Articles

BC Utilities Commission approves a significant investment in natural gas resiliency

Authors:  and * | July 2026 – Volume 14, Issue 2, 2026

On October 27, 2025, the British Columbia Utilities Commission (“BCUC”) approved[1] FortisBC Energy Inc.’s (“FEI”) Tilbury Liquefied Natural Gas Storage Expansion Project (“TLSE Project”), a significant investment in natural gas resiliency. The TLSE Project is a new $1.1 billion Liquefied Natural Gas (“LNG”) facility located in a Vancouver suburb, with two-thirds of the tank reserved for emergency supply in the event of a disruption in natural gas supply to the Vancouver Lower Mainland. The regulatory processes culminating in the BCUC’s approval of the TLSE Project offer insights into how a Canadian utility regulator has approached the issue of natural gas system resiliency in the absence of industry-wide resiliency standards. FEI’s success also illuminates a type of resiliency planning and analysis that can support a significant investment in natural gas infrastructure.

The sections that follow address: (1) the TLSE Project and its resiliency rationale; (2) the regulatory decisions and direction that helped to shape FEI’s evidence in support of the TLSE Project; and (3) aspects of the FEI’s resiliency analysis that demonstrated that the TLSE Project is in the public interest.

THE TLSE PROJECT AND ITS RESILIENCY RATIONALE

In 2020, FEI filed an application for a Certificate of Public Convenience and Necessity (“CPCN”) for its TLSE Project. The TLSE Project, as proposed, consisted of replacing a 55 year-old, 0.6 Bcf, peak shaving LNG facility in the City of Delta with a 3.0 Bcf storage tank and 800 MMcf/d of regasification capacity.[2] The new facility would provide five times the amount of LNG storage, and over five times the regasification capacity as the original facility. Peaking gas supply / peak shaving requirements represented only approximately one-third of the proposed tank and regasification capacity. FEI’s justification for the remainder of the capacity was system resiliency; two-thirds of the tank (2.0 Bcf) would be set aside as a “resiliency reserve” to be used during a supply emergency.[3] The total estimated project cost is $1.14 billion, with the incremental cost of the resiliency reserve and additional regasification representing approximately 22 per cent of this cost.[4]

The rationale for this resiliency investment was that FEI relies on Westcoast Energy Inc.’s T-South pipeline (“T-South”) for the vast majority of its winter supply of natural gas to Metro Vancouver and Vancouver Island.[5] This creates a significant supply risk for FEI. FEI’s evidence was that a total interruption of gas flows (no-flow event) on T-South of less than a day in winter months (even assuming average winter temperatures) would inevitably result in FEI losing the ability to serve Lower Mainland customers within hours.[6] Appliances and commercial and industrial equipment throughout this area would cease to function. At least 600,000 residential, commercial and industrial customers would lose gas service for weeks, primarily due to the time required to relight millions of appliances after gas flows resume on T-South.[7]

FEI’s exposure to this supply risk posed by its reliance of T-South was demonstrated in October 2018 by a two-day T-South no-flow event. An explosion near Prince George had disrupted flows on one of the two T-South pipes, and the regulator had required Westcoast to shut down its other pipe for two days as a precaution. There had been no FEI customer outages in that instance because the no-flow event occurred before the winter heating season; gas demand on FEI’s system was lower, and FEI was able to access sufficient alternative supply to offset the loss of T-South gas. Despite these favourable conditions, FEI was within hours of outages and there would be outages if the same no-flow event were to occur during the winter heating season.[8]

THE ITERATIVE PROCESS THAT CULMINATED IN FEI’S COMPREHENSIVE 2024 RESILIENCY PLAN

There is no formal resiliency planning process or framework in British Columbia for gas utilities, nor are there generic gas resiliency standards. As described below, settling on the nature of FEI’s resiliency planning and reporting was an iterative exercise that occurred over multiple regulatory processes. FEI’s second iteration of its resiliency planning, the 2024 Resiliency Plan, was a comprehensive review of vulnerabilities and included very detailed analysis.[9] The depth of analysis in FEI’s 2024 Resiliency Plan was ultimately key in the BCUC’s approval of the TLSE Project.

