For more than a decade, the U.S. electricity system has been a house divided.
In the early 2000s, the California energy crisis stalled a wave of power sector deregulation that was sweeping the country. Pushed by the promise of greater competition and lower costs, dozens of states had moved to break down the vertically-integrated utility model, setting up organized markets to handle resource planning and dispatch.
But when the brownouts and price spikes hit the Golden State in 2000, the momentum for organized markets screeched to a halt, leaving the nation with a bewildering mix of market and regulatory structures.
To this day, utilities in the Southeast and West continue to operate in the vertically-integrated model, absent the organized market structure that now serves more than two-thirds of Americans. The exception in those regions is California itself, which operates in a market managed by the California Independent System Operator (CAISO).
Now, some backers of organized markets in the West are looking to change that. A formal proceeding at CAISO is now underway that would integrate the 38 separate Western balancing authority areas (BAAs) into a market potentially richer in resources than the Midcontinent Independent System Operator (MISO) or the PJM Interconnection.
Organized markets in other regions have proved that grids with larger geographic footprints and bigger resource bases are “cleaner, cheaper, faster, and safer to operate,” than those run by vertically-integrated utilities, according to a new paper from the Natural Resources Defense Council that seeks to provide guidance to the stakeholders.
“A regional grid can access the untapped flexibility and diversity of resources throughout the West,” Keith Casey, a CAISO vice president recently told Utility Dive.
If the West were to form a single organized market, it would be one that could integrate significantly higher amounts of renewable energy generation, according to paper author Carl Zichella, director of western transmission at NRDC.
“The system is flipping from using a fossil foundation with a renewable energy add-on to one with a renewable energy foundation in which fossil fuel resources are used to deal with fluctuations,” Zichella said. “Where the operator can’t match renewables with renewables, natural gas generation will be available to fill in the blanks.”
How a regional market works
The goal of the NRDC paper, Zichella said, to use lessons from other organized markets to offer recommendations on how best to design one for the West.
The region’s 38 BAAs now operate primarily through bilateral power contracts, which is highly inefficient, he said.
By contrast, generation in organized markets is typically dispatched based on economics. Utilities and other plant owners offer bids into the markets to satisfy demand on an hourly basis. The system operator chooses the lowest-cost resources to meet the demand, working up to more expensive ones until demand is satisfied.
The price paid for the last megawatt purchased — the market clearing price — is paid to all power suppliers that clear the auction.
Demand response programs, which focus on reducing customer usage to balance the grid, are typically among the first resources cleared in auctions where they participate.
Renewables, because they have no fuel cost, are often the lowest cost and first dispatched generation resources, Zichella said, though the historically low price of natural gas means it undercuts wind and solar in some regions. The more renewables there are, the less fossil generation is used to meet load and the less competitive conventional plants become.
“Markets force out of the generation stack the least efficient, most expensive resources,” Zichella said.
Regional market mechanisms can incorporate state-level decisions to protect local autonomy, however. The system operator uses the resource mix established through state procurement practices and renewables mandates and dispatches according to state loading orders.
State mandates increase the supply of renewables, driving out more fossil generation. Local policies to limit emissions are also factored into the market.
In California and the Northeastern member-states of the Regional Greenhouse Gas Initiative, the price on carbon goes into the price of fossil generation as an “adder” that makes it less competitive, Zichella said.
“That is why 0.01% of the generation sold into the California Energy Imbalance Market (EIM) has come from coal, even though participants include utilities with significant coal-fired generation in their resource mixes,” Zichella said. “They don’t get bid because of the higher cost that includes the adder.”
Case for the western market
While proponents of organized markets say that one could help make the West’s grid more efficient, some are not yet convinced the relatively new idea can keep the system viable or deliver power at the lowest cost.
“Southern California Edison (SCE) is looking forward to evaluating the preliminary results of the benefits study of CAISO’s expansion in the West,” was all an SCE statement to Utility Dive said.
“Integrating 15% or 20% renewables or even 30% renewables into the grid may not be a problem but once penetrations get to 40% and higher, those last blocks of renewables can be quite expensive to integrate,” Travis Kavulla, president of the National Association of Regulatory Utility Commissions and a Montana regulator, told Utility Dive.
Even the declining cost of renewables may not abate the costs of overbuilding transmission and capacity resources, he added. “The antidote is for resource planning to be done as much possible by state utility commissions and for utilities to be allowed to use least cost planning.”
A regional market offers just such antidotes, according to Zichella.
One of the paper’s key recommendations is that resource adequacy “continue to be assured through competitive utility procurement under the supervision of state regulators and local utility boards.” The system operator’s job would be to prevent overbuilding.
“A local perspective tends to lead to overbuild because there is not a holistic view of the entire system,” Zichella said. “A big part of the value proposition of regional expansion is the ability to limit new building by sharing the operating and flexibility reserves needed to keep the entire system reliable.”
An example of this value proposition was detailed in a recent paper in the journal Nature Climate Change. The study modeled the potential of a high voltage direct current (HVDC) national grid expansion to cut carbon emissions by connecting the highest-value renewable resources to load centers around the country. The model required the system to “provide electrical power for every hour to every market while operating within current technology limits.”
If that vision of a national transmission system was realized, “carbon dioxide emissions from the U.S. electricity sector could be reduced by up to 80% relative to 1990 levels,” the researchers found, all without an increase in the average cost of electricity.
