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Blog report on the APPrO 2021 Conference

 

By Sean Mallen

Sean Mallen Communications

December 10, 2021

 

 

Power industry professionals attending the APPrO 2021 virtual conference face a scenario that has never been seen since the birth of electrical generation. Climate change is an existential challenge for the world and the power industry is playing a crucial role in finding solutions. At a conference with the theme “The Electric Future,” the word decarbonization was invoked in virtually every session.  As Lisa DeMarco, an expert in climate change law who had attended the COP 26 summit in Glasgow just a few weeks earlier and Senior Partner and CEO at Resilient LLP noted, “it’s a nut to crack.”

 

In a presentation titled “The Planning Outlook,” Chuck Farmer, the Vice President of Planning for the IESO, explained that after years of static demand we are entering a period of growth, potentially much higher growth in the longer term, partly the result of an anticipated upsurge in manufacturing in southwestern Ontario, partly because of the imperative for decarbonization which is fuelling a spike in electric vehicle sales. 

 

“Economic growth and electrification are reshaping the landscape,” said Farmer.

 

Lesley Gallinger, the new IESO President and CEO, told the conference that Ontario’s electricity sector is already leading the way in the fight against climate change, as one of the cleanest systems in North America, producing only 3 % of the province’s greenhouse gas emissions. 

 

But there are big decisions ahead with the upcoming retirement of the Pickering Nuclear Plant’s reactors, a large, emission-free contributor to the grid. The result will likely be a greater reliance on gas-fired generators over the next decade.

 

“Here lies the challenge for us all,” said Gallinger.  “Our system is changing…and it’s up to all of us to respond to this change.”

 

At the request of the provincial government, the IESO conducted a study into the implications of phasing out gas by 2030. The conclusion was that it was not feasible, that an abrupt weaning from such an important contributor would lead to blackouts on high demand days and skyrocketing power bills.

 

“That’s completely unacceptable to our government,” said Ontario Energy Minister Todd Smith in an interview at the conference. Having rejected a 2030 phase-out, he has asked the IESO to explore possibilities for a moratorium on new construction of gas plants. While the government has made a commitment to support the development of electric vehicles in the province, Smith said that the cost of power has to be reasonable.

 

“We understand the transition to electrification isn’t going to happen unless the system is affordable and reliable. When people plug in their vehicle, they have to know the energy is going to flow,” said Smith.

 

In a session shared with power producers from New England, Alberta and British Columbia, APPrO President and CEO Dave Butters hailed what he calls Ontario’s “Clean Energy Advantage”—an electricity system that is 94% carbon free and produces only a small fraction of the province’s GHG emissions and that is well-positioned to support electrification.

 

“Ontario is North America’s climate success story,” said Butters, citing the slogan of a digital campaign APPrO launched in the fall to spread the message.

 

He added that while the grid must continue to drive towards even lower emissions in the long run, the more immediate challenge is to focus on the big emitters outside the electricity sector, led by transportation and buildings. 

 

The conference heard about a variety of innovations designed to drive decarbonization. 

 

Atura Power, a subsidiary of OPG which operates four combined cycle plants, started a hydrogen business this year, exploring possibilities for a series of demonstration projects around the province.

 

“We can be a key player and be a leader in a key energy source for tomorrow,” said Chris Fralick, the President of Atura Power.

 

Small Modular Reactors (SMRs) were the subject of much discussion, particularly OPG’s plan to build one on the site of the Darlington plant by 2028. 

 

Ken Hartwick, OPG President and CEO spoke glowingly of the project.

 

“Everyone tells me don’t go first.  But I’m confident,” he said. “We decided: let’s lead.

 

We’ll have smart partners and we’ll be successful.  We’re excited and hope to be able to announce something soon on that front.”

 

In fact, just a couple of days after the close of APPrO 2021, OPG announced that it had selected GE Hitachi Nuclear Energy to deploy an SMR at the Darlington new nuclear site, the only site in Canada currently licensed for a new nuclear build.  The fight against climate change has given a new life to nuclear power as an emissions free, reliable source of electricity.

 

Carol Gregoris, OPG’s Project Director for the Darlington New Nuclear project, said SMRs have the potential to be deployed much more quickly than a full sized nuclear plant.

 

“By having the first of a kind here in Canada, it’s more likely others will reach out to us for solutions.  SMRs promise to be the next, more accessible way to add more nuclear to our systems,” she said.

 

In a virtual round table discussion among power industry CEOs, John Kousinioris of TransAlta Corp spoke hopefully about the promise of technological innovation to help meet the twin demands of delivering more electricity while reducing emissions. 

 

“You can’t help but be optimistic.  There will be big breakthroughs,” he said.

 

Along with decarbonization, a related and complementary theme running through APPrO 2021 was ESG, with a heavy focus on the power industry’s relations with Indigenous people. 

