California grid data is live – solar developers take note

Some projects take years to move through the interconnection queue. And it often costs thousands, or tens of thousands, to be told that your project won’t fit on the local grid for whatever reason. In markets like Massachusetts, you can then be asked to spend significant amounts of money to upgrade transformers, install new powerlines, or upgrade substations and then play the lottery that later developers take some of those upgrade costs onto their local projects. Things like this can kill the financials of otherwise viable projects.

California has taken steps to mitigate this risk by requiring electricity utilities to provide increasingly detailed maps of the grid. And the newest version of their Integration Capacity Analysis (ICA 20) maps went online as of December 28.

Here’s where these maps live:

Images from PV Magazine

Some of the benefits of the new map structure are noted in the above image, including that they provide circuit level data as well as hourly usage rates on said circuit. Sahm White, Economics and Policy Analysis Director at the Clean Coalition noted:

A developer can now determine, early in the decision-making process, what size of project can be sited at any location with little or no modification to the existing grid. This is critical for easily choosing the best locations for siting projects, and then for projects that are moved forward, being informed with realistic costs and timing expectations regarding interconnection.

The new maps evaluate the most common interconnection capacity factors at the node level on every line section of all primary distribution circuits. Clean Coalition pointed out that level information gives insight at every point on the circuit where there can be a change in values that would affect the ICA results, which would affect how much solar can be attached.

The information will be updated monthly.

Clean Coalition told pv magazine they hope that the hourly data will facilitate even higher levels of integration from insightful developers who make use of energy storage on what might seem like a crowded circuit, but really is a circuit that just need a bit sharper analysis.

ICA 3.0 next steps have already been defined:

  • Current ICA maps pertain to just the distribution grid. ICA 3.0 will add constraints related to the transmission grid that could affect interconnection — for example, other projects being proposed for that part of the transmission grid.
  • ICA 2.0 maps model each circuit, but they do not show how a circuit may affect neighboring circuits. ICA 3.0 will dynamically model multiple circuits and their impact on one another.
  • ICA 3.0 will aim to update the maps in real-time, to ensure that the results are never out of date.

An analysis by the U.S. Department of Energy’s (DOE) National Renewable Energy Lab (NREL)  has found that pre-applications for systems 500 kWAC and greater in Massachusetts were correlated with a 24% increase in interconnection service agreements approved.

It looks like California is at least two generations of technology ahead of other states. Let’s hope the rest of us catch up, so that we have a grid that can make an asset out of every building, every battery, and every solar system.


California grid data is live – solar developers take note, by John Weaver, PV Magazine, January 7, 2019.

Western Regionalization Plan B: Utilities take an interim step to expand the grid

Western utility leaders’ political push to expand California’s grid system into a regional power market was dismissed in the state’s most recent legislative session — but now those leaders are looking toward a different market.

California lawmakers in August rejected Assembly Bill 813, which would have expanded the California Independent System Operator (CAISO) by including other Western state representatives into its governance. California lawmakers, concerned this might compromise the state’s clean energy goals, froze the bill in committee.

Policymakers and utility leaders in California, Washington, Oregon, Nevada and Arizona remain committed to developing some kind of regional cooperation and are discussing an expansion of CAISO’s real time energy imbalance market (EIM) to its day-ahead operations.

“Cautiousness in the West about these things makes evolution better than revolution,” former California Public Utilities Commissioner Mike Florio, a leader in the new regionalization effort, told Utility Dive.

While policymakers have struggled with regionalization, the EIM “has been quietly churning out savings and expanding collaboration and trust between participants,” Florio said. “Now may be the time to expand the EIM to the day-ahead market, which has probably always been a more natural Plan B.”

The existing EIM is a real-time energy market in which Western utilities and CAISO exchange resources to meet demand that was not scheduled in the day-ahead market. Having real time visibility into supplies across an eight-state region allows participating utilities to balance fluctuations in supply and demand at a lower cost, according to CAISO. It also allows avoiding the costs of curtailment.

Participants have saved a cumulative $401 million dollars for ratepayerssince the EIM launched in 2014. Florio and others in California and across the West believe obstacles that blocked efforts to create a Western regional power market will not stop participants from realizing far more savings in a day-ahead EIM.

