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Pursuing Affordable Electricity in Ontario

Published on
January 16, 2020

To understand how to drive and secure lower-cost electricity in Ontario, something widely demanded by residents and businesses alike, it is important to have a comprehensive understanding of the policy and politics underpinning the evolution of Ontario’s electricity market, the challenges that face policymakers in making material changes to the status quo, and the trade-offs involved in reducing ratepayer burden in the near-term.

Indeed, decreasing the cost of electricity for some or all ratepayers requires difficult and substantial political and policy consideration of intrinsic trade-offs. Perhaps the most straightforward approach is a fiscal allocation which defrays electricity sector costs for ratepayers by tapping the province’s broader finances. This is an approach underscored by the previous government through elements of the Ontario Fair Hydro Plan (“OFHP”) to reduce residential electricity bills by 25%, and also by the Ford government by shifting the remaining financed elements of that support to the tax base (rather than creating a liability against future ratepayers), and capping rate increases to inflation. There is certainly an argument to be made that elements of the electricity system, including both its affordability and environmental sustainability, contain some degree of social and/or economic imperative otherwise funded by tax revenues alongside other public policy priorities. We have seen several examples of this to mitigate electricity bills for households, small businesses, farms and certain other consumers over the past decade beyond the OFHP, including: the Ontario Clean Energy Benefit (“OCEB”), the Ontario Rebate for Electricity Consumers (“OREC”), and most recently, the Ontario Electricity Rebate (“OER”).

In parallel, it is difficult to have a meaningful discussion about reducing the cost of the electricity system without considering the drivers of those costs. Ontario’s total cost of electricity service is now approximately $21 billion annually. When these costs on a typical residential electricity bill are broken down, we see that that nearly $0.90 of each $1.00 is attributed to the generation and transportation of electricity in and across Ontario.

                               *Reflects July 1, 2019 RPP Rates for a Mid-Density Hydro One Customer (1,000 kWh/month)

The trouble with addressing those costs head-on is that virtually all of them are fixed, guaranteed or otherwise immovable through entrenched legal or regulatory frameworks.

Although a priority for the Ford government is to further decrease residential and small business electricity bills by another 12%, another and of course deeply related area that policy makers are examining is how best to diminish the size of the oft misunderstood Global Adjustment (“GA”) – particularly given its growing quantum and proportion of the total cost of supply.

GA is a settlement mechanism for differences between the Hourly Ontario Energy Price (“HOEP”) and regulated rates for Ontario Power Generation’s (“OPG”) nuclear and hydroelectric generating stations; payments for building or refurbishing infrastructure such as gas-fired and renewable facilities and other nuclear entities, as well as the contracted rates paid to a number of generators across the province; and the cost of delivering conservation and demand management (“CDM”) programs. Any effort to reduce costs systemically must focus on reducing the GA.

Together, HOEP and GA combine to reflect the total commodity cost of electricity in Ontario.

2008-2018 Monthly Weighted Average HOEP vs. GA

                       Source: IESO

Over the past decade, GA has supplanted HOEP as the primary driver of increasing commodity cost and of commodity cost overall. Since 2009, the value of HOEP has decreased by more than two-thirds, while the cost of GA has approximately quadrupled. The interaction between these two components is related and collectively responsible for much of Ontario’s well above inflation increases to the price of electricity over the past decade.

Whether it is diminished/unrecoverable demand resulting from the 2008 recession, low natural gas prices, coal phase-out, renewable energy, project cost overruns, or political decisions of the past – only pragmatically taking stock of the situation today and assessing practical options is likely to generate incremental improvement in this area and in meaningful electricity price reductions overall. We believe that the government is recognizing this and has taken serious actions.  

During the 2018 provincial election, the Progressive Conservative Party – who won a decisively strong majority mandate to govern – campaigned on the challenges facing average homeowners and businesses in the interest of restoring practicality, affordability and responsibility back to the core of government. Energy figured heavily in this, and a commitment to “stabilize industrial hydro rates through a package of aggressive reforms” was central to the new government’s approach and focus after being elected.

Acting on that commitment, on April 1, 2019 the Ministry of Energy, Northern Development & Mines (“ENDM”) launched a province-wide consultation to hear from businesses and industry groups about the design and effectiveness of Ontario’s current industrial electricity pricing regime and programs. Since that time, ENDM has concluded several sector-specific consultations with various industries and has initiated a second round of roundtable sessions with industry associations. The consultation on this topic has been extensive and the approach fueled by an honest desire to understand the issues and make smart choices to improve Ontario’s economic competitiveness.

Perhaps the most pertinent area for change being considered is the Industrial Conservation Initiative (“ICI”) program. Over the past several years, ICI has been expanded to include smaller, distribution-connected customers, including commercial and institutional sector (i.e. municipal, educational, etc.) facilities whose average annual peak demand is greater than 1,000 kW. We believe that the government is mindful of industry concerns around policy changes that could risk eroding the competitiveness of energy-intensive and trade-exposed cornerstones of the economy or stranding deployed assets and investments that are planned or in progress to manage energy use. We also believe that there is a growing recognition of the long-term value of peak demand reduction in a system planning context – something that provides significant performance within the supply-demand mix today, and that will only grow in years to come to support the refurbishment of nuclear assets over the next decade, and the decommissioning of the Pickering Nuclear Generating Station in 2025.

