INTRODUCTION

Near the end of 2023, two strikingly similar decisions were issued almost simultaneously, one by the British Columbia Utilities Commission (BCUC), the other by the Ontario Energy Board (OEB). Both raised significant concerns about investments in natural gas infrastructure, yet both fell short of considering the broader questions raised by the changing energy context in Canada.

These broader questions include:

• What is the role of the natural gas distribution system?
• Where will the electricity come from?
• Is there a holistic plan for the transition?

This article reviews further those broader questions and highlights the difficulties that can arise when examining them.

OEB AND ENBRIDGE

On December 21,2023, the OEB issued its Decision and Order on the remaining Phase 1 issues in Enbridge Gas Inc.’s (Enbridge) application seeking approval for changes to the rates it charges for the sale, distribution, transmission, and storage of natural gas starting January 1, 2024.

In the decision the OEB Panel determined by majority decision that for small volume customer connections, the revenue horizon that Enbridge uses to determine the economic feasibility of new connections is to be reduced from 40 years to zero, in a move to reduce stranded asset risk to zero, effective January 1, 2025. This methodology effectively precludes connecting any new customers as the costs will far exceed the costs of electric alternatives.

The Panel also reduced Enbridge’s overall proposed capital budget of approximately $1.4 billion for 2024 by $250 million, stating that

[t]he energy transition poses a risk that assets used to serve existing and new Enbridge customers will become stranded because of the energy transition. Enbridge has not provided an adequate assessment of this risk to demonstrate that its capital spending plan is prudent. The stranded asset risk affects all aspects of Enbridge’s system and its proposals for capital spending on system expansion and system renewal.^[1]

The Panel further stated that the

assets Enbridge Gas proposes to add to rate base in 2024 would be depreciated over the next 40 years or more, based on the physical asset life. The same would apply to the assets that Enbridge Gas plans to add in each of the following four years, as proposed in its application, and over the next ten years, as proposed in its Asset Management Plan. It is the 40-year horizon against which the stranded asset risk must be examined, not the five-year horizon of the requested rate term that Enbridge Gas urges the Panel to use. When looked at through the 40-year lens, what Enbridge Gas proposes looks very much like business as usual and it is not sustainable.^[2]

The Panel’s concern about sustainability was also evident in its directives to Enbridge to mitigate stranded asset risk, including:

• put more emphasis on monitoring, repairing and life extension of its system so that replacement projects are only implemented where absolutely necessary
• carry out a risk assessment and to consider a range of risk mitigation measures, including:^[3]
  • How Enbridge Gas would prune its existing system to avoid the replacement of assets.
  • What role Enbridge Gas’s depreciation policy should play in reducing the stranded asset risk.
  • How Enbridge Gas will identify maintenance, repair and life extension alternatives to extend the life of existing assets instead of long-lived replacements that increase the stranded asset risk.

One of the three Panel members, Commissioner Allison Duff, dissented on the zero-year revenue horizon for assessing the economics of small volume gas expansion customers, saying the evidence doesn’t support pushing the connection costs completely up front. In particular, she considers the rationale is conjecture as no developers intervened or filed evidence in this proceeding. Commissioner Duff instead finds that a 20-year revenue horizon is appropriate.^[4]

Commissioner Duff went on to say: “[t]o me, the risk of unintended consequences to Enbridge Gas, its customers and other stakeholders increases given the magnitude of this conclusive change.”^[5]

Commissioner Duff also expressed concern about the feasibility of replacing new gas connections with electricity, writing: “would electricity generators, transmitters, distributors and the IESO be able to meet Ontario’s energy demands in 2025? I don’t know.”^[6]

THE REACTION AND ENBRIDGE’S VIEW

Reaction to the decision was swift. On the very next day, Ontario’s Energy Minister stated that he was “extremely disappointed” in the split decision and vowed to “use all of my authorities as Minister to pause the Ontario Energy Board’s decision…[w]e will not stand for this].”^[7]

The opposition to the decision was focussed on affordability. Minister Todd explained it could lead to tens of thousands of dollars added to the cost of building new homes, which would slow or halt the construction of new homes, including affordable housing.^[8]

Not surprisingly, Enbridge said it is disappointed with the decision and it is “reviewing all of its potential options for challenging the order, including going to court.”^[9]

Enbridge also commented on affordability issues, stating: “[a]t a time when affordability is the number one concern for Ontarians, this decision means that new customers will have to pay for their connection to natural gas immediately rather than over several years, adding unnecessary costs to residents.”^[10]

