A version of this article was originally published on December 22nd, 2016 on Greentech Media.
By Sonia Aggarwal
Back in January, I suggested 2016 was the year for wholesale power market reform. So, was it? OK, of course shifts in these kinds of institutions take longer than one year, but 2016 has seen real progress and there’s a good chance it will continue in 2017 and beyond.
The electricity mix continues to churn. A trend to less energy-intensive economic growth is combining with policy support for wind and solar to produce an oversupply situation. Markets are adjusting by pushing out more expensive nuclear and coal plants. 2016 saw some regulators responding to a temptation to support old facilities in wholesale markets. Take FirstEnergy’s bid to re-regulate in the face of stiff competition for its coal and nuclear facilities in the wholesale market, for example. But the whole idea of competitive markets, promoted by the likes of FirstEnergy themselves, was to shift risk onto independent power producers and allow them to earn upside…or face downside.
During this period of transition, it is particularly important for policymakers to pay close attention to proposed changes in wholesale power markets. Most proposals will invoke reliability. But forward-looking market improvements for reliability will focus on exposing the value of grid services we are likely to need in the future, and finding ways to pay whichever resources are capable of providing them. These market improvements may cause some old plants to retire, but they will also create new revenue streams for existing units—and cost-effective new resources—that are capable of providing valuable grid services.
The Federal Energy Regulatory Commission (FERC, the agency that governs America’s wholesale markets) and forward-thinking regional markets are making moves to get in front of all of this, building new ways to support system reliability and flexibility during this period of transition. But there is plenty more to be done if we are to land on a market that optimizes a clean portfolio of energy resources at least cost. Despite three seats being open in the new year, many remain optimistic that the new commissioners will remain true to the FERC charter and uphold the free market principles that make these markets work.
The four factors in the article from earlier this year are still quite relevant:
The opportunity: Markets can expose the value of co-optimizing power supply and demand
The ability to co-optimize supply and demand will grow in importance as variable renewables become a larger share of the electricity mix. Time-shifting resources like demand response and storage can help tremendously as the power system entwines with the rhythm of natural weather systems.
This year, FERC took two big steps to move us forward on co-optimizing supply and demand. First, the commission issued a rule requiring wholesale markets to settle prices every five minutes. This is great news for flexibility since dispatching and paying market participants on shorter intervals values flexible resources that can respond to price signals quickly. And just last month, FERC proposed a new rule that would knock down barriers to distributed resource participation in wholesale markets. This proposed rule highlights the need to update outdated market design details that have prohibited certain resources, particularly new technologies and demand-side resources, from participating in markets and getting paid for all the valuable services they can provide.
Still, there is more work to be done. For example, dispatchable demand response is not yet fully integrated into real-time grid operations anywhere in the country. A couple years ago, market operators in Texas began to enumerate some of the challenges to overcome to get demand response into traditional real-time dispatch algorithms. Since then, market operators in California and New York have made progress on beginning to build demand response into real-time operations. Hopefully, given today’s big data capabilities and the growth of businesses that could provide reliable dispatchable demand response, market operators can solve challenge this in 2017.
The threat: New technology is hitting the grid — if markets don’t capture the opportunity now, they’ll have to cope later
Many parts of the U.S. are oversupplied right now, which puts downward pressure on wholesale market prices. As a result, in an oversupply situation, a well-functioning market will edge certain uneconomic plants out of the system. Wholesale market operators may be tempted to make changes to market products or market designs to ensure “sufficient” revenue flows to those old plants. But this is a Sisyphean battle.
Rather than adjusting market rules to prop up costly facilities that are no longer serving the system, markets must begin to define and expose the value of specific services needed on the grid—fast start, fast ramping, etc.—and allow all resources to compete to provide those services at least cost. That way, we can pay for the system attributes needed in the future, creating a forward-looking market with solid potential for growth, rather than contorting existing markets to support unneeded, uneconomic plants. Existing plants that can provide valuable services will survive, provided they are cost competitive with new technology options.
Some innovative market products are enabling market operators to value the capabilities that will be needed as the energy mix evolves. For example, PJM’s Regulation D product (originally created in 2012) creates a separate frequency regulation product for resources that are able to respond very quickly but may not be able to sustain energy output over long periods. Other RTOs are now considering adopting similar products. And California’s Flexible Ramping Product, implemented just last month, exemplifies another approach—it’s designed to improve reliability by paying resources capable of ramping quickly for being available.
Of course, as markets adjust to oversupply by leaving behind some generators, policymakers must pay attention to reliability and transition assistance for workers and communities affected by plant shutdowns. Luckily, evidence is growing that we will be quite capable of maintaining reliability as old units shut down and are replaced by portfolios of cleaner resources. As a recent example, a Brattle analysis shows upcoming coal retirements are unlikely to affect reliability in Texas (even though the state has one of the lowest reserve margins in the nation), given other resources under construction, planned, and possible in the near term. And as for transition assistance for affected workers and communities, in many places it will be less expensive to provide future-oriented job training programs or pensions for displaced workers than to continue to use ratepayer funds to prop up overall operations of uneconomic plants.
The need for collaboration: Utilities are grappling with new business models—understanding the value of new services can help
Given FERC’s newest proposed rule to better integrate storage and aggregated distributed resources, the question about the interface between the utility and the market operator is more critical than ever. Some utilities are making progress defining their role and their business model given all the changes we are witnessing, but more specific and clear proposals are badly needed.
New York and California have begun running up against some of these questions. In New York, the Public Service Commission kicked off a process to turn utilities into market platform providers for distributed energy resources. New York prohibits utilities from owning these resources and instead plans to optimize the system via market-based pricing that will interact with wholesale market prices. The details of those interactions between distribution and bulk transmission level prices are still being worked out. California utilities are also piloting auctions for distributed energy resources to compete with centralized generation to provide local capacity. How exactly the resulting revenue streams couple with wholesale market bidding remains to be seen.
Signs point to 2017 being the year for more concrete proposals on how to divide responsibility and activities related to integrating and pricing resources across the transmission-distribution interface.
The why now: Pilots, policies, and today’s plans will shape the next decade or more
Progress in wholesale markets can seem slow, but momentum is building for changes that enable more resources to participate in the markets, and more flexibility to be traded. One change that has helped reward flexible resources is Texas’ “operating reserve demand curve”, which increases real-time market prices in advance of triggering an official scarcity event. This has proven effective, and the mechanism is now spreading across the nation.
And out West, the Energy Imbalance Market now enables six of the region’s largest utilities to trade certain balancing services, increasing the flexibility of the region’s grid. Market benefits have topped $110 million just two years after the program first launched, and several more utilities have stated their intention to join.
And what should we expect in 2017?
If FERC’s proposed rule for storage and aggregated distributed resources is finalized early next year as expected, implementation will move to the regional markets. Each will then propose their own specific changes to their products and operations to enable more resources to participate and get paid in the market. This will advance the conversation about co-optimizing supply and demand, valuing flexibility, and enabling a more diverse set of resources to participate in the market.
One thing is for sure, 2016 saw many positive updates, but more will need to be done in 2017 (and beyond) to future-proof America’s power markets.