TODAY’S STUDY: “FLEXIWATTS” AND THE ECONOMICS OF DEMAND FLEXIBILITY

The Economics Of Demand Flexibility; How “Flexiwatts” Create Quantifiable Value For Customers And The Grid

August 26, 2015 (Rocky Mountain Institute)

Executive Summary

Electric utilities in the United States plan to invest an estimated $1+ trillion in traditional grid infrastructure— generation, transmission, and distribution—over the next 15 years, or about $50–80 billion per year, correcting years of underinvestment. However, official forecasts project slowing electricity sales growth in the same period (less than 1% per year), coming on the heels of nearly a decade of flat or declining electricity sales nationwide. This is likely to lead to increasing retail electricity prices for customers over the same period.

Meanwhile, those customers enjoy a growing menu of increasingly cost-effective, behind-the-meter, distributed energy resource (DER) options that provide choice in how much and when to consume and even generate electricity. These dual trends and how customers might respond to them—rising prices for retail grid electricity and falling costs for DER alternatives that complement (or in extreme cases even supplant) the grid—has caused considerable electricity industry unrest. It also creates a potential for overinvestment in and duplication of resources on both sides of the meter.

Yet utility and customer investments on both sides of the meter are based on the view that demand profiles are largely inflexible; flexibility must come solely from the supply side. Now, a new kind of resource makes the demand side highly flexible too. Demand flexibility (DF) evolves and expands the capability behind traditional demand response programs. DF allows demand to respond continuously to changing market conditions through price signals or other mechanisms. DF is proving a grossly underused opportunity to buffer the dynamic balance between supply and demand. When implemented, DF can create quantifiable value (e.g., bill savings, deferred infrastructure upgrades) for both customers and the grid.

Here, we analyze demand flexibility’s economic opportunity. In the residential sector alone, widespread implementation of demand flexibility can save 10–15% of potential grid costs, and customers can cut their electric bills 10–40% with rates and technologies that exist today. Roughly 65 million customers already have potentially appropriate opt-in rates available, so the aggregate market is large and will only grow with further rollout of granular retail pricing.

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Demand Flexibility Defined

Demand flexibility uses communication and control technology to shift electricity use across hours of the day while delivering end-use services (e.g., air conditioning, domestic hot water, electric vehicle charging) at the same or better quality but lower cost. It does this by applying automatic control to reshape a customer’s demand profile continuously in ways that either are invisible to or minimally affect the customer, and by leveraging more-granular rate structures that monetize demand flexibility’s capability to reduce costs for both customers and the grid.

Importantly, demand flexibility need not complicate or compromise customer experience. Technologies and business models exist today to shift load seamlessly while maintaining or even improving the quality, simplicity, choice, and value of energy services to customers.

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The Emerging Value Of Flexiwatts: The Broader Opportunity For Ders To Lower Grid Costs

Electric loads that demand flexibility shifts in time can be called flexiwatts—watts of demand that can be moved across the hours of a day or night according to economic or other signals. Importantly, flexiwatts can be used to provide a variety of grid services (see Table ES1). Customers have an increasing range of choices to meet their demand for electrical services beyond simply purchasing kilowatt-hours from the grid at the moment of consumption. Now they can also choose to generate their own electricity through distributed generation, use less electricity more productively (more-efficient end-use or negawatts), or shift the timing of consumption through demand flexibility (see Figure ES1). All four of these options need to be evaluated holistically to minimize cost and maximize value for both customers and the grid.

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Findings

Residential demand flexibility can avoid $9 billion per year of forecast U.S. grid investment costs— more than 10% of total national forecast needs—and avoid another $4 billion per year in annual energy production and ancillary service costs.

While our analysis focuses primarily on demand flexibility’s customer-facing value, the potential gridlevel cost savings from widespread demand flexibility deployment should not be ignored. Examining just two residential appliances—air conditioning and domestic water heating—shows that ~8% of U.S. peak demand could be reduced while maintaining comfort and service quality. Using industry-standard estimates of avoided costs, these peak demand savings can avoid $9 billion per year in traditional investments, including generation, transmission, and distribution. Additional costs of up to $3 billion per year can be avoided by controlling the timing of a small fraction of these appliances’ energy demands to optimize for hourly energy prices, and $1 billion per year from providing ancillary services to the grid. The total of $13 billion per year (see Figure ES2) is a conservative estimate of the economic potential of demand flexibility, because we analyze a narrow subset of flexible loads only in the residential sector, and we do not count several other benefit categories from flexibility that may add to the total value.

