19th Annual Electric Market Forecasting Conference to Focus on the Future of Energy Markets

The 2016 Electric Market Forecasting Conference (EMFC), a leading gathering of industry strategists and executives, will feature in-depth discussions on the driving forces of today’s energy markets. The 19th annual conference, organized by EPIS, LLC, will bring together a stellar lineup of speakers as well as senior executives in the industry.  The EMFC will be held at the Atlanta Evergreen Marriott Conference Resort in Atlanta, Georgia, September 14-16, 2016.

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The EMFC features an optional one-day pre-conference training for both new and advanced power market modelers, as well as an AURORAxmp Users’ Group Meeting. Both clients and non-clients are welcome to attend. The two-day conference will include presentations and case studies from industry experts, as well as special events and networking opportunities. Speakers include: Larry Kellerman, managing partner of Twenty First Century Utilities, Morris Greenberg, managing director of gas and power modeling at PIRA Energy Group and Jeff Burleson, VP of system planning at Southern Company. A full list of speakers is available at http://epis.com/events/2016-emfc/speakers.html.

“Over the past 19 years, the Electric Market Forecasting Conference has become established as a valuable, strategic gathering for clients and non-clients alike,” said Ben Thompson, CEO of EPIS. “It is an event where executives and peers in the industry gather to share market intelligence and discuss the future of the industry.”

EMFC has developed a reputation for being an event that delivers real, actionable intelligence, not just abstract concepts. The organizers focus on an agenda filled with speakers who can share experience and takeaways that can be used to have a positive impact on attendees’ organizations. The conference’s intimate environment allows participants to create lasting relationships with peers and luminaries alike.

Now in its 19th year, EMFC is an essential conference for power industry professionals to come together to share best practices and market intelligence. The one-day pre-conference allows AURORAxmp users to learn techniques to master the AURORAxmp application and maximize ROI. More information can be found at: http://epis.com/events/2016-emfc/index.html.

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Living in the Past?

Living in the past is not healthy. Is your database up-to-date? EPIS just launched the latest update to the North American Database, version 2016_v4, marking the fourth North American data update this year! Recent changes in the power industry present challenges to database management which will be discussed in this post.

In general, the transformation in power generation sources in the U.S. coupled with evolving electricity demand and grid management represents a paradigm shift in the power sector. In order to accurately model power prices in the midst of such change, one must have a model built on fundamentals and a database that is up-to-date, has reasonable assumptions, is transparent and is flexible. A recent post described the technical side of working with databases in power modeling. This entry outlines important changes in the East Interconnect, the impacts those changes have on data assumptions and configuration and the steps we are taking to provide excellent databases to our clients.

Recent shifts in power generation sources challenge database assumptions and management. New plant construction and generation in the U.S. are heavily weighted towards renewables, mostly wind and solar and as a result, record generation from renewables has been reported across the East Interconnect. Specifically, on April 6, 2016, the Southwest Power Pool (SPP) set the record for wind penetration:

Record Wind Penetration Levels 2015

Figure 1. Record wind penetration levels in Eastern ISOs compared with average penetration in 2015. SPP holds the record which was reported on April 6, 2016. Record sources: NYISO, SPP, MISO, ISO-NE, PJM. 2015 Averages compiled from ISO reports, for example: NYISO, SPP, MISO, ISO-NE, PJM. *Average 2015 generation used to calculate penetration.

Similarly, the New York City area reached a milestone of over 100 MW in installed solar distributed resources. Accompanying the increase in renewables are increases in natural gas generation and reductions in coal generation. In ISO-NE, natural gas production has increased 34 percent and coal has decreased 14 percent since 2000, as highlighted in their 2016 Regional Electricity Outlook. These rapid changes in power generation sources require frequent and rigorous database updates.

Continued electric grid management changes in the East Interconnect also requires flexibility in databases. One recent change in grid management was the Integrated System joining the Southwest Power Pool, resulting in Western Area Power Administration’s Heartland Consumers Power District, Basin Electric Power Cooperative and Upper Great Plains Region joining the RTO. The full operational control changed on October 1, 2015, thus expanding SPPs footprint to 14 states, increasing load by approximately 10 percent and tripling hydro capacity. Grid management change is not new, with the integration of MISO South in 2013 as an example. Changes such as these require flexibility in data configuration that allow for easy restructuring of areas, systems and transmission connections.

