This post is part of a multi-part series on capacity markets.
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| Source: FERC |
In a previous post, I mentioned that as a result of the Western Electricity Crisis, restructured electricity markets throughout North America all feature capacity markets of some form. I used the term "capacity markets" loosely, as there a great deal of diversity in which capacity is procured, and only in some cases is the market public. ISOs use different names and different measurements for different products. Capacity is also priced in different units, and when I show prices, I will always convert to $/kW-yr, because it is the industry standard for pricing power plants. Many capacity markets take place on a monthly basis, and therefore list prices is $/MW-month, and the conversion to $/kW-yr is to simply multiply by 12 and divide by 1,000. One price of jargon is that the participants in capacity markets are in many cases load serving entities (LSEs). LSEs can be simplistically assumed to be distribution utilities that buy power from interdependent power plants and sell the power it to their local customers through retail electricity tariffs (a utility bill).
Below is a brief description of the different market structures in the U.S.
ISO New England
ISO-NE has a forward capacity market (FCM) in which capacity prices
are made public. The most recent ISO-NE annual market report listed the clearing price of capacity in ISO-NE
as $38.52/kW-yr, the auction floor. This is the price at which ISO-NE
procures capacity from generators. The fact that the price is at the
auction floor can be read as overcapacity in the ISO-NE market in the next few
years.
ISO-NE also has a public forward reserve market (FRM)
for LSEs. Whereas in FCM, the ISO pays generating resources to be
available three years in the future, in the FRM LSEs pay generating resources
to be available as reserves one year in the future. Moreover, the FCM is
only applicable to new investments in capacity, but the FRM is open to
exisiting resources.
Though the public prices allow for market
transparency and increased oversight, a capacity market inherently involves issues of market
power. Therefore, ISO-NE uses market constraints including bid caps and
demand curves to limit bid prices to a reasonable level. A demand curve
models the cost of new entry of a capacity resource, typically a combined cycle
natural gas turbine, in order to get a reasonable approximation of what
capacity should cost.
PJM
Like ISO-NE, PJM has a forward capacity market, which they call
the reliability
pricing model (RPM). In
the most recent May 22, 2012 auction, the average capacity price clearing price among
PJM's various regions was $67.53/kW-yr for 2015/2016 Delivery Year.
This price indicates that PJM is either more constrained or is a more
expensive region in which to build power plants relative to ISO-NE. PJM
also has a forward reserve requirement for LSEs, and they have been
at the forefront of getting demand response to be an active part of the forward
reserve requirement planning process.
New York ISO
NYISO has a capacity market (ICAP), but it looks more similar to ISO-NE's forward reserve market than forward capacity market in that it is based on short-term capacity needs. NYISO is considering a longer-term 4 year capacity market, but has not implemented the market, largely because the ISO is expected to be contrained for electricity reliability purposes in the near future. In the most recent ICAP, the price of capacity for Summer of 2012 was $17.04/kW-yr in Long Island, $15.00/kW-yr in the rest of New York state, and $140.40/kW-yr in New York City.
Midwest ISO
MISO has a capacity market, which is referred to as resource adequacy. In MISO, LSEs have make their own individual load forecasts. They then have the option to procure capacity on MISO's Voluntary Capacity Auction in which participants bid for "Aggregate Planning Resource Credits" (APRCs). In addition, LSEs can trade these APRCs bilaterally among themselves. MISO measures these units. These APRCs represent a monthly value one year in the future, and the most recent auction results show a clearing price of $0.002/kW-yr, approximately zero.
California ISO
CAISO does not have a central capacity market with published market prices, but it does have a one year forward reserve requirement for LSEs in the region. LSEs contract bilaterally with power generators to ensure that they have sufficient capacity. These prices are not public, but have historically been assumed to be between $30-40/kW-yr in public testimony by utilities and regulators.
ERCOT
The Electric Reliability Council of Texas, ERCOT, is the market in the U.S. closest to being energy-only. Energy-only means that ERCOT does not have a formal capcaity market or even forward reserve requirement enforced on LSEs. In practice, however, ERCOT LSEs engage in bilateral contracting with independent power producers to ensure that they will have sufficient capacity to meet their projected demand.
Other Regions
Most other regions of the United States are not restructured markets with an independent system operator, and instead rely on vertically integrated utilities which control generation, transmission, distribution, and retail sales. An example of this structure is Duke Energy. Duke does not explicitly price capacity in a market like an ISO would. Instead, Duke builds power plants when its load forecasts call it to do so, and then includes the cost of these power plants in its rate base, which determines the utility bills that it charges to customers.
Conclusion
This post had a lot more acronyms than I would prefer to include in my posts, but hopefully that illustrates the point that capacity markets are diverse and nonstandard throughout the US. Capacity is planning is important because it influences investment in energy infrastructure, infrastructure that can last for 40 years or longer. Capacity markets in their various forms therefore have big implications for clean energy development, the topic I will look to next.
NYISO has a capacity market (ICAP), but it looks more similar to ISO-NE's forward reserve market than forward capacity market in that it is based on short-term capacity needs. NYISO is considering a longer-term 4 year capacity market, but has not implemented the market, largely because the ISO is expected to be contrained for electricity reliability purposes in the near future. In the most recent ICAP, the price of capacity for Summer of 2012 was $17.04/kW-yr in Long Island, $15.00/kW-yr in the rest of New York state, and $140.40/kW-yr in New York City.
Midwest ISO
MISO has a capacity market, which is referred to as resource adequacy. In MISO, LSEs have make their own individual load forecasts. They then have the option to procure capacity on MISO's Voluntary Capacity Auction in which participants bid for "Aggregate Planning Resource Credits" (APRCs). In addition, LSEs can trade these APRCs bilaterally among themselves. MISO measures these units. These APRCs represent a monthly value one year in the future, and the most recent auction results show a clearing price of $0.002/kW-yr, approximately zero.
California ISO
CAISO does not have a central capacity market with published market prices, but it does have a one year forward reserve requirement for LSEs in the region. LSEs contract bilaterally with power generators to ensure that they have sufficient capacity. These prices are not public, but have historically been assumed to be between $30-40/kW-yr in public testimony by utilities and regulators.
ERCOT
The Electric Reliability Council of Texas, ERCOT, is the market in the U.S. closest to being energy-only. Energy-only means that ERCOT does not have a formal capcaity market or even forward reserve requirement enforced on LSEs. In practice, however, ERCOT LSEs engage in bilateral contracting with independent power producers to ensure that they will have sufficient capacity to meet their projected demand.
Other Regions
Most other regions of the United States are not restructured markets with an independent system operator, and instead rely on vertically integrated utilities which control generation, transmission, distribution, and retail sales. An example of this structure is Duke Energy. Duke does not explicitly price capacity in a market like an ISO would. Instead, Duke builds power plants when its load forecasts call it to do so, and then includes the cost of these power plants in its rate base, which determines the utility bills that it charges to customers.
Conclusion
This post had a lot more acronyms than I would prefer to include in my posts, but hopefully that illustrates the point that capacity markets are diverse and nonstandard throughout the US. Capacity is planning is important because it influences investment in energy infrastructure, infrastructure that can last for 40 years or longer. Capacity markets in their various forms therefore have big implications for clean energy development, the topic I will look to next.
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