Savings from increased efficiency in resource dispatch and sharing renewables could potentially multiply significantly since an estimated 95% of the present market volume is day-ahead activity. But reconsideration of existing transmission charges and bilateral contracts will be necessary to make the day-ahead EIM a reality.

EIM by the numbers

The seven current real time EIM participants working with CAISO are the six state PacifiCorp utilities, NV Energy, Puget Sound Energy, Arizona Public Service, Portland General Electric, Idaho Power, and Powerex.

Regional coordination through voluntary transactions reduces costs and increases reliability in three key ways, according to CAISO. Participants reduce the need for reserves, reduce greenhouse gas emissions (GHGs) by more efficiently integrating renewables and reduce curtailment.

The CAISO Board of Governors appoints the EIM’s Governing Body, which supervises operations. But use of the market is voluntary. This is key to the system’s success because it preserves participating utilities’ autonomy, the Governing Body’s Vice Chair, Carl Linvill, told Utility Dive. Linvill is also a principal of the Regulatory Assistance Project and a former Nevada Public Utilities Commissioner.

If the ongoing stakeholder process results is moving ahead with a regional day-ahead EIM, the CAISO Board of Governors could extend oversight of it to the Governing Body, but utility participation would remain voluntary, Linvill said. “All the current EIM participants have expressed interest in a regional day-ahead market, but they are unlikely to make a firm commitment until studies show benefits are greater than costs.”

EIM benefits “include cost savings and the use of surplus renewable energy,” according to the CAISO Q2 2018 report. Q2’s $71.21 million in benefits and the market’s cumulative $401.73 million in benefits show the EIM is increasing its use of low-cost renewables and reducing curtailment through an automated selection of “the most economic resources across the EIM footprint.”

A significant factor in creating benefits is “transfers across balancing areas”, according to the report. Avoiding renewables curtailment is another benefit that reduces GHGs. In Q2 2018, utilities displacing 55,267 metric tons of CO2 by avoiding 129,128 MWh of renewables curtailment.

These calculated benefits “are in line with analysis conducted by each EIM entity before they joined,” the report concludes, suggesting studies proposed by Linvill could be equally accurate.

Market volumes vary but a “fair” estimate is that the real time EIM handles about 5% of the volume and the day-ahead market makes up the other 95%, according to CAISO Senior Public Information Officer Anne Gonzales. “We are seeing more than $400 million in cost benefits for 5% of the market.”

Examining benefits

California policymakers’ objections to expanding CAISO “do not appear to be implicated in an EIM expansion,” Matthew Freedman, staff attorney for consumer advocacy group The Utility Reform Network (TURN), told Utility Dive. Freedman was one of the most vocal opponents of AB 813 because of the potential threat to the state’s climate policies.

“We need more details before formally committing, but TURN will likely be supportive of a day-ahead EIM because it can address curtailment and over-generation,” he said. The plan would offer benefits of regionalization without requiring the governance change that could allow interference by the Federal Energy Regulatory Commission (FERC) or out-of-state fossil fuel generators.

“A key factor is that participation in the EIM is purely voluntary,” Freedman added. “If FERC were to impose requirements that were very problematic for California, we could withdraw and still have the California ISO system the way it is now.”

Although the November election of a new California governor could change things, a day-ahead EIM is currently CAISO’s primary focus, Linvill said. A day-ahead Market Enhancement initiative is preparing the system to move from a one-hour scheduled resource dispatch to a 15-minute dispatch.

That initiative sets the stage for the Expanded Day Ahead Market, which will extend the day-ahead market to the region’s EIM participants. They would be able to take advantage of the more frequent dispatch of resources when they have unplanned needs to balance their systems.

A primary driver in the 2018 CAISO three-year roadmap is “extending day-ahead market enhancements to other EIM balancing areas,” according to a January 2018 presentation for the Governing Body.

The roadmap promises benefits for day-ahead EIM participants similar to those delivered by the real-time EIM. It forecasts market efficiencies and renewables integration, while protecting local and state regulatory control over resource planning and procurement decisions, and transmission planning and investment decisions.

Only a detailed cost-benefit analysis can show how much bigger the benefits of a day-ahead EIM might be, Linvill said. “But the incremental progress toward regional collaboration and trust has been awesome.”

