Market forces and contract obligations are regularly dipping power prices below zero in California.
The dynamic is not new — negative pricing has occurred sporadically across the country for decades. But now, expanded renewable energy production, especially in the West, is prompting a new round of more consistent negative pricing.
“Negative pricing is driven by a hard-to-fathom dynamic in any efficient market,” said Jeff Bladen, the Market Services Executive Director for the Midcontinent Independent System Operator (MISO). “At times, it is more efficient for energy producers to give energy away free or even pay consumers to take their power plants’ generation than to curtail production because the shutdown and startup of the plant may cost them more.”
To counteract overproduction and negative pricing, grid operators can order the curtailment of utility generation, thermal or renewable.
Until recently, the frequency of negative pricing events was declining around the nation as transmission was built out and grid operators learned better techniques to integrate variable renewable generation.
But this year, western power systems, particularly the California ISO, have seen a boom in negative pricing incidents as flush hydro reserves from a rainy winter come together with an ever-expanding base of intermittent solar generation. Even with persistent curtailment of renewable energy, the average CAISO real-time electricity price dipped below zero twice a day in March.
The negative pricing threatens market revenues for traditional generators, sparking concern from some that flexible gas plants needed to balance out wind and solar production may have to shut down, as the La Paloma plant did last year. Combined with the desire to maximize renewable energy output lost output of renewable energy to curtailment, the concerns have policymakers discussing ambitious market fixes to keep power prices in the black.
Worst in the West
Curtailment of renewable energy by the California Independent System Operator (CAISO) rose steadily in the second half of 2016 as solar penetration reached new highs, according to the grid operator’s March market report.
Curtailment reached record levels during California’s rainy winter as its hydropower supply rose 180% over 2016, said Guillermo Bautista Alderete, CAISO’s Market Analysis Director.
“Of the 288 daily 5-minute intervals, an average of 31% were curtailed in the first three months of 2017,” Alderete said. In 2015, 15% were curtailed; in 2016, that rose to 21%.
This year’s average curtailment is likely to drop after a drier summer and fall, but remain above previous years, he added.
CAISO directs resources to curtail to avoid excess power and negative pricing. But since not all resources can curtail, and because it is costly for many gas plants to shut down completely, prices can dip into negative territory during times of high renewable generation.
The growing role of solar in negative pricing can be seen in the distribution of curtailment events, Alderete said. When wind generation was the cause, the bulk of the negative pricing events fell in windy early morning hours. The bulk of events are now during midday hours when solar production is highest.
During California’s winter, both supply and demand drove high curtailment. In addition to increased solar generation and an unusually abundant hydropower supply, there was seasonally reduced load.
“The typical winter load is around 30,000 MW but in the summer it is in the mid-40,000 MW range,” Alderete said.
Explaining curtailment & negative prices
There are two ways to think about the demand-supply imbalance that causes curtailment and negative prices, according to Alderete. One is the operational challenge of matching supply and demand. The other is the market perspective.
Curtailment happens infrequently in day-ahead markets because supply and demand are balanced in advance. More often, it occurs in the real-time market when high production from subsidized wind and solar push down power prices, forcing traditional generators to choose between the costs of turning off or paying customers to take their power.
“Negative pricing signals there is too much generation,” Alderete said. “For some resources, it is too expensive to shut down so they continue generating, even when they have to pay to do so.”
The Brattle Group's Hannes Pfeifenberger sees negative market prices as a result of policy decisions to support renewables. Wind’s $23/MWh federal production tax credit (PTC) and solar’s 30% federal investment tax credit (ITC) give them an edge over traditional generators on price, and California’s renewable energy mandates allow those resources to be dispatched first in the generation stack, giving them greater influence over power prices.
Other generators weigh the costs of paying customers to take their production against the costs of ramping down. The ITC gives solar a capital expenditure advantage, and rooftop solar typically cannot be curtailed by the grid operator. For wind, the PTC’s before-tax value of up to $37/MWh means operators can afford to sell as low as negative $35/MWh and still potentially benefit, Pfeifenberger said.
Wind and solar generators may also face large penalties for not delivering contracted renewables that utilities need to meet state mandates, he said.
In addition to growing wind and solar, California’s curtailment and negative pricing are worse this year because its normal power trading with the Pacific Northwest has been disrupted by an abundance of hydropower from the wet winter.
Under a 2012 FERC ruling, the Bonneville Power Administration (BPA) is authorized to aggressively curtail wind energy to keep generation flowing from its its eight-state hydropower system. The reason, Spokesperson David B. Wilson said, is that significant unanticipated hydropower curtailment could greatly affect river flows, damaging habitat for salmon and other wildlife.
The FERC decision also validated BPA's long-standing policy of not taking negative bids for hydropower.
“Because of the large amount of publicly available hydro data, paying negative prices would allow other marketers to take advantage of BPA’s need to generate,” Wilson said.
As a result, the Pacific Northwest is curtailing wind to allow hydro to generate, while California is curtailing wind and solar and still experiencing negative pricing. The dual phenomenon has policy watchers searching for ways to prevent that clean power from going to waste.
Cameron Yourkowski, senior policy manager for Renewable Northwest, said these circumstances are revealing significant “market inefficiencies” that impose costs on both systems. Despite open transmission interties, they are forced to keep an estimated 7,000 MW of expensive fossil generation spinning to meet demand peaks, he said.
“Optimizing these things could result in better outcomes and a system operator could do that,” Yourkowski said.
Emerging solutions for the West
One way to better optimize the western power system would be through the expansion to a west-wide ISO, said Steven Greenlee a CAISO spokesperson.