The October 2018 T-South no-flow event raised the profile of natural gas resiliency significantly. In early 2019, the BCUC directed FEI to report on what steps FEI was taking in response to the T-South no-flow event.[10] Then, in accepting FEI’s 2017 Long-Term Gas Resource Plan (“LTGRP”), in response to concerns raised by interveners about the 2018 T-South no-flow event, the BCUC directed FEI to address security of supply concerns in its next LTGRP. The BCUC left it to FEI to determine the content of what would become a Gas System Resiliency Plan.[11]

FEI included the first iteration of its Resiliency Plan as part of its next Resource Plan, filed on May 9, 2022 (2022 LTGRP).[12] Among other potential resiliency investments, FEI’s first iteration of its Resiliency Plan (Initial Resiliency Plan) identified the TLSE Project as a potential resiliency measure to mitigate FEI’s risk exposure to a winter no-flow event on T-South.[13] The Initial Resiliency Plan was largely a qualitative discussion of the most significant customer outage risks facing FEI and potential projects that could be proposed to mitigate those risks.

FEI filed its CPCN application for the TLSE Project on December 29, 2020,[14] while the 2022 LTGRP proceeding was still underway and before the BCUC had opined on the Initial Resiliency Plan. The TLSE Project CPCN application, like the Initial Resiliency Plan, emphasized (i) a T-South no-flow event had already occurred once, and (ii) the significant customer outage consequences from a winter no-flow event were known based on system modelling. System modelling also demonstrated that FEI’s proposed 2.0 Bcf “resiliency reserve” would provide sufficient gas in the Lower Mainland to, at minimum, support winter load for a full three days. FEI characterized the ability to bridge an upstream supply interruption for three days as a Lower Mainland-specific minimum resiliency planning objective.[15]

On March 20, 2024, the BCUC issued its decision on FEI’s 2022 Resource Plan, and directed FEI to prepare another iteration of the Resiliency Plan. The BCUC provided more specific direction to FEI about the content of the next iteration.[16] Shortly thereafter, the BCUC adjourned the regulatory proceeding for the TLSE Project CPCN (Adjournment Decision) and invited FEI to provide additional evidence, offering similar guidance as in its decision on FEI’s 2022 Resource Plan.[17]

The BCUC’s Adjournment Decision identified the following areas of interest, in particular:[18]

  • The current and future threats to the resiliency of FEI’s system in addition to the 3 day no-flow event identified in the Application supporting the TLSE Project;
  • The assets that provide resiliency in FEI’s current system, as well as the existing system resiliency gaps, supported by a quantitative risk evaluation, accounting for probability and consequences;
  • Analysis of how FEI’s planned projects would address or mitigate these resiliency gaps, including consideration of short, medium, and long term options and the associated cost of these options;
  • An assessment of the remaining life of the existing Tilbury Base Plant;
  • The impact, if any, of the loss of contracted storage on the resiliency of FEI’s system;
  • The costs and benefits of the TLSE Project relative to other alternatives that would provide fewer, equivalent or more resiliency benefits to customers; and
  • How the future demand for natural gas would impact the risk that the TLSE Project will not remain used and useful over its expected in-service life.

ELEMENTS OF FEI’S 2024 RESILIENCY PLAN THAT SUPPORTED PROJECT APPROVAL

FEI needed to retain external experts to assist with the necessary analysis, and the analysis and writing took a number of months. FEI filed supplemental evidence, including the next iteration of FEI’s Resiliency Plan (“2024 Resiliency Plan”) on October 24, 2024.[19] The 2024 Resiliency Plan was much more comprehensive and detailed than the Initial Resiliency Plan. FEI’s supplemental evidence addressed all of the points raised in the BCUC’s Adjournment Decision and the 2022 LTGRP decision.

FEI’s 2024 Resiliency Plan included the following notable elements:

  • Identification of all single point of failure vulnerabilities on FEI’s system and upstream that, based on system modelling, had the potential to result in a material customer outage in winter;
  • Definition of a materiality threshold for inclusion in the 2024 Resiliency Plan focused primarily on number of customers affected;
  • Measurement of direct customer impacts (i.e., direct consequences) using two metrics: number of customers experiencing an outage, and customer-outage-days (i.e., number of affected customers multiplied by the expected duration of outage);
  • Development of a model by a third party to estimate the consequential economic impacts associated with each vulnerability based on area-specific GDP information. Despite the uncertainty in this type of modelling (which FEI and its experts acknowledged during the regulatory process), the model enabled a comparison of vulnerabilities based on the type of load being served rather than simply customer count. The GDP loss analysis suggested that an outage in an urbanized area with industrial and commercial customers, such as in Vancouver and the Lower Mainland, has the potential to cause cascading adverse economic impacts;
  • Third-party qualitative evidence of the adverse health effects of exposure to cold during a winter outage;
  • Calculation of the probability of failure for each identified system vulnerability, based on the potential sources of failure or hazard(s);
  • Calculation of risk (probability multiplied by consequences) for each vulnerability. This calculation was performed for all three consequence metrics (customer outages, customer-outage-days, GDP losses), and over various time horizons;
  • Third-party evidence on how to assess risk. A key point in this evidence was that relying solely on probability-adjusted risk calculations can drive poor decision-making in the context of low probability-high consequence events. There is a tendency to underestimate the risk. To overcome this shortcoming, the third-party evidence recommended the risk analysis be supplemented with “scenario-based” analysis, an established approach that focusses on the consequences of an event or system failure. That is, if the consequences are unacceptable, then even a small probability may be intolerable — similar logic underlies why people purchase earthquake or fire insurance.