Demand flexibility offers substantial net bill savings of 10–40% annually for customers. Using current rates across the four scenarios analyzed, demand flexibility could offer customers net bill savings of 10–40%. Across all eligible customers in each analyzed utility service territory, the aggregate market size (net bill savings) for each scenario is $110–250 million per year (see Figure ES3). Just a handful of basic demand flexibility options—including air conditioning, domestic hot water heater timing, and electric vehicle charging—show significant capability to shift loads to lower-cost times (see Figure ES4), reduce peak demand (see Figure ES5), and increase solar PV on-site consumption (see Figure ES6). In Hawaii, electric dryer timing and battery energy storage also play a role in demand flexibility.

Utilities should see demand flexibility as a resource for grid cost reduction, but under retail rates unfavorable to rooftop PV, demand flexibility can instead hasten load defection by accelerating rooftop PV’s economics in the absence of net energy metering (NEM).

Some utilities and trade groups are considering or advocating for changes to traditional net energy metering arrangements that would compensate exported solar PV at a rate lower than the retail rate of purchased utility energy (similar to the avoided cost compensation case discussed above). We build on the analysis presented in RMI’s The Economics of Load Defection and show that, if export compensation for solar PV were eliminated or reduced to avoided cost compensation on a regional scale in the Northeast United States, DF could improve the economics of non-exporting solar PV, thus dramatically hastening load defection—the loss of utility sales and revenue to customer-sited rooftop PV (see Figure ES7).

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Implications

Demand flexibility represents a large, cost-effective, and largely untapped opportunity to reduce customer bills and grid costs. It can also give customers significant ability to protect the value proposition of rooftop PV and adapt to changing rate designs. Business models that are based on leveraging flexiwatts can be applied to as many as 65 million customers today that have access to existing opt-in granular rates, with no new regulation, technology, or policy required. Given the benefits, broad applicability, and cost-effectiveness, the widespread adoption of DF technology and business models should be a nearterm priority for stakeholders across the electricity sector.

Third-party innovators: pursue opportunities now to hone customer value proposition

Many different kinds of companies can capture the value of flexiwatts, including home energy management system providers, solar PV developers, demand response companies, and appliance manufacturers, among others. These innovators can take the following actions to capitalize on the demand flexibility opportunity:

1. Take advantage of opportunities that exist today to empower customers and offer products and services to complement or compete with traditional, bundled utility energy sales.

2. Offer the customer more than bill savings; recognize that customers will want flexibility technologies for reasons other than cost alone.

3. Pursue standardized and secure technology, integrated at the factory, in order to reduce costs and scale demand flexibility faster.

4. Partner with utilities to monetize demand flexibility in front of the meter, through the provision of additional services that reduce grid costs further.

Utilities: leverage well-designed rates to reduce grid costs

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Utilities of all types—vertically integrated, wires-only, retail providers, etc.—can capture demand flexibility’s grid value by taking the following steps:

1. Introduce and promote rates that reflect marginal costs, in order to ensure that customer bill reduction (and thus, utility revenue reduction) can also lead to meaningful grid cost decreases.

2. Consider flexiwatts as a resource for grid cost reduction, and not solely as a threat to revenues.

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3. Harness enabling technology and third-party innovation by coupling rate offerings with technology and new customer-facing business models that promote bill savings and grid cost reduction.

Regulators: promote flexiwatts as a least-cost solution to grid challenges

State regulators have a role to play in requiring utilities to consider and fully value demand flexibility as a lowcost resource that can reduce grid-level system costs and customer bills. Regulators should consider the following:

1. Recognize the cost advantage of demand flexibility, and require utilities to consider flexiwatts as a potentially lower-cost alternative to a subset of traditional grid infrastructure investment needs.

2. Encourage utilities to offer a variety of rates to promote customer choice, balancing the potential complexity of highly granular rates against the large value proposition for customers and the grid.