The current energy imbalance market (EIM) can provide some alternative demand, Greenlee said. “But if there was a Western region market, we could optimize all the participating systems instead of having to do so much of it in the real-time market.”
That CAISO expansion initiative, however, is currently stuck in political stasis after California and neighboring states reached an impasse over governing issues. Unless state leaders can move past the talking point of giving up state sovereignty to a larger electricity market, it looks unlikely to proceed.
Renewable Northwest sees a shorter-term solution, Yourkowski said. At present, California’s rules on capacity payments to out-of-market generators keep natural gas plants idling in anticipation of peak demand.
“If those market rules were structured differently, wind and hydro in the northwest and California’s solar over-generation could replace the natural gas plants,” he said.
Under CPUC rules, capacity payments may go only to generators who bid into California’s real-time market, said Jim Caldwell, senior technical consultant for the Center for Energy Efficiency and Renewable Technologies (CEERT), who is working with Yourkowski.
Generators across the border in the Pacific Northwest do not have that capability.
If the CPUC were to devise a “work-around,” it could allow Northwest hydro to replace fossil fuels in California’s peak demand energy mix, he said. Instead of curtailing renewables at midday, California would export its solar over-generation to the Pacific Northwest, allowing BPA to hold back some of its hydro so that it would be available when California needs it. If BPA knows of the need to ramp down hydro in advance, it can plan releases so they do not harm wildlife habitat.
“California will use the Pacific Northwest like a giant battery,” Caldwell said. “It would not be frictionless, but it is manageable if they plan in advance.”
CAISO would have to make minor changes to its rules and practices, he added, “But we think we can get 80% or more of the benefit that we could from a regional market.”
Yourkowski agreed. The 400 MW of wind and hydro in the Northwest now delivered by the California-Northwest intertie for capacity adequacy could grow to 7,000 MW, he said.
“The new rules aren’t likely to be in place until next year but this year is revealing a lot about where work is needed to make the system more efficient,” Yourkowski said.
Another potential solution involves eliminating the stacking, or “pancaking,” of transmission tariffs as low-cost renewable generation is sent across isolated western balancing areas. That would also help reduce curtailment, Yourkowski said.
Nancy Kelly, a policy advisor at Western Resource Advocates (WRA), said that was the intent behind the formation of the Mountain West Transmission Group (MWTG).
The MWTG utilities include Basin Electric Power Cooperative, Black Hills Corp, Colorado Springs Utilities, Platte River Power Authority, Xcel Energy Colorado, Tri-State Generation and Transmission Cooperative, and Western Area Power Administration.
Transmission constraints that prevented Xcel from joining California’s EIM led to a plan from the MWTG to eliminate pancaking through a single tariff group, Kelly said. A Brattle study found the single tariff could save as much as $14 million a year — sizable, but not compared to the estimated benefits of between $53 million and $88 million per year from a regional market. MWTG first turned to California’s proposed regional market with its tariff proposal, Kelly said. When that effort was delayed, the utilities initiated ongoing talks with the Southwest Power Pool (SPP).
Curtailment for the rest
The curtailment and negative prices roiling California and Pacific Northwest markets are likely to resolve with warmer, drier weather, said Michael Goggin, research director for the American Wind Energy Association.
“The longer-term solution is expanding transmission capacity so high output of any type — wind, solar, or hydro — can be moved to where power is needed,” Goggin said.
Much Western transmission capacity goes unused because bilateral contracts between power producers and buyers, which are the bulk of western energy transactions, require that lines be kept open, Goggin said. Contracts also bypass the price signals that streamline markets’ competitive bidding.
There has been some curtailment and negative pricing in the western parts of the PJM, SPP, and Electric Reliability Council of Texas (ERCOT) markets, Goggin said. But, as detailed in the most recent wind market report from Lawrence Berkeley National Laboratory (LBNL), it has dropped significantly with the addition of transmission capacity, he added.
“Only 1.0% of potential wind energy generation within ERCOT was curtailed in 2015, down sharply from 17% in 2009,” LBNL reported. The main reasons, LBNL added, are transmission line capacity growth and more efficient wholesale markets.
Those market dynamics in ERCOT may be changing, however. As the penetration of subsidized wind and solar increases, the grid operator’s market is seeing very low and negative real-time pricing more frequently, stirring concerns among market observers that it may not provide sufficient incentives to site new generation in the future.
Just this week, generators NRG and Calpine filed a proposal with ERCOT to change pricing and settlement rules, saying that the wind PTC began having a significant impact on prices in 2016. The generators argued the grid operator should consider alternatives to its current socialized transmission planning process to avoid “subversion” of the market model.
It’s not a mess; it’s a market
Most stakeholders reached by Utility Dive agreed markets fixes could go a long way to correcting the negative pricing and curtailment in the West.
The MWTG set out to establish a single tariff, Kelly said, “but realized there are far greater benefits from joining a regional market.”
BPA’s Wilson sharply disagreed. If a market can minimize curtailments, “there may be a small benefit,” he said. But “it is unlikely that organized markets are going to be able to consistently uncover large amounts of generation or load flexibility that existing bilateral markets haven’t already found.”
Brattle’s Pfeifenberger said it is a matter of cost. “The more renewables you curtail, the more costly renewables become because a bilateral market is just not nimble enough.”
CAISO’s Alderete argued against characterizing negative pricing and curtailment as a failure of the market. Instead, the market is doing exactly what it is designed to do, he said. The problem is that the design no longer fits the grid’s needs
“In the past, California’s main concern was having adequate capacity,” he said. “Today, the main concern is having adequate flexible capacity.”