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How Will MOPR’s departure affect the ISO-NE market?

September 21, 2021

The Minimum Offer Price Rule (MOPR) exists to prohibit new capacity resources from offering into the market below their true, i.e. unsubsidized, costs. 

MOPR has garnered its share of controversy since it was enacted a decade ago. The rule was introduced to address the concern about “buyer-side market power.”  The concern is that an entity on the load side may have an incentive to offer supply into the capacity market at below-market prices in order to depress clearing prices, thus reducing capacity costs.   This may degrade the economics for merchant players to the point where new capacity cannot be attracted when needed and existing resources that are needed for reliability may exit the market prematurely. 

States in New England have essentially argued in recent years that MOPR infringes on their rights to determine their generation fuel mixes and unnecessarily keeps renewable resources from clearing the capacity market, requiring consumers to pay twice for capacity–once through a state procurement and a second time to purchase capacity to meet ISO-NE capacity requirements, which the state-procured resources cannot meet due to the MOPR.

In an interview on April 5, 2021, FERC Chairman Richard Glick sided with the states when he noted, “FERC has a responsibility under the Federal Power Act, essentially, to defer to the states, in terms of state decisions about what the generation resource mix should be like. But instead, we’ve implemented these MOPRs, at least in the three Eastern RTOs that have mandatory capacity markets, in a matter that really attempts to block the state clean energy policies or state energy policies in general.”

The issues at stake with MOPR are not going to be solved overnight but ISO-NE has started working on changes this month (June 2021).  As part of this effort, ISO-NE intends to eliminate MOPR with Forward Capacity Auction 17 (2026/27 commitment period).  

While the elimination of MOPR will help renewable resources to clear the capacity market and earn capacity revenues, without accompanying changes to address the price depressing effect of allowing resources to clear at prices below their true costs, the expectation is that capacity prices will plummet.  

With a few thousand MWs of state-procured off-shore wind already on the books, and thousands of MWs yet to come, it is reasonable to expect these MWs will start showing up in Forward Capacity Auctions once the MOPR has been eliminated.  That said, a set of contested changes pending at FERC could facilitate off-shore wind’s entry into the market a bit earlier if FERC sides with NEPOOL stakeholders over ISO-NE.  

In any case, ISO-NE does feel it is important to make accompanying changes that are geared toward maintaining competitive pricing in the capacity market when MOPR goes away. 

ERCOT’S Roadmap to the Future Includes Distributed Energy Resources

August 24, 2021

On July 13, 2021, ERCOT announced the delivery of its “Roadmap to Improving Grid Reliability,” a 60-item plan that addresses needed improvements to ERCOT’s electric grid with the aim of avoiding future failures like the one experienced this past February when much of the state was left without power and over 200 people died amidst record-setting winter temperatures.  

In an official press release announcing the Roadmap’s delivery, ERCOT Board member and Texas Public Utility Chairman claimed the map “puts a clear focus on protecting customers while also ensuring that Texas maintains free-market incentives to bring new generation to the state.”

The notion of the free market is one we at CPower have often discussed in explaining how the ERCOT market differs from others around the country. From its very founding, ERCOT’s energy-only market was designed to let economics, not legislation, drive the action within its marketplace. 

In the wake of February’s tragedy–and the harrowing death toll certainly qualifies the event as such–there has been a wealth of debate in Texas and throughout the US on whether ERCOT’s economically driven approach to grid reliability is the best way to avoid future grid failure.

There is one curious item in ERCOT’s 60-item roadmap that is worth pointing out to large consumer and industrial organizations in Texas.

Item 19 concerning the future of distributed generation, energy storage, and demand response speaks to both legislative and financial methods of exacting change on a grid seeking to cross the bridge to energy’s future. 

Item 19 of the roadmap reads as follows: 

“Eliminate barriers to distributed generation, energy storage, and demand response/ flexibility to allow more resources to participate in the ERCOT market while also maintaining adequate reliability”

With this item, which is “on track” according to the roadmap, we see ERCOT is well on its way to implementing an improvement to its market that is rather similar to the intent of the Federal Energy Regulatory Commission’s Order 2222, which states:

“Order No. 2222 will help usher in the electric grid of the future and promote competition in electric markets by removing the barriers preventing distributed energy resources (DERs) from competing on a level playing field in the organized capacity, energy, and ancillary services markets run by regional grid operators.”

Language like what ERCOT submitted in its roadmap with item 19 wouldn’t raise an eyebrow had it come from any other deregulated US energy market outside of Texas. 

ERCOT Grid Control center in Texas.

That’s because other state and regional energy markets must comply with Order 2222 within FERC’s mandated period of time. ERCOT does not.

Here’s why:

Because its grid is isolated from the surrounding states, ERCOT’s market does not engage in interstate commerce and is therefore not under FERC’s jurisdiction. 

Yet ERCOT appears to be on the road to creating a future marketplace that allows its grid to integrate the flexible DERs CPower and other demand-side energy management companies have been touting for years are necessary to maintain a balanced, dependable grid that is evolving to a cleaner future.  