3. Encourage utilities to seek partnerships that couple rate design with technology and thirdparty innovators to provide customers with a simple, lower cost experience.

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QUICK NEWS, August 31: NEW FINANCE PLAN FOR GEOTHERMAL; SUN IN MAINE; CAN CA CLIMATE BILLS GET BY FOSSIL INTERESTS?

NEW FINANCE PLAN FOR GEOTHERMAL Geothermal Community Could Be a Game Changer

August 27, 2015 (RenewablesBiz)

“…[T]hermal service providers…[may be like solar leasing and] sell thousands of new homeowners on geothermal heating and cooling…[The key] is taking the highest cost of geothermal loop off the table: excavating and drilling to install the ground loop…In Orca Energy’s plan,] Orca owns (and maintains) the ground loop, while the other equipment, heat pumps and so on, are amortized over the 20-year home mortgage…[There] is little impact on their monthly mortgage, but ongoing savings on energy use for the life of the home…Orca meters the thermal BTU of the ground loop and charges [the homeowner] a rate that's lower than the local electrical rate, [creating as much as 30 percent lower heating or cooling bills…” click here for more

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SUN IN MAINE Solar advocates see bright opportunity in northern Maine

Anthony Brino, August 30, 2015 (BDN News)

“…[Counterintuitively,] northern Maine may be one of the best places on the East Coast to turn sunlight into electricity, and it can be affordable for the middle class…On average, across winter, spring, summer and fall, northern Maine gets 4.2 hours of daily usable solar radiation that can be converted into electricity. Mid-Atlantic states such as Connecticut, New York and Pennsylvania might be warmer, but they have more smog and less usable sunlight — about 3.5 hours on average…The cold also is an advantage…[because] silicon wafers and electrical conductors in solar panels thrive in the cold and run more efficiently in the winter, even though there are fewer hours of sunlight…According to Efficiency Maine, a 4.5-kilowatt (or 4,500-watt) photovoltaic system costs about $17,000 in total to purchase and install…[but] it’s a good investment for a long-term homeowner that almost certainly will pay off within 10 years…[and] is expected to [provide power for] 25 years…” click here for more

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CAN CA CLIMATE BILLS GET BY FOSSIL INTERESTS? Historic climate-change bills in California Legislature go down to the wire

Jessica Calefati, August 29, 2015 (San Jose Mercury News)

“With the deadline for lawmakers to finish their work less than two weeks away, Gov. Jerry Brown and state Senate leader Kevin de León are working feverishly to pass what they call the year's most important legislation…The bills, which would dramatically reduce the state's reliance on oil and help to combat climate change, have been praised by everyone from Pope Francis to President Barack Obama to the world's leading scientists…If enacted, the legislation would set international precedent and cement California's reputation as a leader in the fight against global warming…But standing in the way is one of Sacramento's most powerful lobbies, the oil and gas industry, which has spent millions of dollars on advertising that paints a dystopian vision of the future: an out-of-control bureaucracy that would have the power to ration gasoline, punish SUV owners and limit the number of miles Californians drive…After passing the Senate by a wide margin in June, the bills face a much tougher test in the Assembly, which is expected to take them up as early as this week…” click here for more

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Pictures Of Sea Level Rise

Clearly the ocean is getting too big for its beaches. From NASA

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Change And Be Changed

From a courageous new documentary based on a controversial book: The best chance to demand and build a better world? Yes. Change or be changed? No, that opportunity has passed. Now it is change AND be changed. From AtlanticFilmDotCom via YouTube

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Postcards From Hawaii's New Energy Struggle

Hawaii has set its sights on 100% renewables by 2045 and its leaders and people don’t believe the proposed $4.3 billion takeover of its utility will get the state there. Here’s why. From Institute for Local Self-Reliance via YouTube

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PROOF OF GLOBAL SEA LEVEL RISE FROM NASA

Nasa: sea levels rising as a result of human-caused climate change

27 August 2015 (NASA)

“Josh Willis of NASA explains the space agency’s announcement that a long-term satellite imaging study has shown a dramatic rise in sea levels due to climate change. He says the findings that sea levels worldwide rose an average of nearly 3 inches (8 cm) since 1992 could indicate how strongly impacted coastal populations will be in the coming century [an if, as he says, a cm of rise equals 3 feet of beach loss, 24 feet of beach loss has already occurred].” click here for more

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ISRAEL TURNS TO THE SUN

Israeli Solar Warms Up; The country has embraced technological innovation—except in renewable energy. Is that finally changing?