BCUC AND FORTISBC

On December 22, 2023, the BCUC issued its decision denying FortisBC Energy Inc.’s (“Fortis”) application for a Certificate of Convenience and Necessity (CPCN) for its proposed Okanagan Capacity Upgrade Project (OCU), which included the construction, installation, and operation of approximately 30 kilometers of new natural gas pipeline. The denial of the application was a unanimous decision of the two person Panel. The Panel determined that the project was not necessary for public convenience or in the public interest.^[11]

In its application, Fortis stated that the pipeline expansion project is needed to meet its forecast increase in demand for natural gas in the Okanagan region of BC due to population growth. Fortis indicated that it expects to be unable to meet the growing demand with its existing pipeline infrastructure, as early as the winter of 2026/2027.^[12]

The Panel found that Fortis application did not consider the possibility that demand for natural gas in the Okanagan region could flatten or decrease over the next 20 years, due, in part, to BC’s CleanBC Roadmap commitments, BC Building and BC Energy Step Codes impacts, and other planning guidelines or zoning bylaws.^[13]

As stated in the decision, and with the numbers that the determination was based on, the most recent estimate of the project cost was $327.4 million with a delivery rate impact of 2.37 per cent. However, the evidence suggests that this rate impact may be overstated, as the levelized rate impact is 1.78 per cent.^[14]

One focus of the proceeding was the examination of alternatives to the pipeline, trucking CNG to meet peak loads being probably the most examined. Fortis’ position was that this was impractical, but the Panel disagreed. While it accepted that “this is not appropriate for a long-term solution as it has numerous drawbacks” it endorsed it as a short-term solution, stating that “it might be able to cost effectively fill the gap in the meantime.”

The Panel also suggested that other short term mitigation strategies could be targeted to address those parts of their gas transmission system, which Fortis identifies would be the first to experience capacity shortfalls. The first communities to experience capacity shortfalls are identified by Fortis as West Kelowna, Lumby and Lavington, having a combined population of about 40,000.

The only other potential short-term solution (other than trucking) suggested by the Panel was the Peak Shaving CNG Unit outlined in Fortis’s Gibsons Capacity Upgrade Project. The approved but not yet completed Peak Shaving CNG Unit referred to will serve a town of approximately 5,000 on the “Sunshine Coast,” an area that enjoys somewhat warmer winters than the Okanagan.

This peak shaving unit replaces a scheme of barging in CNG on trucks to supplement the capacity of the existing distribution pipeline. It consists of a slow filling peak shaving facility and associated tie-ins to the existing distribution main. The facility draws gas from the existing distribution system during periods of low system demand, compress it, and store it in two high-pressure storage vessels. During periods of high gas demand, the stored gas will be depressurized, heated, and injected back into the distribution system to supplement the supply. Its cost of approximately $12 million is less than that of a pipeline upgrade.^[15]

The Panel directed Fortis to file an alternative plan by July 2024.

THE REACTION TO THE BCUC DECISION

The reaction to the BCUC decision was muted, at least compared to the reaction in Ontario to the OEB decision. Fortis official statement expressed “disappointment” and went on to emphasize:

The Okanagan Capacity Upgrade project is required to meet peak energy demand in the Okanagan region, which occurs during colder winter months when customers rely on gas to heat their homes and businesses… Fortis’ infrastructure is vital to the delivery of renewable and low-carbon gases, which are critical to the Province’s ability to meet its CleanBC targets.^[16]

Although both these decisions speak volumes about their respective regulators’ views on the future of the natural gas system, they are silent on a number of critical questions, such as: What is the role of the natural gas distribution system? Is there a holistic plan for the transition? In the absence of natural gas, where will the electricity come from? Is there a joint plan for the transition?

WHAT IS ROLE OF THE NATURAL GAS DISTRIBUTION SYSTEM?

Both decisions operate from a premise that the need for the natural gas distribution system will be reduced as the demand for conventional natural gas diminishes. Combining that assumption with findings that the demand for conventional natural gas may be reduced or eliminated over the next 40 or so years leads to the conclusion that investments in gas infrastructure must be reduced in order to prudently manage the risk of stranded assets.

However, in both decisions, these assumptions appear to be based on the effective implementation of a particular assumed pathway to decarbonization, specifically the replacement of conventional natural gas with electricity.

Neither decision addresses the difference between the demand for a gas pipeline delivery system as opposed to the demand for conventional natural gas.

