ORDER NUMBER
G-48-26
IN THE MATTER OF
the Utilities Commission Act, RSBC 1996, Chapter 473
and
British Columbia Hydro and Power Authority
Distribution Design Modernization Project
BEFORE:
E. B. Lockhart, Panel Chair
A. C. Dennier, Commissioner
on March 12, 2026
ORDER
WHEREAS:
A. On June 27, 2025, British Columbia Hydro and Power Authority (BC Hydro) filed an application (Application) with the British Columbia Utilities Commission (BCUC), pursuant to section 44.2(1)(b) of the Utilities Commission Act (UCA), seeking acceptance of a schedule of anticipated capital expenditures for the implementation of the Distribution Design Modernization project (Project);
B. The Project will replace distribution design systems (PassPort, Gateway, Maintenance Data Tracking System and the Customer Contribution Calculator) with an SAP-based Enterprise Asset Management system and replace the design and engineering capabilities of BC Hydro’s Distribution Analysis and Design system with commercially available software;
C. The estimated cost range for the Project is $81.1 million to $104.6 million. BC Hydro refers to the upper bound of this cost estimate ($104.6 million) as its authorized cost;
D. By Order G-184-25, dated July 25, 2025, the BCUC established a regulatory timetable for the review of the Application, which included public notice, one round of BCUC and intervener information requests, letters of comment, and final and reply arguments;
E. Residential Consumer Intervener Association, Commercial Energy Consumers of British Columbia, and British Columbia Old Age Pensioners’ Organization et al. registered as interveners in this proceeding;
F. BC Hydro requests that certain information in the Application and responses to information requests be held confidential in accordance with Part IV of the BCUC’s Rules of Practice and Procedure; and
G. The BCUC has reviewed the Application, evidence and submissions of the parties and finds that the following determinations are warranted.
NOW THEREFORE for the reasons outlined in the decision accompanying this order and pursuant to section 44.2 of the UCA, the BCUC orders as follows:
1. BC Hydro’s expenditure schedule for the Project, with an authorized cost estimate of $104.6 million, is accepted.
2. BC Hydro is directed to file Project reports as outlined in Appendix A to the decision accompanying this order.
3. BC Hydro is directed to file a benefits realization report with the BCUC within three years of the Project in-service date, which must include an assessment of the realization of the Project benefits and the extent to which the Project achieved its objectives.
4. All materials filed confidentially in this proceeding will be held confidential unless the BCUC determines otherwise.
DATED at the City of Vancouver, in the Province of British Columbia, this 12th day of March 2026.
BY ORDER
Electronically signed by Blair Lockhart
E. B. Lockhart
Commissioner
British Columbia Hydro and Power Authority
Distribution Design Modernization Project
DECISION
Table of Contents
Page no.
1.2 Legal and Regulatory Framework
2.0 BC Hydro’s Distribution Design Systems
4.1 Description of Alternatives
4.2 Project Alternatives Evaluation
4.2.1 Alternatives to Address the Obsolete DAD Application
4.2.2 Alternatives to Modernize PassPort, Gateway, CCC, and MDTS
5.4 Project Risks and Risk Management
6.0 Project Costs and Bill Impact
7.0 Consultation and Engagement
8.0 Provincial Government Energy Objectives, the Integrated Resource Plan and the Clean Energy Act
1.0 Introduction
On June 27, 2025, British Columbia Hydro and Power Authority (BC Hydro) filed an application (Application) with the British Columbia Utilities Commission (BCUC), pursuant to section 44.2(1)(b) of the Utilities Commission Act (UCA),[2] for acceptance of schedule of anticipated capital expenditures for the implementation of the Distribution Design Modernization project (Project).[3]
BC Hydro relies on a number of software applications to support its distribution design and distribution asset management processes. [4] BC Hydro's existing distribution design systems, specifically PassPort, Distribution Analysis and Design (DAD), Gateway, the Maintenance Data Tracking System (MDTS) and the Customer Contribution Calculator (CCC) were first implemented more than 20 years ago and BC Hydro submits that they are now obsolete and fragmented.
The Project will replace BC Hydro’s outdated systems with modern, fully supported enterprise asset management (EAM) and graphical design applications.[5] BC Hydro explains that the Project is necessary to address limitations in its distribution design systems and to integrate distribution design workflows into a single, cohesive system.[6]
The estimated cost range for the Project is $81.1 million to $104.6 million based on an expected cost estimate of $88.1 million and an authorized cost estimate of $104.6 million.[7]
1.1 Regulatory Process
On July 25, 2025, the BCUC established a regulatory timetable for the review of the Application, which consisted of public notice, intervener registration, one round of BCUC and intervener information requests (IRs), a letter of comment deadline, and final and reply arguments.[8]
The following three parties registered as interveners in this proceeding:
• Residential Consumer Intervener Association (RCIA);
• Commercial Energy Consumers of British Columbia (the CEC); and
• British Columbia Old Age Pensioners’ Organization, Council of Senior Citizens’ Organizations of BC, Active Support Against Poverty, Disability Alliance BC, Tenants Resource and Advisory Centre, and Together Against Poverty Society (collectively, BCOAPO).[9]
The BCUC did not receive any letters of comment in this proceeding.
1.2 Legal and Regulatory Framework
Section 44.2(1)(b) of the UCA provides that a public utility may file an expenditure schedule with the BCUC containing a statement of capital expenditures the public utility has made or anticipates making during the period addressed by the schedule. The BCUC must accept an expenditure schedule filed under section 44.2 of the UCA if the BCUC considers that making the expenditures referred to in the schedule would be in the public interest. The BCUC may also accept or reject part of an expenditure schedule.[10]
Section 44.2(5.1) of the UCA provides that in considering whether to accept an expenditure schedule filed by
BC Hydro, the BCUC, in addition to considering the interests of persons in British Columbia who receive or may receive service from BC Hydro, must consider:
a) British Columbia’s energy objectives, as provided in section 2 of the Clean Energy Act,
b) the most recent of the following documents:
i. an integrated resource plan approved under section 4 of the Clean Energy Act before the repeal of that section;
ii. a long-term resource plan filed by BC Hydro under section 44.1 of the UCA,
c) the extent to which the schedule is consistent with the requirements under section 19 of the Clean Energy Act, and
d) if the schedule includes expenditures on demand-side measures, the extent to which the demand-side measures are cost-effective within the meaning prescribed by regulation, if any.
1.2.1 Applicable Guidelines
Under BC Hydro’s Capital Filing Guidelines, BC Hydro has committed to filing applications under section 44.2 of the UCA for capital projects meeting certain financial thresholds. These guidelines commit BC Hydro to filing applications under section 44.2 of the UCA for information technology projects that exceed $50 million.[11]
BC Hydro states that it has endeavoured to meet the requirements of the BCUC’s 2015 Certificate of Public Convenience and Necessity (CPCN) Guidelines despite this being an expenditure schedule application under section 44.2 of the UCA.[12] The BCUC’s CPCN Guidelines provide general guidance regarding the information that should be included in a CPCN application and the flexibility for an application to reflect the specific circumstances of the applicant, the size and nature of the project and the issues raised by the application.[13]
1.3 Decision Framework
The structure of this decision follows the general framework of the BCUC’s CPCN Guidelines:[14]
• Section 2.0 provides background on BC Hydro’s distribution design systems;
• Section 3.0 considers the need and justification for the Project;
• Section 4.0 addresses the alternatives for the Project;
• Section 5.0 discusses the Project description, including the scope, schedule, benefits and risks of the Project;
• Section 6.0 reviews the estimated cost of the Project and bill impact;
• Section 7.0 examines First Nations consultation and public engagement for the Project;
• Section 8.0 addresses the Project’s alignment with British Columbia’s energy objectives, BC Hydro’s long term resource plan and the Clean Energy Act;
• Section 9.0 sets out the overall determination for the Project; and
• Section 10.0 sets out the reporting requirements for the Project.
2.0 BC Hydro’s Distribution Design Systems
This section provides an overview of BC Hydro's distribution design process and systems and context for the Project.
