Here’s one thing that renewable energy industry groups and states with clean-energy goals can say about mid-Atlantic grid operator PJM’s plan to comply with the Federal Energy Regulatory Commission’s order to rework its capacity markets: It’s better than it could have been.
Last week, PJM filed its plan to comply with FERC’s December order to force all state-subsidized resources to use a “minimum offer price rule,” or MOPR, when bidding into its roughly $10-billion-per-year capacity market. FERC’s MOPR order has been roundly attacked by clean energy groups, environmental advocates, and state utility regulators and attorneys general as an effort to restrict carbon-free resources from the market and privilege fossil-fuel-fired power plants instead — a move that could raise consumer costs substantially.
But PJM’s plan has given some hope to the American Wind Energy Association and the Solar Energy Industries Association that the impact of FERC’s order may not be so dire, at least for the short term, and for certain clean-energy technologies that can prove themselves cost-competitive in some parts of PJM’s 11-state territory.
To understand why, it’s important to explain the methods that FERC’s order established to set the minimum prices that state-subsidized resources will need to use — in particular, resources that will be entering the market for the first time. That’s a critical distinction, since FERC’s order exempts the roughly 5,000 megawatts of existing renewables in PJM’s territory from the MOPR, but it does force the rule upon the roughly 38,000 megawatts of new renewables in the pipeline for the region.
Whether or not these future resources will be able to earn revenue for the capacity they will provide is the key concern for PJM member states such as Illinois, New Jersey and Maryland that have proposed zero-carbon or clean-energy mandates that could be undermined by FERC’s order.
Getting to "Net CONE"
This calculation for new resources is called the net cost of new entry, or “net CONE.” To derive it, PJM’s plan starts with publicly available data to develop an “estimate of the ‘nominal-levelized’ annual cost” to develop and build new resources, as well as annual operations and maintenance costs. That yields a gross cost of new entry, but that’s only the starting point for setting minimum bid prices.
That’s because PJM’s plan also subtracts costs that shouldn’t count toward setting a resource’s cost of new entry. For instance, PJM assumes that all new wind and solar resources will be able to earn the 30 percent federal tax credits now available to them and subtracts 30 percent from their generic “gross CONE” figures to account for that.
PJM’s plan also subtracts the energy and ancillary services revenue they can expect to earn in markets to reflect the fact that almost all resources will be earning a significant portion of their money from those real-time markets. (Resources that don’t generate electricity, such as energy efficiency and demand response, are an obvious exception to this rule.)
Finally, PJM’s plan subjects all wind and solar resources to an “assumed annual capacity factor,” which reflects PJM’s experience of each resource’s average annual output levels compared to their full nameplate capacity. That’s already a standard method for determining the capacity value of intermittent wind and solar, since their output varies from hour to hour and season to season, compared to power plants that can run at their chosen capacity around the clock.
The results of all these calculations yield a “default net CONE” figure for all potential new resources entering the PJM market, as shown in the table below from PJM’s filing. (Note that PJM’s figures for natural-gas combined cycle and combustion turbine power plants lack starting cost data because PJM has an established set of rules for applying the MOPR to those resources. Note also that PJM's costs for nuclear and coal plants may be considered moot, as no plans to build new coal and nuclear plants are on the books.)
Regional differences provide hope for solar
These final figures present significant challenges for new renewables because they will force developers of those projects to submit bids that are significantly higher than the historical clearing prices for PJM’s capacity market. By way of example, the average clearing price in PJM's last auction in 2018 came in at $140 per megawatt-day, and the previous year’s auction saw average clearing prices of $76 per megawatt-day.
In particular, offshore wind power projects have higher construction costs, and thus higher net CONE figures — in the $3,000 per megawatt-day range. This is almost certain to price them out of the market, a major challenge for PJM member states with big plans for offshore wind, including New Jersey, Maryland, and Virginia. Minimum prices for onshore wind are also high, in the $1,000 per megawatt-day range.
