«18 Month Outlook An Assessment of the Reliability and Operability of the Ontario Electricity System FROM APRIL 2015 TO SEPTEMBER 2016 18-Month ...»
2.4 Updates to Operability Outlook The Outlook for surplus baseload generation (SBG) conditions over the next 18 months uses the updated planned generator outages. The generator outage plans are submitted by market participants to the IESO’s IOMS. This Outlook is based on submitted generation outage plans as of February 13, 2015.
3 Demand Forecast The IESO is responsible for forecasting electricity demand on the IESO-controlled grid. This demand forecast covers the period April 2015 to September 2016 and supersedes the previous forecast released in November 2014. Tables of supporting information are contained in the 2015 Q1 Outlook Tables spreadsheet.
Electricity demand is shaped by a several factors which have differing impacts. These factors can be grouped into those that increase demand (population growth and economic expansion), those that reduce demand (conservation and embedded generation) and those that shift demand (time of use rates and the Industrial Conservation Initiative [ICI]). How each of these factors impacts electricity consumption varies by season and time of day.
Grid-supplied energy demand is forecasted to remain virtually flat over the forecast horizon.
Growth in 2015 is projected to be small (0.1%) and much of the growth in 2016 (0.5%) will be due to the additional “leap year” day. Economic expansion and population growth will offset much of the reductions stemming from increased embedded generation and conservation savings over the forecast horizon.
Peak demands are subject to the same forces as energy demand, though the impacts vary. This is true not only when comparing energy versus peak demand, but also in comparing the summer and winter peak. Summer peaks are significantly impacted by the growth in embedded generation capacity and pricing impacts (ICI and time-of-use rates). The majority of embedded generation is provided from solar powered facilities that have high output levels during the summer peak period and no output during the winter peak periods. Over the shoulder periods the timing of the peak hour and sunset are moving so the impact of embedded solar will vary.
The ICI will have interesting impacts on winter and summer peaks in 2015 due to the fact that the program does not run on a calendar year but from May to April. The ICI impacts for May 2014 to April 2015 will have generally materialized in January 2015 as the summer of 2014 was so mild. With the return of more typical weather the ICI impacts for May 2015 to April 2016 will most likely be observed in the summer of 2015. As a result, both the winter and summer peaks of 2015 will be subject to ICI reductions.
Minimum demand levels are similarly impacted by these same forces – primarily economic activity and embedded generation. The recession had led to lower levels of industrial activity, particularly overnight and on weekends due to reductions in the number of shifts. Although most embedded generation is solar, embedded wind generation contributes to lower minimums by supplanting grid-supplied electricity. However, offsetting some of this downward pressure on minimums there is a significant price incentive to shift load to overnight hours. Over the forecast, a relatively small increase in embedded wind generation and modest economic growth and load shifting will lead to a small increase in minimum demand levels over the forecast.
The following tables show the seasonal peaks and annual energy demand over the forecast horizon of the Outlook.
3.1 Actual Weather and Demand Since the last forecast the actual demand and weather data for November, December, and January have been recorded.
November November’s temperature was colder than normal ranking it in the top ten of the past 30 • Novembers. As a result, Ontario’s energy demand for the month was 11.5 TWh (11.3 TWh weather corrected). The actuals and weather corrected values were the lowest since 1997.
The November peak occurred on the ninth coldest day of the month as the cold weather • generally landed on the weekends. Despite this the peak was 20,102 MW (21,298 MW March 23, 2015 Public Page 5 18-Month Outlook Update weather corrected as the peak didn’t occur on the coldest day). These peaks are consistent with the levels seen since the recession.
Wholesale customers’ consumption for the month decreased by 1.6% compared to the • previous November.
December December was milder than normal. Monthly energy demand was 12.2 TWh and bumped • up to 12.4 TWh after correcting for weather. Both values are low by historical standards for December.
