Protected Areas announced proposed amendments to the TIER system. These amendments come after the Alberta government freezing the industrial carbon price at $95 per tonne in May 2025 followed by stakeholder consultations held in June 2025. These changes aim to enhance competitiveness for large industrial emitters, address evolving federal regulations, and support Alberta's emissions reduction goals while addressing economic pressures, such as US tariffs on Canadian energy. These amendments are set to be formalized in the fall of 2025. Key details of the proposed amendments include:
- Opt-Out Option for Smaller Facilities – Smaller facilities that voluntarily opted into the TIER system can now opt out for 2025 to reduce compliance costs and regulatory requirements.
- New Direct Investment Pathway for Compliance – On-site emissions reduction investments will be recognized as a new way for entities to meet their compliance obligations. The announcement does not provide much detail in respect of how such investments will be recognized. More information on this compliance pathway will be forthcoming.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
SUSTAINABILITY
Within the ATCO group of companies (including CU Inc.), our guiding principle is to deliver long-term value to our customers, share owners, and other stakeholders through sustainable growth. This requires more than strong financial performance – it requires integrating financial and environmental, social and governance (ESG) considerations into our strategy and anticipating the evolving needs and expectations of society and our customers.
For decades, our commitment to these principles has guided investments in critical energy infrastructure, created ambitious and transformative partnerships with Indigenous communities, and supported the growth and prosperity of the hundreds of communities we are privileged to serve. We continue to pursue growth by investing in regulated utilities, modular construction and manufactured housing, and clean technologies including carbon capture, hydrogen, renewable power, and electrification. Our priority is scalable projects that deliver measurable impacts today while laying the groundwork for long-term transformation.
When we disclosed our 2050 net-zero ambition in our 2021 Sustainability Report, we recognized it would require unprecedented, coordinated action across industries, policy, and markets. However, recent shifts—including regulatory and policy changes, legal liability concerns, and macroeconomic pressures—have introduced uncertainty regarding the feasibility, timing, and pathways for achieving net-zero by the middle of this century. While our commitment to enabling the energy transition remains strong, we continue to review our 2050 net-zero ambition and the key dependencies influencing the pace of transition. Our 2025 Sustainability Report will be published in May of 2026.
The 2024 Sustainability Report, ESG Datasheet, materiality assessment, 2024 highlights, and other disclosures are available on our website at www.canadianutilities.com.
OTHER EXPENSES AND INCOME
A financial summary of other consolidated expenses and income items for the third quarter and first nine months of 2025 and 2024 is given below. These amounts are presented in accordance with IFRS accounting standards. They have not been adjusted for the timing of revenues and expenses associated with rate-regulated activities and other items that are not in the normal course of business.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||
|---|---|---|---|---|---|---|
| ($ millions) | 2025 | 2024 | Change | 2025 | 2024 | Change |
| Operating costs | 324 | 319 | 5 | 1,080 | 1,084 | (4) |
| Depreciation and amortization | 153 | 146 | 7 | 454 | 438 | 16 |
| Net finance costs | 93 | 99 | (6) | 276 | 294 | (18) |
| Income tax expense | 19 | 18 | 1 | 99 | 93 | 6 |
OPERATING COSTS
Operating costs, which are total costs and expenses less depreciation and amortization, increased by $5 million in the third quarter of 2025 compared to the same period in 2024. Increased operating costs were mainly due to higher flow-through expense in Natural Gas Distribution for third party franchise and transmission fees, Electricity Transmission and Electricity Distribution's increased equipment maintenance, and the recognition of transition costs related to activities to shift the managed information technology (IT) services from a single-vendor service provider to a hybrid model of multiple new vendors and internal teams. Increased operating costs were partially offset by realized cost efficiencies.
Operating costs, which are total costs and expenses less depreciation and amortization, decreased by $4 million in the first nine months of 2025 compared to the same period in 2024. Decreased operating costs were mainly due to the restructuring costs incurred in 2024 and realized cost efficiencies. Lower operating costs were partially offset by higher flow-through expense in Natural Gas Distribution for third party franchise and transmission fees, and the recognition of transition costs related to activities to shift the managed IT services from a single-vendor service provider to a hybrid model of multiple new vendors and internal teams.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $7 million and $16 million in the third quarter and first nine months of 2025 compared to the same periods in 2024 mainly due to ongoing capital investment.
NET FINANCE COSTS
Net finance costs decreased by $6 million and $18 million in the third quarter and first nine months of 2025 compared to the same periods in 2024 mainly due to higher interest income and lower financing costs due to decreased interest rates.
INCOME TAX EXPENSE
Income taxes increased by $1 million and $6 million in the third quarter and first nine months of 2025 compared to the same periods in 2024 mainly due to higher IFRS earnings before income taxes, partially offset by investment tax credits and previously unrecognized deferred income taxes.
