California’s Flood of Green Energy Could Drive a Record 8GW of Curtailment This Spring

Last month, the California Independent System Operator quietly announced that it could face a record-breaking need for curtailments — paying, or forcing, generators to stop pumping electricity into a transmission grid that just doesn’t have the demand for it at the time.

“With the bountiful hydro conditions expected this year and significant additional solar installations both in the form of central station and on rooftops, we expect to see significant excess energy production this coming spring,” CAISO CEO Stephen Berberich wrote in a memo to the grid operator’s board of directors. “Currently, the forecast is that we could have the need to curtail from 6,000 [megawatts] to 8,000 [megawatts].”

Managing oversupply conditions isn’t new to CAISO, spokesperson Steven Greenlee said. But, he added, “We haven’t had this potential amount of excess supply on the grid before.”

The biggest contributor is the heavy rain and snow that has helped California fill its depleted reservoirs. Many of them are now so full that they’re likely to go into “spill” mode this spring, Greenlee said. And “when they’re in spill and they’re generating electricity, we have to take that electricity, because they can’t turn their generators off.”

California hasn’t had so much hydro power coming on-line since 2011, he said. And that was years before solar power became a significant contributor to the state’s midday energy mix. “We didn’t really start adding solar until 2014,” he said. But CAISO has added about 2,000 megawatts per year since then, totaling 9,792 megawatts in June of last year. “We expect it’s going to [bring on-line] another 2,000 megawatts from 2016 to 2017,” he said.

All of this solar has led to what CAISO calls the “duck curve” — a deep dip in demand during solar-saturated midday hours, followed by a steep ramp as solar fades away. And this supply-demand pattern is happening even faster than CAISO first predicted in 2013, he said. An analysis by energy consultancy ScottMadden found that California is about two years ahead of CAISO’s duck curve schedule, in terms of the lows it’s hitting on certain sunny, mild spring days, when solar power surges and air conditioners aren’t being turned on to soak it up.

CAISO’s curtailment plan: From “decremental” bids to “exceptional dispatch”

Curtailment is generally the last step in a long process governed by CAISO, as manager of a commodity market that has to be kept in perfect balance at all times. First of all, when supply of power of any kind exceeds demand, prices drop, and generators can reduce output in response, if they have the flexibility and economic incentives to do so, Greenlee said.

Of course, most of CAISO’s oversupply is coming from generation resources that lack that flexibility, which has led to an increasing incidence of negative pricing.

CAISO’s next step is to offer generators the opportunity to make money by reducing their power output, he said. “Once we go into an excess or oversupply condition, our market first goes out and sends signals to the generators that say, ‘How much would you take, bid in as a price, to reduce or quit producing?’”

That’s called a “decremental” bid, as opposed to an incremental bid that pays generators to increase production, and through it, “The market solves that oversupply almost in every instance,” he said.

If all of these market measures fail to bring supply in balance with demand, “We will go in and start manually intervening in the market,” he said. “We will cut self-schedules, and if that hasn’t worked, we will ‘exceptionally dispatch’ units to go offline.”

These manual “exceptional dispatch” interventions do occasionally happen, he said. But they’re very rare. Out of the 240 million megawatt-hours or so that CAISO delivered in 2016, it curtailed about 308,000 megawatt-hours, almost all of it through decremental bids. Self-scheduled cuts and manual interventions made up 1 percent or less of that total, he said.

But “unless we take actions to mitigate the excess supply, the times we’ll have to manually intervene in the market will increase,” he said. “We’re seeing our oversupply earlier than what we have forecasted. We’ve got to keep pressing on and implementing new solutions.”

Looking for solutions: Flexible solar farms, broader grid markets, time-of-use pricing

CAISO has far fewer levers to pull on the demand side of the equation, Greenlee noted. California does have hundreds of megawatts of demand response, of course. But that doesn’t really help solve the oversupply problem, since it’s set up to get customers to reduce their power use. A demand-side effort to solve curtailment would instead encourage people to use more electricity, he said.

That could happen through time-of-use pricing schedules or special tariffs that offer exceptionally low prices, or even direct payments, during periods of oversupply. California is in the midst of shifting all of its big utilities to time-of-use rates by 2020, and CAISO is working with the California Public Utilities Commission to “develop the rate tiers to incentivize people to use excess energy when we have it, which is now in the mid-mornings to mid-afternoons,” Greenlee said. “That’s kind of a flip — it used to be that the rates would disincentivize use during that time.”

CAISO is also increasingly relying on its links to the broader U.S. Western grid, he noted. In 2014, it expanded its Energy Imbalance Market to include Rocky Mountain state utility PacifiCorp, as well as Nevada utility NV Energy. This real-time market is useful to find demand for excess energy, in what CAISO calls “avoided curtailment,” he said. This chart shows that most of the transfers are happening during the same midday hours that solar is generating at its peak, indicating the source of the megawatts being exported.

CAISO also wants the California legislature to pass a law allowing it to expand its balancing authority, said Greenlee. “Then we could optimize all of those resources in the day-ahead timeframe, rather than dealing with excess supply through our real time Energy Imbalance Market,” he said. Day-ahead markets are a lot easier to participate in than real-time markets, opening up a broader potential customer base. CAISO’s plans were put on hold during last year’s busy legislative session, but Senate Bill 350, the omnibus energy bill passed last year, requires that the state explore it as part of its renewable energy goals.