Challenges in charges

Day-ahead market expansion does not have a regional market’s planning efficiencies, but it offers operational efficiencies and advance unit commitment that create savings, Florio said.

Both the CAISO Board and its EIM Governing Body supporting the ongoing stakeholder initiatives for extension of the day-ahead market to the EIM entities and want to see studies go forward, Linvill said.

However, stakeholders must resolve important and difficult issues, according to CAISO’s roadmap. First, others will need to agree to CAISO’s transmission access charge (TAC).

“It is imposed on flows in or out of the California system, but it is punitively high,” former Washington Utilities and Transportation Commissioner Phil Jones told Utility Dive. “The need to recover cost is understandable, but it is a disincentive for Pacific Northwest participants.”

Second, existing bilateral contracts for transmission and the revenue rightsfor opening capacity on contracted lines to relieve congestion must be settled.

“Long term rights holders expect more revenues,” Florio said. “This friction can be reduced if the rules are clear, but it will take considerable negotiation, and maybe a little creativity, to figure out what works.”

Third, it will be necessary to resolve the “resource sufficiency” issue to ensure no participant is “leaning on others for capacity, flexibility or transmission,” according to the roadmap.

“A participant without its own resources cannot rely on the spot market to serve its load because that could trigger an energy crisis,” Florio said. “But the real time EIM has a resource sufficiency test ready. That leaves transmission as the big question.”

Finally, there needs to be transparently attributed accounting for all day-ahead and real time transactions, including resource sufficiency transactions that impact GHG accounting, the roadmap reported.

To be fair to those with existing investments and to ensure that future investments make sense, it will first be necessary to know what the costs for transmission will be and how they compare to benefits, which “will require a detailed study,” former Public Utilities Commission of Nevada Commissioner Rebecca​ Wagner told Utility Dive.

California needs greater access to other markets, “either through the EIM expansion or an alternative,” Freedman said.

One way would be expanding the CAISO limit on exports, Freedman said. “A recent study showed relaxing the net export limit from 2,000 MW to 8,000 MW would resolve 75% of the curtailment that full regional expansion resolved.”

Other options include a “voluntary reserve sharing agreement” to reduce costs and fossil fuel use for reserves or a resource adequacy agreement connecting California with Pacific Northwest hydro, he added.

“Regionalization made the CAISO less willing to explore alternative approaches,” Freedman said. “Taking it off the table could provide an opportunity to find better solutions. A day-ahead EIM is the logical next step, but first there needs to be a cost-benefit analysis.”

Looking ahead

The day-ahead market will begin operating with 15-minute interval scheduling sometime in 2019, according to Linvill. The enhancements now being designed will make it possible to extend the day-ahead market to EIM participants.

The proposal is “the right path” and should offer benefits “above and beyond what we’re seeing in the real time EIM,” Wagner said. “It is not a substitute for full regionalization, but if I was still a regulator, I would want my regulated utility to explore it and I would want to hear from them on it.”

It is not clear whether a day-ahead EIM’s benefits would be a small incremental increase or a significant increase, she added. “But, from a regulator’s point of view, if there is a chance to save ratepayers money by delivering electricity more efficiently, we should be exploring it.”

Though other markets have developed from real time EIMs, a day-ahead EIM has never been an interim step to regionalization, Florio said. “But any time people work together on a common problem, it lays the groundwork for taking another step. Building confidence takes time.”

If AB 813 had passed, a regional system could not have been achieved before about 2022, which is when the CAISO’s day-ahead EIM is likely to be in service, he added. If, during that time, national politics change, full regionalization might be reconsidered.

“If there was an administration in Washington pushing to do something about climate, it would add some momentum that is not there now,” Florio said. “For now, there is a lot to be said for moving systematically, in small steps.”


Western Regionalization Plan B: Utilities take an interim step to expand the grid, by Herman K. Trabish, Utility Dive, October 30, 2018.

FERC Proposes to Open up Wholesale Markets for Energy Storage and Aggregation

The Federal Energy Regulatory Commission just took its strongest step yet to initiate markets for energy storage across the nation.

The commission, which governs interstate power transmission and wholesale markets, proposed a rule Thursday that would require each regional transmission organization and independent system operator to create rules for energy storage to participate in wholesale markets. The new regulations would have to recognize “the physical and operational characteristics of electric storage resources,” which differ from traditional grid infrastructure in that they can act as both a load and a generator, and perform a multitude of functions if given the chance.