LIQUIDITY AND CAPITAL RESOURCES
Our business strategies, funding of operations, and planned future growth are supported by maintaining strong investment grade credit ratings and access to capital markets at competitive rates. Primary sources of capital are cash flows from operations and capital markets. Liquidity is generated by cash flows from operations and is supported by appropriate levels of cash and available committed credit facilities.
CREDIT RATINGS
The following table shows the credit ratings assigned to CU Inc. at September 30, 2025.
| DBRS | Fitch | |
|---|---|---|
| CU Inc. | ||
| Issuer | A (high) | A- |
| Senior unsecured debt | A (high) | A |
| Commercial paper | R-1 (low) | F2 |
| Preferred shares | PFD-2 (high) | BBB+ |
On July 23, 2025, DBRS Limited affirmed its 'A (high)' long-term corporate credit rating and stable outlook on CU Inc.
On October 27, 2025, Fitch Ratings affirmed its 'A-' issuer rating with a stable outlook on CU Inc.
LINES OF CREDIT
At September 30, 2025, CU Inc. and its subsidiaries had the following lines of credit.
| ($ millions) | Total | Used | Available |
|---|---|---|---|
| Long-term committed | 900 | 35 | 865 |
| Uncommitted | 100 | 36 | 64 |
| Total | 1,000 | 71 | 929 |
Of the $1 billion in total lines of credit, $100 million was in the form of uncommitted credit facilities with no set maturity date. The other $900 million in credit lines was committed, with maturities between 2026 and 2027, and may be extended at the option of the lenders. The majority of the credit lines are provided by Canadian banks.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
CONSOLIDATED CASH FLOWS
At September 30, 2025, the Company's cash position was $15 million. This represents an increase of $43 million compared to the cash position at September 30, 2024. Cash movements for the third quarter and first nine months of 2025 and 2024 are outlined in the following table:
| Three Months EndedSeptember 30 | Nine Months EndedSeptember 30 | |||||
|---|---|---|---|---|---|---|
| ($ millions) | 2025 | 2024 | Change | 2025 | 2024 | Change |
| Cash position, beginning of period | 10 | (273) | 283 | (163) | (71) | (92) |
| Cash from (used in): | ||||||
| Operating activities | 360 | 318 | 42 | 1,298 | 1,182 | 116 |
| Investing activities | (331) | (321) | (10) | (997) | (889) | (108) |
| Financing activities | (24) | 248 | (272) | (123) | (250) | 127 |
| Cash position, end of the period | 15 | (28) | 43 | 15 | (28) | 43 |
The opening cash position of $10 million in the third quarter of 2025 was $283 million higher compared to the opening cash position for the third quarter of 2024 mainly due to the timing of debt issuances.
The opening cash position of $(163) million in the first nine months of 2025 was $92 million lower compared to the opening cash position for the first nine months of 2024 mainly due to repayment of long-term debt, and funding of capital projects.
OPERATING ACTIVITIES
Cash flows from operating activities of $360 million and $1,298 million in the third quarter and first nine months of 2025 were $42 million and $116 million higher than the same periods in 2024 mainly due to the timing of settlement of accounts payable and the collection of trade receivables from customers, and increased customer contributions in Electricity Transmission and Natural Gas Transmission.
INVESTING ACTIVITIES
Cash flows used in investing activities of $331 million and $997 million in the third quarter and first nine months of 2025 were $10 million and $108 million higher than the same periods in 2024 mainly due to increased capital expenditures related to ongoing system upgrades in Natural Gas Distribution and Natural Gas Transmission, projects related to system reliability and safety and climate resiliency and adaptation, and growth projects for new customers. Increases were partially offset by the timing of settlement of accounts payable for capital projects.
Cash Used for Capital Expenditures
Capital expenditures for the third quarter and first nine months of 2025 and 2024 are shown in the table below.
| Three Months EndedSeptember 30 | Nine Months EndedSeptember 30 | |||||
|---|---|---|---|---|---|---|
| ($ millions) | 2025 | 2024 | Change | 2025 | 2024 | Change |
| Electricity Distribution | 99 | 115 | (16) | 291 | 319 | (28) |
| Electricity Transmission | 71 | 80 | (9) | 216 | 173 | 43 |
| Natural Gas Distribution | 110 | 105 | 5 | 311 | 296 | 15 |
| Natural Gas Transmission | 78 | 64 | 14 | 223 | 140 | 83 |
| Total (1) (2) | 358 | 364 | (6) | 1,041 | 928 | 113 |
(1) Includes additions to property, plant and equipment, intangibles, and $8 million and $21 million (2024 - $4 million and $10 million) of capitalized interest during construction for the third quarter and first nine months of 2025.
(2) Includes $29 million and $90 million for the third quarter and first nine months of 2025 (2024 - $18 million and $77 million) of capital expenditures that were funded with the assistance of customer contributions and government grants.