Variability in parameters, such as fuel prices and demand, introduce further difficulty in modeling power markets. The so called “Polar Vortex” weather phenomena shocked North Eastern power markets in the winter of 2013/2014 with cold temperatures and high natural gas prices resulting in average January 2014 energy prices exceeding $180/MWh in ISO-NE. It seemed like the polar opposite situation occurred this last winter. December 2015 was the mildest since 1960, and together with low natural gas prices, the average wholesale power price hit a 13-year low at $21/MW. The trend continued into Q1 of 2016:

Monthly average power price in ISO-NE Q1 2014 and 2016

Figure 2. Monthly average power price in ISO-NE in Q1 2014 and 2016. Variability between years is a result of high natural gas prices and cold weather in 2014 versus low natural gas prices and mild weather in 2016.

Whether extreme events, evolving demand or volatile markets, capturing uncertainty in power modeling databases is challenging. In AURORAxmp, users can go one step further by performing risk simulations; specifying parameters such as fuel prices and demand to vary across a range of simulations. This is a very powerful approach to understanding the implications of uncertainty within the input data.

The aforementioned changes in generation, grid management and demand, offer exciting new challenges to test power market models and data assumptions. To test our platform, EPIS performs a historical analysis as a part of each database release. Inputs of historical demand and fuel prices are used to ensure basic drivers are captured and model output is evaluated not only in terms of capacity, but monthly generation, fuel usage and power prices. The result of this process is a default database that is accurate, current, contains reasonable assumptions, is transparent and is flexible to ensure you have the proper starting point for analysis and a springboard for success.

With the release of North_American_DB_2016_v4, EPIS continues to provide clients with superb data for rigorous power modelling. The 2016_v4 update focuses on the East Interconnect and includes updates to demand, fuels, resources, DSM and other miscellaneous items. Clients can login to our support site now to download the database and full release notes. Other interested parties can contact us for more information.

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Uncertainty for ERCOT Markets

AURORAxmp data is ready to take on the unpredictable nature of ERCOT’s markets.

The ERCOT reserve margin is by no means certain in 2016. According to the latest NERC 2015 Long-Term Reliability Assessment, ERCOT is showing a healthy reserve in the summer of 2016. However, NERC and others have had a tendency to miss the target in regards to reserve margin in this region. Reviewing projections for the 2015 summer period, the NERC Summer Reliability Assessment showed anticipated reserves in ERCOT of 16.24%, and the final Seasonal Assessment of Resource Adequacy (SARA) from ERCOT agreed that the region was expected to have sufficient capacity to meet peak demands with a 14.26% margin. Interestingly, the final forecast was an abrupt change from the preliminary forecast issued only 2 months prior which anticipated an 11.45% margin, or a 2% shortfall of the NERC reference margin of 13.75%. According to the final report:

The ERCOT Region is expected to have sufficient installed generating capacity to serve forecasted peak demands in the upcoming summer season (June – September 2015)… The primary reason for this change is the summer weather forecast, which generally indicates milder conditions than the 12-year normal forecast used in the Preliminary Summer SARA. As a result, the demand forecast for summer has decreased…

However, a few months later, ERCOT announced in a press release that it experienced its highest peak demand on record, “For the first time in this grid operator’s history, hourly demand within the Electric Reliability Council of Texas (ERCOT) system today broke the 69,000 MW threshold…”. Days later, in another press release, ERCOT reported the record peak was broken again by over 800 MW. Ultimately ERCOT missed the mark in its final, more optimistic report, and this shows how volatile projections can be. Not to say that NERC, FERC, ISO or RTO assessments aren’t excellent tools for understanding some of the fundamentals of a market, it’s just important to remember how significantly reality can differ from constantly changing expectations and how important it is to do analysis around the key fundamental drivers.

Once again, ERCOT has released its latest demand forecast. Has it overstated its margin once again? That question is enough to make one pause. Compliance extensions filed in 2015 for over 5 GW of Mercury and Air Toxic Standards (MATS) forced retirements, expire in 2016. Will they all be compliant and stick around or were they just hoping to operate one more year before finally deciding to retire? A lot of unknowns, but certainly the situation in ERCOT could be much tighter than some of these assessments suggest. With so much going on in 2016 for ERCOT, this year could be a pretty wild ride.

We are in the midst of a large ERCOT update of resources and demand that will be coupled with the latest ERCOT nodal case. Our data is net up in supply, but this is accompanied by an increase in the demand forecast. We have also added demand response units to capture their paramount importance to proper modeling of the system.  This database release is due out in Q1 2016 and is ripe for 2016 summer analysis.  Couple this with AURORAxmp’s risk analysis and you’ll be prepared for the market’s uncertainties.

For additional information, please contact us

Filed under: Power Market InsightsTagged with: , ,