Back in January, I suggested 2016 was the year for wholesale power market reform. So, was it? While shifts in these kinds of institutions take longer than one year, we’ve seen real progress on the four factors that made 2016 a turning point, and we believe progress will continue in 2017.
America’s electricity mix continues to churn. A trend of 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, and in 2016 some regulators gave in to the temptation of supporting old facilities in wholesale markets. Take FirstEnergy’s bid to re-regulate in the face of stiff wholesale market competition for its coal and nuclear facilities, 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, policymakers must pay particularly close attention to proposed wholesale power market changes. Most proposals will invoke reliability, but forward-looking market improvements for reliability will expose the value of grid services we’re likely to need in the future while 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 capable of providing valuable grid services.
The Federal Energy Regulatory Commission (FERC, the agency that governs America’s wholesale markets) and some of the forward-thinking regional markets are making moves to build new ways to support system reliability and flexibility during this transition period. But plenty more can be done to build markets optimizing a clean portfolio of energy resources at least cost. Despite three of five FERC seats being open in 2017, we remain optimistic the new commissioners will stay true to the FERC charter and uphold the free market principles that make these markets work.
2016’s four factors are still quite relevant, and will continue driving change in 2017:
The opportunity: Markets can expose the value of optimizing both power supply and demand
The ability to balance 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 syncs with the rhythm of natural weather systems.
FERC took two big steps in 2016 to co-optimize supply and demand. First, the commission issued a rule requiring wholesale markets to settle every 5 minutes. This bolsters flexibility since dispatching and paying market participants on shorter intervals values flexible resources able to quickly respond to price signals. Second, FERC proposed a new rule last month to knock down barriers preventing distributed resource participation in wholesale markets. This proposed rule highlights the need to update outdated market design details prohibiting certain resources like energy storage and demand response from participating in markets and getting paid for the valuable services they can provide.
Still, more work remains to be done. For example, dispatchable demand response is not yet fully integrated into real-time grid operations anywhere in the country. In 2014, Texas market operators began enumerating the challenges to overcome to get demand-response into traditional real-time dispatch algorithms. Since then, California and New York market operators have taken initial steps toward building demand response into real-time operations. Hopefully, given today’s big data capabilities and the growth of businesses able to provide reliable, dispatchable demand response, market operators can solve this challenge 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 with capacity right now, putting downward pressure on wholesale market prices. As a result, well-functioning markets will edge certain uneconomic plants out of the system. Wholesale market operators may be tempted to change 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 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.), allowing all resources to compete evenly and provide those services at least cost. This will 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 and uneconomic plants. Existing plants able to provide valuable services will survive, provided they are cost competitive with new technology options.
Innovative market products are enabling market operators to value the capabilities 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 can 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: This new product is designed to improve reliability while ensuring resources capable of ramping quickly get paid for that valuable service.
Of course, as markets adjust to oversupply by leaving behind some generators, policymakers must consider reliability and transition assistance for workers and communities affected by plant closures. Luckily, evidence is growing that markets will be quite capable of maintaining reliability as old units shut down and are replaced by portfolios of cleaner resources.
A recent 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), because of other resources under construction, planned, or possible in the near-term. And, providing future-oriented job training programs or pensions for displaced workers is a less expensive way to support affected workers and communities than continuing 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 business model given all the changes we are witnessing, but more specific and clear proposals are badly needed.
New York and California are have begun running up against some of these questions. In New York, the Public Service Commission began a process to turn utilities into market platform providers for distributed energy resources. Since New York prohibits utilities from owning these resources, the commission plans to optimize the system via market-based pricing that will interact with wholesale market prices. We can expect more of the details of those interactions between distribution and bulk transmission level prices to be worked out in 2017. California utilities are also piloting distributed energy resource auctions to compete with centralized generation in providing local capacity, but exactly how 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 enabling more resources to participate in the markets and trade more flexibility. One change already helping 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 to be effective, and the mechanism is now spreading across the nation, especially as regional market operators look to implement FERC’s 5-minute settlement rule.
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.
These steps will each advance the conversation about balancing supply and demand, valuing flexibility, and enabling a more diverse set of resources to participate in the market. 2016 saw many positive steps forward, but far more progress is needed in 2017 (and beyond) to future-proof America’s power markets.
Sonia Aggarwal directs America’s Power Plan.