Geographic dispersal of resources was key to the cost savings and carbon cuts.
“All the sensitivities show a bigger area connected by HVDC transmission costs less and mitigates more carbon,” Chris Clack, a NOAA research scientist and report co-author told Utility Dive when it was released.
While SCE was not yet ready to endorse an expansion of the organized market where it now operates, other western utilities are pushing the process.
The Warren Buffett-owned PacifiCorp utilities, serving six states in the region, are active participants in CAISO’s Western region market planning process.
“Increased regional coordination of Western energy systems is key to helping keep costs affordable for customers, ensuring and enhancing grid reliability, and providing the best way for states and the region to integrate renewable energy sources and meet clean energy requirements,” Communications Manager Bob Gravely emailed Utility Dive.
Idaho Power expects its participation in the EIM, scheduled to begin in 2018, to “facilitate increased reliability for the electric system and we anticipate economic savings to our customers through lower production costs," according to Spokesperson Stephanie McCurdy. But is not yet ready to pursue a full regional market, she added.
Avista Utilities, which supplies electricity to Washington and Idaho, is interested in the emerging EIM but do not yet see ‘immediate business drivers” for participation in it or a region-wide system, according to Director of Power Supply Scott Kinney.
Capacity market concerns
While many renewable energy advocates support the idea of a western organized market, some worry that it would also give new life to fossil fuel plants that would otherwise retire. In particular, environmentalists’ concerns center on the subject of capacity markets.
Market forces would be expected drive out coal in a West-wide market, Zichella said. "In the last five years, PJM and MISO have retired over 30,000 MW of coal-fired electricity because the clearing prices are not supporting them.”
Capacity markets do, however, support some older coal plants in markets like PJM or ISO-New England, he said. They are intended to ensure sufficient supply to meet rare periods of sharply peaking demand.
In those markets, the grid operators pay some generators to keep capacity available even if they are not able to earn adequate returns in the day-ahead and real-time energy markets, the paper reports.
“That is a concern for the environmental groups that want to see coal plants out of the system as quickly as possible,” Zichella said.
Capacity markets are a “mixed bag,” the paper reports. “They can keep a few uneconomical and polluting power plants on life support” but the same “out-of-market prices” create opportunities for demand side resources such as demand response and battery storage.
“PJM’s annual capacity market clears more than 10,000 MW of demand response to serve resource adequacy purposes, thereby avoiding 10,000 MW of existing or new fossil-fueled generation,” the paper adds.
But like other resource-rich markets such as the Southwest Power Pool, the West does not need a capacity market, Zichella argued.
The West has wind generation with capacity factors higher than its natural gas plants and abundant solar, he said. Because those renewables are spread across three time zones, abundant afternoon California solar can be exported east to help meet evening peaks. Strong nighttime winds in the Midwest and Plains, meanwhile, can be exported to the West to meet evening peaks.
Existing natural gas plant capacity factors in the West are around 30%, leaving 70% of that supply available as flexibility if the system is in place to share it, Zichella said.
The proposed regional system “should avoid the establishment of a capacity market, which can perpetuate uneconomical generation…[and] is not needed in the Western Interconnection to meet reliability,” the paper concludes.
“Insisting on a capacity market could sabotage the regional market because it opens the possibility of keeping inefficient and polluting resources around,” Zichella said. “It is not necessary so why hang the whole idea up for it.”
Moving to top-down planning
As western states continue to add more renewable energy, “a more holistic planning process will be needed,” the paper argues.
There are two kinds of planning, Zichella said — "top-down and bottom-up.”
Regional market planning would be a top-down look at the whole system, instead of the bottom-up perspective the 38 individual BAAs now have.
Resource Adequacy assessments would continue to be done regularly because in any given year needs can shift, Zichella said.
A larger framework would provide more clarity about “short- and long-term system and reliability needs” and better understanding of how “non-wire” approaches like energy efficiency, demand response, and on-site electricity storage could be of greater value to the system, the paper reports.
A system operator could also see and use existing capacity more efficiently to avoid congestion or the overbuilding of reserves and transmission, it adds.
It would also be easier to identify and respond to barriers to renewables integration, Zichella said. That is what MISO did through the set of transmission multi-value projects it planned and is building to help member states meet their renewables mandates.
Planning for stranded assets
There is another kind of planning that will be necessary to make a West region market appealing to utilities, Zichella said.
With an accelerated transition to renewables, utilities and their regulators will become increasingly concerned about pricing operational plants out of the market before they go offline — creating what’s termed a “stranded asset.”
“There are strategies for dealing with stranded assets,” Zichella said. An example is in the recent Oregon legislation that increased that state’s renewables mandate to 50% by 2040. The transition to renewables was scheduled to allow utilities there to depreciate their coal plants in coordination with the mandate’s interim targets.
“Utah has also been talking about accelerated depreciation for coal plants so they can be taken off the books faster,” Zichella said. “The idea is to allow them to recover their costs but hopefully not replace the coal plants with natural gas generation.”
There is also a larger perspective, he added. “The Wyoming and Montana economies, for instance, are based on resource extraction industries, but they have the opportunity to soften their glide path with renewables and new transmission.”
States rich with wind and solar will be able to develop "reciprocal relationships throughout the West, Zichella said. “There are adequate resources to meet any grid condition.”