While solar farms are the main driver of the duck curve, they don’t have to just be passive providers of power, he added. Last year, CAISO joined First Solar and the National Renewable Energy Laboratory (NREL) in a project to prove that PV farms can shape and shift energy output through advanced inverter controls, in ways that could rival natural-gas-fired peaker plants, at least in terms of fast-acting frequency response.

But as more solar comes on-line, curtailments are likely to increase, which could create an “economic limit to deployment” for solar power in California, as NREL noted in a recent study on the state’s 50 percent by 2030 renewable portfolio standard goals. “If we have to start turning renewables down or off, it undermines the effort to reach the goal that the renewable portfolio standard sets,” Greenlee said.

CAISO has predicted that it will see 13,000 megawatts of solar power on the grid by 2020, giving the state “thousands and thousands of megawatts we’re going to have to deal with,” he added. “We’re already being proactive in looking for solutions,” such as launching the country’s first market opportunity for distributed energy resource providers, or DERPs, to aggregate solar, demand response, energy storage, electric vehicles or other flexible loads into resources for its energy market.

At the same time, CAISO’s role has its limits, Greenlee said. It doesn’t track demand by end user — “All we do is get a schedule in that says to deliver 100 megawatts of electricity to four hours to a particular substation.” That means it doesn’t directly track what’s going on with rooftop solar on the distribution grid, besides seeing it as a reduction of load. “That’s behind the meter, and we’re still wholesale.”

Building a Better Electric Grid, for a Better California

What would you think if someone told you there was a machine that could deliver limitless amounts of clean energy to everyone, while also taking in new supplies from anywhere? A device able to knit together constantly changing power flows from the sun and wind, and balance them with reserves stored in giant batteries, electric vehicles, even water?

Today’s grid is becoming smarter and more dynamic while making a tremendous difference in the way we energize our modern lives.

Oh, and one that could enable all of the latest high-tech innovations for those who desire them, while also providing reliable electricity for people who simply want the lights to come on and their wall outlets to work, without thinking about any of those things.

Much of that machine is already in place, right now. And PG&E is working hard to modernize it and make it even better.

We call it the electric grid. It has been an amaz­ing engineering feat since the days of Thomas Edison. For more than a century, the basic con­cept — move power from the production plant to the consumer, as quickly and safely as possible — stayed pretty much the same.

Here in California, that’s changing. Today’s grid is becoming smarter and more dynamic, and enabling new players in the energy business. That’s making a tremendous difference in the way we energize our modern lives, as well as helping the state deliver on its vision for a cleaner, more sustainable future.

Already, nearly one-third of the electricity PG&E supplies to our customers comes from renewable sources such as solar and wind — a goal set by California that we’re meeting nearly four years ahead of schedule.

Even better, when you include all of our low-and no-carbon resources, nearly 70 percent of the electricity on PG&E’s grid is now greenhouse-gas free, making our energy among the cleanest in the nation.

To us, that’s a signal that the clean-energy chal­lenge is entering a new phase — one of scale and systems, available to all.

The technology needed to power a low-carbon economy is increasingly available, and it’s possi­ble that the remaining gaps, such as cost-effec­tive energy storage, will also be filled faster than expected.

The task now is to connect the best of these innovations with markets that allow them to grow, while also inte­grating them in ways that create expo­nentially more value for every energy user — no matter who they are, where they live, or what they do.

The smart grid we’re building today will accom­plish that by functioning much like the inter­net — a platform that provides universal access to clean energy, while creating new choices for consumers and spreading the gains of a low-car­bon economy as widely as possible.

But to fully unleash that potential, companies such as PG&E need to continue making significant investments in the grid. And that, in turn, requires policies that can keep pace with rapidly evolving technology and market forces.

As we shift to an economy where electricity is produced and used differently, the cost of the grid will need to be recovered in ways that more accurately reflect the services that energy com­panies like PG&E provide — while still rewarding customers for their own clean-energy contribu­tions. The benefits must also be accessible and affordable to all of our customers — including small businesses, families, and those who need help paying their bills.

Making sure that the system works for every­one is one of PG&E’s key responsibilities, and an essential part of our job. It’s also part of why that work is so meaningful.

Since those early days of our industry when the grid was being invented, I don’t think there’s ever been such rapid change, with such important con­sequences. And as in Edison’s time, our success in building a better energy system promises to make a real difference in people’s lives — both our own, and all of the generations to come.


Building a Better Electric Grid, for a Better California, Geisha Williams, Pacific Gas & Electric, March 16, 2017.

PG&E Renewable Energy Deliveries Grow; GHG-Free Portfolio Is Nearly 70 Percent

SAN FRANCISCO, Calif. – Nearly 70 percent of the electricity Pacific Gas and Electric Company (PG&E) delivered to its customers in 2016 came from greenhouse gas-free resources, the company announced this week.

One of the nation’s cleanest energy companies, PG&E delivered an average of 32.8 percent of its electricity in 2016 from renewable resources including solar, wind, geothermal, biomass and hydroelectric sources. That’s more than a three-percent increase in just one year, and the highest percentage yet for the state’s largest combined natural gas and electric company. A total of 69.3 percent of PG&E’s electric power mix is from nuclear, large hydro and renewable sources of energy.