Currently, both Enbridge and Fortis sell a limited amount of what they call “renewable natural gas” (RNG) through the same pipeline delivery system. Although RNG is currently not an approved compliance pathway in BC, the BCUC Panel did acknowledge that should it become one, “there may well be little variance in the trajectory of FEI’s longer-term peak demand forecast.”^[17] However, due to that uncertainty and also because there has been no decision to date on the Revised Renewable Gas Comprehensive Review proceeding the Panel declined to take into account the possibility that Fortis’ load forecast may be reasonable.

The BCUC recently issued a report on renewable natural gas in which it considered the issue of abated gas, which it defined as conventional natural gas combined with environmental attributes (EA) derived from any source other than the production of biomethane.^[18]

The report included a recommendation that the provincial government

consider legislative changes to recognize abated gas. The abated gas should be derived from EAs that arise from processes that clearly fulfil the objectives of the CEA [Clean Energy Act], the CleanBC Roadmap to 2030 and British Columbia’s broader GHG reduction commitments, and are therefore an acceptable and achievable pathway to emission reductions for the Province.^[19]

Is there a possibility that the existing natural gas pipeline system could be used to transport other gasses to provide home heating, such as hydrogen, conventional natural gas combined with carbon capture and storage schemes or other abated gasses?

These are difficult issues for the regulator to address. No legislative framework exists in either province that includes clear policy on these schemes. Further, they involve new and evolving technologies with uncertain outcomes and largely unknown cost implications.

WHERE WILL THE ELECTRICITY COME FROM?

Largely unaddressed in both decisions was the question of where the electricity would come from if the demand for natural gas is partially or completely replaced by electrification of home heating.

In Ontario, while the IESO has been optimistic about the ability of the electric system to fully eliminate natural gas generation in its own electricity system by 2050. Starting with a moratorium on new natural gas fired generation in 2027, in a report issued in late 2022 it stated that to do so will require about $400 billion in capital spending and new, large-scale nuclear plants.

Further, in an assessment of resource adequacy in the 2025-2027 period, the IESO reports that “Ontario will require an additional 4,000 MW of electricity between 2025 and 2027 — the equivalent of adding a city the size of Toronto to the power grid”. IESO further recommends that the province step-up natural gas use to help avoid an energy shortage, stating there is no “like-for-like” replacement for natural gas.

As a result, the provincial government approved the IESO’s plan to add up to an additional 1,500 MW of new natural gas capacity between 2025 and 2027, and 2,500 MW of non-natural gas generation — directing that at least 1,500 MW of which should be storage, while the rest should be other clean sources such as hybrid solar-battery technology or new hydroelectric power.^[20]

It appears that all else equal in the short-term, incremental electricity load requires additional gas-powered electricity generation. If that is the case, in the short-term at least, replacing natural gas with electricity means replacing natural gas with electricity that may be generated using natural gas.

However, it is not clear whether the OEB Panel considered any of these factors. If its decision results in a switch from natural gas to electricity in the short-term. Will that increase the electric load needed in the 2025 to 2027 period beyond that considered in the 2022 IESO study? The Panel majority did not appear to consider the impact of its decision on electricity demand — and where any additional incremental electricity would come from to provide for building heating needs that would otherwise have been supplied by natural gas — although the dissenting Commissioner did.

In BC, on February 24, 2023, Fortis filed, in its long-term resource plan proceeding, its “Kelowna Electrification Case Study.” The study concludes that

at 100 percent electrification of gas load and a mean daily temperature of -26 Celsius (C), peak demand in 2040 would more than triple, from 472 megawatts (MW) to 1,429 MW, resulting in a high-level estimate of between approximately $2.6 and $3.4 billion in capital expenditures on the electric distribution and transmission system which would be needed in less than 20 years. Even at 25 percent electrification of gas load, peak demand would increase to 711 MW and result in an estimated range of $1.3 to $1.7 billion in capital expenditures over this same timeframe.^[21]

However, the BCUC Panel does not appear to have considered this evidence in the OCU proceeding, even though the Utilities Commission Act requires it to consider a utility’s most recently filed long-term resource plan when considering an application for new infrastructure such as this new pipeline.^[22]

Electricity is supplied to the Okanagan are by a sister corporation, Fortis Electric. Fortis Electric filed its most recent Long Term Resource Plan in 2021. That plan did not identify any increased heating load from the reduction of natural gas demand.

Further, according to its 2020 Annual Report, approximately 18 per cent of Fortis Electric’s electricity is acquired through a Power Purchase Agreement from BC Hydro, which supplies electricity to most of the province.^[23] BC Hydro filed its Integrated Resource Plan in late 2022. It did not identify any increase in demand to replace natural gas as a home heating fuel. Although it has since revised its load forecast, and its Integrated Resource Plan hearing is ongoing, it is not clear whether this provides any additional capacity for the Okanagan or whether it has sufficient infrastructure to deliver that additional capacity.