Cash used for capital expenditures was $358 million in the third quarter of 2025, $6 million lower compared to the same period in 2024 mainly due to timing of capital project spend in Electricity Distribution and Electricity Transmission, partially offset by increased spending related to ongoing system upgrades and growth projects for new customers, including Yellowhead in Natural Gas Transmission and CETO in Electricity Transmission.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
Cash used for capital expenditures was $1,041 million in the first nine months of 2025, $113 million higher compared to the same period in 2024 mainly due to increased spending related to ongoing system upgrades and growth projects for new customers, including Yellowhead in Natural Gas Transmission and CETO in Electricity Transmission.
FINANCING ACTIVITIES
Cash flows used in financing activities were $24 million in the third quarter of 2025, $272 million higher than the same period in 2024 mainly due to the higher repayments of long-term debt in the third quarter of 2025, and higher dividends paid to the Class A and B share owner.
Cash flows used in financing activities were $123 million in the first nine months of 2025, $127 million lower than the same period in 2024 mainly due to increased debt issuances related to growth projects for new customers, including Yellowhead in Natural Gas Transmission and CETO in Electricity Transmission, partially offset by higher repayments of long term debt in 2025.
Debt Issuances
In September 2025, CU Inc. issued $370 million of 4.787 per cent debentures maturing on September 16, 2055. The proceeds from the issuance will be used to finance capital expenditures, repay existing indebtedness, and for other general corporate purposes.
SHARE CAPITAL
CU Inc.'s equity securities consist of Class A shares and Class B shares.
At November 5, 2025, the Company had outstanding 3,570,322 Class A shares and 2,188,262 Class B shares.
QUARTERLY INFORMATION
The following table shows financial information for the eight quarters ended December 31, 2023 through September 30, 2025.
| ($ millions) | Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 |
|---|---|---|---|---|
| Revenues | 822 | 920 | 701 | 656 |
| Earnings for the period | 135 | 212 | 89 | 67 |
| Adjusted earnings (loss) (1) | ||||
| Electricity (2) | 93 | 86 | 81 | 83 |
| Natural Gas (2) | 97 | 130 | 20 | 1 |
| Financing & Other (2) and Intersegment Eliminations | (5) | (1) | — | — |
| Total adjusted earnings (1) | 185 | 215 | 101 | 84 |
| ($ millions) | Q4 2023 | Q1 2024 | Q2 2024 | Q3 2024 |
| Revenues | 783 | 880 | 696 | 645 |
| Earnings for the period | 105 | 200 | 49 | 63 |
| Adjusted earnings (loss) (1) | ||||
| Electricity (2) | 83 | 88 | 76 | 83 |
| Natural Gas (2) | 84 | 121 | 23 | (4) |
| Financing & Other (2) and Intersegment Eliminations | — | (4) | (5) | (6) |
| Total adjusted earnings (1) | 167 | 205 | 94 | 73 |
(1) Total of segments measure (as defined in NI 52-112). See "Other Financial and Non-GAAP Measures" and "Reconciliation of Adjusted Earnings to Earnings for the Period" in this MD&A.
(2) Non-GAAP financial measures (as defined in NI 52-112). See "Other Financial and Non-GAAP Measures" and "Reconciliation of Adjusted Earnings to Earnings for the Period" in this MD&A.
Our financial results for the previous eight quarters reflect the timing of utility regulatory decisions, and the seasonal nature of demand for natural gas and electricity.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS 10
ADJUSTED EARNINGS
Adjusted earnings in the fourth quarter of 2024 were higher compared to the same period in 2023 mainly due to growth in rate base and an increase in ROE. Higher adjusted earnings were partially offset by higher interest expense resulting from short term borrowings and tax adjustments recorded by Electricity Distribution
Adjusted earnings in the first, second and third quarters of 2025 were higher than the same periods in 2024 mainly due to growth in rate base and cost efficiencies. Higher earnings were partially offset by a decrease in 2025 ROE which is set at 8.97 per cent compared to the 2024 rate of 9.28 per cent, and the completion of ECM funding of up to 0.5 per cent additional ROE in 2024 for Electricity Distribution and Natural Gas Distribution.
EARNINGS FOR THE PERIOD
Earnings for the period include timing adjustments related to rate-regulated activities. They also include one-time gains and losses, impairments, dividends on equity preferred shares, and other items that are not in the normal course of business or a result of day-to-day operations recorded at various times over the past eight quarters. These items are excluded from adjusted earnings and are highlighted below:
- In the fourth quarter of 2023, the Company recognized an impairment of $34 million (after-tax) mainly related to certain computer software assets which are not expected to be used in the Company.
- In the second and fourth quarters of 2024, the Company recorded restructuring costs of $32 million (after-tax) and $5 million (after-tax), respectively, mainly related to staff reductions and associated severance costs.