“Delivering this amount of renewable electricity strongly confirms PG&E’s continued commitment to a cleaner energy future for our customers and all of California. We embrace our role as a leader in renewable energy, and we are full speed ahead in reaching our next targets,” said Geisha Williams, CEO and President, PG&E Corporation

This record level of renewable deliveries also propels PG&E toward California’s goal of 50 percent renewables by 2030.

The renewable energy milestone comes as the energy company has continued to deliver strong electric reliability over the last decade. By investing in its electric infrastructure and integrating innovative technology to make its power grid smarter and more resilient, PG&E has reduced the number and duration of power outages impacting its customers.

California’s Renewables Portfolio Standard is one of the most progressive clean energy mandates in the country. Established in 2002, it required energy providers to increase renewable energy deliveries to 20 percent by 2017, and in 2008 expanded the goal to 33 percent by the end of 2020. Nearly achieving 33 percent renewable energy delivery and continuing the company’s advanced pace of renewable energy integration reflects PG&E’s larger commitment in the fight against climate change, said Williams.

PG&E has been a leader in clean energy and energy efficiency for nearly 50 years, beginning with energy conservation programs in the 1970s and continuing in the early 2000s with the first clean energy power purchase contracts.

PG&E’s diverse renewable power mix includes solar, wind, geothermal, bio-power and small, eligible-renewable hydroelectric energy. In 2016, PG&E expanded purchases of biomass electricity to help address the state’s historic tree mortality crisis. In addition, PG&E has connected 285,000 customers with private rooftop solar to the energy grid – representing about 25 percent of the nation’s rooftop solar and more than 2,409 MWs of clean energy. The company owns one of the nation’s largest hydro-electric systems, as well as Diablo Canyon Power Plant, both of which emit no greenhouse gases. The entire diverse portfolio allows PG&E to deliver more than 69.3 percent of its power from sources which emit no greenhouse gases.

PG&E Renewable Energy Deliveries Grow; GHG-Free Portfolio Is Nearly 70 PercentPacific Gas and Electric Company, March 16, 2017.

Net Metering 2.0 Slows down California’s Residential Solar Market

If there is one state that has led the charge towards a renewable energy future in America, it’s California. The state not only installed the nation’s first large-scale solar and wind installations in the 1980s and 1990s, but has led in terms of proactive policies to support the growth of solar and other forms of renewable energy.

As such, it was no surprise when California’s changes to net metering in January 2016, dubbed “Net Metering 2.0”, were less severe than those in other states. However, while the basic features of retail-rate net metering were preserved, in the utility areas where Net Metering 2.0 has been implemented the effect on the residential market has been a distinct chill.

Statistics provided by the State of California show an average of 11 MW of residential solar installed each month in the service area of San Diego Gas & Electric Company in the second half of 2016, compared to 16.9 MW each month for the first half of the year. This decline of more than a third (35%) came after the utility hit program caps and transitioned to the Net Metering 2.0 program in late June.

“The market has had to adjust to the new rules,” Daniel Sullivan, the founder and president of San Diego-based Sullivan Solar Power told pv magazine. “I don’t think the majority of companies know how to sell under the new policy.”

In December, Pacific Gas & Electric Company also hit its program cap and switched to the new program, however state data for January and February 2017 is not yet available.

Erratic policy behavior

California Solar Energy Industries Association (CalSEIA) says that the impacts came even before the policy was implemented and notes that the changes to net metering are only the latest in a series of changes that have had negative effects on California’s solar market.

“We saw a 2% increase in the number of people going solar in 2016 over 2015,” CalSEIA Executive Director Bernadette Del Chiaro told pv magazine. “The last time California saw that little growth in the market was 2008.”

Del Chiaro blames the slowing of the market on the combination of rate design changes in 2015, Net Metering 2.0 and “the combined ‘solarcoaster’ brought about by erratic policy behavior” around the federal Investment Tax Credit (ITC) and net metering.

One of the more potentially damning aspects of the change to Net Metering 2.0 is the move to time-of-use (TOU) rates. As California’s significant solar generation has more than compensated for mid-day peak demand and daytime prices have fallen, the electricity exported to the grid by behind-the-meter solar installations will be credited at a lower rate than the electricity such customers purchase in the evening.

Del Chiaro says that the California Public Utilities Commission (CPUC) has the ability to manage the impact of TOU rates by ensuring that rate changes are gradual. “It remains to be seen whether CPUC will take a cautious and more protective approach,” she muses. “It’s clear that the legislature wants the solar market to continue to grow sustainably, but it is unclear just how much of that directive the CPUC will heed and steward.”

Customer acquisition

GTM Research says that there are more than policy issues leading to a slowdown in California’s residential market. GTM Research Associate Director of U.S. Solar Cory Honeyman describes the decline in compensation from Net Metering 2.0 as “relatively manageable”, and says that there are other problems, including in the territory of utilities which are still on the original net metering program.

“Most importantly, the challenge of customer acquisition becoming costlier and longer has been the primary driver of the residential solar slowdown in SCE and PG&E,” Honeyman told pv magazine. “As customers in certain neighborhoods remain flooded with door-to-door sales, and some installers rely too heavily on low-quality leads from third-party originators, California is the prime example of a market where inefficient customer-acquisition strategies have slowed down the market.”