If approved, the proposed rule could greatly expand the role of energy storage in wholesale markets — and the size of the industry itself. So far, storage has been relegated to the few areas that passed enabling policies.

The PJM grid operator created a frequency regulation market and became the largest U.S. market for energy storage. It has seen 250.5 megawatts of cumulative deployments since 2013, according to GTM Research. The California ISO established a “non-generator” resource type that allowed storage to compete in the markets, and California became the second most prolific U.S. market for energy storage, with 73.2 megawatts deployed.

ISOs and RTOs serve about 70 percent of the country, so if FERC requires all ISOs and RTOs to adopt similar policies, the geographically cloistered storage industry could quickly go nationwide.

“This isn’t just clarifying existing rules; it’s redefining the rules to acknowledge the fact that energy storage cannot adequately participate right now and changing the rules to accommodate it,” said Daniel Finn-Foley, senior analyst for energy storage at GTM Research. “It’s a really big deal.”

The proposed rule also directs grid operators to adjust their rules so that distributed energy resource (DER) aggregators can compete in wholesale markets “under the participation model that best accommodates the physical and operational characteristics of its distributed energy resource aggregation.” This could expand the market potential for a host of distributed resources, like demand response, energy efficiency, storage and renewables. The numerous companies with business strategies that hinge on aggregation will have a greatly expanded geographical scope.

To be clear, this rule is by no means finalized. This announcement followed a request for information back in April. After publication of the proposal in the federal register, stakeholders will have 60 days to submit comments. At that point the commissioners will re-evaluate the rule in light of the new information submitted. They could pass it as-is, or pass a revised version, or keep deliberating.

Adding to the variables, President-elect Donald Trump will have an opportunity to appoint two new commissioners after taking office January 20, so the new blood could influence the direction of the final wording. Keen observers of the storage industry will want to keep their eyes on this process for the next few months — and beyond.

“This will create at least a basic level of access for storage to all of the market products of each RTO and ISO,” said Jason Burwen, policy and advocacy director at the Energy Storage Association, a storage industry group. But, he added, “Implementation matters. Each RTO and ISO will make decisions about how it wants to go about this.”

The FERC proposal could accelerate the integration of storage into the grid far beyond the status quo trajectory, but ultimately the more local decisions will govern the details of how storage actually participates in the markets.

To learn more about this and other pressing storage industry developments, join Greentech Media for the U.S. Energy Storage Summit Dec. 7-8 in San Francisco. Now in its second year, the Summit will bring together utilities, financiers, regulators, technology innovators and storage practitioners for two full days of data-intensive presentations, analyst-led panel sessions with industry leaders and extensive, high-level networking. Learn more here.

FERC Proposes to Open up Wholesale Markets for Energy Storage and Aggregation, by Julian Spector, Greentech Media, November 18, 2016.

The New Green Grid: Utilities Deploy ‘Virtual Power Plants’

The tens of thousands of tons of natural gas that surged into the Southern California sky late last year were supposed to have fueled the region’s power plants and heated its homes. Instead, the massive leak at the Aliso Canyon storage site left California electricity providers racing to replace the lost supplies to avoid blackouts and recurring outages in the coming months.

But Los Angeles area utilities aren’t solely seeking more fossil fuels to fill the gap in natural gas. They are also turning to “virtual power plants”: sprawling networks of independent batteries, solar panels, and energy-efficient buildings that are tied together and remotely controlled by software and data systems. The goal of these virtual power plants is to collectively reduce customers’ energy demand at peak hours and provide renewable energy supplies in targeted areas. This would allow utilities to offset some of the needs for power from conventional sources and avoid disruption on the grid.

Energy experts say that the ongoing response to California’s natural gas shortfall may serve as a high-profile test case for virtual power plants, an emerging field of clean energy that is projected to more than quintuple in size in the United States within a decade, rising from about 4,800 megawatts in capacity in 2014 to nearly 28,000 megawatts by 2023, according to Navigant Research, a consulting and market research firm. Power providers in the U.S. and Europe are increasingly experimenting with these systems to help manage and harness the value of thousands of distributed energy systems – the various energy storage, efficiency, and renewable energy installations scattered across the grid.