- In the second quarter of 2024, the Company recorded an $8 million (after-tax) reduction to earnings related to an AUC enforcement decision on two historical matters the Electric Transmission business had self-reported to AUC Enforcement staff.
- In the first quarter of 2025, the Company recorded restructuring costs of $10 million (after-tax) mainly related to staff reductions and associated severance costs.
- In the first, second and third quarters of 2025, the Company recognized IT transition costs of $7 million (after-tax), $4 million (after-tax), and $2 million (after-tax) respectively. The transition costs were primarily related to activities to shift the managed IT services from a single-vendor service provider to a hybrid model of multiple new vendors and internal teams.
OTHER FINANCIAL AND NON-GAAP MEASURES
This MD&A should be read with the Company's unaudited interim consolidated financial statements for the nine months ended September 30, 2025. The unaudited interim consolidated financial statements are prepared according to International Accounting Standard (IAS) 34 Interim Financial Reporting using accounting policies consistent with IFRS as issued by the International Accounting Standards Board (IFRS Accounting Standards).
This MD&A contains various "total of segments measures" and "non-GAAP financial measures" (as such terms are defined in NI 52-112), which are described in further detail below.
TOTAL OF SEGMENTS MEASURE
NI 52-112 defines a "total of segments measure" as a financial measure disclosed by an issuer that (a) is a subtotal or total of two or more reportable segments of an entity, (b) is not a component of a line item disclosed in the primary financial statements of the entity, (c) is disclosed in the notes to the financial statements of the entity, and (d) is not disclosed in the primary financial statements of the entity.
Consolidated adjusted earnings (loss) is a total of segments measure, as defined in NI 52-112.
The consolidated adjusted earnings (loss) total of segments measure is most directly comparable to total earnings for the period. A comparable total of segments measure for the same period in 2024 has been calculated using the same composition
and is disclosed alongside the current total of segments measure in this MD&A. A reconciliation of the total of segments measure with total earnings (loss) for the period is presented in this MD&A.
NON-GAAP FINANCIAL MEASURES
NI 52-112 defines a "non-GAAP financial measure" as a financial measure disclosed by an issuer that (a) depicts the historical or expected future financial performance, financial position or cash flows of an entity, (b) with respect to its composition, excludes an amount that is included in, or includes an amount that is excluded from, the composition of the most directly comparable financial measure disclosed in the primary financial statements of the entity, (c) is not disclosed in the financial statements of the entity, and (d) is not a ratio, fraction, percentage or similar representation.
Adjusted earnings (loss) for each of Electricity Distribution, Electricity Transmission, Total Electricity, Natural Gas Distribution, Natural Gas Transmission, and Total Natural Gas are non-GAAP financial measures, as defined in NI 52-112.
Adjusted earnings (loss) are defined as earnings (loss) for the period after adjusting for the timing of revenues and expenses associated with rate-regulated activities and dividends on equity preferred shares of the Company. Adjusted earnings (loss) also exclude one-time gains and losses, impairments, and items that are not in the normal course of business or a result of day-to-day operations.
Adjusted earnings (loss) present earnings from rate-regulated activities on the same basis as was considered prior to adopting IFRS Accounting Standards - that basis being the US accounting principles taking into account a more likely than not recognition threshold for rate regulated activities. Management's view is that adjusted earnings (loss) allow for a more effective analysis of operating performance and trends. Adjusted earnings (loss) are presented in Note 3 of the unaudited interim consolidated financial statements.
Adjusted earnings (loss) are most directly comparable to earnings (loss) for the period but is not a standardized financial measure under the reporting framework used to prepare our financial statements. Adjusted earnings (loss) may not be comparable to similar financial measures disclosed by other issuers. For investors, adjusted earnings (loss) may provide value as they exclude items that are not in the normal course of business and, as such, provide insight as to earnings resulting from the issuer's usual course of business. A reconciliation of adjusted earnings (loss) to earnings (loss) for the period of the Company is presented in this MD&A.
RECONCILIATION OF ADJUSTED EARNINGS TO EARNINGS FOR THE PERIOD
Adjusted earnings (loss) are earnings (loss) for the period after adjusting for the timing of revenues and expenses associated with rate-regulated activities and dividends on equity preferred shares of the Company. Adjusted earnings (loss) also exclude one-time gains and losses, impairments, and items that are not in the normal course of business or a result of day-to-day operations.
Adjusted earnings (loss) are a key measure of segment earnings that management uses to assess segment performance and allocate resources. It is management's view that adjusted earnings (loss) allow a better assessment of the economics of rate regulation in Canada than IFRS earnings. Additional information regarding this measure is provided in the "Other Financial and Non-GAAP Measures" section of this MD&A.