As noted previously, the BCUC had wanted more evidence that FEI was focussing on the right resiliency investments. The analysis above allowed the BCUC to compare the relative risk presented by vulnerabilities across FEI’s system. It demonstrated that FEI was proposing to invest to mitigate its largest risks. It also demonstrated that the unmitigated risk associated with a T-South no-flow event was very large, and the unmitigated risk would still be very large under any realistic scenario assumptions. The BCUC stated, for instance:[20]

Despite the broad ranges of probabilities and consequences presented by FEI in the 2024 Resiliency Plan, its analysis demonstrates that the risk associated with a loss of supply from the T-South pipeline is significantly greater than any other of the identified gas infrastructure vulnerabilities. Further, the magnitude of the risk is significant in and of itself, as illustrated by the potential billions of dollars of GDP losses that could result from a single winter no-flow event. It is clear that any prolonged outage of supply from the T-South pipeline during the winter would put hundreds of thousands of customers at risk of losing service. FEI provided extensive evidence in the initial phase of the proceeding to demonstrate that a loss of service at this scale would take several weeks to restore service.

…

In instances where there appeared to be a considerable degree of uncertainty, such as with the rate of failure of the T-South pipeline due to internal hazards, FEI demonstrated that the outcomes of its analysis were not materially sensitive to changes in the assumed inputs. FEI also provided benchmarks against which to compare its Baseline value of pipeline rate of failure, such as data from PHMSA and TSB. Further, the Panel observes that there are aspects of the 2024 Resiliency Plan that may actually understate the overall level of risk, such as Exponent’s exclusion of any impacts arising from cybersecurity breaches or malicious acts.[21]

The risk analysis in the 2024 Resiliency Plan also provided a baseline that allowed FEI to demonstrate the different risk mitigation benefits under each of the project alternatives. This was important in addressing the BCUC’s expressed desire for information on the relative risk reduction for the amount of investment. In essence, the analysis showed that a larger facility provided significantly greater protection against an outage than a smaller facility. Given the strong economies of scale when constructing an LNG facility, customers were clearly getting better value from a larger facility. The BCUC stated:

As for FEI’s methodology for assessment of the various Tilbury and non-Tilbury alternatives, the Panel finds the assumptions and criteria to be thorough and reasonable. They support the choice of [the largest facility] as the Preferred Alternative in light of the significant additional gas supply and resiliency benefits and economies of scale associated with that alternative relative to the other Viable Alternatives.[22]

FEI was able to use the analysis in the 2024 Resiliency Plan to show the considerable risk mitigation value customers would receive even under adverse assumptions about the facility’s service life. The BCUC had, in the Adjournment Decision, expressed concern about declining load and stranded assets as a result of the energy transition.[23] This evidence supported both the need for the TLSE Project and FEI’s proposal to construct the largest facility alternative.

Interveners generally accepted the analysis in the 2024 Resiliency Plan, including the underlying risk posed by a winter T-South no-flow event. All but one of the intervening ratepayer groups accepted the resiliency need and ultimately supported the TLSE Project as proposed. In several cases, interveners changed their views and supported the TLSE Project after seeing FEI’s supplemental evidence and the 2024 Resiliency Plan.

CONCLUSION

The BCUC’s decision in respect of FEI’s Initial Resiliency Plan, the Adjournment Decision and its decision granting a CPCN for the TLSE Project all show a recognition of the importance of resiliency in the gas system. The decisions also illustrate the challenges that utilities face, despite that recognition, in justifying a significant investment in natural gas system resiliency at this time in the absence of industry-wide resiliency standards. The iterative process was lengthy, complex and costly. However, it ultimately resulted in a robust resiliency planning framework that will continue to serve FEI for years to come. And most importantly, it culminated with the approval of a very important resiliency project.

 

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