But the minimum prices for solar power aren’t nearly as high, Casey Roberts, staff attorney with the Sierra Club’s Environmental Law Program, noted in an interview last week. That’s largely because their upfront and ongoing costs are lower than those for wind, and because PJM assumes that they will have higher capacity factors than wind farms. That’s particularly true for tracking solar PV systems, which can maximize their hourly output throughout the day by following the sun’s course through the sky.
This means that “tracking solar, even at its default value, has a good shot at clearing in some zones,” Roberts said. “For fixed solar, that’s not so much the case — but they’re still within what I would call striking distance.”
Whether solar farms can hit that “striking distance” will very much depend on what zone of PJM’s territory they’re in, however, she said. That’s because prices in PJM’s markets vary widely between its different “Locational Deliverability Areas."
That’s particularly true for “constrained” Locational Deliverability Areas such as those served by New Jersey utility Public Service Enterprise Group and Baltimore Gas & Electric on the Atlantic seaboard, and in the northern Illinois region served by utility ComEd, where 2018 capacity market clearing prices neared or exceeded $200 per megawatt-day, compared to $140 across the rest of PJM.
This chart, which shows the different default net CONEs for different PJM zones, highlights Roberts’ observation. While minimum prices for fixed solar remain in the $350 to $400 per megawatt-day range, tracking solar minimum prices are in the $150 to $200 per megawatt-day range.
And because FERC’s order is expected to drive an increase in capacity market prices, those minimums may be competitive in future auctions. According to analysis from consultancy ICF, implementing FERC’s order is expected to drive a $20 to $30 per megawatt-day increase in clearing prices in PJM’s next capacity auction.
The big opportunity to lower costs for wind and solar
But the most important chance for solar and wind power comes in PJM’s plan to allow a “resource-specific exemption” allowing a new project to demonstrate that its actual costs are lower than the applicable default MOPR Floor Offer Price and then “offer at that lower price.”
This exemption offers a chance for solar and wind power developers to lower their net costs of new entry and thus their minimum bid price. The costs of wind and solar power have been falling dramatically and consistently over the past decade. That downward price pressure is expected to continue over the coming decade, driving down the installed capital costs that form the starting point for PJM’s generic net CONE figures.
Georgios Papadimitriou, head of Enel Green Power North America and an American Wind Energy Association board member, lauded PJM’s plan last week for allowing the “rapidly decreasing costs of developing large-scale renewable projects” to be reflected in future years by including this exemption. And Katherine Gensler, the Solar Energy Industries Association’s vice president of regulatory affairs, said the plan will offer renewables a chance to “compete on a level playing field with other capacity providers.”
Room for improvement on assumed capacity factors
Beyond lowering the capital costs that form the numerator of the MOPR equation, PJM’s proposed exemption also offers wind and solar projects a chance to improve several metrics in the denominator side of the equation.
For example, PJM’s filing noted that wind and solar projects can request higher capacity factors than the generic percentages that PJM has provided, which will lower their minimum bids. Projects could increase their capacity factors through design or siting choices, or potentially through adding energy storage to capture power generated in excess of demand at some times and discharging it during times when it’s needed more.
Finally, PJM’s exemption offers projects an opportunity to prove their technologies can reliably serve as long as 35 years, much longer than the current default 20-year assumption. “That 20-year asset life may not, in all instances, be appropriate as different resource types have different inherent characteristics that may allow them to remain economic for a longer period of time,” PJM wrote.
That’s critical, because PJM calculates the annual share of capital costs that serve as the starting point for its MOPR by dividing their total capital costs by the number of years they’ll be in service, Sierra Club’s Roberts noted. Dividing that total capital cost figure by 30 or 35, instead of 20, will obviously lower that annual figure quite significantly, she said.
Wind and solar projects may well be able to serve for longer than 20 years, given their relative lack of wear and tear compared to thermal generators, she added. “PJM really heard the clean-energy suppliers on that point.”
Of course, PJM's plan must still win approval from FERC's Republican majority if the grid operator is to meet its own goal of resuming its capacity auctions before the end of 2020. But the changes could provide renewable energy with a far greater hope of earning a place in PJM's capacity market than most industry observers thought possible just a week ago.