Energy market offer flexibility project explained: Q&A with Vamsi Chadalavada, ISO-NE’s executive VP and COO

Vamsi Chadalavada, executive vice president and chief operating officer of ISO-NE

On December 3, 2014, ISO New England completed major enhancements to the region’s wholesale energy market that will allow for more accurate price signals in the market and improve power grid reliability. View the press release, and continue reading to learn from Vamsi Chadalavada, ISO New England’s executive vice president and chief operating officer, about the Energy Market Offer Flexibility project, the reasons for undertaking such a massive project, and the benefits to the region’s wholesale electricity markets and to power system reliability.

What is the Energy Market Offer Flexibility project?
The Energy Market Offer Flexibility Project is the most extensive market revision the ISO has undertaken since 2003, when we launched the wholesale energy market structure that we use today. It has completely revised how resource owners submit their offers to supply energy into the day-ahead and real-time power markets.

Before we launched the hourly offer system on December 3, 2014, generator owners were limited to one offer—these offers define the amount of power they’re willing to supply, and the price at which they’re  willing to supply it—in the day-ahead market for the following day. After submitting their offer, they had only one opportunity to revise it before the operating day. During the operating day, they could not change their offers. This system worked well for a long time but, as natural gas price volatility has increased in recent years, we’ve seen more instances where generators’ actual costs of operating in real time are quite different from the costs upon which they based their day-ahead offers.

The new system gives generators the necessary flexibility—now they can submit a different offer for every hour of the following day and also update their offers during the operating day in the real-time market if the price of their fuel changes. We expect these enhancements will positively impact power system reliability because they will foster more accurate price signals in the wholesale energy markets, which in turn will provide incentives to resources to generate electricity when we need it, and help attract and retain the resources needed to meet consumer demand.

Another key change is that the market parameters have been expanded to include negative offers. Before, the minimum offer was $0 per megawatt-hour (MWh). Now, resources can provide power at prices as low as -$150/MWh—or, to put it another way, they can PAY as much as $150/MWh to stay online and produce power.

The ISO dispatches the lowest-cost resources first to meet demand, consistent with system reliability needs. There are times—usually in the very early hours of the morning—when more electricity is being generated than needed, but supply and demand must always be in near-perfect balance. On these occasions, the ISO needs to reduce the amount of electricity being produced. When this situation occurs, prices dip very low, and sometimes would be administratively set to $0 by the ISO to provide the incentive for resources to stop generating. However, our operating experience has shown that even at $0/MWh, certain resources want to stay online and continue to generate electricity. These resources, such as wind plants, have low or no fuel costs and may also be eligible for other financial incentives, such as tax credits, for producing electricity. Submitting a negative offer will help ensure the resource is selected to run, even when demand is very low. When prices are in the negative range, other types of resources will not want to run. This will avoid situations where there’s too much generation on the system.

How do hourly offers work?
Under the new system, resources can submit a different supply and price offer for every hour of the following day, which means they can submit as many as 24 different offers in the day-ahead market for the next day, the operating day. They also have one opportunity to change each of those offers in the day-ahead market, during the reoffer period. And during the operating day itself, they can update each hour’s offer up to 30 minutes before the hour begins.

With this ability, resources’ offers are reflecting their true cost of providing power to the system. Resources know what their costs are, and will submit prices that are more accurate; before, they may have included in their supply offer an estimation of what their fuel cost might turn out to be. Pricing accuracy and greater certainty that actual costs will be recouped are important elements of a well-functioning market; these will act as incentives for resources to generate power when needed, and to stay in the market. That’s acutely important now because New England is facing more power plant retirements that are eroding the capacity to meet resource adequacy requirements.

You said it’s “the most extensive market revision since 2003.” Can you explain what was involved?
Virtually every software application and department at the ISO was affected in some way. Most significantly, the systems running the Day-Ahead and Real-Time Energy Markets, system dispatch, and billing and collections were extensively revised. The software revisions had to enable resources to change data up to 24 times, twice, in the day-ahead market and up to 24 times in the real-time market. Also, a change in supply offers made into the market can also mean a change in how the system is dispatched. Obviously, that’s significantly more complex than the previous system. 

The ISO acts as a clearinghouse for market participants, handling billing for generators, demand-response providers and transmission owners and collections from load-serving entities. Instead of one or two prices and quantities for a day, our settlements systems now have to be capable of crunching the numbers for 24 hours in the day. In a similar vein, the Internal Market Monitoring department has to be able to review every offer to determine if it is consistent with input costs, which change at least as often as the offers change.