 

Ken Hartwick highlighted OPG’s release this fall of its Reconciliation Action plan, which commits to “growing economic impact for Indigenous communities and businesses to $1 billion over the next 10 years, through ongoing operations, projects and initiatives.”

 

Hartwick noted that OPG has already partnered with First Nations on several projects.

 

Brian Vaasjo, President and CEO of Capital Power added: “They often have much greater knowledge of the land and environment. Participation is the right thing to do.”

 

Vaasjo said that while some progress has been made, and he is pleased with Capital Power’s collaboration with a First Nation just west of Edmonton, the industry still has substantial work to do.

 

Sean Willy, President and CEO of Des Nedhe Developments brought the message home with his personal story as an Indigenous person born in the Northwest Territories who is now working with consortiums to help make major power developments happen.

 

“It’s now a reality that you can’t deploy these big projects without Indigenous partnerships and inclusion,” he said.

 

Heather Campbell of Alberta Innovates added that gender equity should be part of the conversation, calling for more women in STEM (science, technology, engineering and math), particularly engineering. 

 

“Women are drawn to clean tech, but are still significantly under-represented,” said Campbell. “Clean energy is our opportunity to build back better and, in my world, better means inclusive.”

 

APPrO’s Dave Butters felt that the discussions about equity were a powerful and important theme of the conference, calling meaningful Indigenous participation in power projects “a moral imperative.”

 

“And it produces a better project. When we talk about inclusivity, it’s about more than gender or race it’s about all the people who live in this country.  It’s hard to get there if some people are economically disadvantaged. That’s equity and justice,” said Butters.

 

 

 

 

 

Canada’s first local electricity market is off to a promising start. Breaking new ground, a wide variety of local distributed energy resources (DER) will start delivering services to the grid on May 1. During the November 2020 capacity auction, a range of projects totalling 10 MW were accepted at a clearing price of $0.64 per kW-day. Although it was only a demonstration project, the results appear to be attractive, indicating that local utilities and transmission system operators may benefit from distributed market-based local capacity and the ability to defer more expensive infrastructure upgrades. Major innovation could be afoot if this kind of market continues to develop and grow.

 - Jake Brooks

 

 

 

The following is a summary of an expert panel discussion on the York Region Non-Wires Alternatives Demonstration Project. The panel was held online as part of the APPrO 2020 conference on December 2, 2020, soon after the first capacity auction results were announced.

 

 

Panelists:

 

Pat Lo, Senior Manager, Partnerships, IESO

 

Geri Yin, Head, Grid Innovation, GRE&T Centre, Alectra Utilities

 

Jen Hiscock, Assistant Program Director / Smart Grid & Energy Storage, Natural Resources Canada, and Session Moderator

 

 

 

Jen Hiscock: This new demonstration project, valued at more than $11 million, marks the first time NRCan (Natural Resources Canada) has invested in this kind of market-based solution. Rather than focusing on technology application, the project looks at how development of a local market might make services available economically to the wholesale grid. Funding has been provided equally by the federal government and the IESO.

 

 

 

The project area covers a subset of the Alectra service territory. It was chosen based on the location of expected demands on the distribution and transmission grids, looking at what could be done on the distribution side to address some of the system constraints if a non-wires alternative approach is taken. Existing stations are approaching their limits, and a growth trend is anticipated for a number of years. The question arose as to whether some of the needed capacity upgrades could be deferred by leveraging existing or new customer-owned assets.

 

 

 

The assets under consideration ranged from 100 kW to 3 MW – like batteries and space conditioners, remotely controllable. Resource types include demand response, gas-fired generation and storage.

 

 

 

The first market auction, which sought 10 MW of capacity for a 6-month commitment period from May to October 2021, had just cleared at the time of the conference, at a price of $0.64 / kW-day (see chart). Another auction is scheduled for fall of 2021.

 

 

 

Pat Lo: One of the objectives of the project was to find out what resources are available in the community, and to identify specifically what local resources could be used to meet local system needs. What value streams are available among these non-wires alternatives? And under the heading of interoperability, what value would there be at the wholesale level as well? What correlation might there be between prices in the transmission and distribution markets? How reliable will the resources be? Are the various types of resources available competitive with each other?

 

 

 

Geri Yin:  The capacity auction was run on November 18 and 19, 2020 – a real competition! Local resources representing 34.3 MW of capacity registered to participate, well exceeding our set capacity target of 10 MW.  We’ve seen a diverse group of participants: aggregated residential customers, supermarket operators, manufacturers, a district energy utility, and other local companies are among the successful providers. The types of DERs that have cleared the capacity market include behind-the-meter CHP, C&I Load Curtailment, Residential DR (Smart Thermostats), and behind-the-meter Gas-fired Generation.