Honeyman says that such customer-acquisition issues are becoming more critical in California, where solar is already deployed on 8% of the available residential roofs.

Daniel Sullivan of Sullivan Solar Power says that part of the problem is the approach being used by many installers, which he calls “used-car sales tactics at its best”. He says that this is having an impact on potential customers. “People are confused, and they are suffering from buyer’s fatigue,” Sullivan notes.

Energy storage to the rescue?

Much of the hope for the future of California’s residential solar market is in battery storage, and CalSEIA’s Del Chiaro notes that behind-the-meter storage is the most important tool that customers have to manage and control their own energy usage.

Daniel Sullivan agrees that TOU rates are increasing the importance of battery storage. “People need batteries to keep their investments protected,” he observes.

In this regard, the policy momentum is good. Though the first two rounds of available subsidies will likely not last long, last week a commissioner at CPUC issued a proposed decision that would double funding for the state’s Self Generation Incentive Program (SGIP). Del Chiaro notes that there are also two bills in the California Assembly to further support behind-the-meter energy storage.

It remains to be seen if California’s residential storage market can ramp quickly enough. In July, Southern California Edison will transition to Net Metering 2.0, as the third and final of the state’s investor-owned utilities to do so.

Net Metering 2.0 Slows down California’s Residential Solar Market, by Christian Roselund, P.V. Magazine, March 15, 2017.

Rooftop Solar Installations Rising but Pace of Growth Falls

Solar power led the nation last year among new sources of electricity production, but growth slowed significantly as California homeowners and businesses cooled to the idea of rooftop panels.

U.S. rooftop solar installations increased 19% in 2016 compared with an average growth of 63% year-over-year from 2012 to 2015, even as the solar industry celebrated a record-breaking year.

Solar energy represented 39% of new electricity production in 2016 compared with 29% for natural gas. Overall, solar still provides just 4% of the nation’s electricity capacity.

Industry experts attributed some of the slowing expansion of the rooftop solar sector to policies that have increased consumer costs as well as to moves by the utility sector to stifle homeowner and business efforts to generate their own electricity from the sun.

The latest data from the Solar Energy Industries Assn. highlights the ongoing tension between the focus on centralized power production from big power companies and those seeking more independence from the electric grid to help the environment and as a way to save money.

As the largest U.S. solar market, California is at the center of the conflict. The California Solar Energy Industries Assn. warns that if policymakers fail to pay attention to changing growth patterns, rooftop solar could face significant harm.

Bernadette Del Chiaro, executive director of the California group, said the state in 2016 had just a 2% increase in the number of consumers who installed solar systems through the state’s three investor-owned utilities. The industry associations expect a decline in solar installations in California during 2017 compared with 2016.

“This is definitely the first year since 2008 that we have had basically zero growth,” Del Chiaro said.

Consumers, she said, are questioning whether going solar will actually help their bottom lines.

“You try to do the math with consumers, you can’t even with a straight face look across the table and explain to consumers how they’re going to save,” Del Chiaro said. “Policies need to stop harming this market.”

The national solar association, which produced the findings with Boston-based GTM Research, agreed that utility-scale solar outpaced rooftop solar. But on a nationwide scale, the solar group expects to see continued growth in both sectors.

“In large markets, like in California, you have the lowest lowest hanging fruit of consumers have probably been picked already,” said Tom Kimbis, SEIA’s executive vice president. “That doesn’t mean that there’s still not low-hanging fruit.”

Beyond California, Kimbis points to emerging solar markets in South Carolina, Utah and Texas as places where the rooftop market can be sustained.

Along with the continued growth in the utility sector, Kimbis said SEIA expects the number of solar installations to triple the current 42.8 gigawatts of capacity over the next five years.

Part of the growth will be driven by a growing number of state requirements such as California’s 50% clean energy mandate by 2030. Senate leader Kevin de Leon (D-Los Angeles) proposes to make it 100% clean energy by 2045.

Richard McMahon, vice president of energy supply and finance at the Edison Electric Institute, a utility industry trade group, said utility-scale solar provides broad benefits, including ensuring reliability of service and lower costs.

Citing an MIT study, McMahon said the installed cost of large scale solar is “more than 80% less than private rooftop solar.”

“EEI’s member companies will continue to invest in America’s energy future and remain focused on providing reliable, affordable and increasingly clean energy to all customers,” McMahon said.

And despite the slower growth in rooftop solar, solar companies are optimistic. The fatigue from the presidential election cycle, heavy rains in California and other issues unrelated to the solar market contributed to the slowdown in rooftop solar growth, they say.

Rooftop solar leader Sunrun Inc., one of the nation’s leading residential solar companies, said it expects a sustained growth rate of 20% in rooftop solar over the long term. There are five times more solar-ready homes in California than are currently sporting solar panels, and the growing electricity storage industry will make solar packages more appealing, the company said.

“We are seeing strong signs that customers are engaging with us and a rebound is beginning,” said Bob Komin, Sunrun’s chief financial officer.

Solar companies also are developing new products and offerings to attract customers.

Tesla Inc. Chief Executive Elon Musk announced in October that his company plans to offer solar shingles for residential rooftops as early as this summer as a more attractive alternative to rectangular panels attached to roofs.