The peak occurred on December 2, which was the third coldest day of the month but was • preceded by and followed by rather mild days. Therefore, the peak was a rather modest 20,938 MW (21,322 MW weather corrected). This was lower than last December but an increase over 2012. There was a “cold snap” later in the month but it occurred over the holiday period and therefore did not generate high peak demands.
Wholesale customers’ capped off a negative quarter with consumption dropping by 1.4% • compared to December 2013.
January The weather for January was colder than normal. Energy demand for the month was •
13.1 TWh (12.8 TWh weather corrected) which is low by historical standards. The actual was the second lowest and the weather corrected the lowest January since market opening.
Whereas the month was colder than normal, the peak temperature was just slightly colder • than normal. The peak demand for the month was on the coldest day and was 21,814 MW (21,531 MW weather corrected). These are quite low by historical standards for January, but this year was different as the ICI significantly reduced the January peak. This was the first time that the ICI was “in play” during the winter.
Wholesale customers’ consumption continued the weakness of the last quarter of 2014 into •
2015. Year over year consumption fell by 3.2%.
February The weather for February was significantly colder than normal. Energy demand for the • month was 12.3 TWh, the highest February since 2008. However, the weather corrected value was a much more modest 11.5 TWh, which is consistent with the relatively flat levels of demand since the recession.
The peak for the month was 21,494 MW, which was lower than last year’s February peak.
• However, this year’s peak was significantly impacted by the ICI. The weather corrected value of 20,132 MW was low by historical standards, but that was partially due to the ICI impacts. The peak occurred on February 19th,which was the second coldest day of the month and during a course of a “cold snap”.
Wholesale customers’ consumption continued to decline, falling 4.7% compared to the • previous February. That marked five consecutive months of contraction.
March 23, 2015 Public Page 6 18-Month Outlook Update Overall, energy demand for the four months from November to February was down 2.1% compared with the same four months one year prior. After adjusting for the milder weather, demand for the four months showed much larger decline of 2.7%.
For the four months, wholesale customers’ consumption posted a 2.7% decrease over the same months a year prior with Pulp & Paper, Iron & Steel and Petroleum Products accounting for most of the reductions.
The 2015 Q1 Outlook Tables spreadsheet contains several tables with historical data. They are:
1 Weekly Weather and Demand History Since Market Opening • Table 3.3.
2 Monthly Weather and Demand History Since Market Opening • Table 3.3.
3 Monthly Demand Data by Market Participant Role.
• 3.2 Forecast Drivers Economic Outlook The wild volatility in global markets over the past few months should eventually bode well for Ontario’s economy. Lower energy prices and a lower dollar should benefit Ontario’s export oriented industrial sectors. Once markets stabilize, Ontario should show stronger growth than in recent years. Look for activity to pick up in the latter half of 2015. Despite a strong period of growth in 2014, the industrial sector ended the year on a weaker note. As energy prices and the dollar stabilize Ontario should be able to capitalize on stronger U.S. growth.
Wholesale customers’ electricity consumption had shown consistent growth since August 2013 before tailing off in the final quarter of 2014. As mentioned above, the level of activity should pick up for this sector throughout 2015.
Ontario’s economy should see improved growth in 2014 and 2015. Table 3.3.4 of the • 2015 Q1 Outlook Tables presents the economic assumptions for the demand forecast.
Weather Scenarios The IESO uses weather scenarios to produce demand forecasts. These scenarios include normal and extreme weather, along with a measure of uncertainty in demand due to weather volatility.
This measure is called Load Forecast Uncertainty.
5 of the 2015 Q1 Outlook Tables presents the weekly weather data for the • forecast period.
3.3 Demand Response, Conservation and Embedded Generation Demand response programs, conservation initiatives and embedded generation can all impact demand over the forecast horizon. Demand response (DR) can be defined as the changing of electricity consumption by end-use customers in response to market prices or market signals.
Ontario’s 2013 Long-Term Energy Plan assumes that DR will play a more significant role in the future.