This massive undertaking began more than two years ago, when the ISO first brought the proposal to revise the market rules to committees of stakeholders, including people in the industry, policymakers and regulators, and consumer advocates and other end-users. The New England Power Pool (NEPOOL, the organization of market participants) and the ISO jointly filed the Energy Market Offer Flexibility proposal at the Federal Energy Regulatory Commission in July 2013. As soon as the commission issued its order approving the proposal, in October, 2013, we began working closely with Alstom, the company that provides the ISO’s suite of systems covering reliability and markets, to revise those systems. About 120 ISO employees from almost every department worked on the project, contributing 120,000 staff hours to revise home-grown ISO software applications, rewrite code, test revised applications, train internal and external stakeholders, and ensure market participants’ software systems would interact correctly with the new systems.

We‘re very grateful for the valuable input from our stakeholders, who helped us develop and refine the new rules, and who participated in training and testing in advance of implementation, ensuring a smooth transition to the new system.

Why did the ISO undertake this massive project?
At the highest level, resources that are meeting a critical system need should be able to, at a minimum, recover their costs. When that happens, market prices more accurately reflect the realities of generating electricity and meeting demand, and the incentives to produce power are more closely aligned with the demand for power.

To explain the drivers for this project, we have to go back a few years. The hourly offers project grew out of the Strategic Planning Initiative, which the ISO launched in 2010 to identify and address the key issues that threatened the continued reliability of New England’s power system. We identified the region’s dependence on natural gas for electricity production as a key risk; this risk has become even more pronounced in the rapidly transforming industry landscape of recent years.

Currently, about half the electricity produced in New England is generated by power plants that burn natural gas. If natural gas generators had access to an unlimited supply of natural gas, that dependence would not be a major challenge by itself. But here in New England, when demand for natural gas is peaking, which happens in the winter, the natural gas pipelines feeding the region are not able to deliver enough gas to meet demand for both heating purposes and power generation. Natural gas generators often have trouble getting fuel, particularly on very cold days, and our system operators have already experienced serious challenges to maintaining reliability. While our focus is on a reliable power system, the natural gas pipeline constraints also cause gas price spikes which, in turn, have caused wholesale electricity prices to spike.

Now we have a set of interconnected challenges. First, a significant portion of the generating fleet is sometimes unable to get fuel at critical times. Then, we’ve seen declining resource performance, especially among some of the older fossil-fuel-fired power plants. Third, nearly 3,500 megawatts of coal, oil, and nuclear generation have retired or will soon be retiring from the system. The end result is serious power grid reliability challenges. These reliability challenges and price volatility are only going to get more severe until more natural gas infrastructure is added, because the replacement capacity for these retiring generators is most likely to be more natural-gas-fired generators.

This background brings us to the reason the ISO moved to modify the market design and introduce hourly offers. The pipeline constraints have led to great volatility in natural gas prices, especially in winter when gas is in greatest demand. Under the old market rules, natural-gas-fired and other generators would submit their offers to supply power at a certain price based on the cost of fuel, for the following day. By the next day—the operating day—the price of natural gas had sometimes changed; and it was also changing throughout the course of the day. Under the previous system, generators were locked into a price that often had become obsolete by the time they were required to run, and many times they were running at a loss. We looked to hourly offers to address the problem and restore the incentives that an efficient marketplace should provide—that is, prices that reflect the cost of production.

How’s the new system been working out?
The new market has been working very well, especially given the sheer complexity and number of computer systems involved. There have been a few minor glitches, which is to be expected in a project of this magnitude, but so far, the system has run as designed. In fact, after being up and running for less than two days, the new software experienced a real-life “stress test.” On December 4, a capacity deficiency occurred on the grid, and the software performed well.

Are lots of market participants using the capability? Are they changing their offers all the time?
Many market participants are changing their offers as natural gas prices go up and down. Some have even submitted negative offers and negative pricing has occurred on a few occasions since the beginning of December. Of course, there are some resources that are likely to retain the same offers for longer periods of time—those with stable fuel costs may not need to update their offers very often.

Will generators ever revise their offers downward if their fuel price drops?
Yes. And the market monitoring department continues to screen offers to ensure they are consistent with the resource’s costs.

When we launched the standard market design in 2003—the markets as they’re currently structured, with locational pricing in eight zones, and the addition of the day-ahead market—why wasn’t hourly offer capability included?
At that time, fuel costs were more stable, and there wasn’t a need for a generator to have the ability to refine and change supply offers so frequently. In addition, the technical capabilities were not far enough along to take the plunge back then.

Features & Interviews
natural gas, wholesale markets, wholesale prices