Recent events underline the amount of electrification required to serve heating load on peak days. On January 12,2024, cold temperatures broke numerous temperature records in BC. According to a Fortis press release, its gas system provided 21,763 MW, which by comparison, is almost double the 11,300 MW provided by BC Hydro.^[24] Clearly, replacing natural gas as a heating fuel with electricity will require considerable thought and planning.

IS THERE A HOLISTIC PLAN FOR THE TRANSITION?

In the Enbridge decision, the Panel stated,

In the face of the energy transition, Enbridge Gas bears the onus to demonstrate that its proposed capital spending plan, reflected in its Asset Management Plan, is prudent, having accounted appropriately for the risk arising from the energy transition. The record is clear that Enbridge Gas has failed to do so. Enbridge Gas has taken the position that there is no stranded asset risk for the purposes of setting rates for 2024. This is not logical.^[25]

Indeed, it isn’t logical if one assumes that the demand for conventional natural gas will drop significantly in the near to medium term. However, as Commissioner Duff highlighted in her dissent, where will the electricity to replace the demand for natural gas come from? Until regulators can get some visibility on where, and at what cost, is it indeed prudent for them to assume we don’t need conventional natural gas?

In the BC decision, the regulator directed Fortis to find a short-term fix while the future of the gas distribution system in BC becomes clearer. It found:

a significant risk that the forecast growth flattens or potentially begins to decline due to Fortis’ inability to serve new customers’ space and water heating needs resulting from the province’s commitments in the CleanBC Roadmap, the changes to the BC Energy Step Code and the ZCSC.^[26]

Again, a not unreasonable conclusion on its face. However, as with the OEB decision, it assumes that natural gas — or any other product transported by the pipeline — will be unable to meet government’s decarbonization goals and that natural gas can be replaced by zero emitting electricity at a reasonable cost and within the required timeframe.

Is this the most prudent approach? Does denying an application for capacity that is demonstrably needed in the short term in an attempt to save the ratepayer cost actually increase the risk to the utility’s customers?

They are at the forefront when risks materialize, such as increased energy costs or brownouts or blackouts when there is insufficient energy on cold winter days.

To make these determinations requires a much more holistic view than was taken in either of the decisions. That said though, it is difficult for regulators to obtain a holistic view of the energy transition. In many cases, legislation is not in place to support the transition and technology is developing rapidly. Further, regulators have always viewed specific applications on their own merit, often with different Panels examining different applications. This can lead to unavoidable siloing of issues.

The Kelowna Study concludes that there are opportunities for solutions to managing the energy transition through the operation of an integrated gas and electric system.

Additionally, the BCUC recently led an exercise to develop joint load forecasts for both BC Hydro and Fortis. This resulted in each company providing responses to various scenarios put forward by the other. This evidence was filed in both the Fortis and BC Hydro recently filed Resource Plan proceedings.

Regulators need the holistic view that these exercises can provide. The Electrification and Energy Transition Panel convened by the Ontario government, seems to agree. In its recent report, issued after both of these decisions, one of the 7 principles and next steps it sets out for “Ontario to navigate and succeed in the transition towards a clean energy economy in the long term” is: “Ensuring effective collaboration and integration in energy planning across fuels, especially electricity and natural gas, across end use sectors and across levels of government, to ensure investments and innovation can be deployed in a way that unlocks their full value.”^[27]

CONCLUSION

Neither of these decisions involved significant sums of money — several hundred million in each case — relative to rate bases that are measured in the billions. It is also not unusual for a regulator to deny a spending application of that magnitude. Further, both decisions were well reasoned, at least in the arguably narrow framework the decision makers set for themselves. Why are they important?

Their importance lays in what they didn’t say as opposed to what they did say. Neither decision fully examined the broader context of the energy system. As a result, they may have unintended consequences. However, as outlined in this article, the broader context can be difficult to discern, with much uncertainty arising from policy and changing technology.

While issues arising from technology change can be largely intractable, policy can be clarified. For regulators to make informed decisions requires a holistic view of an energy transition that is not always amenable to such views. It also requires policy makers to provide clear policy direction when at all possible and when not possible to ensure that they encourage and support the regulator to take steps to consider all the aspects of the energy system when making decisions about the energy transition.

* David Morton is a professional engineer with over 45 years of experience. He specializes in utility regulation and energy policy. He led the British Columbia Utilities Commission (BCUC) for eight years where, among other responsibilities, he conducted several significant inquiries for the British Columbia government. He remains involved in international energy regulatory associations and frequently participates in global conferences and mentoring sessions.

