A recent Federal Energy Regulatory Commission decision illustrates the complicated dance between states and the federal government on climate policy.
According to some energy aficionados, natural gas is the “blue bridge to the green future.” Combined cycle gas turbine (CCGT) power plants are highly efficient and emit about half the carbon dioxide per unit of electricity as coal plants, plus natural gas prices have fallen dramatically recently. Natural gas surpassed coal as the primary source of electricity in the US in 2015 and hasn’t looked back since.
But, things are not so easy for natural gas power plant owners these days. My husband works for Calpine, which operates 80 mostly natural gas plants around the country, so I see firsthand the challenges he wrestles with. A recent case before the Federal Energy Regulatory Commission (FERC) highlights the difficulties for natural gas plants, particularly those that rely on compensation from competitive wholesale markets.
Capacity Markets Fall Short
Here’s the basic story. Like many wholesale electricity markets in the U.S., the PJM Interconnection – the regional electricity market centered in Pennsylvania, New Jersey and Maryland – has a capacity market. Capacity markets are designed to ensure that there are sufficient resources on the electricity grid to meet future peak demand. Utilities and other electricity suppliers are required to purchase enough capacity to cover their expected peak demand and then some.
In a textbook economics world, capacity markets would not exist. Instead, during times of peak demand, spot market prices for electricity would go up until the market cleared. They might periodically be very high, but if firms like Calpine anticipated these high prices, they would have the right incentive to build capacity to be in the market during the peak periods.
But, in the real, not-textbook, world, spot market electricity prices are capped and other services are not priced appropriately. So, most regional electricity markets include capacity markets. (I am not taking a stand on whether Texas, which does not have a capacity market, conforms to textbook economics or isn’t a part of the real world!)
Many natural gas power plants earn a good chunk of their revenue through capacity markets. In 2017, revenues from the PJM capacity market would have accounted for almost 40 percent of the earnings for a theoretical, new CCGT plant. (The remaining 60 percent came from the energy and ancillary service markets.)
Here’s the rub. The total revenues – capacity plus energy plus ancillary services – are not high enough to cover a new CCGT power plant’s costs. In the figure below, the orange line represents the capital cost of operating the new plant spread over 20 years. (The calculation is re-done every year, so the line is declining over time as the levelized costs of the new plant change.) The dots reflect the net revenue the plant would have received in various sub-locations within PJM, after subtracting out variable costs, like fuel costs. In 2017, the plant wouldn’t cover its costs in 17 of 20 locations – not a good situation if the aim is to ensure that there’s enough capacity in the market. Other years have been better, but there are areas where the plant would have been losing money consistently for each of the 9 years.
Source: PJM State of the Market, Chapter 7
State Intervention in Markets
Calpine argues that part of the insufficient revenue problem is that capacity market prices are suppressed by bids from power plants that receive either implicit or explicit subsidies. For example, renewable plants built to satisfy state renewable portfolio standards receive implicit subsidies. I see Calpine’s logic – they’re basically trying to make money selling lemonade in a neighborhood full of kids whose parents buy them adorable stands and pay for the Newman’s Own.
Two years ago, Calpine lodged a complaint with FERC, arguing that PJM needed to fix the capacity market to account for the subsidized (parent-supported) plants. Last month, FERC issued an order agreeing with Calpine.
A lot of the subsidies are for renewables, but lately nuclear and other types of plants got into the subsidy game. The FERC decision lists:
- 1,400-3,360 MWs of nuclear generation eligible for zero-emission credits under a law recently enacted in Illinois,
- 3,360 MW at the Salem and Hope Creek nuclear facilities that would receive similar payments under legislation recently enacted in New Jersey,
- 1,350 MWs of off-shore wind generation required under procurement programs under existing law in Maryland (250 MW) and New Jersey (1,100 MW), and
- 5,000–8,000 MWs of generation from various renewable resources eligible under RPS programs in various PJM states, including New Jersey, Delaware, and the District of Columbia.
FERC Is from Mars, States Are from Venus
What does this mean for CCGT owners like Calpine? They own existing plants, so their costs of continuing operations are lower than the costs reflected in the orange line in the figure above since most of their capital costs are now sunk. If revenues get too low, though, they won’t even cover their going-forward costs and will be forced to shut down. Plus, when they decided to build their plants, they presumably expected market revenues would cover their operating and capital costs.
FERC is required to ensure that wholesale power prices are “just and reasonable.” In this case, they interpreted that to mean that Calpine had a point. FERC prescribed a way for PJM to adjust its capacity market so that subsidized plants don’t drive prices down as much. (Of course, we don’t expect the regulator to step in every time reality differs from an investor’s expectations, as Severin discussed here.)
On the other hand, some states are subsidizing renewables and zero-emission nuclear plants to do exactly what Calpine is complaining about – they intend to drive fossil-fuel-fired power plants out of the market as part of the transition to a low-carbon electricity grid. This highlights the difficulty enacting state-level climate policy when FERC and other federal agencies don’t share the same goals.
Other states are taking different approaches to aligning wholesale markets with state environmental policies. For example, New York is considering incorporating carbon pricing directly into its wholesale markets and Energy Institute alumnus Matt White crafted a clever capacity market tweak in New England (Competitive Auctions for Sponsored Policy Resources – CASPR) that basically involved subsidized resources “buying out” unsubsidized resources. FERC has already approved CASPR, and whatever New York implements would require FERC approval.
So, I expect continued friction between FERC and the states and lots of acronym-rich and wonky discussions with my husband. The bridge to a low-carbon electricity system is long and filled with interesting twists and turns.
Catherine Wolfram is Associate Dean for Academic Affairs and the Cora Jane Flood Professor of Business Administration at the Haas School of Business, University of California, Berkeley. She is the Program Director of the National Bureau of Economic Research's Environment and Energy Economics Program, Faculty Director of The E2e Project, a research organization focused on energy efficiency and a research affiliate at the Energy Institute at Haas. She is also an affiliated faculty member of in the Agriculture and Resource Economics department and the Energy and Resources Group at Berkeley.
Wolfram has published extensively on the economics of energy markets. Her work has analyzed rural electrification programs in the developing world, energy efficiency programs in the US, the effects of environmental regulation on energy markets and the impact of privatization and restructuring in the US and UK. She is currently implementing several randomized controlled trials to evaluate energy programs in the U.S., Ghana, and Kenya.
She received a PhD in Economics from MIT in 1996 and an AB from Harvard in 1989. Before joining the faculty at UC Berkeley, she was an Assistant Professor of Economics at Harvard.