Here we have an example of ERCOT agreeing with Federal legislation despite the truth that they are under no legal obligation to do so. 

Why? 

In the simplest of terms, Order 2222 is a piece of legislation aimed at fostering just and reasonable competition in the wholesale marketplace. 

ERCOT’s market is and always has been designed with competition in mind. Look no further than item 19’s language for proof that the future of ERCOT’s grid involves allowing more energy resources to enter the marketplace and compete, not fewer. 

ERCOT is expressly stating that it believes more distributed generation, energy storage, and demand response in its marketplace is the best way to ensure a more reliable grid for Texas and more value for its market participants. 

As the Supreme Court is fond of saying, it is written. As Texans like to say, let’s get to work and take care of business.

 

 

 

What has California Learned from the 2020 Blackouts?

August 18, 2021

The sweltering heat that raged across thirteen western states from August 14-17, 2020, had a significant impact on the tens of millions of people who experienced record high temperatures well above 100°F. The triple-digit temperatures had an historic effect on California’s electric grid, too. Consider August 17 as a case-in-point in the energy deficiency the state’s grid operator faces. 

According to CAISO’s market policy and performance vice president, Mark Rothleder, CAISO had expected the load on its grid to peak near 49,800 MW on August 17 during the 5-6 pm PT hour with available capacity near 46,000 MW, leaving a 3,600 MW shortfall.

Night-long exposure photograph of the Santa Clarita wildfire in CA. The Santa Clarita Valley mountains have drawn firefighters and emergency crews in the hills toward acton.

By 8 pm PT on the 17th, that gap would grow to more than 4,400 MW as peak load approached 47,428 MW, but capacity had fallen to around 43,000 MW due to solar generation declining with the setting sun. 

Faced with more inevitable forced outages on August 17, CAISO’s own CEO, Steve Berberich spoke before the ISO’s Board of Governors and said, “The situation could have been avoided,” and further asserted that the state’s resource adequacy program is “broken and needs to be fixed.”

A proposed decision on the future of resource adequacy in California is due in mid-June 2021.

Lack of Imports During the Heatwave

The scorching temperatures drove a massive demand for energy throughout the western US, resulting in California’s inability to import electricity from neighboring states as it typically does in the evenings when its robust solar resources go offline with the setting sun.  

In its official analysis, CAISO detailed a series of events explaining how “realtime imports increased by 3,000 MW and 2,000 MW on August 14 and 15, respectively, when the CAISO declared a Stage 3 Emergency.” but ultimately “the total import level was less than the CAISO typically receives.”

Unable to import needed electricity and hamstrung by rising demand amidst record-high temperatures, the California grid suffered its first blackouts in nineteen years. 

The Push to Address Climate Change

Californians, by and large, see the recent wildfires and heat waves that have ravaged the Golden State and wreaked havoc on its grid as events driven by climate change. 

The state’s drive toward its energy future subsequently involves not only taking steps toward making its grid resilient but doing so in a way that minimizes its climate impacts.  

The state’s three main energy organizations–The California Independent System Operator (CAISO), the California Public Utilities Commission (CPUC), and the state’s energy commission (CEC)–have been closely examining the recent grid failures and have submitted two reports (Preliminary and Final Root Cause Analysis) seeking to establish a root cause for the blackouts .   

While they may not agree on any single culprit for California’s grid woes and for the August blackouts, the big three organizations rightfully believe that establishing grid resilience and serving the state’s ratepayers are the priorities.  

Balancing Energy, Capacity, and Renewables for Grid Resiliency

California’s renewable energy resources performed as expected in 2020, despite some slanted media coverage that may have tried to pin them with the lion’s share of the blame for the August blackouts in 2020. 

California has no intention of veering from the state’s long-traveled path of developing and integrating more renewable energy into its generation mix. 

In the wake of the 2020 blackouts, the resource adequacy proceeding in California is looking at how to ensure that the state procures energy sufficiency-–

i.e. electricity needed to serve the state on a day-by-day, moment-to-moment basis–in addition to capacity sufficiency–i.e. reserves that can be called on in the event of an emergency.

The proceeding is trying to establish the optimal balance between energy and capacity that can be procured within state boundaries so it can then be determined just how much reliance should be placed on imports now and in the future. 

As is the case with other states in different energy markets around the US, California is at somewhat of a tipping point with so much of its generation mix dependent on renewables with inherent intermittency that renders them unavailable at unpredictable times in the day when the sun isn’t shining or the wind isn’t blowing.  

Like many grids facing a similar predicament, California’s grid of today and the future needs to ensure that its load begins to follow its supply, meaning that demand-side resources adopt agile flexibility that can react to sudden disruptions in electricity supply due to intermittency.

Those disruptions and foreboding heatwaves show no signs of diminishing in 2021 and beyond. It’s time for California to shore up its grid’s reliability with an energy marketplace that rewards flexible resources on the demand side.

The grid and the people it serves depend on it.

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