Daniel Gross, August 7, 2015 (Slate)

“…[After six years of development, the first utility-scale solar plant to be built in Israel went online last month. A 40-megawatt solar power plant, it is a joint venture of Arava Power and a subsidiary of Électricité de France. Though modern Israel has become known as ‘startup nation’ for the ability of its nascent tech firms to balloon to global scale in a matter of months and the country’s immense solar resources, the government-owned Israel Electric Corporation has preferred to rely on coal, natural gas, and diesel. Last year, Israel derived less than 2 percent of its power from renewable sources.] The reasons for this aversion to solar-energy innovation are very Israeli—nationalized ownership of significant resources, endemic bureaucracy, fractious politics, and a legacy of socialism…[But in] spite of the bureaucracy and the speed bumps, Israel’s desert is slowly beginning to bloom with silicon panels that help convert the sun’s rays into electrons. Arava Power’s plant won’t hold its title as Israel’s largest solar generating facility for long. Earlier this summer, construction on one of the long-delayed, 110-MW Ashelim plants began.” click here for more

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INDIA FIXES WIND

Wind forecast to help tap more power

U. Tejonmayam, August 28, 2015 (Times of India)

“Tamil Nadu has the enviable status of being one of the largest wind power-producing states; it also possesses more around 7,800MW installed capacity of this renewable power. Now to reap the most of this resource, the state is utilising a new wind power forecasting service…[Wind’s variability] can be rectified if the energy can be estimated beforehand for its effective management. The new prediction system developed by National Institute of Wind Energy (NIWE) in collaboration with Vortex Factoria De Calcul SL, a Spanish-based company, requires availability-based tariff (ABT) metres in wind energy pooling sub-stations. So far, these meters have been installed in 80 sub-stations in the state and by the end of this month another 40 sub-stations will have them…The system will provide the forecast every 15 minutes for up to 10 days in advance. This will help Tangedco in scheduling and dispatching electricity from wind turbine generators…” click here for more

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EU BACKS WIRELESS EV CHARGING PILOT

EU-funded project develops wireless recharging solutions for electric cars

2015 August 28 (Xinhua)

“The European Union-funded FASTINCHARGE [wireless electric vehicle recharging project aimed at making EVs] more appealing to consumers…[is] due for completion this year…[R]esearchers have completed the design of a new wireless charging station, with key features including simplicity of use, easy maintenance, accessibility and clear visual indications on how to position the car…The new station is also equipped to exchange charging data with the vehicle, including user ID, supplier ID, duration of charge and energy meter information, and provide communication and guidance throughout the charging process…The project also investigated en route wireless charging technologies, which have the potential to significantly increase vehicle range and reduce the size of on-board energy storage systems…The project team [is] running a series of demonstration tests of the panels in the northern French city of Douai…[to] assess the efficiency and viability of wireless charging, the benefits to EV users and the impact on the electric grid.” click here for more

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A WAY TO MAKE THE PARIS DEAL WORK BETTER

The sense in Republican climate-change nonsense

Stephen Stromberg, August 25, 2015 (Washington Post)

"Conservatives often insist that it’s pointless to cut climate change-causing greenhouse gas emissions: It would amount to unilateral economic disarmament; China and the rest of the world wouldn’t reduce pollution…This is a poor argument, mostly…It doesn’t consider the risks of not trying to fight climate change…But there’s still a nugget of wisdom buried in all the nonsense: As world negotiators meet in Paris later this year to construct a global emissions-cutting pact, they must recognize that countries will have incentives to lie and cheat the system, and they must agree on mechanisms to expose emissions-cutting fraud and other types of climate deceit…[ Perverse Effects of Carbon Markets… underscores this crucial point. Swedish researchers found that people in Russia and Ukraine took wanton advantage of a poorly implemented European emissions program…[T]he underlying lesson is a global one: You can’t just assume that various national and subnational officials will comply with their commitments in good faith…This will not be easy. The United States and Europeans will probably push hard for some kind of international emissions monitoring, review and verification at the Paris climate talks…Accountability can’t be a side issue in Paris…” click here for more