The following tables reconcile adjusted earnings (loss) to the directly measurable financial measure, earnings (loss) for the period.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
(5 millions)
Three Months Ended
September 30
| 2025 | Electricity | Natural Gas | Financing & Other | Intersegment Eliminations | Consolidated |
|---|---|---|---|---|---|
| 2024 | |||||
| Revenues | 354 | 306 | — | (4) | 656 |
| 340 | 304 | — | 1 | 645 | |
| Adjusted earnings (loss) | 83 | 1 | — | — | 84 |
| 83 | (4) | (6) | — | 73 | |
| Transition of managed IT services | — | (2) | — | — | (2) |
| — | — | — | — | — | |
| Rate-regulated activities | (11) | (4) | — | — | (15) |
| (12) | 6 | — | — | (6) | |
| IT Common Matters decision | (1) | — | — | — | (1) |
| (3) | (2) | — | — | (5) | |
| Dividends on equity preferred shares of the Company | 1 | — | — | — | 1 |
| 1 | — | — | — | 1 | |
| Earnings (loss) for the period | 72 | (5) | — | — | 67 |
| 69 | — | (6) | — | 63 |
(5 millions)
Nine Months Ended
September 30
| 2025 | Electricity | Natural Gas | Financing & Other | Intersegment Eliminations | Consolidated |
|---|---|---|---|---|---|
| 2024 | |||||
| Revenues | 1,069 | 1,216 | — | (8) | 2,277 |
| 1,041 | 1,186 | — | (6) | 2,221 | |
| Adjusted earnings (loss) | 250 | 151 | (1) | — | 400 |
| 247 | 140 | (15) | — | 372 | |
| Restructuring | (6) | (4) | — | — | (10) |
| (13) | (19) | — | — | (32) | |
| Transition of managed IT services | (5) | (8) | — | — | (13) |
| — | — | — | — | — | |
| Rate-regulated activities | (29) | 17 | — | — | (12) |
| (36) | 27 | — | — | (9) | |
| IT Common Matters decision | (2) | — | — | — | (2) |
| (9) | (7) | — | — | (16) | |
| ATCO Electric settlement | — | — | — | — | — |
| (8) | — | — | — | (8) | |
| Dividends on equity preferred shares of the Company | 3 | 2 | — | — | 5 |
| 3 | 2 | — | — | 5 | |
| Earnings (loss) for the period | 211 | 158 | (1) | — | 368 |
| 184 | 143 | (15) | — | 312 |
RESTRUCTURING
The Company recorded restructuring costs of nil and $10 million (after-tax) (2024 - nil and $32 million (after-tax)) in the third quarter and first nine months of 2025. These costs are mainly related to staff reductions and associated severance costs. This restructuring is a continuation of the restructuring activities commenced in 2024. As these costs are not in the normal course of business, they have been excluded from adjusted earnings.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
TRANSITION OF MANAGED IT SERVICES
The Company recognized IT transition costs of $2 million and $13 million (after-tax) in the third quarter and first nine months of 2025. The transition costs were primarily related to activities to shift from a single-vendor service provider to a hybrid model of multiple new vendors and internal teams. The transition activities commenced on January 1, 2025 and will be completed in 2025. As these costs are not in the normal course of business, they have been excluded from adjusted earnings.
RATE-REGULATED ACTIVITIES
ATCO Electric Transmission, ATCO Electric Distribution, ATCO Electric Yukon, Naka Power Utilities (NWT), Naka Power Utilities (Yellowknife), ATCO Gas and ATCO Pipelines are collectively referred to as the Utilities.
There is currently no specific guidance under IFRS Accounting Standards for rate-regulated entities that the Company is eligible to adopt. In the absence of this guidance, the Utilities do not recognize assets and liabilities from rate-regulated activities as may be directed by regulatory decisions. Instead, the Utilities recognize revenues in earnings when amounts are billed to customers, consistent with the regulator-approved rate design. Operating costs and expenses are recorded when incurred. Costs incurred in constructing an asset that meet the asset recognition criteria are included in the related property, plant and equipment or intangible asset.
The Company considers standards issued by the Financial Accounting Standards Board (FASB) in the United States as another source of generally accepted accounting principles taking into account a more likely than not recognition threshold in accounting for rate-regulated activities in its internal reporting provided to the senior management team (SMT). The SMT believes that earnings presented in this manner are a better representation of the operating results of the Company's rate-regulated activities. Therefore, the Company presents adjusted earnings as part of its segmented disclosures on this basis. Rate-regulated accounting (RRA) standards impact the timing of how certain revenues and expenses are recognized when compared to non-rate regulated activities, to appropriately reflect the economic impact of a regulator's decisions on revenues.