Coupled with a growing array of storage options, including Tesla’s Powerwall or Sonnen’s home battery, consumers could largely become independent of their utility even as the power companies press for more solar of their own.

“Storage is definitely the game changer,” said Austin Perea, a solar analyst for GTM Research who worked on the report.

Rooftop Solar Installations Rising but Pace of Growth Falls, by Ivan Penn, Los Angeles Times, March 15, 2017.

California Solar Industry and Utilities Unveil Dueling Solar-Storage Tariffs

California is already breaking ground in attempting to properly value the distributed technologies hitting the grid. So far, that’s been done through large-scale capacity contracts, demand response auction mechanisms, and utility pilots. Now the state is opening another front in distributed energy integration: tariffs.

Over the next year or so, the state’s investor-owned utilities are under regulatory pressure to create specially designed, optional tariffs available to homeowners or businesses that want to invest in solar PV, batteries, EVs or on-site energy controls.

These rates would change from hour to hour, but with drastic price differentials between on-peak and off-peak times than the mass-market time-of-use (TOU) rates being rolled out across the state over the next four years. Such extreme price differentials could punish customers who can’t shift energy use.

But they could also provide the financial incentives to cover the costs of adding a battery to a new or existing solar PV installation, to charge up when prices are low and discharge when they’re high. And unlike mass-market TOU rates, they could include different measures of real-time value — price changes based on wholesale grid power costs, for example, or demand charges or distribution grid values aimed at getting customers to change energy-use patterns to mitigate local grid congestion needs.

All of these options are now on the table in the general rate cases being put forward by Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric. PG&E’s rate case is coming first — and we’ve already seen new tariff proposals come out from the utility and from the Solar Energy Industries Association (SEIA), two parties that have clashed before over solar-friendly rate design.

Two different approaches to solar-storage tariff design 

This week, SEIA filed testimony (PDF) with the California Public Utilities Commission asking the regulator to reject PG&E’s proposed solar-storage rate schedules for residential and small commercial customers, and to go instead with an SEIA-designed set of rates. The solar group has also proposed a new “Option S” rate for large commercial and industrial customers to encourage solar-storage systems, something that PG&E hasn’t yet considered in its rate cases.

SEIA lays out two main reasons why it doesn’t like PG&E’s rate schedules for residential and small commercial customers, called E-DMD and A1-DMD, respectively, and why it wants to replace them with its own E-STORE and A1-STORE rates instead.

PG&E’s rates would include a “significant non-coincident demand charge based on the customer’s maximum 15-minute demand each month, whenever it occurs.” And as we’ve seen from debates around the country, while some utilities have supported adding demand charges to solar net metering customers, solar industry groups have universally opposed them.

“We’re categorically opposed to residential demand charges,” SEIA’s Brandon Smithwood said in a Wednesday interview, making PG&E’s idea of adding demand charges to its residential rate a non-starter.

And while SEIA isn’t opposed to demand charges for small commercial customers, it would like to implement them in a different way. Instead of basing them on any single 15-minute spike over the course of a month, it’s proposing “daily demand charges,” imposed on customers only during the day’s peak demand hours.

The difference, Smithwood explained, is that “with a monthly demand charge, it’s just that one 15-minute interval.” If a customer fails to prevent it, they’ve “blown [their] savings for the month.” With a daily demand charge, by contrast, “We could shape that demand charge so that it really sends a better price signal. We would be moving demand charges toward something that actually works better for customers, and makes more sense for a public policy standpoint.”

California hasn’t used daily demand charges before, making SEIA’s proposal a novelty in the state’s utility policy. Here’s how it describes the concept in its testimony: “The daily demand charge of $0.6390 per kW/day applies each and every day to the highest 60-minute demand during the 3 p.m. to 8 p.m. peak period. This rate element provides the storage user with a strong incentive to use storage both to reduce and to flatten their delivered load from the utility during the peak period, and to discharge storage when the stored power provides the greatest system benefits.”

The second big problem SEIA has with PG&E’s proposal is that it doesn’t believe the differences between on-peak and off-peak prices are significant enough. “It just won’t pencil out,” he said. “Even if you could manage your non-coincident residential demand charges, there’s not enough differential there.”

SEIA’s rate differentials, by contrast, are quite high — as much as 40 cents between the 52 cents per kilowatt-hour on-peak price and the 12 cents per kilowatt-hour off-peak price for residential customers under its E-STORE rate.

But this is the kind of “spicy” differential needed to cover the extra costs of adding batteries to solar, which SEIA has estimated at 33 cents per kilowatt-hour. “You need the big — ‘spicy’ is the word commission staff like to use — more ambitious, more technology-focused, time-of-use rates, with that big differential between on-peak and off-peak,” Smithwood said.

SEIA’s testimony backs this up with its own analysis of how a 10-kilowatt-hour battery, cycling daily between the off-peak and peak periods, would fare over a year’s time under both proposed rates. Under the E-STORE rate, that system would realize $1,062 per year in benefits — “economic if such storage units have reliable lives of 10 years and costs below $10,000. Such units appear to be commercially available soon, for example, the Tesla Powerwall 2.”

In contrast, “We estimate that [PG&E’s] E-DMD rate will provide annual benefits of just $509, assuming optimistically that the storage can reduce the customer’s non-coincident demand charge by 50 percent of the unit’s output capacity.”