BC Hydro explains that in 2008, it initiated a strategy to adopt SAP as its default enterprise resource planning (ERP) solution and consolidate all core business processes into a single ERP system. BC Hydro established the ERP program in January 2022 to provide oversight and to coordinate activities of various projects required to modernize BC Hydro’s ERP and EAM software systems (ERP Program).[15] The Project is the third project within the ERP Program for which BC Hydro is seeking BCUC acceptance of the expenditure schedule; in February 2025, the BCUC accepted the expenditure schedules for the S/4 HANA project and the stations project.[16]
Distribution design is the process of planning, designing and managing projects to add, modify, replace or retire assets involved in the distribution of electricity.[17] Distribution design projects are initiated as work requests and refer to work executed through the distribution design business process.[18] The creation and retirement of assets involve the distribution design process and the maintenance of assets engages the distribution asset management process.[19]
BC Hydro states that it receives more than 50,000 distribution work requests each year, of which 30 percent relates to complex distribution design projects. BC Hydro states that it completed approximately 14,400 design projects through the distribution design process in fiscal 2025. The design work for these projects can be performed by BC Hydro resources or by external service providers such as third-party engineering firms.[20]
BC Hydro relies on a number of software applications to support its distribution design and distribution asset management processes, including commercial software packages such as PassPort, SAP, AutoCAD, and GE Smallworld and custom-built applications such as DAD, Spatial Asset Management, Street Lighting Information Management, Joint Use Administration System, Gateway, Design Hub, the MDTS database, and the custom-built extension to PassPort, CCC. The diagram below provides an overview of the applications that BC Hydro uses in its distribution design and distribution asset management processes currently, which will change if this Project is implemented.[21]
Figure 1: Applications in BC Hydro’s Distribution Design Current Systems
Software applications that are subject to replacement as part of the Project scope are noted below:
• PassPort – software that supports the management of BC Hydro’s station, substation and transmission line assets. For distribution design projects, PassPort is used for compatible unit estimating and for planning the labour, materials and services required to execute design projects;[22]
• DAD – a custom-built application that is used to design changes to the distribution system. It uses the geospatial mapping components of GE Smallworld and captures asset information about BC Hydro’s distribution system such as the location of these assets and how they are connected from the substation to the customer;[23]
• Gateway – a custom-built application that initiates work requests and distribution design projects in PassPort, including new customer connections and system extensions;[24]
• CCC – a custom-built extension to PassPort used to calculate the overall estimated cost of a design, including the amount a customer must contribute per BC Hydro’s Electric Tariff.[25] BC Hydro states there are no commercially available alternatives for CCC as this extension uses tariff rules and Distribution Extension Policy requirements that are specific to BC Hydro; and[26]
• MDTS – BC Hydro uses the MDTS as a database to track and report on end-of-life replacements of distribution equipment.[27]
BC Hydro states the Project will not only align with BC Hydro’s strategy to adopt SAP as BC Hydro’s default ERP solution but will also help upgrade and integrate BC Hydro’s core business processes within SAP, ensuring a cohesive and efficient IT environment.[28]
3.0 Project Need
This section outlines the need for the Project and discusses the deficiencies and capability gaps in the current distribution design system.
BC Hydro states that its distribution design applications, specifically PassPort, DAD, Gateway, the MDTS and the CCC, were first implemented more than 20 years ago. These design applications are no longer able to effectively support the growing volume and complexity of work requests as BC Hydro continues to expand its distribution network. BC Hydro states that the Project is needed to address the obsolescence and fragmentation of the following distribution design applications:
• The current version of PassPort, Asset Suite 8, is beyond end-of-life and the vendor will not support it after 2026.[29] The lack of vendor support prevents BC Hydro from applying necessary updates to other operating systems and databases as these updates would be incompatible with the current version of PassPort. The inability to receive necessary updates may cause frequent system outages, leaving BC Hydro vulnerable to cybersecurity threats such as ransomware attacks and data breaches.[30]
• DAD software is obsolete because it lacks the required functionalities found in modern design software. As DAD does not include all required built-in engineering calculators and does not integrate with widely used software such as AutoCAD, engineering calculations and designs are completed manually, resulting in increased project delivery times, greater workload and higher potential for errors and inconsistencies. Further, additional reliance on custom developments in DAD inhibits BC Hydro’s ability to readily adapt to new industry standards, regulatory changes, or technological advancements.[31]
• Gateway is obsolete as it no longer supports BC Hydro’s current operational requirements. BC Hydro submits it is challenging to update and maintain Gateway to meet new industry standards, regulatory changes, or cybersecurity requirements due to its proprietary source code, which requires specialized knowledge that is increasingly difficult to source as technology evolves.[32]
• The CCC is obsolete as it no longer meets BC Hydro’s current needs and is difficult to modify.[33] In the event of a change to regulatory policy or business rules, BC Hydro’s IT team reprograms the CCC, which has become increasingly difficult due to increased risk of system failure and the team’s limited familiarity with legacy code that was developed 20 years ago.[34]
• The MDTS was developed 20 years ago and is considered obsolete and fragmented because it has limited scalability, increased cybersecurity risks and lacks vendor support.[35]
BC Hydro states that these distribution design applications lack the capability necessary to manage the future demands of electrification and customer connections.[36] For example, BC Hydro reports a 45 percent increase in demand for design hours and a 65 percent increase in distribution capital spending from 2019 to 2025.[37] It cites increasing volume of customer work requests, system capacity and reliability investments, end-of-life asset replacements, higher economic activity and population growth as some of the drivers for the growth in design hours and capital spend.[38] It forecasts the growth trend to continue up to 2035 for both hours and spend resulting in an overall 74 percent increase in hours and a 105 percent increase in spend compared to 2019.[39]
BC Hydro notes that customers are increasingly requesting improvements to BC Hydro’s distribution connection process, which is being impacted in part by the reliance on fragmented and obsolete technology supporting distribution design functions.[40] BC Hydro gathered feedback from its customers and external stakeholders, which identified the following areas for improvement in BC Hydro’s distribution and customer connections process: (i) reducing connection timelines; (ii) enhancing communication throughout the Project’s lifecycle; (iii) ensuring consistency in the end-to-end process; and (iv) improving customer service responsiveness.[41]
As a result, BC Hydro states that the key objectives of the Project are to: (i) reduce fragmentation of the information technology systems,[42] and (ii) address the following four capability gaps identified in the distribution design system that impact operational efficiency, costs to deliver distribution projects and customer satisfaction[43]:
• Capability Gap 1 – Limitations of DAD, BC Hydro’s design application: The lack of integration between DAD and AutoCAD results in duplicative work, leading to increased costs and operational inefficiencies.
• Capability Gap 2 – Inefficiencies and risks due to system fragmentation and lack of integration: The fragmentation across PassPort, DAD, Gateway, CCC, MDTS, SAP and AutoCAD software applications creates inefficiencies in BC Hydro’s design processes.
• Capability Gap 3 – Inefficiencies in customer cost estimation and service request management: Systems and processes used to manage service requests and cost estimation are outdated and fragmented, resulting in inefficiencies and inaccuracies.
• Capability Gap 4 – Cost and productivity challenge for external service providers (ESPs) due to use of outdated and fragmented systems: BC Hydro relies on ESPs to complete a portion of the distribution design work. Its use of custom-built, proprietary systems lowers the productivity of ESPs as they commonly have a high turnover rate and require significant effort in training their new employees.
Positions of the Parties
BCOAPO agrees that the capability gaps that BC Hydro has identified need to be addressed.[44]
The CEC states it has heard from BC Hydro’s commercial sector ratepayers about the need for much greater attention to distribution system design and timeliness for the connections processes. Consequently, the CEC supports the Project and submits that BC Hydro has provided adequate rationale and supporting evidence to justify the Project.[45]
RCIA states that the Project appears justified to address service gaps and replace aging systems.[46] It accepts there is broad consensus on the need and urgency of the Project.[47]
Panel Determination
The Panel finds that BC Hydro has established the need to modernize its distribution design system, much of which is more than 20 years old. The evidence establishes that BC Hydro’s systems are obsolete and fragmented and rely on custom-built applications to address their limitations. The Panel notes that the vendor of PassPort will not support the current version of its software after 2026. The Panel accepts that operating without vendor support is not an option and that BC Hydro must address this issue.
We are satisfied that BC Hydro has demonstrated that DAD no longer meets BC Hydro’s distribution design needs and that the workarounds developed to address this limitation are inefficient and lead to increased risk of errors. In addition, we accept that the obsolescence and fragmentation among BC Hydro’s other systems, namely PassPort, Gateway, the CCC and the MDTS, are contributing to increased costs and risk as well as operational inefficiencies.
The Panel notes that none of the interveners dispute the need for the Project.
4.0 Project Alternatives
In evaluating alternatives, BC Hydro completed two assessments:
1. Alternatives to address the obsolete and custom-built DAD software; and
2. Alternatives to modernize PassPort, Gateway, CCC, and MDTS.
BC Hydro explains that it conducted separate assessments because the replacement of DAD is functionally distinct from the modernization of the broader suite of enterprise systems.[48]
4.1 Description of Alternatives
For addressing the issues with DAD, BC Hydro assessed three alternatives:[49]
• Alternative 1 – maintaining the status quo.
• Alternative 2 – enhancing DAD by custom-developing new functionalities to provide the capabilities of a modern graphical design system.
• Alternative 3 (the preferred alternative) – replacing DAD with a commercially available graphical design product.
For modernizing PassPort, Gateway, CCC, and MDTS applications, BC Hydro evaluated three alternatives:
• Alternative 1 – Upgrade PassPort from Asset Suite 8 to a vendor-supported version, Asset Suite 9, keep Gateway, CCC, and MDTS as-is, and retain the existing process (technical upgrade only). This upgrade would provide vendor support and mitigate the risks associated with the obsolescence of PassPort.[50]
• Alternative 2 – Reimplement a vendor-supported version of PassPort that replaces Gateway and MDTS, redevelop CCC as a new custom-built extension, and redesign the process (PassPort reimplementation with process redesign).[51]
Similar to Alternative 1, PassPort would be upgraded to Asset Suite 9. BC Hydro assumes the upgraded PassPort would provide functionality to replace Gateway. The CCC extension would be rebuilt with an updated custom-built CCC extension, and MDTS would be replaced by standard PassPort EAM capabilities.[52]
• Alternative 3 (the preferred alternative) – Replace PassPort, Gateway, and MDTS with SAP EAM, replace CCC with a new custom-built SAP extension, and redesign the process (SAP EAM implementation with process redesign).