Using the definition above, DR is comprised of five programs: peaksaver®, dispatchable loads, Demand Response 3 (DR3), time-of-use (TOU) tariffs and the Industrial Conservation Initiative (ICI). However, for the purposes of the 18-Month Outlook, peaksaver®, dispatchable loads and March 23, 2015 Public Page 7 18-Month Outlook Update DR3 are treated differently than TOU or ICI. Demand Measures (DM), which include peaksaver®, dispatchable loads and DR3, are treated as resources that can be dispatched in the same way that generators are. TOU, ICI, conservation impacts and embedded generation output are factored into the demand forecast as load modifiers.
3.3.1 Demand Measures There are a number of changes occurring to demand measures over the 18-Month Outlook period. Existing DR3 resources, which began the transition into IESO’s Capacity Based Demand Response (CBDR) program in March 2015, are contracted for multi-year terms, expiring at the latest, in 2018.
A DR Auction is currently being developed by the IESO to maintain the existing DR Capacity and to replace the existing practice of multi-year contracting with a more cost-competitive mechanism. The first DR Auction is expected to be held in December 2015 with a delivery date of May 2016. Discussions with stakeholders about the development of the DR Auction are underway; details can be found on the DR Auction Stakeholder Engagement page on the IESO’s website.
The IESO is interested in learning about how DR can play an expanded role in meeting the needs of Ontario’s electricity system. Specifically, the IESO seeks to evaluate the capabilities of DR for both responding to five minute and hourly load changes in the real-time energy market and committing to load curtailment day ahead or three hours ahead of real-time in return for certain guarantees. To support this goal, the IESO will be procuring up to 100 MW of priceresponsive consumption capability from demand-side resources to participate in pilot projects.
These pilot projects will also help identify opportunities to enhance participation of DR in meeting our existing system needs. The pilot will be launched via a competitive Request for Proposal (RFP) in early 2015.
In terms of the demand forecast, the actual impacts of these programs are added back to the demand and the forecast is based on demand prior to the impact of these programs. The total demand measure capacity is discounted based on historical performance and contract data, to reflect the reliably available resource capacity which is then included in the resource portfolio.
3.3.2 Load Modifiers Conservation, TOU, ICI and embedded generation are accounted for in the demand forecast.
Conservation will continue to grow throughout the forecast period, and the demand forecast is decremented for the impacts of conservation. The impact of TOU rates and ICI are factored into the demand forecast as they have a downward impact on peak demands.
Embedded generation capacity will continue to grow over the forecast horizon. The forecast of grid supplied electricity is directly impacted by the growth of distribution connected generation as it supplants the need for bulk system power. The forecast accounts for the growth in embedded generation production.
- End of Section March 23, 2015 Public Page 8 18-Month Outlook Update 4 Resource Adequacy Assessment This section provides an assessment of the adequacy of resources to meet the forecast demand.
When reserves are below required levels, with potentially adverse effects on the reliability of the grid, the IESO will reject outages based on their order of precedence. Conversely, an opportunity exists for additional outages when reserves are above required levels.
The existing installed generation capacity is summarized in Table 4.1. This includes capacity from new projects that have completed commissioning and the market entry process.
Table 4.1: Existing Generation Capacity as of February 13, 2015
During this Outlook period, the IESO is moving forward with the second phase of its energy storage procurement. Qualified applicants will be selected, and a draft RFP will be issued shortly after. The IESO is seeking a broad range of technologies that can provide the best longterm benefits.
The Phase II storage RFP for 16 MW will allow the IESO to build on its previous procurement by expanding its storage portfolio and creating new learning opportunities. In 2014, the IESO completed the Phase I RFP for 34 MW of its current storage procurement. The first of these will come into service during this outlook period.
The IESO initially procured six megawatts of storage—a battery and flywheel to provide regulation service—in 2012. These two projects are now operational.