Rate-regulated accounting differs from IFRS Accounting Standards in the following ways:
| Timing Adjustment | Items | RRA Treatment | IFRS Treatment |
|---|---|---|---|
| Additional revenues billed in current period | Future removal and site restoration costs, and impact of colder temperatures. | The Company defers the recognition of cash received in advance of future expenditures. | The Company recognizes revenues when amounts are billed to customers and costs when they are incurred. |
| Revenues to be billed in future periods | Deferred income taxes and impact of warmer temperatures. | The Company recognizes revenues associated with recoverable costs in advance of future billings to customers. | The Company recognizes costs when they are incurred, but does not recognize their recovery until customer rates are changed and amounts are collected through future billings. |
| Regulatory decisions received | Regulatory decisions received which relate to current and prior periods. | The Company recognizes the earnings from a regulatory decision pertaining to current and prior periods when the decision is received. | The Company does not recognize earnings from a regulatory decision when it is received as regulatory assets and liabilities are not recorded under IFRS Accounting Standards. |
| Settlement of regulatory decisions and other items | Settlement of amounts receivable or payable to customers and other items. | The Company recognizes the amount receivable or payable to customers as a reduction in its regulatory assets and liabilities when collected or refunded through future billings. | The Company recognizes earnings when customer rates are changed and amounts are recovered or refunded to customers through future billings. |
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
For the third quarter and first nine months of 2025 and 2024, the significant timing adjustments as a result of the differences between rate-regulated accounting and IFRS Accounting Standards are as follows:
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||
|---|---|---|---|---|---|---|
| ($ millions) | 2025 | 2024 | Change | 2025 | 2024 | Change |
| Additional revenues billed in current period | ||||||
| Future removal and site restoration costs (1) | 35 | 31 | 4 | 100 | 94 | 6 |
| Revenues to be billed in future periods | ||||||
| Deferred income taxes (2) | (37) | (31) | (6) | (106) | (93) | (13) |
| Impact of warmer temperatures (3) | (6) | (5) | (1) | (13) | (1) | (12) |
| Settlement of regulatory decisions and other items | ||||||
| PBR2 re-opener proceeding refund to customers (4) | (7) | — | (7) | (7) | — | (7) |
| Other | — | (1) | 1 | 14 | (9) | 23 |
| (15) | (6) | (9) | (12) | (9) | (3) |
(1) Removal and site restoration costs are billed to customers over the estimated useful life of the related assets based on forecast costs to be incurred in future periods.
(2) Income taxes are billed to customers when paid by the Company.
(3) Natural Gas Distribution's customer rates are based on a forecast of normal temperatures. Fluctuations in temperatures may result in more or less revenue being recovered from customers than forecast. Revenues above or below normal temperatures in the current period are refunded to or recovered from customers in future periods.
(4) In connection with the PBR2 re-opener proceeding (Phase II Decision), Electricity Distribution and Natural Gas Distribution refunded $3 million (after-tax) and $4 million (after-tax), respectively, to customers for the three and nine months ended September 30, 2025.
IT COMMON MATTERS DECISION
Consistent with the treatment of the gain on sale in 2014 from the IT services business by CU Inc.'s parent, Canadian Utilities, financial impacts associated with the IT Common Matters decision are excluded from adjusted earnings. The amount excluded from adjusted earnings in the third quarter and first nine months of 2025 was $1 million and $2 million (after-tax) (2024 - $5 million and $16 million (after-tax)).
ATCO ELECTRIC SETTLEMENT
On June 24, 2024, AUC Enforcement filed a joint submission with ATCO Electric seeking the AUC's approval of a settlement agreement involving two historical matters ATCO Electric had previously identified and self-reported to AUC Enforcement staff. The settlement agreement includes an administrative penalty of $3 million, and a refund to customers through a billing adjustment to the AESO of $4 million. In the first nine months of 2024, the Company recognized costs of $8 million (after tax) related to the proceeding. As this is not in the normal course of business, it has been excluded from adjusted earnings.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
SEGMENTED RECONCILIATION OF ADJUSTED EARNINGS TO EARNINGS FOR THE PERIOD
The following tables reconcile adjusted earnings (loss) for Utilities to the directly comparable financial measure, earnings (loss) for the period.