 

 

 

The local capacity market cleared at a competitive price of just $0.64/ kilowatt-day, or $640/MW-day. This was 40% of the price cap which was $1.6/kw-day or $1,600/MW-day.  The demonstration’s clearing price for the full six-month commitment period (May – October) in 2021 is about $80,000/MW.

 

 

 

The capacities cleared through the local auction market were pretty much evenly distributed among the two zones – zone 1 in Vaughan and zone 2 in Markham and Richmond Hill. The two-zone market is expected to generate more learnings and enable better understanding of local market dynamics that can be used during the next round of the market auction. 

 

 

 

Alectra was thrilled with the results of the auction. The amount of interest from the market and the diversity of the successful participants and resources shows tremendous potential for using local solutions as a cost-effective alternative to traditional electricity infrastructure to meet local and regional energy needs. It is clear that there is a viable local market for DERs to participate as grid energy resources.

 

 

 

Another important aspect is that this local market gives the community the opportunity to take an active role in building a more sustainable grid - by deferring traditional infrastructure, while at the same time generating a new source of income. 

 

 

 

Jen Hiscock: Remember that nobody put a thumb on the scale in any way to determine who would win or who would perform better in this auction. We tried to make the playing field as level as possible. It’s also good to see the level of resources that can participate – resources in the range of a few hundred kilowatts would never be engaged at the scale the IESO deals with. In addition, the new sources of revenue created for customers will help them commit to increasing electrification. This could be important considering that efficiency alone may not be enough to get to the 2050 decarbonization goal.

 

 

 

Questions

 

 

 

1. The pilot has allowed testing of a number of parameters, but there are others we can’t yet test. What limitations in testability did it encounter?

 

 

 

Pat Lo: The dispatch process will be real, not simulated. The IESO will be calling on the resources, and they will come online. However, we can’t directly apply the results to the wholesale market. Some of the remaining barriers are in the regulatory domain. But the regulator is highly involved and is reviewing the project. We’re hoping that, working with the regulator, we’ll be able to provide enough insight so as to make broader choices in the future.

 

 

 

2. There’s always been some doubt as to how many customer assets we can leverage. Tell us about the process of recruiting customers.

 

 

 

Geri Yin: We took a staged or phased-in approach to engage stakeholders and acquire participants to the program. Engagement via the IESO webinars began in December of 2019. Last July the IESO and Alectra jointly hosted a stakeholder engagement session on the detailed design of the Demonstration Program Rules and Participant Contracts, followed quickly by the marketing campaign, where Alectra worked closely with the IESO on marketing and communication strategy. Alectra was taking a customized, one-on-one approach with the customers, helping them understand what the program is about, what they’re being asked to do, and what’s in it for them. We educated customers about the program with our marketing materials and tools. We’re also collaborating with industry associations – such as EDA, OEA, Vaughan Chambers of Commerce, the Markham Board of Trade, and so on, who are also networking and getting the program out through their own channels.

 

 

 

3. Have any of them had to do their own retrofits or upgrades in order to participate? Or were they able to sign up on the spot?

 

 

 

Geri Yin: Some had their resources readily available, some are looking at building DERs. Some will be ready for the second-round market auction next fall.

 

 

 

Jen Hiscock: This sort of approach is extremely transparent in order to allow everyone who wants to play and to allow for broad competition. The project methodology was designed to maximize the breadth of competition, not to create a rush to connect.

 

 

 

4. This is the first such project in Canada. Is there a basic structure to a project like this to help other system operators and LDCs who might want to set up something similar?

 

 

 

Pat Lo: LDCs have their own set of system operations specific to the distribution network – opening and closing breakers, planning system outages – while we’re talking about more market-based constructs, procuring energy resources. So they might have to acquire that capacity, understanding how market systems operate. The IESO’s approach to market operation properly stresses full transparency, including costs, cost breakdowns, rules and contracts.  There shouldn’t be anything to hide.

 

 

 

As to the regulatory side, the OEB right now is in a transitional state and they’re looking at more innovation. We’re seeing some good progress. Two of the key takeaways for me are a) the importance of getting to know the markets, and b) learning how to manage the regulatory nuances that will alleviate barriers to developing these new markets.

 

 

 

Geri Yin: Other LDCs may need to work to develop a local energy market perspective. This could mean getting their executives on board, developing the appropriate expertise – in the legal area, system planning, the control room, etc., and making sure the needed processes are established.

 

 

 

They will need a software platform that’s able to register DERs, and allow participants to bid into capacity and energy markets. The system will need the capability for qualifying and contracting DERs, forecasting demand, scheduling, dispatching, performing M&V and settlement, etc. Regulatory changes will clarify and enable the cost recovery for operating this type of local market; but before that happens, ring-fencing the internal resources devoted to the projects (separating them from normal utility business) is necessary so that it will not affect ratepayers.