“There’s been a significant uptick in interest from utilities and other power-sector shareholders to deploy these solutions for their different needs,” Omar Saadeh, a senior analyst at GTM Research, said by phone from San Francisco.

Propelling this demand overall is the nation’s ongoing shift away from a centralized electricity market — where hulking, fossil fuel-fired power plants send electrons across state borders via transmission lines — toward a network of localized and lower-carbon supplies, Saadeh said. “The whole notion that utilities are transitioning into a decentralized system is where this interest in virtual power plants and other technologies has really emerged,” he added.

GTM Research projects that just the software component of virtual power plants – known as “distributed energy resource management systems” – will soon double in market value, from roughly $50 million in 2014 to $110 million in 2018. Add in the renewable energy technology, batteries, and other components, and the virtual power plant market could grow from $1.5 billion in annual revenue in 2016 to a $5.3 billion market by 2023, with the U.S. taking $3.7 billion of that year’s total and Europe snagging $1.3 billion, Navigant projected in 2014. Peter Asmus, principal research analyst for Navigant in San Francisco, said the market may actually be worth much more, given the recent growth in residential and commercial battery systems from companies such as LG Chem and Panasonic.

In California, the gas shortfall resulting from the Aliso Canyon leak is speeding the adoption of these emerging energy technologies. The California Public Utilities Commission in late May ordered Southern California Edison (SCE), the region’s main power provider, to “expedite its purchase of energy storage” this summer to help “alleviate the electric reliability risks to the Los Angeles Basin,” a process that’s still ongoing. Utility commissioners also asked SCE to hasten the rate at which privately owned batteries, solar, and other distributed systems are connected to the grid.

SCE obtains most of its natural gas supplies from Southern California Gas Company, which owns the underground Aliso Canyon facility that leaked more than 97,000 metric tons of methane from late October 2015 through mid-February this year. Only about 15 billion cubic feet, or less than one-fifth of the facility’s capacity, remains available for electricity and heating service in the region, California regulators estimated.

Stem Inc., an energy storage provider, says it expects to accelerate some of its existing virtual power plant projects in the Los Angeles area as a result of California’s response efforts.

The startup uses batteries and software to help major retail and hospitality companies, such as Whole Foods and Marriott, reduce their electricity bills. In the last seven years, Stem has installed battery systems (occasionally paired with rooftop solar) in hundreds of large buildings across California. Batteries are charged when electricity rates are low. Stem’s software systems then analyze a building’s energy use along with information on utility rates. When power prices are most expensive, the system automatically reduces the use of utility-provided electricity and instead draws from the battery.

In this way, the owners of individual buildings can lower the “peak demand” fees that utilities charge them each month. But collectively, the benefits are even greater, John Carrington, Stem’s chief executive officer, said in a phone interview. Through its software, Stem can coordinate the systems in its customers’ buildings to reduce area-wide energy demand when power is suddenly needed. Stem received a contract in 2014 to provide SCE with 85 megawatts of virtual power in densely populated areas where existing supplies are constrained.

Carrington said Stem is now working with “all the Los Angeles-area utilities on very fast-responding and quick installations of our product.” For virtual power, he added, the response to Aliso Canyon “could really serve as an inflection point for the industry.”

Not all virtual power plants work exactly like Stem’s aggregated network of buildings, which use batteries and energy management systems. In fact, the definition of a “virtual power plant” is still a bit vague and subjective, especially since many of these technologies remain in the pilot and development stages. Generally, however, the systems follow one of three models.

The first is a supply-side system, which is more prevalent in European nations like Germany and Denmark, where small-scale renewable energy projects already abound. In this model, local governments and grid operators can coordinate the output of independent solar arrays and wind farms — which operate intermittently and at different hours — with hydropower, biogas, and other low-carbon resources, thus simulating the output of a 24-hour power plant. In November, German technology giant Siemens Corp. and the utility giant RWE said they would jointly build the IT backbone of a mass-market virtual power plant that will coordinate hundreds of megawatts’ worth of distributed energy projects such as wind and solar farms.