Under this alternative, BC Hydro would also update the business process for managing distribution design to align with the capabilities of the new software.[53]
4.2 Project Alternatives Evaluation
4.2.1 Alternatives to Address the Obsolete DAD Application
BC Hydro states that Alternative 1, maintaining the status quo of DAD, is not a viable alternative due to its lack of integration with industry-standard tools and missing critical functionality. These limitations would reduce efficiency, increase the risk of errors, and prevent BC Hydro from meeting evolving distribution work demands.[54]
Similarly, Alternative 2, enhancing DAD, is also not viable. BC Hydro notes that DAD is now far surpassed by modern graphical design products and upgrading it to meet industry standards would require significant investment. In addition, BC Hydro lacks the internal expertise to perform such an upgrade and would face high costs and risks in maintaining a highly customized system.[55]
As a result, BC Hydro concluded that the only viable alternative is Alternative 3, replacing DAD with a commercially available graphical design product that aligns with industry best practices and is widely used by other utilities.[56]
4.2.2 Alternatives to Modernize PassPort, Gateway, CCC, and MDTS
BC Hydro states that Alternative 1, which is a technical upgrade only, is not viable because it would not address system fragmentation or close the capability gaps, which are the two key objectives of the Project.[57] BC Hydro considered the remaining two alternatives, PassPort reimplementation with process redesign or SAP EAM implementation with process redesign, to be viable alternatives.
BC Hydro applied a structured decision-making process using five criteria to compare the two viable alternatives, as shown in Table 1, below. BC Hydro observes that although both alternatives fully address the first criteria, addressing the risks and challenges of obsolete and custom-built applications, Alternative 3 outperforms Alternative 2 on four of the five criteria. BC Hydro submits that the results of the structured decision-making process show that Alternative 3 is the preferred alternative.[58]
Table 1: Structured Decision Making of the Alternatives[59]
To support its conclusion, and with reference to the criteria listed in Table 1 above, BC Hydro observes that Alternative 3 fully closes the capability gaps and creates an effective foundation for future investments in advanced asset management business capabilities.[60] In addition, BC Hydro notes that the degree of Project risk for Alternative 3 is lower than for Alternative 2 (‘high’, versus ‘high to very high’) because it does not require the development of complex interfaces with another ERP system, which simplifies implementation and results in comparatively lower risk.[61]
BC Hydro compared the net present value (NPV) of discounted cash flows of the estimated Project implementation costs, ongoing costs and savings as the fifth criteria in the structured decision-making process.[62] The NPV informs the selection of the most economically viable alternative and incorporates a range of quantitative benefits that would be delivered under Alternatives 2 and 3, such as cost savings, productivity improvements, and operational efficiencies.[63] BC Hydro calculates the NPV by assessing risks that could impact BC Hydro’s ability to achieve each benefit and uses a conservative set of assumptions to define low-range benefit performance and an optimistic set of assumptions for high-range benefit performance.[64]
BC Hydro calculated the 10-year NPV for Alternatives 2 and 3 using Association for the Advancement of Cost Engineering (AACE) International Class 5 cost estimates under the following three scenarios:[65]
• Mid-range estimated costs/mid-range estimated benefits (i.e., the expected scenario);
• High-range estimated costs/low-range estimated benefits (i.e., the worst-case scenario); and
• Low-range estimated costs/high-range estimated benefits (i.e., the best-case scenario).
The following table summarizes the NPV of discounted cash flows for Alternatives 2 and 3 under each of the three scenarios.
Table 2: NPV of Discounted Cash Flows of the Two Viable Alternatives[66]
As shown in Table 2 above, Alternative 2 has a lower NPV than Alternative 3 in each scenario due to the additional costs of maintaining complex interfaces and the need to continue to run and support PassPort.
BC Hydro states the cost of reimplementing PassPort is higher than implementing an SAP-based EAM system primarily due to the need to design, develop, implement and sustain complex interfaces, which is often one of the more complicated and costly components of large IT projects.[67]
BC Hydro also notes that the benefits under Alternative 2 are reduced because distribution design workflow will remain split across multiple applications, reducing efficiency gains from the new technology. Ongoing support for PassPort and CCC as on-premises applications would also reduce potential cost savings from retiring legacy systems.[68]
BC Hydro states that it estimated the mid-range implementation cost for Alternative 2 by applying a 20 percent increase to the implementation cost of Alternative 3.[69] It submits that this adjustment is reasonable given the additional complexity and effort required to develop a custom interface between PassPort and SAP, which is one of the most complex and resource-intensive elements of technology projects. The 20 percent adjustment is consistent with BC Hydro’s experience with similar projects involving complex interfaces, including the Stations project, where it applied comparable adjustments to non-SAP alternatives that required PassPort-SAP integration.[70]
BC Hydro concludes that Alternative 3, which implements an SAP-based EAM system, is the preferred alternative. BC Hydro states that Alternative 3 delivers a stronger NPV, fully mitigates the risks associated with outdated, fragmented, and custom-built applications through full vendor support, and fully closes the identified capability gaps. Alternative 3 also enables operational improvements, supports future investments in advanced asset management, and simplifies BC Hydro’s distribution design technology landscape.[71]
Positions of the Parties
Interveners had the following comments on the first assessment that BC Hydro conducted to evaluate the three alternatives to address the obsolete and custom-built DAD software.
BCOAPO states that it agrees with BC Hydro’s assessment that the only viable alternative for addressing DAD’s issues is to replace DAD with a commercially available graphical design product.[72]
The CEC accepts that neither Alternative 1 nor Alternative 2 is an appropriate option.[73]
RCIA agrees that maintaining the status quo does not appear viable due to significant capability gaps such as system fragmentation and the limits of legacy DAD functionality.[74]
Interveners had the following comments on the second assessment that BC Hydro conducted to evaluate the three alternatives to modernize PassPort, Gateway, CCC, and MDTS.
BCOAPO states that it agrees with BC Hydro’s overall assessment that Alternative 3 is the preferred alternative. However, BCOAPO also states that since Alternative 1 might be technically possible, the fact that it does not resolve the fragmentation issues does not make it non-viable, and therefore it submits that BC Hydro should have included this alternative in the structured decision-making assessment.[75]
The CEC states that it agrees that Alternative 3 is the preferred option.[76]
RCIA accepts that the obsolescence of existing systems, limited support, duplication in processes and overall deficiencies justify the selection of Alternative 3 in this instance.[77] However, RCIA is concerned with BC Hydro’s approach to the assessment of Project alternatives.[78] It argues that BC Hydro should have evaluated all alternatives, including the status quo, because without understanding the relative costs, risks, and other impacts associated with each option, it is not possible to weigh and balance each alternative. The fact that BC Hydro deemed Alternative 1 as not viable, RCIA submits, does not remove the need to quantify key sustainment risks associated with each alternative.[79]
RCIA recommends BC Hydro conduct a sensitivity analysis to quantify the NPV of all alternatives, including Alternative 1, by modeling sustainment risks, such as maintenance costs, cybersecurity contingencies, and compatibility-related fixes. Further, RCIA submits that any assessment of project alternatives should always include consideration of the status quo, including identification and quantification of risks,[80] and therefore RCIA recommends that the BCUC direct BC Hydro, for future projects, to provide a qualitative and quantitative analysis of the costs, risks, and benefits of all project alternatives, including the status quo, to ensure accurate benchmarking of value.[81]
In reply, BC Hydro submits that it would have been imprudent for BC Hydro to commit resources to evaluate alternatives that were not feasible or clearly inferior, including RCIA’s suggested NPV analysis for non-feasible alternatives. Instead, BC Hydro describes its approach as consistent with the BCUC’s CPCN Guidelines, namely to “identify alternatives that it deemed to be not feasible at an early screening stage and provide the reason(s) why it did not consider them further.”[82]
Panel Determination
The Panel finds that replacing DAD with a commercially available graphical design product, BC Hydro’s preferred alternative in the first assessment, is the only option that addresses the limitations of the DAD system. The Panel accepts BC Hydro’s assessment that this approach aligns with industry best practices. Moreover, we accept that the size and complexity of BC Hydro’s operations require an updated industry standard design system.
The Panel also finds that SAP EAM implementation with process redesign, BC Hydro’s preferred alternative for modernizing PassPort, Gateway, CCC and MDTS, is the best option. We are satisfied that BC Hydro, using a structured decision-making process, has appropriately identified and evaluated the various alternatives to address the identified need. The Panel considers that BC Hydro’s evaluation of the two viable alternatives using five criteria reasonably supports its conclusion that Alternative 3 offers the best alignment with BC Hydro’s
long-term strategy, provides a scalable foundation for future investments and fully closes the capability gaps.
The Panel accepts that Alternative 3 has a lower NPV of implementation costs than Alternative 2 due to Alternative 2’s higher implementation and ongoing support costs, driven by the increased complexity involved in developing and sustaining complex integrations between the EAM system and the ERP system. Although the alternatives analysis shows that Alternative 3 delivers a better NPV, the Panel notes that the quantification of benefits has many subjective elements and therefore places less weight on the benefits estimate.
The Panel does not accept RCIA’s suggestion that an assessment of project alternatives should always include identification and quantification of risks of maintaining the status quo even if the status quo is not a viable alternative. Such an analysis would not have been a good use of BC Hydro resources in this case. The BCUC’s CPCN Guidelines only require a comparison of the costs, benefits, risks etc. of the feasible alternatives. As such, the Panel considers that a direction to include all alternatives (including those deemed non-feasible) in a quantitative/qualitative analysis would not be aligned with the guidelines.
5.0 Project Description
The following sections outline the scope, schedule, benefits, risks and risk management of the Project.
5.1 Project Scope
The Project comprises the following three main scope elements, which BC Hydro notes are interrelated and will be performed concurrently:[83]
1. Replacement of the following existing systems: (i) Gateway, PassPort and the MDTS applications with a consolidated SAP EAM system, (ii) the CCC application with a new custom-built extension in SAP, and (iii) the DAD software with the AutoCAD based Automated Utility Design (AUD) software;
2. Design and implementation of new business processes based on the capabilities and industry best practices of the new information technology; and
3. Migration of data, such as in-flight work requests and distribution design projects to the new information technology.
BC Hydro states it will use the standard processes enabled by SAP and AUD to develop and implement new business processes to cover a range of distribution design functions, including managing service requests, scope changes to design projects, project estimates and customer contribution calculations.[84] BC Hydro has engaged Accenture as its systems integrator for the Project to determine how best to align any new business processes to SAP and AUD while fulfilling BC Hydro’s business requirements.[85]
BC Hydro confirms that the standard AUD processes fully meet BC Hydro’s business requirements. BC Hydro states it has identified only one gap where the standard SAP processes do not fully meet BC Hydro’s business requirements. This gap relates to the calculation of customer contributions, which reflect BC Hydro-specific tariff and extension policy requirements.[86] These requirements are embedded within the CCC extension, which requires customization to meet BC Hydro’s specific needs.[87]
BC Hydro states it is preparing the functional specifications for the CCC[88] and has included costs to develop the CCC extension in the expected cost estimate for the Project.[89] BC Hydro states that it may need additional customizations if it identifies new business requirements, in which case it will manage the need through the Project’s change control process with changes approved only for new requirements deemed high priority and feasible within the Project schedule and budget.[90]
5.2 Project Schedule
BC Hydro provides the following schedule of major milestones and key activities for the implementation phase of the Project:
Table 3: Project Key Implementation Phase Milestones and Activities[91]
The Project’s committed in-service date of February 2027 and committed completion date of September 2027 include a six-month schedule contingency to cover changes that are within BC Hydro’s control (e.g., additional time for testing the updated software).[92]
BC Hydro asserts that the Project schedule is reasonable, and delaying the Project would prevent it from addressing the challenges facing BC Hydro’s distribution design systems.[93]
5.3 Project Benefits
BC Hydro states that by modernizing its aging distribution design systems, the Project will deliver benefits – both qualitative as well as quantitative – through efficiency gains, cost reductions, risk mitigation and business improvements.[94]
BC Hydro states the qualitative benefits relate to reducing risks in current information technology and design processes and represent areas where the Project might deliver additional value beyond monetary savings. Some qualitative benefits include reduction in business continuity risk, enhanced ability to adjust to changing requirements, improved attraction and retention of employees, increased employee and contractor satisfaction, reduced cycle times for customer projects, and improved data quality and reporting.[95]
BC Hydro notes, for example, that it expects the Project will reduce the timing of commencement of the detail design for service requests by streamlining the design process and ensuring that designers are assigned to projects earlier. As a result, BC Hydro will be able to reduce the time required to complete customer work, contributing to increased customer satisfaction.[96]
BC Hydro notes that the median total duration for design connections has increased from 135 days in 2022 to 202 days in 2025. In addition, BC Hydro reports that customer satisfaction metrics in 2025 indicate that 49 percent of customers are satisfied with their overall experience with the distribution connection process and that among dissatisfied customers, 63 percent cited lengthy durations from service request initiation to completion as a key factor.[97]
BC Hydro states that it expects the Project to create annual quantitative benefits ranging from $18.3 million to $25.2 million, with an expected benefit of $21.7 million. BC Hydro explains that it has assumed a full benefit realization by year 3 post “go-live”, although it anticipates that some benefits may be fully realized earlier.[98]
BC Hydro identifies 13 quantitative benefits and groups them into six categories. The table below provides a summary of the six benefit categories and the estimated range of annual savings:
Table 4: Quantitative Benefits Summary[99]
BC Hydro plans to monitor, assess and document the realization of Project benefits, the extent to which Project objectives can be achieved, and the contributing factors involved. While BC Hydro does not plan to report anticipated time savings to the BCUC, it will incorporate the impact of realized benefits into future revenue requirements applications.[100] In addition, BC Hydro states that it plans to develop annual scorecards to measure and track benefits delivery post-implementation, ensuring ongoing alignment with project objectives.[101]
BC Hydro states that it expects the Project to deliver value to BC Hydro based on its analysis of the benefits. It calculated the NPV of the Project using an AACE International Class 3 cost estimate over a 10-year asset life under nine scenarios, the results of which are summarized below in Table 5. The calculation reflects the anticipated timing of benefit realization, including a ramp-up period to account for adoption and stabilization. Under the most likely scenario (mid cost and expected benefits), BC Hydro originally forecasted the Project to generate a positive NPV of $3.8 million over a ten-year asset life.[102]
Table 5: NPV of the Project Based on Class 3
Project Cost Estimates NPV of Cash Flows ($ million)[103]
During the proceeding, however, BC Hydro noted that recent changes to its Distribution Extension Policy[104] will reduce the estimated benefit for one of the benefit categories listed in Table 4 above, “increased contributions due to improved estimating,” by approximately 25 percent. As a result, the NPV of the Project shifts from +$3.8 million to -$3.1 million under the mid-cost scenario at the expected benefit level. Nevertheless, BC Hydro confirms that this change in NPV does not impact its assessment of the need for the Project.[105]
5.4 Project Risks and Risk Management
BC Hydro states that the Project adheres to BC Hydro’s Information Technology Delivery Standard Practices to ensure effective management of scope, schedule, cost, and risk. It submits that it examined the key risks of the Project and has implemented mitigation measures to address these risks.[106] BC Hydro states that it identified material risks for the implementation phase of the Project, which it groups into the following four categories:[107]
• Business risk: risks related to the realization of benefits that are dependent upon the adoption of change within the business;
• Technology risk: risks related to the maturity of the technology;
• Project delivery risk: risks related to the delivery of the Project; and
• Readiness risk: risks related to the ability of the organization to execute the Project.
Within each risk category, BC Hydro describes individual risks, the likelihood of occurrence, the impact of the risk on the Project should it occur and mitigation plans.[108] BC Hydro assesses the overall qualitative level of risk based on combined risk likelihood and impact scores.[109]
In addition to the risk categories that it assessed for the Project, BC Hydro explains that it assesses cybersecurity risks at the enterprise level, rather than on a project-by-project basis. BC Hydro states that a major enterprise-wide cybersecurity event could affect the delivery of the Project in two key ways:[110]
• System Interruption: a significant event, such as a ransomware attack, could disrupt corporate systems and services that the Project depends on, impeding progress and potentially delaying milestones.
• Resource Constraints: In the event of a critical cybersecurity incident, key technical resources (including internal subject matter experts assigned to the Project) may be redirected to respond to the broader security incident. This diversion could result in schedule delays and increased costs.
In the event of a cybersecurity incident, BC Hydro states it will follow the procedures established in its Cybersecurity Incident Response Plan. Further, if a cybersecurity event impacts the Project schedule or budget, then BC Hydro would manage the impact through the schedule and cost contingency or Project reserve allocations.[111]
Positions of the Parties
Interveners made the following submissions regarding the Project’s scope and schedule:
BCOAPO states that it has no issues with the scope of the Project.[112] The CEC states that it finds the Project design and schedule to be acceptably planned and comprehensive.[113]
RCIA agrees that customer-driven improvements fall within the scope of the Project because delays and inconsistent service affect residential ratepayers. It also accepts the urgency of the Project, because of customer concerns about timeliness, communications and reliability.[114]
Interveners also made numerous submissions regarding benefits and risks, some of which are set out below.
BCOAPO submits that BC Hydro should be directed to provide the annual scorecards that it plans to develop to measure and track the benefits delivery of the Project post-implementation as part of its future revenue requirement applications (RRAs) and indicate how these benefits have been incorporated.[115]
In reply, BC Hydro states that a compliance filing would be more effective than BCOAPO’s proposal, as it would avoid any additional burden of reporting in future RRAs.[116]
The CEC acknowledges the qualitative benefits that BC Hydro has identified may be significant in facilitating improved decision-making and customer access to BC Hydro; it recommends that the BCUC attach moderate to significant weight to the qualitative benefits. In addition, the CEC states that it accepts BC Hydro’s estimate of $21.7 million per year regarding quantified benefits from efficiency gains and reduced costs.[117] The CEC finds a cost risk of -$3.1 million NPV to be acceptable given the expected benefits of the Project, which include significantly updated functionality for the key area of distribution design.[118]
The CEC observes that BC Hydro’s risk assessment is reasonable and appropriately considered. The CEC considers the greatest risks to be general cost overrun through scope creep and that the quantitative cost savings benefits are not achieved as planned.[119]
The CEC recommends that the BCUC direct BC Hydro to provide copies of its documentation of the Project benefits realization to the BCUC and interveners within 2.5 years of implementation.[120] The CEC submits that accurate benefits assessment, testing, and monitoring is critical to the proper management of the utility and should be routinely documented in follow-up reporting in order to ensure that future projects are appropriately assessed.[121]
In reply, BC Hydro submits that while it has proposed robust reporting for the Project, it is not opposed to providing additional reporting on benefits realization.[122] If the BCUC directs BC Hydro to provide a benefit realization report, BC Hydro submits that the report should be required within three years after the Project’s
go-live date. Based on the Project schedule, BC Hydro would file the report in early 2030, which would allow enough time for anticipated cost savings to be realized and assessed given that BC Hydro’s conservative estimate includes a ramp-up of benefits within year 2 post go-live. BC Hydro anticipates that benefits realization reporting may need to be provided on a confidential basis, consistent with the rationale for confidential treatment of the Project benefits provided as Appendix C to the Application.[123]
RCIA acknowledges that BC Hydro has identified that it may need additional customization for the CCC application if it identifies new business requirements, in which case it will manage the need through the Project’s change control process. However, RCIA notes the lack of information regarding how many high-priority changes can be absorbed before milestones or benefit realization are affected. It states that without reporting on the volume and impact of change requests, stakeholders cannot assess cumulative schedule pressure.[124] RCIA proposes that BC Hydro’s annual progress reports include a cumulative summary of CCC-related change requests, detailing their assessed priority and impact on Project scope. RCIA further recommends any change request resulting in a material reduction in functionality or a delay to benefit realization be reported through the material change reporting framework, rather than be deferred to the annual filing.[125]
In reply, BC Hydro submits RCIA’s proposed reporting on CCC-related changes is redundant and should be rejected. It states that such changes will either be included in the annual progress reports, if noteworthy, or in a material change report if material.[126]
RCIA outlines its concerns with BC Hydro’s risk management and benefits realization. It states that “while BC Hydro’s project management framework and processes for technological projects appear extensive, RCIA is concerned that the qualitative risks are documented but not quantitatively modeled.”[127] RCIA notes that although BC Hydro identifies factors – qualitative risks – that could impede the realization of qualitative benefits,
BC Hydro does not incorporate these factors in its NPV analyses. This omission, RCIA submits, means that the Project’s NPV may be overstated and leads to uncertainty about the speed and reliability of benefit realization.[128]
RCIA acknowledges that while BC Hydro plans to measure benefits internally, it does not commit to external Key Performance Indicators (KPIs) associated with the expected benefits. RCIA recommends approval of the Project expenditure schedule be conditional upon BC Hydro defining and reporting on a focused set of post-implementation KPIs tied to key quantified benefit drivers including Geographic Information System (GIS) error reduction, connection-cycle-time, customer satisfaction, time-to-invoice and cyber readiness.[129]
In reply, BC Hydro submits that such a requirement is redundant because it intends to develop annual scorecards to measure and track benefits delivery post-implementation, ensuring ongoing alignment with project objectives. Accordingly, BC Hydro submits that there is no need to direct the development of additional KPIs. BC Hydro is not opposed to providing a post-implementation report on Project benefits realization.[130]
RCIA acknowledges BC Hydro’s approach to treating cybersecurity risks at an enterprise-level but notes that a significant cyber incident during cutover could delay the realization of Project benefits. RCIA recommends that BC Hydro report any cyber incidents materially impacting Project milestones within the 30-day material change reporting framework.[131]
In reply, BC Hydro states that RCIA’s proposed cybersecurity incident reporting is redundant because such incidents would already be reported under BC Hydro’s proposed material change reporting framework.[132]
Panel Determination
The Panel finds that the scope and schedule of the Project are appropriate and meet the stated needs and objectives of the Project. We are persuaded that BC Hydro should not delay the Project because of the urgency of addressing current system limitations and the forecast increase in distribution design work.
The Panel acknowledges the thoughtful submissions from all parties regarding the benefits and risks associated with the Project, as well as how BC Hydro proposes to report post-implementation on the benefits realization of the Project.
The Panel is satisfied that BC Hydro has appropriately considered Project risks and risk management. We consider that BC Hydro has methodically assessed the likelihood of a risk occurring as well as the impact of a risk on the Project should one occur, and its process to mitigate risks during Project execution is reasonable.
The Panel finds that monitoring and documenting the Project’s quantitative benefits will be valuable for evaluating the accuracy of BC Hydro’s forecast of benefits and will help inform the use of the same methodology in future technology projects. Filing a benefits realization report three years after the Project go-live date will allow BC Hydro sufficient time to realize and assess anticipated cost savings. We consider a compliance filing report to be more efficient than adding another report to the already extensive RRA review process.
Accordingly, the Panel directs BC Hydro to file a benefits realization report with the BCUC within three years of the Project in-service date, which must include an assessment of the realization of the Project benefits and the extent to which the Project achieved its objectives. Although BC Hydro anticipates that it may need to file this report confidentially, the Panel declines to make such a direction regarding confidentiality at this time. BC Hydro can address this matter when it files the report.
The Panel does not accept RCIA’s recommendation for the BCUC to conditionally approve the Project pending BC Hydro's definition and reporting on post implementation Project KPIs. The UCA does not permit conditional approval of an expenditure schedule; section 44.2 of the UCA requires the BCUC to accept or reject the expenditure schedule, or a part of a schedule. While noting RCIA's concerns regarding the risk of benefit realization, the Panel is persuaded that BC Hydro will appropriately track benefit realization, such as through its annual scorecards.
In addition, the Panel considers that the KPIs recommended by RCIA may be impacted by other actions that
BC Hydro could take outside of the Project, for example, hiring more designers, and therefore the KPIs may not directly correlate with the benefits from the Project implementation. The Panel finds that BC Hydro’s proposed documentation of the Project quantitative benefits will provide a more direct correlation between the Project implementation and the actual benefits achieved.
The Panel does not accept RCIA’s recommendation to require additional reporting from BC Hydro regarding cyber incidents and CCC scope changes. The Panel considers that should a cyber incident or a change to the CCC result in a significant impact to the Project schedule, cost or scope, BC Hydro will report on these matters through the material change reporting framework.
Lastly, we observe that BC Hydro’s statement that it could charge costs of realized cybersecurity risks to its Project reserve allocations appear misaligned with evidence from the Application, which identifies that Project reserve allocations are for unknown risks or for a particular discrete risk. Since cybersecurity is not a discrete or an unknown risk, the Panel considers that any costs associated with the realization of a cybersecurity risk would not be charged to the Project reserve.
6.0 Project Costs and Bill Impact
6.1 Project Costs
BC Hydro states that the Project has an estimated cost range of $81.1 million to $104.6 million. This range is based on an expected cost estimate of $88.1 million, applying an estimating accuracy of +15% / -10%, and an authorized cost estimate of $104.6 million.[133] The expected cost estimate is based on definition phase designs and the planned scope and schedule of Project activities, and aligns with an AACE International Class 3 cost estimate. The assigned estimating accuracy range reflects professional judgment, taking into account the level of design completion to date.[134]
Table 6 summarizes the breakdown of the expected and authorized cost estimates for the Project.