 

 

 

Pat Lo: The auction has demonstrated that this kind of capacity procurement is fairly economic. This initiative is strategically important.

 

 

 

Jen Hiscock: We always expected a pilot to be a little more expensive than a full scale-up. This pilot will be important as a benchmark. It’s not unusual for people to underestimate the cost of change management at the early stages of a new initiative. There will be a need in many cases to devote time and effort to the development of human resources.

 

 

 

5. What would be needed to make this scale up in Ontario?

 

 

 

Pat Lo:  The intent is to take the current wholesale capacity price and compare it to the clearing price of the local auction. That will give us an idea of what resources clear at what level. It will also help us understand what the values are for non-wires alternatives in terms of capital deferral.

 

 

 

FERC Order 2222 is making large strides in the United States. The IESO will be learning from that and likely making moves in that direction as well.

 

 

 

6. Geri, did you have a comment on getting the scale you wanted?

 

 

 

Geri Yin: It definitely required a shift in our thinking about scale. From one perspective we were looking at how to enable customers to have more control of how they use energy. From another perspective we are looking at how to ensure efficient and innovative investment in utility infrastructure. To get to scale, we need to have systems such as DERMS connected to the various DMS at utilities/DSO (i.e., SCADA, GIS, etc.)   – allow the DSO to be able to fully integrate the DERs into the grid; be able to control, monitor, manage and optimize DERs, while offering customers grid services to monetize their DERs.  Ultimately, we will need a new regulatory framework (i.e., new tariff and rate design/structure) to incent investment in and cost recovery associated with adopting DERs as grid solutions to avoid or defer traditional poles and wires investment.

 

 

 

7. Where is the money for these settlements coming from?

 

 

 

Jen Hiscock: Some of the money for the demonstration project is coming from NRCan funding. And that’s part of why the OEB is happy to have you go ahead; ratepayers aren’t paying for the settlements at this point. But if we want this to get to scale, where will the value come from? Under the traditional TSO approach, we’d only be talking about wholesale clearing prices, but since it’s at the distribution level, we can also add any asset deferrals on the LDC side. So what are the easiest values to realize, in order to minimize administrative costs?

 

 

 

Pat Lo: The way utilities are traditionally set up, it’s often easier for them to rate-base everything. We need to consider if there are other ways to ensure capacity is in place. Can utilities acquire capacity services from market participants for example? Can utility capital be used to secure capacity from DERs, or do we just change the structure entirely to compensate utilities differently?

 

 

 

8. How might anyone considering a role as power producer participate in this project? I’d like to include options for aggregation and behind the meter opportunities.

 

 

 

Pat Lo: We wanted to procure three types of resources, but for this pilot we were only able to organize to get two. There is no storage – that would have been hard to make an investment in given the tight timelines for participation in the first capacity auction. In future we’d love to see some kind of adjustment, so we could see how well it competes.

 

 

 

9. How can future auctions be designed to recognize the lead time that’s often necessary to develop new DER projects to participate effectively? The local region might not have many additional existing assets to leverage.

 

 

 

Pat Lo: This is a two-year market. Typically in such market, once you secure a contract, there’s a short window to get your asset online, six months in this case. For this demonstration project it is not expected to be economic to build new generation. For new resources, we’ll have to consider more enduring programs, possibly with conditional roll-outs. The point here was to gather more evidence about DER behaviour from a system perspective, to determine if this approach would be economic. It appears to be so, and it now seems like we have a good opportunity to push the system boundaries, encourage collaboration with the regulator – and to tie in with climate initiatives as well, as part of a move toward net zero while delivering net benefit for ratepayers.

 

 

 

Acronyms used in this report:

 

DERMS: Distributed Energy Resource Management System

 

DMS: Distribution Management System

 

DSO: Distribution System Operator

 

SCADA: Supervisory Control and Data Acquisition

 

TSO: Transmission System Operator

 

NRCan: Natural Resources Canada

 

 

 

 * * *

 

 

 

For more information, see these pages on the IESO, Alectra and APPrO websites:

 

https://www.alectra.com/nwa

 

https://www.ieso.ca/en/Sector-Participants/Engagement-Initiatives/Engagements/IESO-York-Region-Non-Wires-Alternatives-Demonstration-Project

 

Slide deck from the NRCan presentation to the APPrO 2020 conference

 

 

 

Conference registrants can see the video and access presentation materials on the APPrO conference app at this location:

 

 

 

APPrO plans to host discussion on related questions at the upcoming 33^rd Canadian Power Conference on November 29 and 30, 2021 including sessions focused on DERs and the York Region Demonstration Project.

 

 

 

 

 

 

 

***

 

 

 

A version of this article is also published on LinkedIn at this location.

 

 

 

This article represents the views of the author. It is intended to prompt further discussion and may not reflect the position of APPrO or of any APPrO member.