Concurrent with the province’s consultations on industrial electricity prices, the Independent Electricity System Operator (“IESO”) has been updating its long-term demand forecasting to determine future energy and capacity needs, something we expect to be released in the coming weeks through the Annual Planning Outlook (“APO”). Decisions that materially impact the effectiveness of ICI to manage peak demand must go hand-in-hand with this system planning exercise.

Beyond the continuation of the ICI program and an appreciation of its value to the system, we believe that progress could be made in advancing incremental rate options that could induce commercial and industrial behaviour to provide a quantifiable benefit to the electricity system in order to avoid future costs. Developing an approach which offers a greater range of optionality to Ontario’s commercial and industrial sectors and enabling them to respond to market signals to curtail or encourage demand, could address many industry concerns while still providing system benefits for all ratepayers.  

For example, Ontario’s peak demand requirements are distinctly seasonal (Summer/Winter) with peaks occurring at different times of the day in each season, and with relatively low overall demand occurring during shoulder seasons (Fall/Spring). This could include modelling a seasonal, week-day time-of-use (“TOU”) regime for Class B commercial or industrial facilities, as well as any current ICI participants that might opt for a framework that provides an opportunity for more assured reductions. Such rate structures for larger customers exist as options in other jurisdictions (i.e. Alabama, South Carolina) to recognize the high variability in consumption profiles between industries. If this policy option were to be pursued, the first step could be to offer it on a pilot basis in a limited number of local distribution companies (“LDCs”) for a period of time before making it available province-wide.

Should something of this nature move forward, it would lend itself well to the increased attractiveness of small to mid-sized behind-the-meter systems that can accommodate multiple hours of daily utilization for those customers that participate. Obviously, the hypothetical value proposition for behind-the-meter service providers depends on the TOU peak to off-peak price ratios determined to be sufficient to incent participation and operational responsiveness.

To achieve overall system savings, the government is right to focus on finding ways to reduce the GA while maintaining investor confidence. Announced alongside the 2019 Fall Economic Statement, ENDM Minister Greg Rickford issued a directive (Order in Council 1499/2019) to the IESO to retain an independent third party to undertake a targeted review of existing generation contracts – with a focus on larger gas, wind and solar assets with contracts expiring within the next ten years – and provide recommendations on cost-saving opportunities. To note, the directive expressly excludes the Bruce Power Refurbishment Implementation Agreement and contracts related to CDM initiatives. Shortly thereafter, Charles River Associates was retained to conduct the review. On November 19, 2019 the IESO sent letters to dozens of larger generation contract holders requesting ideas and proposals for voluntary contract renegotiations that could yield system savings. The IESO received an indeterminate number of responses by the December 14, 2019 deadline, and will report its findings to government by the end of February 2020.

While the government cancelled 778 Feed-in-Tariff (“FIT”) and Large Renewable Procurement (“LRP”) generation contracts that had not achieved key milestone dates, as well as the 18.5 MW White Pines Wind Project, they have repeatedly rejected recommendations to unilaterally terminate operational projects. Due to the obvious need to preserve investor confidence in Ontario’s economy, as well as the substantial liability costs of termination, this is the right approach to take. That said, “blending and extending” or other more creative voluntary opportunities could potentially lead to near-term GA reductions while shoring up future supply when it is needed, at potentially lower cost.

Without intervention, either on the supply or demand side as noted above, electricity prices will continue to increase in the near and longer-term future. A major focus for the IESO in the coming years will be addressing an anticipated 2,000 MW capacity shortfall in the mid-2020s following the eventual retirement of the Pickering Nuclear Generating Station, while finding ways to lower costs. This means finding efficiencies and optimizing the system.

Better utilizing existing assets and looking for opportunities to achieve greater efficiencies will be critical, particularly by looking at resources such as interties (to enhance the trade capabilities and liquidity of the market), existing generators and their capabilities to better align with existing and future needs, and harnessing the economic and operational potential of energy storage at both a distribution and utility-scale level. This would align Ontario’s market with the direction of the United States, where the Federal Energy Regulatory Commission (“FERC”) has issued new requirements to level the playing field. Under FERC Order 841, U.S. system operators must establish participation models and market rules that recognize the physical and operational characteristics of electricity storage resources.

Furthermore, both the IESO and Ontario Energy Board (“OEB”) have several initiatives underway to reform and modernize the treatment of distribution-level resources. There is a universal acceptance that these assets should be afforded greater opportunities to deliver system services where economic and applicable for the reliability of an evolving grid.

Electricity remains an important and volatile subject in the public discourse, and while there are several challenging policy levers at the government’s disposal, it is likely not to be just one in isolation which can or should be pulled to materially make that incremental difference. In a recent year-end interview, when asked what his most challenging portfolio is, Premier Ford responded noting, “It’s energy…we’re going to find a way – one way or another – to find…savings on hydro bills. We may have to be creative.” Thankfully, given the knowledge of trade-offs involved and recent experiences to draw from, we believe there is a prudent and reasonable way to make the progress that Ontarians expect.

See also the following related publications from the Sussex Strategy Group: