The state of US wholesale power markets: Is reliability at risk from low prices?
In early May, the Federal Energy Regulatory Commission’s (FERC) technical conference explored problems in U.S. wholesale markets, specifically how new state policies impact and interact with wholesale power markets in the U.S. The conference included written statements and testimony by dozens of panelists, many from companies that own power plants and operate in regional markets.
While the conference did not produce a solution to the problem, one reality became abundantly clear: Generators are concerned about falling revenues making their plants uneconomic and want market modifications to remedy this situation. Many attendees, including state regulators, market operators, and FERC commissioners and staff, seemed receptive to this complaint.
But a closer look at data from several of the nation’s wholesale power markets indicates a “problem” does not actually exist at all; wholesale markets are operating as intended. In part one of this three-part series, we evaluate why generator revenues are shrinking, and why the consequences of falling revenues aren’t actually a problem.
Natural gas is largely responsible for shrinking revenue in the energy market
There’s no denying that prices in U.S. wholesale power markets have been steadily declining for several years. In PJM, prices have dropped by more than 40 percent since 2014, falling from $49 to $29. ISO-NE has experienced a similar drop of 55 percent, down from $65 in 2014 to $29 in 2016. In both PJM and ISO-NE, 2016 prices were the lowest since the markets were initially created.
The price decline is due in large part to the falling cost of natural gas, which sets prices during the most profitable hours in the energy market. As shown in the figure below, annual average electricity prices in PJM, ISO-NE, and NYISO clearly mirror the price of gas.
As natural gas prices have fallen over the past 5-10 years, so too have average wholesale electricity prices (2014’s Polar Vortex, which heavily skewed the annual average, was an outlier). Because gas generation has become so cheap, it has displaced significant coal generation. For example, in PJM, coal’s share of generation has fallen from 50 percent in 2010 to less than 35 percent today. Gas has made up this difference, increasing from 12 percent of the generation mix to 27 percent over the same period. Renewables have remained less than 3 percent of PJM’s mix over the whole period.
Declining prices exert outsized pressure on coal and nuclear units. Coal not only makes less revenue per unit of electricity it generates as prices drop, but also generates less electricity overall as cheaper natural gas units take its place. Nuclear units tend to have very high fixed annual costs and rely on higher average prices to recover these costs. Because nuclear plants are much cleaner but struggle with low prices, several states including Illinois and New York have passed policies to support nuclear plants by paying for their zero carbon attributes. Regardless, the net effect is that falling natural gas prices have significantly lowered the amount of revenue in the energy market flowing to all generators, especially coal and nuclear plants.
Markets continue to deliver more capacity, despite oversupply
FERC’s conference focused on three regions in particular with market operators that administer forward capacity markets (FCMs): ISO-NE, PJM, and NYISO. FCMs are auctions for capacity (megawatts) – as opposed to generation (megawatt-hours) – guaranteeing a fixed payment to generators over a future time period for being available to generate electricity.
The FCM mechanism was developed by grid operators to address the missing money problem, where price caps and other electricity market shortfalls lower the total amount of revenue available to generators. In theory, capacity markets were designed to provide new and existing generators with revenue missing due to price caps and other volatility reduction measures, which leave energy market revenues short of covering generators’ going-forward costs.
Wholesale power markets were designed to facilitate generation competition and shift the risk of overpaying for capacity or over-procuring capacity from electricity customers onto independent power producers (IPPs). To accomplish these goals, wholesale power markets should to provide investment signals for entry and exit based on market supply and demand. That means, especially for the capacity market, that prices should increase and incent new generation when the prospect exists for insufficient supply. Similarly, when supply is too high, prices should decrease and incent units to retire, whether or not they have reached the end of their useful lives. This is part of the risk that IPPs take on by choosing to participate in a competitive market.
Consider the current level of capacity in each of the U.S. markets relative to the required reserve margins:
Every wholesale power market in the U.S. is supplied above its reserve margin, which is the minimum amount of extra capacity needed to comply with national reliability standards.. In some instances, like in PJM, markets have almost double the amount of excess capacity needed to meet reliability standards, the cost of which is being passed through to electricity customers. Well-intentioned state policies supporting nuclear units that would otherwise retire are only reinforcing an existing trend, not defining it.
Some may claim these policies interfere with “price formation” in wholesale power markets. However the primary outcome of such policies is to keep capacity around that is providing uncompensated value (e.g. zero-carbon electricity) and would otherwise retire. By encouraging otherwise uneconomic plants to stay in service, the impact of such policies is keeping additional capacity online, adding to the overcapacity problem across U.S. markets.
Given the very high levels of excess capacity in some U.S. markets, it’s unsurprising that generators are worried about collecting revenue from the capacity market. But it’s important to remember that the energy and capacity markets, working in tandem, should incentivize units to leave the market when too much capacity exists.