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COST OF NO CLIMATE: $44 TRILLION – CITIBANK

Cost of not acting on climate change $44 trillion: Citi

Anmar Frangoul, 18 August 2015 (CNBC)

“Up to $44 trillion could be going up in smoke if the world does not act on climate change, according to [ Energy Darwinism II: Why a Low Carbon Future Doesn't Have to Cost the Earth from CitiGroup, which forecasts] that spending on energy will hit around $200 trillion in the next 25 years…The study then examines two scenarios: one that Citi describe as an 'inaction'…and another that looks at what could happen if a low carbon, ‘different energy mix’ is pursued…[The central case in the report is that the costs in terms of lost (gross domestic product) GDP from not acting on climate change can be $44 trillion dollars by the time we get to 2060…[The report authors see December's crucial United Nations COP21 meeting in Paris] as hugely significant, with the aim of reaching an agreement to keep global warming below two degrees centigrade…[because] all of the players are arriving with positively aligned intentions, including the big emitters: the US and China...” click here for more

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SHALE GAS OUTPUT DROPS

EIA expects near-term decline in natural gas production in major shale regions

August 26, 2015 (U.S. Energy Information Administration)

“Natural gas production across all major shale regions in EIA's Drilling Productivity Report (DPR) is projected to decrease for the first time in September. Production from these seven shale regions reached a high in May at 45.6 billion cubic feet per day (Bcf/d) and is expected to decline to 44.9 Bcf/d in September. In each region, production from new wells is not large enough to offset production declines from existing, legacy wells…Given the substantial drop in rig counts since the fourth quarter of 2014 in each of the DPR regions and growing declines in production from legacy wells, productivity increases are less able to completely offset lower rig counts and legacy-well declines…Several external factors could affect the estimates, such as bad weather, shut-ins based on environmental or economic issues, variations in the quality and frequency of state production data, and infrastructure constraints. These factors are not accounted for in the DPR…” click here for more

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THE STATUS OF SELF-DRIVING CARS

Autonomous Vehicles; Advanced Driver Assistance Systems and the Evolution of Self-Driving Functionality: Global Market Analysis and Forecasts

3Q 2015 (Navigant Research)

“The first combinations of advanced driver assistance features, now available in some 2016 vehicle models, offer semi-autonomous driving under specific circumstances. Cars will soon have the ability to cruise on freeways and safely navigate traffic jams with minimal driver input…[because] it is now feasible to install the multiple sensors necessary for such capability…[M]ore comprehensive self-driving features will be brought to market by 2020…While more [technology] testing is still needed to develop robustness, the biggest practical hurdles to clear before the rollout of self-driving vehicles to the public are related to liability, regulation, and legislation. In the long term, though, autonomous vehicle technology has the potential to institute major change in personal mobility, particularly in large cities. According to Navigant Research, 85 million autonomous-capable vehicles are expected to be sold annually around the world by 2035…” click here for more

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ORIGINAL REPORTING: WHAT SUNEDISON'S BIG BUY INTO BATTERY STORAGE COULD OFFER

What SunEdison's big buy into battery storage could offer utilities; Inside the biggest global renewables developer’s acquisition of Solar Grid Storage

Herman K. Trabish, March 9, 2015 (Utility Dive)

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SunEdison, the world’s biggest developer of large-scale solar and wind projects, has acquired the assets of Solar Grid Storage, one of the most promising start-ups among energy storage providers.

That follows last year’s announcements of a gigawatt-scale battery factory to serve Tesla and SolarCity and Southern California Edison’s 261 MW storage capacity procurement. U.S. deployments in energy storage were up 40% in 2014 and are gathering a momentum that recalls the emergence of solar a few years ago.

“We got out in front and created a business model and got projects in the ground,” explained Solar Grid Storage (SGS) CEO Tom Leyden. “We now have data that shows a way to make the numbers work. And we intend to expand it.”

