Capacity Markets – Renewable Generation

This post is part of a multi-part series on capacity markets.

Capacity Markets – Definition

Capacity Markets – Background

Capacity Markets – A look across the United States

Capacity Markets – Renewable Generation

In a previous post, I described how electricity markets in the US provide incentives for independent power generators to build and maintain generating capacity.  Capacity ensures that the grid has sufficient ability to generate the necessary electricity during peak hours.  These markets function well for traditional natural gas power plants which can be turned on and off fairly easily.  The post looks at the current methodology for valuing the capacity of renewable intermittent resources, such as wind or solar.

In general, wind blows stronger at night, but this chart of the power output 

every day for a month of a California wind farm shows that there can be 

quite a lot of variability

Peak hours for the grid in most of the United States are during the summer afternoons when buildings have their air conditioner turned on (the exceptions are winter-peaking areas in the northern United States where customers have a lot of baseboard electric heating).  Often, the wind is not blowing its strongest on hot afternoons.  In addition, while these hours tend to be sunny, there could be significant cloud cover during an important hour, or the air conditioning load could remain high at dusk when the sun sets.  Wind and solar cannot be counted on to be available the same as a natural gas combustion turbine.

This one day chart of the power output from a photovoltaic solar
installation shows the impact that cloud cover can have on solar power.
Geographic diversity of solar power throughout the state should mute
many of these variations for the purpose of system-wide capacity. 

On the other hand, conventional power plants such as a natural gas power plan is not available all the time either, and it still receives capacity value.  Conventional resources have scheduled maintenance, and unplanned outages.  Moreover, even if wind and solar do not always perform at their maximum rated output during peak hours, surely they are providing some benefit which could be estimated statistically.

California has attempted to address this issue by creating a net qualifying capacity (NQC) methodology to determine the amount of resource adequacy a power plant of a given technology provides.  Resource adequacy, as I mentioned previously, is the closest thing California has to a forward capacity payment.

The NQC for renewables is determined by an “exceedance methodology”, calculate by California state regulators: the public utilities commission (CPUC), the energy commission (CEC), and the ISO (CAISO).  The exceedance approach measures the minimum amount of generation produced by the resource in a certain percentage of peak hours.  The exceedance level used to calculate the QC of wind and solar resources is 70%.  Another way to describe the exceedance level is that the 70% exceedance level of a resource’s production profile is the maximum generation amount that it produces at least 70% of the time (during peak hours).  The peak hours, for the purpose of the exceedance methodology calculation, are 5 hours a day, 4-9 p.m. November to March and 1-6 p.m. April to October.**  These hours vary regionally, and would not make sense for a grid at a different latitude than California. 

To determine the minimum production level of solar and wind resources for 70% of the peak hours, California looks at historical values for load data and power output from solar and wind resources.  Typically, an average of the past 3 years is used.

NQC values for renewable power resources are dependent on seasonality, geographic diversity of the resource, and site specific factors. Anecdotally, I would expect the NQC value of a solar facility to be approximately 25-35% of its installed capacity (measured in MWs), and the NQC value for wind to be approximately 10-20%.

**5 hours a day year round is a relatively conservative metric because the industry standard for determining capacity among distributed resources is the top 250 load hours of the year.  250 hours is an “eyeballed” number for the peak hours in which the grid is most likely to have an outage.  A more rigorous loss of load probability (LOLP) analysis is done for reliability planning, but for economic estimates of resource planning, 250 hours will usually suffice.  5 hours a day is roughly 20% of the hours in the year, whereas 250 hours is less than 3% of the hours in the year.

Capacity Markets – A look across the United States

This post is part of a multi-part series on capacity markets.

Capacity Markets – Definition

Capacity Markets – Background

Capacity Markets – A look across the United States

Capacity Markets – Renewable Generation

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.

Capacity Markets – Background

This post is part of a multi-part series on capacity markets.

Capacity Markets – Definition

Capacity Markets – Background

Capacity Markets – A look across the United States

Capacity Markets – Renewable Generation

In 2000 and 2001 the Western United States went through an energy crisis.  I was a student in a California public school at the time, and I remember getting to go outside and mess around because there was a rolling brownout during class.  The crisis cost Californians millions and led to the wacky recall of Governor Gray Davis though, for students at the time, it was awesome.

While most citizens blamed Enron and moved on, the Western U.S. Energy Crisis had a lasting impact on electricity market policies.  In its simplest form, the traditional electricity business model is to have one utility own all the power plants, transmission lines, and distribution lines and then sell power to end consumers.  Under this system, an electricity market is unnecessary.  The basic idea of electricity deregulation is that while transmission and distribution wires are a natural monopoly and should not be duplicated, electricity generation is not a natural monopoly.  Therefore, it makes sense to have one company (a utility) own the wires while other companies compete to make the cheapest power plants and sell power to the grid.  From this notion comes electricity markets.