1. Phase 1 Enbridge Gas Inc: 2024-2028 Rates Proceeding (21 December 2023), EB-2022-0200, at 2, online: OEB <www.rds.oeb.ca/CMWebDrawer/Record/827754/File/document>.
2. Ibid at 21.
3. Ibid.
4. Ibid.
5. Ibid at 2.
6. Ibid.
7. Government of Ontario, “Ontario Government Standing Up for Families and Businesses” (22 December 2023), online: <news.ontario.ca/en/statement/1004010/ontario-government-standing-up-for-families-and-businesses>.
8. Ibid.
9. The Canadian Press, “Minister to overrule Ontario Energy Board, says decision will raise cost of new homes” (22 December 2023), online: <www.toronto.ctvnews.ca/minister-to-overrule-ontario-energy-board-says-decision-will-raise-cost-of-new-homes-1.6699449>.
10. Ibid.
11. British Columbia Utilities Commission, News Release, “BCUC Rejects FortisBC Energy Inc. Okanagan Capacity Upgrade Project” (22 December 2023), online (pdf): <docs.bcuc.com/documents/NewsRelease/2023/2023-12-22-NEWS-RELEASE-BCUC-Rejects-FortisBC-Okanagan-Upgrade-Project.pdf>.
12. Ibid.
13. Ibid.
14. FortisBC Energy Inc: Application for a Certificate of Public Convenience and Necessity for the Okanagan Capacity Upgrade Project (14 August 2023) Final Submission, at para 134, online (pdf ): <docs.bcuc.com/documents/arguments/2023/doc_72977_20230814feifinalargument.pdf>.
15. FortisBC Energy Inc: Annual Review for 2023 Delivery Rates (5 December 2022), BCUC G-352-22, online: BCUC <www.ordersdecisions.bcuc.com/bcuc/orders/en/521395/1/document.do>.
16. FortisBC, “Statement regarding BCUC decision on the Okanagan Capacity Upgrade Project” (22 December 2022), online: <www.fortisbc.com/news-events/media-centre-details/2023/12/22/statement-regarding-bcuc-decision-on-the-okanagan-capacity-upgrade-project>.
17. Supra note 15 at 24.
18. British Columbia Utilities Commission, Inquiry into the Acquisition of Renezable Naturel Gas by Public Utilities in British Columbia, Phase 2 Report (Vancouver: British Columbia Utilities Commission, 2023) at 24.
19. Ibid at iii.
20. Independent Electricity System Operator, Evaluating Procurement Options for Supply Adequacy: A Resource Adequacy Update to the Minister of Energy, Resource Adequacy Update (Toronto: Independent Electricity System Operator, 2023).
21. FortisBC Energy Inc & FortisBC Inc, Kelowna Electrification Case Study — Electrification and the Impacts of Cold Temperature on Peak Demand and System Upgrade Costs, (Vancouver, FortisBC, 2023), at 1, online (pdf): <docs.bcuc.com/documents/proceedings/2023/doc_70278_b-20-fei-evidentiary-update.pdf>.
22. Utilities Commission Act, RSBC 1996 c 473, s 46(3)(1).
23. FortisBC Inc, Annual Information From: Fort the Year Ended December 31, 2020, (FortisBC, 2021), online (pdf ): <www.cdn.fortisbc.com/libraries/docs/default-source/about-us-documents/fbc-aif-2020-final-mar-26-2021-sedar.pdf?sfvrsn=c8b7cc8e_2>.
24. Colin Dacre, “During peak demand, FortisBC’s natural gas system delivered double the energy of BC Hydro” (15 January 2024), online: <www.castanet.net/news/BC/467369/During-peak-demand-FortisBC-s-natural-gas-system-delivered-double-the-energy-of-BC-Hydro>.
25. Supra note 1 at 21.
26. FortisBC Energy Inc: Application for Certificate of Public Convenience and Necessity for the Okanagan Capacity Upgrade Project (22 December 2023), G-361-23, online: BCUC <www.ordersdecisions.bcuc.com/bcuc/decisions/en/522057/1/document.do>.
27. Electrification and Energy Transition Panel, Ontario’s Clean Energy Opportunity: Report of the Electrification and Energy Transition Panel, (Electrification and Energy Transition Panel: 2023), at 2, online: <www.ontario.ca/files/2024-02/energy-eetp-ontarios-clean-energy-opportunity-en-2024-02-02.pdf>.