Leyden declined a prediction for what backing from SunEdison’s balance sheet will mean but noted IHS forecasts for 775 MW of grid connected photovoltaic (PV) solar plus storage globally by the end of this year and for a 40 GW cumulative installation of grid-connected energy storage in the U.S. by 2022.

The U.S. added almost 62 MW of energy storage in 2014 and is expected to add 220 MW in 2015, more than three times the 2014 installations, according to GTM Research.

“Like most solar companies, SunEdison had been looking at storage for the last year or so,” Leyden said. SGS was looking for money to ramp up operations and had several options when SunEdison approached last summer. The final deal structure was an asset transfer. “SunEdison bought everything. All the operating assets and the pipeline.”

Storage will make more of SunEdison’s 8.1 GW global pipeline of wind and solar projects grid-available. “Storage is a perfect complement to our business model,” explained SunEdison's Advanced Solutions General Manager Tim Derrick. “With this acquisition we have added the capability to pair energy storage with solar and wind projects, thereby creating more valuable projects."

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The breakthrough business model

Leyden and his team approached the storage business like they had the solar business earlier in their careers. They went looking for a viable market. They saw opportunity in the PJM frequency regulation market and stayed focused on it. “We got four projects in the ground,” Leyden said. “Three have solar attached.”

The breakthrough was that SGS gave the storage to the PV developers. “They could offer their customers emergency back-up power free because we derived revenues from bidding the excess capacity of the inverter into the PJM frequency regulation market,” Leyden explained.

In frequency regulation, power from the battery is used temporarily to balance the system and then returned to the battery. “The work is done by the inverter,” Leyden said. That requires a dual-use inverter to perform both the PV functions and the battery charge-discharge function. Two manufacturers, Princeton Power and DynaPower, supply the advanced inverters. “Conventional inverter companies have not previously provided this kind of inverter but they are all working on one now.”

SGS delivers a 10 foot by 20 foot container with inverter, control systems, safety devices, and “everything necessary to be a plug and play system,” Leyden said. “It replaces the standard inverter.”

SGS batteries use lithium ion phosphate chemistry. “We don’t anticipate using anything else,” Leyden said. “But there are other chemistries and technologies. We are technology agnostic. We are about deployment. If flywheels were the way to go, we would do flywheels. It is really about enhancing our solar and wind projects and bringing more value to customers and investors.”

After Superstorm Sandy, the PJM region’s heightened focus on energy response “put us on steroids,” Leyden said. “Buyers were interested and policymakers and regulators were pressured to make systems more resilient.”

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Markets

Selling frequency regulation is, however, a merchant operation. Leyden wants to open new opportunities for storage by including it into a viable product forSunEdison’s Terraform Power YeildCo.

“YieldCos are conservative instruments,” Leyden said. “We are working on a way to put our PV plus storage or wind plus storage projects into a form that offers the comfort they need. Someone, a hedge fund or an insurance company, needs to guarantee a floor price.

It is key to scalability. That is where solar companies are going.”

In markets where mandates require utilities to acquire storage, a lease payment agreement with a utility might adequately secure revenue that could be monetized through the Yieldco, he added.

Leyden expects to first work the PJM frequency regulation market and the California storage mandate for SunEdison. He is also interested in other grid operators like ERCOT, MISO, NE ISO, and NY ISO. As the utility sector evolves toward more distributed generation, he said, utilities can and should play a constructive role in the storage market.

“Very much like solar ten years ago, there are a lot of emerging battery markets and it will be creative chaos for a while because everyone wants a piece of the action,” Leyden said. “Market by market it will be different because storage can be used a lot of different ways.”

The key will be finding markets where the numbers work. “They are still relatively limited but we are just at the beginning of this and what happened in the solar industry is going to happen in storage. The prices are going to come down.”

The weighted average storage system price in 2014 was $2,064 per kW, according to GTM Research. But the cost depends on how the system is used and how much battery there is, Leyden said. For frequency regulation, “you don’t need a lot of battery. It is not an energy market, it is a power market.”

The SGS battery is about $1 per watt and, with the inverter and the balance of system, “we are seeing systems at between $1.20 and $2.50 per watt,” Leyden said. A “significant revenue opportunity” is necessary to justify adding that cost to a $2 per watt PV system, which is why storage is not yet widespread.