In 1998, prior to the crisis, California transitioned to a system in which independent power producers (Dynergy, Mirant, Reliant, etc) sold electricity to distribution companies (PG&E, SCE, SDG&E, etc) on a day-ahead basis.  Pre-1998, the utilities owned both the power plants and the transmission and distribution.  The day-ahead power auction became coordinated through a central exchange, the California Power Exchange.  This system was generally described as “deregulation” or “partial deregulation” and was expected to reduce the cost of electricity to end consumers. 

California at the time was part of the Western Systems Coordinating Council (WSCC), now the Western Electricity Coordinating Council (WECC), which covers the Western Interconnection.  An interconnection represents a region in which all electric utilities are electrically tied together during normal system conditions and operate at a synchronized frequency (here is a map of interconnections in North America).

Electricity demand in the WSCC had been growing rapidly, led by growth in California and the southwestern United States.

Consumption by state, 1997-1998

Source:   Fisher, J. and Duane, T. "Trends in Electricity Consumption, Peak Demand, and Generating Capacity in California and the Western Grid, 1977-2000," Program on Workable Energy Regulation, University of California Energy Institute, Berkeley, CA, March 2002.

Meanwhile the region had faced years of low investment in electricity generating capacity.  Factors for low investment included the economic recession in the early 1990s which decreased demand as well as concern on the part of utilities that upcoming deregulation might limit their ability to recover the cost of building new facilities.

New utility capacity by state, 1977-1997

Source:   Fisher, J. and Duane, T. "Trends in Electricity Consumption, Peak Demand, and Generating Capacity in California and the Western Grid, 1977-2000," Program on Workable Energy Regulation, University of California Energy Institute, Berkeley, CA, March 2002.

Events came to a head in shortly after California partially deregulated the electricity sector in 1998.  In early 2000, wholesale electricity prices in the day-ahead market shot upward, reaching over 20x typical levels.  At the same time, the Pacific Northwest experienced its most significant drought in decades, causing a decrease in the hydroelectric power that could be exported from Washington and Oregon to California.

Water Discharge at the Dalles Dam, Columbia River

Source: Green Jouleus from U.S. Geological Service

This chart shows the water discharge at The Dalles Dam on the Columbia River, a measurement that serves as a bellwether for hydroelectric output in the Pacific Northwest.  It shows clearly that output spiked in April 2000 in parallel with spiking electricity prices in California.  However, due to the drought, hydroelectric output at this level was unsustainable and The Dalles had its lowest output in decades during the 2000-2001 period, the height of the Western Electricity Crisis.

One clear result of the Western Electricity Crisis has been a policy shift away electricity markets based largely on short-term sport market prices toward electricity markets which incorporate long-term capacity planning.  The WECC needed more electricity generation due to increased demand in the late 1990s, but utilities did not want to built generation out of fear of market deregulation.  Had regulators not intervened, the market would have corrected itself eventually.  High electricity prices of the crisis would have been a strong incentive for companies to build additional power plants and sell power at high rates.  Unfortunately, power plants take time to site and build, and in the meantime high prices caused large-scale blackouts across the state.

As a result of the Western Electricity Crisis, most restructured electricity markets throughout North America feature some type of market for capacity.  These markets facilitate payments to power producers in order to ensure that enough generating capacity will be available in future years to meet expected load.  Capacity markets represent central planning in that the free market does not decide how much generating capacity will get built–a regulator's load forecast does.  Regulators also demarcate the zones in which growth constraints are different (such as Manhattan Island vs. upstate New York), creating different prices for capacity within those zones.  Such a system makes sense given the time it takes to build power plants, and the costs of volatile prices to both consumers and power producers who are attempting to finance large investments.

Capacity Markets – Definition

I decided to write a multi-part series on capacity markets.  Capacity is one of the services that generators of electricity sell to the grid.  When a power plant sells capacity, the grid receives the right but not the obligation to procure a set number of MWs from the generator during a future time frame (typically a six months to one year period which will occur one to three years in the future).  The amount of capacity procured by the grid is determined based on a long-term forecast of expected electricity demand, which is impacted by factors such as the economy, technological advances, and weather.

My capacity market series will cover the following topics:

Capacity Markets – Definition

Capacity Markets – Background

Capacity Markets – A look across the United States

Capacity Markets – Renewable Generation