At present, PG&E hasn’t provided an alternative analysis of its own rates. The utility recently testified to the CPUC that it “did not perform any analysis to determine the point at which the solar plus on-site battery storage would become economic under the proposed E-DMD and A1-DMD residential and small commercial rates.”

The intricacies of creating, and comparing, never-before-seen DER tariffs

These are only two sets of multiple DER tariffs being proposed in California, and it can be hard to parse out the complex differences between all of them. At GTM’s California’s Distributed Energy Future 2017 conference held last week in San Francisco, we heard a debate between SEIA’s Sean Gallagher and Environmental Defense Fund senior economist James Fine over another proposal coming from SDG&E, specifically for EV charging.

EDF’s Fine pointed out that SDG&E’s experimental tariff for its Vehicle-to-Grid Integration pilot would be based on day-ahead forecasts of hour-by-hour prices the next day, with some adjustment for day-of changes. That will give EV drivers — or the EVs themselves — the data required to avoid high-price hours and take advantage of low-price hours.

EDF is also asking PG&E and Southern California Edison to consider what it calls a “smart home rate,” which would expand the scope of customers beyond single-technology categories like solar-storage or EVs, to include demand response via smart thermostats, grid-responsive loads and other behind-the-meter controls.

The basic concept includes some sort of monthly service fee (albeit one that’s as low as possible); a grid charge that allows customers to benefit by managing their load profile; and day-ahead hourly price signals that accurately reflect a broad range of costs and values.

Gallagher previewed SEIA’s E-STORE proposal in his CDEF talk, but also provided a critique of what SDG&E and EDF have proposed. In his view, hour-by-hour prices that change daily might push too much risk onto the customers and provide “too much certainty for the utility,” he said.

Fine agreed that “the concern is that this is maybe too risky for many customers.” On the other hand, he acknowledged that “there’s also an attractive, profitable opportunity for customers who want to take on that risk” — or perhaps are willing to hire a DER provider or aggregator to do it for them.

Given all the uncertainty over how these kinds of rates will work in the real world, both Gallagher and Fine agreed that it’s important to have a number of options available to customers.

Both also promoted tariffs that don’t just compel people to reduce energy at moments of high costs and high demand, but that also offer incentives to actually increase energy use during negative pricing events when demand is low and renewable energy supply is high — such as during the midday belly in California’s “duck curve.”

SEIA’s concept for this is called “discount days,” which would work along the lines of the critical peak pricing days widely used by California utilities (only in reverse), while EDF’s concept would embed these discounts in day-ahead pricing.

The debate over DER-based tariffs is just beginning, but this will be the year that helps set the terms for rollouts across the state. PG&E’s general rate case will likely take until the end of 2017 to complete, SDG&E’s is set to close it in the third quarter, and Southern California Edison’s will conclude in 2018.

California Solar Industry and Utilities Unveil Dueling Solar-Storage Tariffs, by Jeff St. John, GreenTech Media, March 17, 2017.

SDG&E Invests in Energy Storage with Flow Battery Technology

SDG&E is unveiling a new vanadium redox flow battery storage pilot project in coordination with Sumitomo Electric, which stemmed from a partnership between Japan’s New Energy and Industrial Development Organization and the California Governor’s Office of Business and Economic Development.

During the four-year demonstration project, SDG&E will be researching if flow batterytechnology can economically enhance the delivery of reliable energy to customers, integrate growing amounts of renewable energy and increase the flexibility in the way the company manages the power grid.

“SDG&E is continuously at the forefront of delivering clean energy solutions and championing innovative technologies to assess the long-term benefits for our customers,” said Caroline Winn, SDG&E’s chief operating officer. “This pilot will advance our understanding of how this flow battery technology can help us increase the reliable delivery of clean energy to our customers and align with state and local carbon emission reduction goals.”

The vanadium redox flow battery storage facility will provide 2 MW of energy, enough to power the energy equivalent of about 1,000 homes for up to four hours. Like other battery storage systems, the battery will act like a sponge to soak up renewable energy harnessed from the sun and release it when resources are in high demand.

Flow battery systems have an expected life-span of more than 20 years, and could have less degradation over time from repeated charging cycles than other technologies. SDG&E will be testing voltage frequency, power outage support and shifting energy demand.

“We are delighted to see our first flow battery system operating in the U.S. through the multiple-use operation of the battery system in SDG&E’s distribution network, we would like to prove its economic value and potential use on the electric grids,” said Junji Itoh, managing director of Sumitomo Electric.

“California continues to lead the nation when it comes to growing the economy and decreasing emissions,” said Sid Voorakkara, Deputy Director for External Affairs at the Governor’s Office of Business and Economic Development. “GO-Biz is proud to partner with NEDO to bring this demonstration project to life and increase opportunities for economic growth powered by renewable energy.”

SDG&E has been a leader in bringing energy storage options into the region with the recent unveiling of the world’s largest lithium ion battery storage facility in Escondido and a smaller facility in El Cajon. To date, SDG&E has about 100 MW of energy storage projects completed or contracted.

SDG&E Invests in Energy Storage with Flow Battery Technology, Electric Light & Power, March 17, 2017.

As California Prepares for Wholesale Distributed Energy Aggregation, New Players Seek Approval

California’s push to make aggregated distributed energy resources into transmission grid market players is the most developed in the country. But it’s still about a year from going live in a big way.