Table 6: Authorized and Expected Cost Estimates ($ million)[135]
|
Cost Components |
Capital Cost |
Cloud Operating Cost |
Operating Cost |
Dismantling Cost |
Total Cost |
|
Expected Cost Estimate |
$42.1 |
$32.5 |
$13.4 |
$0.02 |
$88.1 |
|
Total Project Reserve |
$9.1 |
$6.2 |
$1.2 |
$0.0 |
$16.5 |
|
Authorized Cost Estimate |
$51.2 |
$38.7 |
$14.6 |
$0.02 |
$104.6 |
BC Hydro explains that the expected cost estimate includes costs for the identification, definition and implementation phases.[136] In addition, it includes a contingency allowance calculated as 15 percent of total implementation phase direct costs, consistent with BC Hydro’s standard practice for technology projects. The contingency covers costs that cannot be specifically identified at the time of estimation but are reasonably expected to arise. The Project’s steering committee must approve any expense from the contingency allowance.[137]
BC Hydro states that the authorized cost estimate is calculated as the sum of the expected cost estimate and a total Project reserve. The purpose of the total Project reserve is to address cost risks associated with the Project that are not reflected in the expected cost estimate. Access to this reserve requires additional financial approval from BC Hydro’s President and CEO.[138]
The cloud operating costs listed in Table 6 above relate to one time implementation costs and ongoing annual usage fees for cloud-based services. Cloud computing enables on demand, fee for use access to shared IT resources without BC Hydro owning or directly managing the underlying infrastructure. BC Hydro explains that it treats the cloud expenditures as capital costs to ensure consistency with how the BCUC would have reviewed the Project if delivered under BC Hydro’s traditional, utility owned computing model. [139]
BC Hydro states that it expects the Project to result in net ongoing incremental support costs for the distribution design systems of approximately $72.9 million over a ten-year period.[140]
6.2 Bill Impact
BC Hydro states that under both the expected cost estimate and the authorized cost estimate, its revenue requirements increase initially in fiscal 2026 during Project implementation, driven primarily by operating costs such as data migration and change management. Revenue requirements increase further in fiscal 2027 as the Project is placed into service and cost recovery from ratepayers begins.[141]
Under the expected cost estimate, the increase in revenue requirements peak in fiscal 2028 at approximately $17.7 million, representing a 0.29 percent cumulative incremental bill impact, which is the first fiscal year in which a full year of Project costs are recovered. Under the authorized cost estimate, the peak increase in fiscal 2028 is approximately $19.7 million, corresponding to a 0.32 percent cumulative incremental bill impact.[142]
After fiscal 2028, BC Hydro notes that cumulative incremental bill impacts decline primarily due to lower interest costs over time, because amortization of the Cloud Cost Regulatory Account and capitalized project costs reduces outstanding debt, together with expected future capital cost savings from the Project that reduce future borrowing requirements.[143]
Positions of the Parties
BCOAPO states it has no issues with the expected or authorized costs for the Project.[144] BCOAPO does, however, comment on the cumulative bill impact analysis, which it notes BC Hydro did not update to account for the reduction in benefit savings due to the recent changes to BC Hydro’s Distribution Extension policy. Factoring in the impact of this change is likely to increase the cumulative bill impacts post-2028, and BCOAPO submits this warranted further explanation.[145]
The CEC states that it finds the cost estimate to be reasonably developed.[146] The CEC notes that it expects that the downward adjustment to the NPV analysis due to the change in Distribution Extension policy would have a corresponding impact on the bill impact analysis, given that the quantitative benefits are included in the bill impact analysis.[147]
In reply to both interveners’ comments, BC Hydro confirms that it expects the change to the Distribution Extension policy to increase the cumulative incremental bill impacts for the Project by less than 0.01% per year and asserts that this negligible change does not call into question the merits of the Project.[148]
Panel Determination
The Panel finds that BC Hydro’s cost range ($81.1 million to $104.6 million) for the Project is reasonable. The expected cost estimate, $88.1 million based on an AACE International Class 3 cost estimate, falls within the BCUC’s CPCN Guidelines’ recommended estimate class. Interveners do not raise any concerns with this, nor does the evidence indicate any reason to question the accuracy of BC Hydro’s calculations.
The Panel considers that the estimated incremental bill impact of the Project, 0.29 percent using the expected cost estimate, is reasonable. Further, we are satisfied that the change to the Distribution Extension policy has an inconsequential impact on the cumulative bill impact.
7.0 Consultation and Engagement
BC Hydro explains that since the Project uses on-site servers and does not require an expansion of BC Hydro’s physical footprint, no environmental, or socio-economic impacts arise from the Project and no First Nations consultation obligations are triggered by the implementation or ongoing operation of the Project.[149]
Positions of the Parties
None of the interveners commented on matters regarding consultation or engagement.
Panel Determination
The Panel is satisfied that there are no engagement or consultation obligations arising from the implementation of the Project because it does not require an expansion of BC Hydro’s physical footprint and has no environmental or socio-economic impact.
8.0 Provincial Government Energy Objectives, the Integrated Resource Plan and the Clean Energy Act
BC Hydro states that the BCUC must consider section 44.2 (5.1) of the UCA, except for section 44.2 (5.1) (c) as there are no prescribed targets or guidelines under section 19 of the Clean Energy Act and section 44.2 (5.1) (d) because the schedule does not contain expenditures on demand side measures.[150]
British Columbia’s Energy Objectives
BC Hydro submits that the Project supports the energy objective in section 2(f) of the Clean Energy Act to ensure its rates remain among the most competitive of rates charged by public utilities in North America, as well as the objectives in section 2(f.1) to ensure that changes to its rates are reasonably predictable and reasonably consistent from year to year and section 2(f.2) that increases to its rates do not exceed cumulative inflation.[151]
BC Hydro states that it expects to be able to manage the incremental bill impact of the Project within the cumulative inflation target. In addition, it states that it is advancing the Project to allow it to upgrade the distribution design and work management systems in a cost-effective manner.[152]
BC Hydro’s Long-Term Resource Plan
At the time of filing the Application, BC Hydro’s most recent long-term resource plan filed under section 44.1 of the UCA was its Updated 2021 Integrated Resource Plan, which the BCUC accepted in March 2024. Subsequently, BC Hydro filed its 2025 Integrated Resource Plan with the BCUC on October 31, 2025. BC Hydro submits that its 2025 Integrated Resource Plan is a long-term strategic plan to meet B.C.’s growth in electricity demand. BC Hydro states that the Project supports the plan by helping to ensure the safe and efficient operation of its power system in order to deliver energy resources to BC Hydro’s customers and enabling key business functions.[153]
Additionally, BC Hydro submits that its forecast of increasing distribution design work aligns with its 2024
10-Year Capital Plan. This plan outlines a strategic commitment of more than $5 billion and is intended to specifically connect new customers in high-growth areas.[154]
BC Hydro states it is making significant investments in its distribution infrastructure to ensure delivery of reliable electricity to homes, businesses and growing communities across the province. BC Hydro’s key investment drivers include, among other things, industrial and commercial electrification, electric vehicle infrastructure and population growth.[155] BC Hydro states the Project will meet growing demands of electrification and increased customer connections by reducing the fragmentation of the current distribution system and closing the current system’s capability gaps.[156]
Positions of the Parties
Interveners had no submissions regarding whether the Project supports BC’s energy objectives or aligns with the 2025 Integrated Resource Plan.
RCIA states that it acknowledges the broad consensus that the Project supports BC Hydro’s objectives in the plan. It submits that this consensus heightens the importance of verifying that the Project’s benefits will materialize in time to support the forecast increase in design hours and associated capital spend. Therefore, RCIA recommends approval of the Project be conditional upon BC Hydro defining and reporting on at least some of the KPIs that RCIA proposes related to IRP-relevant outcomes.[157]
Panel Determination
The Panel considers that the Project supports the energy objectives set out in the Clean Energy Act. The updates to BC Hydro’s distribution design system in a cost-effective manner will support BC Hydro in handling the increasing volume and complexity of distribution design work requests. The Panel is satisfied that BC Hydro has demonstrated that it can manage the incremental rate impact of the Project within the cumulative inflation target.
The Panel also considers that the Project supports the 2025 Integrated Resource Plan by helping to ensure the safe and efficient operation of BC Hydro’s power system to deliver energy resources to BC Hydro’s customers and to enable key business functions.
We do not accept RCIA’s recommendation that we conditionally approve the Project pending BC Hydro's definition and reporting KPIs related to IRP-relevant outcomes, primarily because the UCA does not permit conditional approval of an expenditure schedule. Additionally, we are satisfied that BC Hydro will appropriately track Project benefit realization, as discussed above in Section 5.
9.0 Overall Determination
Pursuant to section 44.2(3) of the UCA, the Panel accepts the capital expenditure schedule for the Project submitted by BC Hydro, with an authorized cost of $104.6 million. The Panel finds that making the expenditures referred to in the expenditure schedule is in the public interest. In making this determination, the Panel has examined each of the relevant considerations set out in section 44.2(5.1) of the UCA and finds that these considerations support acceptance of the expenditure schedule for the Project.
10.0 Project Reporting
In accordance with the BC Hydro 2024 Major Capital Filing Guidelines, BC Hydro proposes to report on the Project as follows:[158]
• Annual progress reports regarding the Project costs and risks within 45 days of the end of each reporting period;
• In the event of a material change[159] between annual progress reports, BC Hydro will file a material change report, within 30 days of the date on which the material change occurs or within 30 days of the appropriate authority within BC Hydro being informed of a potential material change, whichever is earlier; and
• A Project completion and evaluation report, by the earlier of one month after review by BC Hydro’s Board of Directors or 24 months after the Project in-service date.
BC Hydro proposes that the threshold for providing variance explanations be set at 30 percent for both the annual progress reports and the Project completion and evaluation report. BC Hydro acknowledges this is a change from previous variance reporting thresholds[160] and submits that this change would improve efficiency by eliminating the need to track separate thresholds or retroactively explain variances in final reporting that were not addressed in annual reporting. BC Hydro acknowledges that a 30 percent threshold may result in some large cost variances not triggering reporting but states these are generally covered by contingency funds or offset by other variances. [161]
Positions of the Parties
The CEC considers the thresholds and timing BC Hydro proposes for material change, annual progress reports and Project completion and evaluation reports to be acceptable.[162]
BCOAPO has no issue with BC Hydro’s plans regarding Project reporting or its proposed variance reporting thresholds.[163]
Panel Determination
The Panel finds it appropriate for BC Hydro to report on the Project based on a 30 percent cost variance threshold for annual reports and a 10 percent cost variance threshold for the final report, consistent with the approach used for other BC Hydro major capital projects. We consider that a standard approach to metrics such as project cost variance reporting allows for direct comparisons across the major projects on which BC Hydro reports to the BCUC. BC Hydro currently reports at 30 and 10 percent project cost variances for annual and final reports, respectively, for all of its BCUC-approved major projects. We are not persuaded that a deviation from this practice is necessary or appropriate for this Project, given its magnitude.