“When the costs come down, new markets will open up,” Leyen said. SunEdison’s balance sheet and project pipeline will make for volumes that will reduce the SGS costs for goods and capital. “A 30% price reduction is possible in the next couple of years and as much as a 50% to 60% reduction in the couple of years after that,” Leyden predicted. “Price is on a downward trajectory. Tesla’s gigafactory will drive prices down even more. Just the announcement of it drove prices down.”

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How utilities can play

Storage needs to be a part of the utility move into distributed generation because that is “the missing link” to much greater penetration of renewables on the grid, Leyden said. “We have spent a fair amount of time with utilities and we think they can play a constructive role.”

SGS has talked to Dominion, PSE&G, and all the utilities in PJM. There were also talks with New England utilities such as National Grid, United Illuminating, JCP&L, and Atlantic City Electric. “There are a lot of things they could do with batteries, like smoothing peak demand, providing volt-var support, helping with black start, and backing up substations,” Leyden said.

Regulated utilities see the opportunity to add such capabilities and are less concerned with cost because they can rate base storage, Leyden explained. Unregulated utilities like Constellation and NextEra want to seize the business opportunity.

“Utility executives definitely recognize change is coming and storage is part of their future,” Leyden said. “They may, though, have work to do internally because the utility culture is built on having central power plants, not distributed ones, and distributed generation with storage has new challenges.”

SGS got “fairly significant pushback” on PV plus storage from a New Jersey utility, he recalled. “There is no rational reason for it. It is just emotional.”

Utility engineers are often intrigued by storage as an elegant way to allow more renewables on overloaded circuits, Leyden said. “Atlantic City Electric was shutting down some of their circuits to solar because of concerns it would destabilize them but by adding storage that was solved.”

Aggregated residential solar and virtual storage

Leyden is also thinking about the residential solar market and SunEdison’s newly instituted residential solar division. Residential battery storage systems are expensive because their stored energy doesn’t have value except as little-used backup power. “We are working on aggregating residential and commercial systems into a big virtual storage asset and we hope to have that capability by the end of the year,” Leyden said.

For frequency regulation, the storage can be anywhere in a grid operator’s territory. “We can aggregate residential systems in New Jersey with a commercial system in Maryland for PJM. The more aggregated, the more frequency regulation we can market.”

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QUICK NEWS, August 26: NEW ENERGY READY TO TAKE CONTROL; THE PRESIDENT BOOSTS SOLAR; EV CHARGING ON THE GO

NEW ENERGY READY TO TAKE CONTROL Wind Energy Could Blow U.S. Coal Industry Away

Henry Hewitt, 23 August 2015 (OilPrice)

“…Wind leads solar energy in capacity installed as well as output (world solar capacity passed 200 GW this year); and other than a few welcome cases (so far) where PV comes in under 5 cents per kWh, wind is generally cheaper…[S]ome of the world’s industrial giants have not only taken a keen interest in wind energy but have also taken the lead in sticking turbines in the ground…Passing the 400 GW mark this year, world wind capacity already exceeds U.S. coal capacity and will likely pass natural gas power capacity in the U.S. this year. It topped U.S. nuclear capacity many years ago, and has now caught up worldwide…[W]ind not only can but will replace nuclear as a source of carbon free, risk free energy, with no fuel cost and no externalities…[The Old Guard will…[argue] wind is intermittent, so the capacity factor is far below that of coal, gas or nuclear…[but the] National Renewable Energy Laboratory (NREL) recently released data showing that the Capacity Factor (CF) for wind power can reach 65%, which is comparable to that of fossil fuel based generation…” click here for more

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THE PRESIDENT BOOSTS SOLAR Obama Flies to the Nevada Desert to Promote Solar Energy

Gardiner Harris, August 24, 2015 (NY Times)

“President Obama flew west into the blistering sun of this desert oasis…to speak with great hope about solar and other renewable forms of energy… The speech, at the National Clean Energy Summit, came as his administration announced a series of measures to encourage solar power construction, including making an additional $1 billion in loan guarantee authority available in a federal program for innovative versions of residential rooftop solar systems…With the nation’s electrical needs growing only modestly, executives in the renewable power industry are depending on electric utilities to retire their aging coal-fired power plants and replace them with renewable power sources. The administration’s power plan is expected to accelerate that process…” click here for more