It’s also facing some key challenges, like getting approval — or at least “concurrence” — from the utilities that run the distribution grids where these newly minted DER providers will carry out their megawatt-scale energy shifting acts.

And then there’s the question of whether distributed energy resources (DERs) will be worth more at wholesale than they are under California’s new distribution grid values — or whether those values can be stacked together.

All of this uncertainty hasn’t stopped companies from applying for the job. Lorenzo Kristov, market and infrastructure principal at state grid operator CAISO, said at last week’s California’s Distributed Energy Future 2017 conference in San Francisco that several companies have already submitted applications to become DER providers under the new program. “I’d imagine they’re in the process of developing their actual resources they’ll be providing in the market,” he said.

Kristov didn’t name the companies involved. But a November 2016 report from CAISO to the Federal Energy Regulatory Commission does name four companies that have signed up for a “pro forma distributed energy resource provider agreement” — the first step in becoming a distributed energy resource provider, or DERP.

One was utility San Diego Gas & Electric, which proposed a 3- to 4-megawatt aggregation of energy storage sites across its territory — the largest of the four proposed projects. SDG&E proposed a 2018 start date.

Another was Apparent Energy, which said it was ready to launch in early 2017, working with Silicon Valley Power and Palo Alto’s municipal utility on two aggregations of 1 to 1.5 megawatts each. But a December report from Silicon Valley Power noted that Apparent “could not make a business case in SVP territory” at that time, although “as DG resources potentially grow and as the CAISO markets evolve, there could be potential.”

A third was Galt Power, a participant in other North American transmission markets, which proposed working with energy developer Customized Energy Solutions. The companies are “in discussions with several entities seeking to aggregate renewables and small-scale storage.”

Finally, there was Olivine, a scheduling coordinator that serves as an intermediary between CAISO and DER providers, which is “working with a number of clients, including municipalities, community choice aggregators, and resource owners.” Because every would-be DERP has to work through a scheduling coordinator, it’s hard to know which of Olivine’s clients might be involved in the company’s application.

Olivine is also involved in the Demand Response Auction Mechanism, or DRAM, pilot program, which has so far put together more than 100 megawatts of DER resources from companies including Stem, Advanced Microgrid Solutions, EnergyHub, Ohmconnect and AutoGrid. CAISO’s report notes that Olivine is “considering the addition of distributed energy resources and the potential conversion of storage and electric vehicle assets currently participating as demand response resources,” indicating that some of these DRAM clients could also be eyeing their potential as DERPs.

CAISO just published its “new resource implementation process” on its DERP website this week, opening up the potential for more applications.

California grid-DER integration: A long path from concept to reality

Last summer, after years of effort, CAISO got federal approval for its new distributed energy resource provider tariff. It allows for DERPs to submit aggregations of between 500 kilowatts and 10 megawatts that can meet the requirements for its day-ahead and hourly energy markets, or its faster-responding ancillary services markets.

Since then, California’s efforts have helped jump-start bigger changes. In October, FERC issued a ruling that opened the option of aggregated DERs for the rest of the country’s independent system operators (ISOs) or regional transmission organizations (RTOs), opening a vast new potential market.

That’s only potential, though. It can take years for FERC orders like these to make their way through grid operator technical working groups and stakeholder proceedings and into real-world markets. No other region is as far along as California right now, although mid-Atlantic grid operator PJM has opened a discussion, or a “problem statement” in its terminology, and Texas grid operator ERCOT, which is outside FERC’s jurisdiction, has held an on-again, off-again discussion on the subject.

Applying for DERP status is only the first step in a multi-stage process, Kristov noted. CAISO’s recently released “new resource implementation process” includes a 43-item list of requirements involving interconnection, metering, telemetry, topology and other such technical details. Once those are completed, it will take months more to process and verify each aggregation, he said.

In the meantime, CAISO is busy working with the California Public Utilities Commission and utilities in the state on another challenge — getting more visibility between transmission and distribution grids.

“The ISO only sees the system down to the transmission-distribution interface,” or the transmission substations that connect the state’s high-voltage grid with the distribution grid. “Even if we have telemetry to some of the devices, we don’t have the distribution system data,” said Kristov.

The gaps between transmission- and distribution-level values and capabilities

That can cause problems in two directions, Kristov said. For the distribution utility, there’s the prospect of half a megawatt or more of load suddenly dropping away or coming on-line under CAISO dispatch, causing local grid instability. FERC’s order this fall specified that distribution utilities have the right to review the composition of these DER aggregations. To solve that problem right now, CAISO requires each DERP to “obtain concurrence from the applicable utility distribution company (UDC) or metered sub-system (MSS)” to alleviate concerns, involving a utility-by-utility process that takes up to 30 business days.

In the other direction, CAISO needs to worry about distribution grid topologies, or states of network interconnection, he said. California’s transmission system is pretty stable topologically — it doesn’t see major switches and shifts in the flow of power. “But in distribution, they’re having changes in topology all the time, they’re switching circuits,” he said, and “that can affect whether a DER can respond to a dispatch or not.”

Both of these problems could be addressed by better visibility and data-sharing between utilities and CAISO, he noted. “The ISO could provide those dispatch instructions to the distribution company, and the distribution company could know…‘Oh, that’s where it is; it’s going to happen 5 minutes from now — will that cause a problem for us?’”