Having accepted the expenditure schedule for the Project, the Panel directs BC Hydro to provide reports on the Project as specified in Appendix A to this decision.
Dated at the City of Vancouver, in the Province of British Columbia, this 12th day of March 2026.
Electronically signed by Blair Lockhart
_________________________________
E. B. Lockhart
Panel Chair/Commissioner
Electronically signed by Ana Dennier
_________________________________
A. C. Dennier
Commissioner
British Columbia Hydro and Power Authority
Distribution Design Modernization Project
PROJECT REPORTING
The scope of the reporting for the duration of the Project will comprise the following:
1. Annual Progress Reports
Each report is required to detail:
• Actual costs incurred to date for the Project compared to the authorized cost estimate provided in Table 5-3 of the Application, highlighting variances with an explanation of variances greater than 30 percent for any row number or line item;
• Updated forecast of costs for the Project, highlighting the reasons for costs that are forecast to have variances greater than 30 percent for any row number or line item; and
• The status of Project risks noted in chapter 6 of the Application, highlighting the status of identified risks, changes in and additions to risks, the options available to address the risks, the actions that BC Hydro is taking to deal with the risks and the likely impact on the Project’s schedule and cost.
BC Hydro must file annual progress reports within 45 days of the end of each annual reporting period, with the first report covering the period ending March 31, 2027.
2. Material Change Reports – A material change (Material Change) is a change in BC Hydro’s plan for the project that would reasonably be expected to have a significant impact on the schedule, cost or scope, such that:
• Schedule – There is a delay in the committed forecast in-service date of February, 2027 for the Project, as outlined in Table 5-6 of the Application;
• Cost – The authorized cost is forecast to exceed the BC Hydro authorized amount of $104.6 million for the Project (as detailed in row X of Table 5-3 of the Application); or
• Scope – There are one or more changes to the project deliverables and the work required to create those deliverables or the main components of the project scope provided in section 5.2 of the Application.
In the event of a Material Change, BC Hydro must file a Material Change report with the BCUC explaining the reasons for the Material Change, BC Hydro’s consideration of the Project risk and the options available, and actions BC Hydro is taking to address the Material Change. BC Hydro must file the Material Change report within 30 days of the Material Change occurring or within 30 days of the appropriate approval authority within BC Hydro being informed of a potential material change, whichever is earlier.
3. Project Completion and Evaluation Report
A Project Completion Evaluation Report for the Project is due the earlier of one month after review by BC Hydro’s Board of Directors, or 24 months after the Project in-service date. The report is to include:
• The final cost of the Project, including a breakdown of the final costs;
• A comparison of the final costs of the Project to the estimates provided in Table 5-3 of the Application; and
• An explanation for any cost variances that exceed 10 percent for any of the Project’s cost items provided in Table 5-3 of the Application.
British Columbia Hydro and Power Authority
Distribution Design Modernization Project
LIST OF ACRONYMS
|
Acronym |
Description |
|
AACE |
Association for the Advancement of Cost Engineering |
|
Application |
Application for acceptance of a schedule of anticipated capital expenditures for the implementation of the Distribution Design Modernization project |
|
AUD |
Automated Utility Design |
|
BC Hydro |
British Columbia Hydro and Power Authority |
|
BCOAPO |
British Columbia Old Age Pensioners’ Organization, Council of Senior Citizens’ Organizations of BC, Active Support Against Poverty, Disability Alliance BC, Tenants Resource and Advisory Centre, and Together Against Poverty Society |
|
BCUC |
British Columbia Utilities Commission |
|
CCC |
Customer Contribution Calculator |
|
CPCN |
Certificate of Public Convenience and Necessity |
|
DAD |
Distribution Analysis and Design |
|
EAM |
Enterprise Asset Management |
|
ERP |
Enterprise Resource Planning |
|
ERP Program |
ERP and EAM software systems |
|
ESPs |
External Service Providers |
|
GIS |
Geographic Information System |
|
KPI |
Key Performance Indicator |
|
MDTS |
Maintenance Data Tracking System |
|
NPV |
Net Present Value |
|
Project |
Distribution Design Modernization Project |
|
RCIA |
Residential Consumer Intervener Association |
|
RRAs |
Revenue Requirement Applications |
|
The CEC |
Commercial Energy Consumers of British Columbia |
|
UCA |
Utilities Commission Act |
British Columbia Hydro and Power Authority
Distribution Design Modernization Project
EXHIBIT LIST
Exhibit No. Description
Commission documents
|
A-1 |
July 16, 2025 – Panel Appointment
|
|
A-2 |
July 25, 2025 – Order G-184-25 establishing a regulatory timetable |
|
A-3 |
August 22, 2025 – BCUC providing information to interveners regarding Information Requests |
|
A-4 |
September 5, 2025 – BCUC Information Request No. 1 to BC Hydro |
|
A-5 |
CONFIDENTIAL – September 5, 2025 – BCUC Confidential Information Request No. 1 to BC Hydro |
|
A-6 |
January 13, 2026 – BCUC letter regarding BCOAPO name change |
Applicant documents
|
B-1 |
PUBLIC – June 27, 2025 – British Columbia Hydro and Power Authority (BC Hydro) – Distribution Design Modernization Application Public
|
|
B-1-1 |
CONFIDENTIAL – June 27, 2025 – BC Hydro submitting Distribution Design Modernization Application
|
|
B-1-1-1 |
CONFIDENTIAL – October 24, 2025 – BC Hydro submitting Errata No. 1 to the Distribution Design Modernization Application
|
|
B-2 |
July 30, 2025 – BC Hydro submitting Public Notice Confirmation |
|
B-3 |
PUBLIC – October 20, 2025 – BC Hydro submitting response to BCUC Information Request No. 1
|
|
B-3-1 |
CONFIDENTIAL – October 20, 2025 – BC Hydro submitting response to BCUC Information Request No. 1
|
|
B-4 |
PUBLIC – October 20, 2025 – BC Hydro submitting response to BCUC confidential Information Request No. 1
|
|
B-4-1 |
CONFIDENTIAL – October 20, 2025 – BC Hydro submitting response to BCUC confidential Information Request No. 1
|
|
B-5 |
PUBLIC – October 20, 2025 – BC Hydro submitting response to Intervener Information Request No. 1
|
|
B-5-1 |
CONFIDENTIAL – October 20, 2025 – BC Hydro submitting response to Intervener Information Request No. 1
|
|
B-6 |
PUBLIC – October 20, 2025 – BC Hydro submitting response to confidential Intervener Information Request No. 1
|
|
B-6-1 |
CONFIDENTIAL – October 20, 2025 – BC Hydro submitting response to confidential Intervener Information Request No. 1
|
Intervener documents
|
C1-1 |
August 11, 2025 – Commercial Energy Consumers Association of BC (CEC) – Request to Intervene by David Craig |
|
C1-2 |
September 3, 2025 – CEC submitting Confidentiality Declaration and Undertaking Forms |
|
C1-3 |
PUBLIC – September 12, 2025 – CEC submitting Information Request No. 1 to BCH |
|
C1-3-1 |
CONFIDENTIAL – September 12, 2025 – CEC submitting Information Request No. 1 to BCH |
|
C2-1 |
August 11, 2025 – BC Old Age Pensioners’ Organization, Council of Senior Citizens’ Organizations of BC, Active Support Against Poverty, Disability Alliance BC, Tenants Resource and Advisory Centre, and Together Against Poverty Society (BCOAPO) – Request to Intervene by Irina Mis |
|
C2-2 |
September 12, 2025 – BCOAPO submitting Information Request No. 1 to BCH |
|
C2-3 |
January 7, 2026 – BCPIAC submission regarding BCOAPO and change to COSCO |
|
C3-1 |
August 11, 2025 – Residential Consumer Intervener Association (RCIA) – Requests to Intervene by Abdulrahman Abomazid |
|
C3-2 |
September 3, 2025 – RCIA submitting Confidentiality Declaration and Undertaking Forms |
|
C3-2-1 |
October 16, 2025 – RCIA submitting updated Confidentiality Undertaking Forms |
|
C3-3 |
September 12, 2025 – RCIA submitting Information Request No. 1 to BCH |
[1] Authorized cost is a BC Hydro term, which refers to the expected cost of the Project, plus a Project reserve.
[2] Utilities Commission Act, R.S.B.C., 1996, c. 473.
[3] Exhibit B-1, p. 1-1.
[4] Ibid., p. 2-12.
[5] Ibid., p. 3-4.
[6] Ibid., p. 3-3.