The second model focuses primarily on “demand response” – cutting consumption, through energy efficiency systems and software, during hours when electricity demand is highest. This reduces the need for utilities to fire up costly fossil-fuel “peaker” plants to provide limited spikes of supplies.

The basic premise of demand response — utilities charge large energy users a lower rate year-round in exchange for powering down during peak hours — has existed for decades. But modern software and data systems take what used to be a building-by-building approach and spread it across thousands of sites into a reliable, scalable virtual power plant, according to Sarah McAuley, senior director of marketing for EnerNOC, an energy software and services firm in Boston.

EnerNOC dominates this field in the U.S. The company pays the owners of commercial and industrial buildings to let it periodically reduce their power consumption when the grid is overburdened, or to avoid high electricity prices. EnerNOC’s software platform can notify manufacturers when they should switch into maintenance mode for a few hours, or advise office managers to scale back air conditioning use. A small device tied to the electricity meter then sends data to EnerNOC, which measures and tracks energy reductions at each individual site.

The company can offer those “negawatts” of reduced energy use to grid operators, which in turn pay EnerNOC for the service. EnerNOC’s largest market is the PJM Interconnection, which coordinates the movement of wholesale electricity among 13 Eastern and Midwestern states.

“Instead of meeting consumer demand for electricity by adding more electricity to the system, we pay people to reduce their usage,” McAuley explained in an email. “The effect is that there’s enough power to go around.”

The third model of virtual power plants is, like Stem’s approach, a mixed bag of assets such as battery storage, solar power, and energy efficiency systems that both reduce consumption and supply clean power in targeted ways. Navigant’s Asmus said this sector could see the most growth in the United States, particularly as the cost of battery systems continues to plummet and solar panels proliferate across U.S. rooftops.

Much of U.S. growth, however, will initially be concentrated in only a handful of states — primarily California and Hawaii, but increasingly New York and the mid-Atlantic states, as well. Some state legislatures and utility regulators have adopted rules, or are developing policies, that make it easier to integrate small-scale renewables systems into the broader grid. But in other areas, including the Rocky Mountain states, regulations haven’t caught up with the emergence of new electricity models.

“These are very nascent technologies,” said GTM analyst Saadeh, “and it’s a very nascent market, in terms of understanding from a utility and regulatory perspective.”

Virtual power plants make more economic sense in areas with high concentrations of wind and solar power, according to Saadeh. On their own, managing thousands of independent, intermittent renewable energy systems can create logistical challenges for utilities, which have to ensure that too much solar power doesn’t flood the grid at once or that customers can turn their lights on when the wind isn’t blowing. Power companies thus have greater incentive to tap technologies that best coordinate the benefits of those disparate systems, especially in areas with higher concentrations of renewables.

“A distributed grid with a high penetration of renewable energy needs some sort of flexibility,” Saadeh points out. “Virtual power plants offer that.”

Technology firms, utilities and regulators are also still in the early stages of figuring out the right market value for virtual power plants and how they should compete in the electricity market. The startup Olivine has several pilot projects in California that aim to answer those kinds of questions.


Until recently, little was known about the extent of methane leaking from urban gas distribution pipes and its impact on global warming. But recent advances in detecting this potent greenhouse gas are pushing U.S. states to begin addressing this long-neglected problem.

“A lot of technologies are being developed, but there’s a big gap between that and actually getting to money and providing services to the grid,” said Beth Reid, Olivine’s chief executive officer.

In one pilot project with the utility PG&E Corp., an array of various, aggregated assets – including battery storage, electric vehicles, and more – are participating in the wholesale electricity market, just like a conventional power plant. The idea is to show that virtual power plants can provide flexible, fast-responding power services to the grid to help plug the intermittent supply gaps from wind and solar power, akin to a gas-fired peaker plant. Participants receive monthly payments for providing their power supply capacities to the pilot market.

Reid said she expected virtual power plants will ramp up dramatically as pilot projects help to sort out the different technologies and systems, and states continue removing regulatory hurdles.

“There’s still a lot of experimentation about who actually owns the resources of a virtual power plant and different mechanisms in different states,” she said. “But I think it’s going to significantly scale [up] – not even in the next decade, but the next three to five years.”

The New Green Grid: Utilities Deploy ‘Virtual Power Plants’, by Maria Gallucci, Yale360, August 1, 2016.