California’s utilities are arguably ahead of many in the country in terms of visibility into their distribution grids, with widely deployed smart meters and multiple pilot projects integrating DERs into the software and control systems that run their low-voltage networks. But they’ve still got a long way to go, as evidenced by the multibillion-dollar grid modernization investments utilities are asking the CPUC to approve for the coming years.

The state’s big investor-owned utilities are also mapping out their distribution grids to find the value of DERs as part of their multibillion-dollar annual capital investment budgets, under the CPUC’s distribution resources plan and integration of distributed energy resources proceedings. This process will create valuable data for CAISO as well as the utilities, Kristov noted.

Indeed, the value of DERs for local grid needs may well exceed the value they can realize on wholesale energy and ancillary services markets, he said. “DER substituting for distribution assets is probably more promising than DER substituting for transmission assets,” explained Kristov — an observation backed up by a Lawrence Berkeley National Laboratory analysis of the state’s future energy needs.

At the same time, CAISO does see great value in DERs that can help it manage the “duck curve” imbalances that solar power is causing on California’s grid, he said. “That problem can be solved very well at the distribution level.” But “not all the value has been clearly monetized in terms of services to be able to do that.”

As California Prepares for Wholesale Distributed Energy Aggregation, New Players Seek Approval, by Jeff St. John, GreenTech Media, March 14, 2017.

East Bay Community Energy Seeks Chief Executive Officer

The Chief Executive Officer (CEO) will report to the Board of Directors of East Bay Community Energy and will provide strategic leadership and direct all activities within the organization.

The CEO will coordinate all aspects of launching and operating the Community Choice program, and building it into an innovative enterprise that benefits Alameda County residents and businesses.

The CEO will have responsibility over the functional areas of power procurement, integrated resource planning, energy infrastructure development, internal operations, marketing, customer service, community stakeholder relations, finance, and regulatory and legislative affairs.

The CEO will work with numerous stakeholders including County residents, businesses, labor representatives, community groups, government officials, other CCA programs, regulatory bodies, and energy and utility experts. The CEO will utilize a combination of EBCE staff and contractor support, as may be needed to perform the required functions of EBCE.

The complete job notice is downloadable here.

GRID Alternatives Adds Sunrun as Another Option for Third-Party Ownership

The California Public Utilities Commission approved Grid Alternatives’ proposal to allow Sunrun to own and operate projects for the Single Family Affordable Solar Homes (SASH) Program.

Last week, the California Public Utilities Commission (CPUC) approved the addition of Sunrun to Grid Alternatives’ third-party operator (TPO) partners as part of the Single-family Affordable Solar Homes (SASH) incentive program.

The decision marks the second time Grid Alternatives has successfully petitioned the commission to allow TPO financing for the SASH program. It first added Clean Power Finance (CPF) in 2015.

Until the approval of CPF, TPOs had been forbidden for use in the SASH program over customer-protection fears. Therefore, Grid Alternatives’ no-cost solar systems could only be operated by the three investor-owned utilities in the state.

In 2015, the CPUC reauthorized the program but cut the offered incentive from $6.00/watt to $3.00/watt. To accommodate those cuts and recognizing the maturation of the TPO market in the state, the CPUC allowed Grid Alternatives to petition for the inclusion of CPF as a financing partner. After last week’s approval, Sunrun joins the list as a second option.

Before it approved that deal, however, Grid Alternatives had to prove that CPF met 12 minimum customer-protection standards, including:

  1. Ensure SASH customers receive at least 50% of the savings, as compared to standard utility rates, from the solar generating equipment;
  1. Reduce or eliminate barriers for customers with poor credit (low FICO scores) to qualify and participate;
  1. Address concerns that homeowners may have about moving or selling their home during the TPO contract term;
  1. Cover maintenance, operations, inverter replacement, and monitoring;
  1. Prohibit liens on homes;
  1. Minimize the risk to the low-income customer that the solar system would be removed for delinquent payments;

7. Ensure that all costs are apparent and upfront and that there is no risk that the TPO deal would result in an additional financial burden to the family;

  1. Standardize financial terms for low-income customers where possible;
  1. Protect the customer against terms that could change after contract signing;

10. Require that TPO agreements note the potential for additional costs associated with the contract, if applicable;

11. Require the TPO provider to clearly explain that rate changes will affect the economics of a power purchase agreement; and

12. Require that TPO agreement provisions spell out what happens in the event that the solar financing company defaults.

In 2008, Grid Alternatives was selected by the CPUC to manage the $162 millionSingle-family Affordable Solar Homes (SASH) incentive program, which aims to help low-income Californians install solar systems.

Grid Alternatives started offering the TPO model to SASH host customers in 2015. As of July 2016, the company says 389 projects totaling 1.2 MW have been completed utilizing the TPO model and SASH 2.0 incentive funding.

The CPUC said Grid Alternatives has guaranteed SASH customers will receive at least 50% of the savings compared to standard utility rates, including those who move to time-of-use rate under California’s Net-Metering 2.0.

GRID Alternatives Adds Sunrun as Another Option for Third-Party Ownership, by Frank Andorka, pv magazine, March 6, 2017.

The California Public Utilities Commission has approved a second third-party operator partner for Grid Alternatives’ low-income solar installation program. (pv magazine)