[7] Ibid., p. 5-13.
[8] Order G-184-25, dated July 25, 2025.
[9] On January 7, 2026, the BC Public Interest Advocacy Centre (BCPIAC) filed a letter in the proceeding advising that the BC Old Age Pensioners’ Organization has decided to wind down its operations. BCPIAC requested that its client list in this proceeding be modified to remove BCOAPO effective immediately and advised that its client list will now be as follows: Council of Senior Citizens’ Organizations of BC, Active Support Against Poverty, Disability Alliance BC, Tenants Resource and Advisory Centre, and Together Against Poverty Society (COSCO or COSCO et al.). For the purposes of this decision, the Panel refers to this intervener as “BCOAPO.” See Exhibit C2-3 and Exhibit A-6.
[10] UCA, section 44.2(1)(b), section 44.2(3), section 44.2(4).
[11] BC Hydro 2024 Capital Project Filing Guidelines, Section 11, p. 4.
[12] Exhibit B-1, p. 1-19.
[13] Appendix A to Order G-20-15, dated February 12, 2015, BCUC 2015 Certificate of Public Convenience and Necessity Guidelines (CPCN Guidelines), p. 1. Available at https://docs.bcuc.com/documents/Guidelines/2015/DOC_25326_G-20- 15_BCUC-2015-CPCN-Guidelines.pdf
[14] Ibid.
[15] Exhibit B-1, p. 2-15.
[16] Order G-44-25, dated February 25, 2025.
[17] Exhibit B-1, p. 1-1.
[18] Ibid., p. 2-2.
[19] Ibid., p. 2-6.
[20] Ibid., pp. 2-3 to 2-4.
[21] Ibid. p. 2-13, Figure 2-2.
[22] Exhibit B-1, p. 5-4.
[23] Ibid., p. 2-13, Table 2-1.
[24] Ibid., p. 2-14, Table 2-1.
[25] Ibid., p. 2-13, Table 2-1.
[26] Ibid., p. 4-9, footnote 3.
[27] Ibid., pp. 2-6 to 2-7.
[28] Ibid., pp. 2-15 to 2-16.
[29] Exhibit B-1, p. 1-3.
[30] Ibid., p. 3-8.
[31] Ibid., p. 3-9.
[32] Ibid., pp. 3-10 to 3-11.
[33] Ibid., p. 3-11.
[34] Exhibit B-5, CEC IR 1.5.1.
[35] Exhibit B-1, pp. 3-7 to 3-8.
[36] Ibid., pp. 3-8, 4-10.
[37] Ibid., p. 3-6.
[38] Exhibit B-4, CEC IRs 1.3.1, 1.3.3.
[39] Exhibit B-1, p. 3-6.
[40] Ibid., p. 1-1.
[41] Exhibit B-5, CEC IR 1.7.1.
[42] Exhibit B-1, p. 4-10.
[43] Ibid., pp. 3-12 to 3-22.
[44] BCOAPO Final Argument, p. 4.
[45] CEC Final Argument, pp. 4, 11.
[46] RCIA Final Argument, p. 2.
[47] Ibid., p. 19.
[48] Exhibit B-1, p. 4-1.
[49] Ibid., p. 4-3.
[50] Ibid., p. 4-5.
[51] Ibid.
[52] Exhibit B-1, p. 4-9.
[53] Ibid.
[54] Ibid., pp. 4-3 to 4-4.
[55] Ibid., p. 4-4.
[56] Ibid.
[57] Ibid., p. 4-2.
[58] Ibid., p. 4-5.
[59] Exhibit B-1, p. 4-6, Table 4-1.
[60] Ibid., p. 4-14.
[61] Ibid., p. 4-16.
[62] Ibid.
[63] Ibid., p. 4-19.
[64] Exhibit B-5, CEC IR 1.10.1.
[65] Exhibit B-1 p. 4-16.
[66] Exhibit B-1, p. 4-17, Table 4-5.
[67] Ibid., p. 4-7.
[68] Ibid., p. 4-17.
[69] Ibid., p.4-18.
[70] Exhibit B-3, BCUC IR 1.4.1.
[71] Exhibit B-1, p. 4-8.
[72] BCOAPO Final Argument, p. 8.
[73] CEC Final Argument, p. 12.
[74] RCIA Final Argument, p. 7.
[75] BCOAPO Final Argument, p. 17.
[76] CEC Final Argument, p. 14.
[77] RCIA Final Argument, p. 6.
[78] Ibid.
[79] Ibid., p. 7.
[80] Ibid.
[81] Ibid., p. 20.
[82] BC Hydro Reply Argument, pp. 6 – 7.
[83] Exhibit B-1, pp. 5-1, 5-2.
[84] Ibid., p. 5-7.
[85] Ibid., p. 5-8.
[86] Exhibit B-5, BCOAPO IR 1.19.1.
[87] Ibid., BCOAPO IR 1.3.1.
[88] Ibid.
[89] Ibid., BCOAPO IR 1.19.1.
[90] Ibid.
[91] Exhibit B-1, p. 5-23, Table 5-6.
[92] Ibid., p. 5-23.
[93] BC Hydro Final Argument, p. 47.
[94] Ibid.
[94] Exhibit B-1, p. 3-22.
[95] Exhibit B-1, pp. 3-28 to 3-30.
[96] Ibid., p. 3-30, Table 3-2.
[97] Exhibit B-5, CEC IR 1.7.1.
[98] Exhibit B-1, p. 3-23.
[99] Ibid., p. 3-24, Table 3-1.
[100] Exhibit B-5, CEC IR 1.14.1.
[101] Exhibit B-1, p. 6-5.
[102] Ibid., p. 3-31.
[103] Ibid., p. 3-31, Table 3-3.
[104] The BCUC approved amendments to the Distribution Extension Policy by Order G-59-25, dated March 5, 2025.
[105] Exhibit B-4, BCUC IR 1.1.9.
[106] BC Hydro Final Argument, p. 50.
[107] Exhibit B-1, p. 6-2.
[108] Exhibit B-1, pp. 6-5 to 6-17.
[109] Ibid., pp.6-2 to 6-4.
[110] Exhibit B-3, BCUC IR 1.8.1.
[111] Ibid., BCUC IR 1.8.1
[112] BCOAPO Final Argument, p. 18.
[113] CEC Final Argument, p. 20.
[114] RCIA Final Argument, p. 19.
[115] BCOAPO Final Argument, p. 22.
[116] BC Hydro Reply Argument, p. 14.
[117] CEC Final Argument, pp. 9 – 10.
[118] Ibid., p. 20.
[119] Ibid., p. 23.
[120] Ibid., pp. 1, 17-18.
[121] Ibid., p. 16.
[122] BC Hydro Reply Argument, p. 13.
[123] Ibid., pp. 13-14.
[124] RCIA Final Argument, p. 15.
[125] Ibid.
[126] BC Hydro Reply Argument, p. 15.
[127] RCIA Final Argument, p. 10.
[128] RCIA Final Argument, p. 11.
[129] Ibid., pp. 13-14.
[130] BC Hydro Reply Argument, p. 17.
[131] RCIA Final Argument, p. 16.
[132] BC Hydro Reply Argument, p. 17.
[133] Exhibit B-1, p. 5-13.
[134] Ibid.
[135] Ibid., p. 5-18, Table 5-3.
[136] Exhibit B-1, p. 5-14, Table 5-1.
[137] Ibid., p. 5-18.
[138] Ibid., p. 5-18 to 5-19.
[139] Ibid., p. 5-15.
[140] Ibid., p. 5-19.
[141] Ibid., pp. 5-21 to 5-22.
[142] Ibid., p. 5-22.
[143] Ibid.
[144] BCOAPO Final Argument, p. 18.
[145] BCOAPO Final Argument, p. 19.
[146] CEC Final Argument, p. 19.
[147] Ibid.
[148] BC Hydro Reply Argument, p. 12.
[149] Exhibit B-1, p. 1-9.
[150] Ibid., p. 1-17.
[151] Exhibit B-1, p. 1-16. The Panel notes that British Columbia’s energy objectives were modified by the British Columbia’s Energy Objectives Regulation, B.C. Reg. 234/2012 as amended.
[152] Ibid.
[153] BC Hydro Final Argument, p. 57.
[154] Exhibit B-5, CEC IR 1.3.3.
[155] Ibid.
[156] Exhibit B-1, p. 4-10.
[157] RCIA Final Argument, p. 19.
[158] Exhibit B-1, p. 1-18.
[159] A material change refers to a change that has a significant impact on the Project schedule, cost or scope. BC Hydro 2024 Capital Project Filing Guidelines, p. 6.
[160] The BCUC has previously set the threshold for providing variance explanations at 30 percent for annual reports and 10 percent for Project completion and evaluation reports, including for BC Hydro’s Enterprise Resource Planning projects (Order G-44-25, Appendix A), the John Hart project (Order G-107-23, Appendix A) and the Ladore project (Order G-263-24, Appendix A).
[161] Exhibit B-5, BCOAPO IR 1.4.1.
[162] CEC Final Argument, p. 17.
[163] BCOAPO Final Argument, p. 22.