| ($ millions) | |||||||
|---|---|---|---|---|---|---|---|
| 2025 | CU Inc. | ||||||
| 2024 | Electricity | Natural Gas | Consolidated | ||||
| Electricity Distribution | Electricity Transmission | Consolidated Electricity | Natural Gas Distribution | Natural Gas Transmission | Consolidated Natural Gas | ||
| Adjusted earnings (loss) | 39 | 44 | 83 | (27) | 28 | 1 | 84 |
| 36 | 47 | 83 | (25) | 21 | (4) | 79 | |
| Transition of managed IT services | — | — | — | (2) | — | (2) | (2) |
| — | — | — | — | — | — | — | |
| Rate-regulated activities | (7) | (4) | (11) | (2) | (2) | (4) | (15) |
| (7) | (5) | (12) | 9 | (3) | 6 | (6) | |
| IT Common Matters decision | — | (1) | (1) | — | — | — | (1) |
| (1) | (2) | (3) | (3) | 1 | (2) | (5) | |
| Dividends on equity preferred shares of the Company | — | 1 | 1 | — | — | — | 1 |
| — | 1 | 1 | — | — | — | 1 | |
| Earnings (loss) for the period | 32 | 40 | 72 | (31) | 26 | (5) | 67 |
| 28 | 41 | 69 | (19) | 19 | — | 69 | |
| ($ millions) | |||||||
| --- | --- | --- | --- | --- | --- | --- | --- |
| 2025 | CU Inc. | ||||||
| 2024 | Electricity | Natural Gas | Consolidated | ||||
| Electricity Distribution | Electricity Transmission | Consolidated Electricity | Natural Gas Distribution | Natural Gas Transmission | Consolidated Natural Gas | ||
| Adjusted earnings | 117 | 133 | 250 | 70 | 81 | 151 | 401 |
| 104 | 143 | 247 | 73 | 67 | 140 | 387 | |
| Restructuring | (4) | (2) | (6) | (2) | (2) | (4) | (10) |
| (8) | (5) | (13) | (16) | (3) | (19) | (32) | |
| Transition of managed IT services | (5) | — | (5) | (8) | — | (8) | (13) |
| — | — | — | — | — | — | — | |
| Rate-regulated activities | (15) | (14) | (29) | 25 | (8) | 17 | (12) |
| (23) | (13) | (36) | 34 | (7) | 27 | (9) | |
| IT Common Matters decision | (1) | (1) | (2) | — | — | — | (2) |
| (5) | (4) | (9) | (6) | (1) | (7) | (16) | |
| ATCO Electric settlement | — | — | — | — | — | — | — |
| — | (8) | (8) | — | — | — | (8) | |
| Dividends on equity preferred shares of the Company | 1 | 2 | 3 | 1 | 1 | 2 | 5 |
| 1 | 2 | 3 | 1 | 1 | 2 | 5 | |
| Earnings for the period | 93 | 118 | 211 | 86 | 72 | 158 | 369 |
| 69 | 115 | 184 | 86 | 57 | 143 | 327 |
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
OTHER FINANCIAL INFORMATION
INTERNAL CONTROL OVER FINANCIAL REPORTING
The certification of interim filings for the interim period ended September 30, 2025, requires that the Company disclose in the interim MD&A any changes in the Company's internal controls over financial reporting (ICFR) that occurred during the period that have materially affected, or are reasonably likely to materially affect, the Company's ICFR. The Company confirms that no such changes were identified in the Company's ICFR during the three months beginning on July 1, 2025 and ending on September 30, 2025.
FORWARD-LOOKING INFORMATION
Certain statements contained in this MD&A constitute forward-looking information. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "plan", "estimate", "expect", "may", "will", "intend", "should", "goals", "targets", "strategy", "future", and similar expressions. In particular, forward-looking information in this MD&A includes, but is not limited to, references to: strategic and growth plans and opportunities; the Company's 2050 net-zero ambition; the expected timing of commencement, completion or commercial operations of activities, contracts and projects; the expected term of contracts; the impact or benefits of contracts, including economic and other benefits for the Company and its partners and counterparties; expectations regarding ATCO Pipelines' 2026-2028 GRA; expectations regarding Yellowhead, including the anticipated size and specifications of the project, the anticipated total investment in the project, the anticipated timing for and number of regulatory applications and decisions, the expected timing for commencement of construction and in-service date of the project, and expectations regarding the project's funding structure, sources of funding for the project and potential Indigenous equity participation on the project; expectations regarding CETO, including the anticipated size, capacity and benefits of the project, the anticipated timing for energization of the project, and the anticipated total investment in the project; expectations regarding the PBR2 re-opener proceedings, including timing expectations, scope of the proceedings, and anticipated outcomes; expectations regarding the use of proceeds resulting from CU Inc.'s recent debenture issuance; the expected impact of new legislation; the expected timing and impact of policy and regulatory decisions and new policy and regulatory announcements; and the Company's liquidity, capital resources, contractual financial obligations and other commitments.
