The Electricity Market Forum (EMF), an initiative of the Independent Power System Operator, is calling on market participants to focus on long and short term actions that will make the provincial electricity market both fairer and more efficient. The EMF was established in March 2011 to focus on operational challenges that arise under the current structure rather than on higher level issues of market structure and energy policy. Its Report, including a set of recommendations and a “Road Map,” was released in December. On the whole, Market Forum members felt the electricity market is largely working well but there was “a need for some fairly significant refinements of the electricity market.” The most significant of these deals with what the Forum sees as the need to re-orient a broader set of electricity market participants around supply and demand fundamentals. The benefits of doing so could be significant, the report says, resulting in potential savings of billions of dollars over the next twenty years.
As the Forum says in its report, “Improving efficiency in the IESO-administered markets is primarily about having a ‘higher fidelity’ energy price signal. For example, there are components of the hourly market uplift that represent the marginal cost of energy. These costs could be reflected in the HOEP but currently are not. An enhanced price signal is necessary to encourage customer engagement and to prompt action in response to actual system conditions.”
The Forum groups its Road Map initiatives into three broad categories: (i) Integrating the Changing Supply Mix; (ii) Engaging and Empowering Consumers, and (iii) Improving Efficiency. (See below for the full list of recommendations.)
Under (i): The report stresses that procurement decisions should be informed by market and power system needs and system limitations. Although there is a potential “capacity gap” arising in around 2018, that gap can be filled relatively easily if existing infrastructure is re-contracted and reconfigured. The Forum’s advice is to think carefully about adding new capacity, even targeted new capacity, saying that OPA procurement decisions need to be “informed by market and system needs and system limitations,” and suggesting that “new and existing contracts contain strong market-based incentives.” This would be one way to avoid adding to the present surplus generation situation, while filling in the anticipated demand-supply gap expected to emerge around 2018. That would benefit consumers both by putting off the cost of new procurement until needed, while reducing the cost of managing present-day surplus. The Market Forum’s facilitator, the firm of Power Advisory LLC, has estimated that the cost of 1,000 MW of new supply would be in the billions of dollars.
Second, the transition to a cleaner supply mix through the phase-out of coal and the increased reliance on less flexible forms of generation, notably wind and solar, puts increased demand on system operators to find other ways to meet flexibility requirements, such as load following and ramping. The IESO’s present tools for doing so, as the report says, are “blunt instruments that lack transparency and are often less efficient and therefore can be costly. They are best considered as temporary workarounds.” One of the suggestions is to assess the need for – and the viability of – a new ramp and/or load following ancillary service that can then operate under market rules to produce greater efficiency.
Objective (ii) would have the consumer able and incented to exercise greater control over demand, while at the same time helping the system meet its capacity and operability needs. In this vein, the IESO will launch a consultation so that it can hear from customers about the barriers to and opportunities associated with increased demand-side participation. Since most customers, even many commercial customers, are not interested in daily fine-tuning of their energy use, the means would mostly involve demand aggregation and the use of smart grid and smart home technology, tracking an enhanced price signal.
Under (iii) improving efficiency, the report says “The current Hourly Ontario Energy Price (HOEP) provides a reasonable approximation of the marginal costs of energy in the province. However, there are ways in which the fidelity of this market price could be improved. For example, there are components of the hourly market uplift that represent the marginal cost of energy. These costs could be reflected in the HOEP but currently are not. This results in a less refined HOEP, and therefore impacts the size of Global Adjustment.”
To remedy the concerns listed above, the Forum makes a number of recommendations under various headings, suggesting that the IESO review a number of its practices, for example, replacing the two-schedule price-setting system – admittedly a complex task, but one it calls overdue.
In response to the Forum’s fourth recommendation (on developing new ancillary services), APPrO member Northland Power commented that it “agrees that, to reduce CMSC payments in the IESO Market, a ramp or load following service should be made available and thus true system ramp rates can be used in the Market Schedule.”
The Forum observes that “one of the advantages of increasing price fidelity is that it should facilitate easier trade with our neighbouring jurisdictions. This will provide one more source of needed flexibility to our system.”
The Forum’s Report, recommendations and roadmap are available from the IESO at http://www.ieso.ca/marketforumreport.
More general information on the work of the EMF:
http://www.ieso.ca/imoweb/consult/evolving_ontario_electricity_market.asp
Electricity Market Forum – The recommendations
1. The IESO should review how its current programs, products, and mechanisms impact the structure of the HOEP. The purpose of this review is to identify whether the HOEP includes components that unnecessarily dampen real-time price signals.
2. The IESO should commission a review of global adjustment to allow greater responsiveness from customers for costs that are now included in global adjustment. Specifically, the review should include:
• the unbundling of global adjustment into its component parts by reference to the types of costs it recovers (for example, separating capacity from energy costs);
• allocating global adjustment components appropriately in light of these costs;
• considering the potential to expand definition of customers who are charged global adjustment on the basis of peak demand; and
• developing market mechanisms for customers and others to manage global adjustment costs (e.g. capacity mechanisms).
3. The IESO, the OPA and the OEB should jointly engage in a consultation to review the accessibility, relevance, and timeliness of information and data provided by them to market participants and policy makers.
4. The IESO should examine whether new ancillary services or changes to market design should be developed to better manage the changing supply mix. Any new products or changes should allow both generators and loads to participate. Any new products or changes should promote cost effective ways of supplying greater flexibility to the system as a way to mitigate operability challenges, particularly surplus baseload generation. New products or changes could include:
• Ramp and/or load following service;
• Co-optimization of energy/operating reserve/regulation; and
• Changes to unit commitment.
5. Any potential Market Rule changes should be coordinated with and include consideration of existing OPA contract provisions.
6. The OPA’s procurement process should seek to better ensure that:
• procurement decisions are informed by market and system needs and system limitations; and
• new and existing contracts contain strong market based incentives;
7. The OEB’s approach to determining payments to OPG’s prescribed assets and the OEB’s treatment of export transmission tariffs should be reviewed in regards to their efficiency in the market.
8. The IESO should engage in a stakeholder consultation focussed on customers (including loads, LDCs, retailers, aggregators, etc.) to understand the barriers to increased demand-side participation in order to determine the opportunities for cost-effective demand side participation in the supply of necessary system services and enhancing responsiveness to real time system conditions. This includes looking at how customers can engage in the market to cost effectively provide:
• peak management and load shifting;
• services in established IESO Administered Market ancillary services (e.g. Regulation and Operating Reserve); and
• new services or products to benefit system operability (e.g. Ramp, load following, SBG relief).
9. The IESO customer consultation should correspond with and provide input into the OPA’s review of its demand response program that is currently underway, and the development of the next generation OPA/LDC Master Agreement on Conservation.
10. The OEB’s Regulated Price Plan (including time-of-use prices), customer classifications and the structure of utility rates should be designed to provide signals that customers can rely upon to manage their electricity usage in light of system needs and costs.
11. The IESO should consider improving, amending, or replacing the two-schedule price setting system in order to improve scheduling, dispatch and pricing efficiency.
The review should include:
• addressing Congestion Management Settlement Credits;
• reducing design complexity;
• improving compatibility with other markets; and
• potential for a day ahead market.
12. The IESO should review whether there are barriers to maximizing potential benefits to Ontario from greater alignment with regional markets through intertie transactions. The scope and requirements of such a review would include identifying opportunities for electricity trade, identifying barriers and addressing feasible options for solutions. Such a review should include:
• More frequent scheduling of intertie transactions;
• Potential to trade long-term capacity and/or operating reserve; and
• Potential for load following and/or regulation services.