Although the Company believes that the expectations reflected in the forward-looking information are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and no assurance can be given that these expectations will prove to be correct. Forward-looking information should not be unduly relied upon. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties, and other factors, which may cause actual results, levels of activity, and achievements to differ materially from those anticipated in such forward-looking information. The forward-looking information reflects the Company's beliefs and assumptions with respect to, among other things: the applicability and stability of legal and regulatory requirements in the jurisdictions in which we invest and/or operate; the payment of fees owing pursuant to applicable contracts; certain regulatory applications being made and approved; the growth of energy demand; inflation; the development and performance of technology and technological innovations and the ability to otherwise access and implement all technology necessary to achieve business objectives; continuing collaboration with certain business partners and engagement with new business partners, and regulatory and environmental groups; the performance of assets and equipment; demand levels for oil, natural gas, gasoline, diesel and other energy sources; certain levels of future energy use; future production rates; future revenue and earnings; the ability to meet current project schedules and complete proposed development projects at currently estimated project budgets; the availability of financing sources on acceptable terms; and other assumptions inherent in management's expectations in respect of the forward-looking information identified herein.
The Company's actual results could differ materially from those anticipated in this forward-looking information as a result of, among other things: risks inherent in the performance of assets; capital efficiencies and cost savings; applicable laws and regulations and the interpretation and manner of enforcement of such laws and regulations; changes to government policies; regulatory decisions; competitive factors in the industries in which the Company operates; evolving market or economic conditions; credit risk; interest rate fluctuations; the availability and cost of labour, materials, services, infrastructure, and future demand for resources; the development and execution of projects, including development projects not proceeding on schedule or at all, or at currently estimated budgets; the availability of financing sources for development projects on acceptable terms; prices of electricity, natural gas, natural gas liquids, and renewable energy; the development and performance of technology and new energy efficient products, services, and programs including but not limited to the use of
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
zero-emission and renewable fuels, carbon capture, and storage, electrification of equipment powered by zero-emission energy sources and utilization and availability of carbon offsets; potential cancellation, termination, default, non-compliance, or breach of contract by contract counterparties; the risk that payments owed may not be collected or received in a timely manner, or at all; risks associated with potential litigation proceedings; potential damage to our brand and/or reputation that may result from a failure to perform, or from factors outside of our control, or negative publicity related to significant projects, investments, operations or activities; the risk of operational disruptions, outages, or force majeure events; the occurrence of unexpected events such as fires, extreme weather conditions, explosions, blow-outs, equipment failures, transportation incidents, and other accidents or similar events; global pandemics; the imposition of or changes to existing customs duties, tariffs or other trade restrictions; geopolitical tensions and wars; and other risk factors, many of which are beyond the control of the Company. Due to the interdependencies and correlation of these factors, the impact of any one material assumption or risk on a forward-looking statement cannot be determined with certainty. Readers are cautioned that the foregoing lists are not exhaustive. For additional information about the principal risks that the Company faces, see the "Business Risks and Risk Management" section in the 2024 MD&A.
This MD&A may contain information that constitutes future-oriented financial information or financial outlook information, all of which are subject to the same assumptions, risk factors, limitations and qualifications set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise or inaccurate and, as such, undue reliance should not be placed on such future-oriented financial information or financial outlook information. The Company's actual results, performance and achievements could differ materially from those expressed in, or implied by, such future-oriented financial information or financial outlook information. The Company has included such information in order to provide readers with a more complete perspective on its future operations and its current expectations relating to its future performance. Such information may not be appropriate for other purposes and readers are cautioned that such information should not be used for purposes other than those for which it has been disclosed herein. Future-oriented financial information or financial outlook information contained herein was made as of the date of this MD&A.
Any forward-looking information contained in this MD&A represents the Company's expectations as of the date thereof, and is subject to change after such date. The Company disclaims any intention or obligation to update or revise any forward-looking information whether as a result of new information, future events or otherwise, except as required by applicable securities legislation.
ADDITIONAL INFORMATION
Additional information relating to the Company, including the Company's audited consolidated financial statements for the year ended December 31, 2024, unaudited interim consolidated financial statements for the nine months ended September 30, 2025, and most recent Annual Information Form dated March 31, 2025, can be found on SEDAR+ at www.sedarplus.ca.
Copies of these documents may also be obtained upon request from Investor Relations at 3rd Floor, West Building, 5302 Forand Street S.W., Calgary, Alberta, T3E 8B4, telephone 403-292-7500, or email [email protected]. Corporate information is also available on the Company's website at www.canadianutilities.com.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS
GLOSSARY
AUC means the Alberta Utilities Commission.
Class A shares means Class A non-voting common shares of the Company.
Class B shares means Class B common shares of the Company.
Company means CU Inc. and, unless the context otherwise requires, includes its subsidiaries.
Customer contributions are non-refundable cash contributions made by customers for certain additions to property, plant and equipment. These contributions are made when the estimated revenue is less than the cost of providing service.
ECM means efficiency carry-over mechanism.
GAAP means Canadian generally accepted accounting principles.
GRA means general rate application.
IFRS means International Financial Reporting Standards.
ROE means return on equity.
SMT means senior management team, and is comprised of the Chief Executive Officer and the other members of the Executive Committee.
CU INC. 2025 MANAGEMENT'S DISCUSSION & ANALYSIS