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EV CHARGING ON THE GO England will test electric car charging lanes

Bianca Seidman, August 25, 2015 (CBS News)

“Some roads in England…could make electric vehicles a more feasible form of transportation if a new trial of wireless charging lanes is successful…The goal is to allow ultra-low emission vehicles to travel longer distances without the need to stop and charge…in a way that governments can afford…Later this year, Highways England will begin off-road tests of charging lanes for electric and hybrid vehicles. They will create mock roads built with charging coils under the pavement, which correspond to special receivers that will be fitted to electric vehicles. If the trials are successful after 18 months, the agency will conduct trials on working roadways. The UK government has committed £500 million ($784 million) over the next five years to advancing this technology…Similar projects are in progress in the United States…Highways England says that, in addition to testing the wireless and in-road charging solutions for electric vehicles, they are committed to installing plug-in electric charging stations every 20 miles on the highway.” click here for more

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TODAY’S STUDY: SOLAR THIS YEAR

Tracking the Sun VIII: The Installed Price of Residential and Non-Residential Photovoltaic Systems in the United States

Galen Barbosde and Naim Darghouth, August 2015 (Lawrence Berkeley National Laboratory)

Executive Summary

Now in its eighth edition, Lawrence Berkeley National Laboratory (LBNL)’s Tracking the Sun report series is dedicated to summarizing trends in the installed price of grid-connected solar photovoltaic (PV) systems in the United States. The present report focuses on residential and nonresidential systems installed through year-end 2014, with preliminary trends for the first half of 2015. As noted in the text box below, this year’s report incorporates a number of important changes and enhancements. Among those -changes, this year's report focuses solely on residential and nonresidential PV systems; data on utility-scale PV are reported in LBNL’s companion Utility-Scale Solar report series.

Installed pricing trends presented within this report derive primarily from project-level data reported to state agencies and utilities that administer PV incentive programs, solar renewable energy credit (SREC) registration systems, or interconnection processes. In total, data were collected for roughly 400,000 individual PV systems, representing 81% of all U.S. residential and non-residential PV capacity installed through 2014 and 62% of capacity installed in 2014, though a smaller subset of this data were used in analysis.

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Important to note is that the data analyzed within this report:

• Represent the up-front price paid by the PV system owner, prior to receipt of incentives

• Are self-reported data provided by PV installers to program administrators • Differ from the underlying cost borne by the developer and installer

• Are historical and therefore may not be indicative of prices for systems installed more recently or prices currently being quoted for prospective projects

• Exclude third-party owned (TPO) systems for which reported installed prices represent appraised values, but include TPO systems for which reported prices represent the sale price between an installation contractor and customer finance provider (see Text Box 2 within the main body of the report for further details)

Key findings from this year’s report are as follows, with all numerical results denoted in real 2014 dollars and DC watts:

Installed Prices Continued their Rapid Descent through 2014 and into 2015. National median installed prices in 2014 declined year-over-year by $0.4/W (9%) for residential systems, by $0.4/W (10%) for non-residential systems ≤500 kW, and by $0.7/W (21%) for non-residential systems >500 kW. Preliminary data for the first half of 2015 indicate that installed price declines have persisted into 2015 and are on pace to match those witnessed in recent years.

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Recent Installed Price Reductions Have Been Driven Primarily by Declines in Soft Costs. Installed price reductions over the 2008 to 2012 period were a steep drop in global prices for PV modules. Since then, however, module prices have generally flattened, while installed prices have continued to fall as a result of a steady decline in non-module costs. From 2013 to 2014 specifically, residential non-module costs fell by $0.4/W, representing virtually the entire year-over-year decline in total installed prices. Recent non-module cost declines can be partly attributed to reductions in inverter and racking equipment costs, but are primarily associated with reductions in PV soft costs, which include such items as marketing and customer acquisition, system design, installation labor, permitting and inspection costs, and installer margins. Soft cost reductions are partly due to steady increases in system size and module efficiency, though likely also reflect a broad and sustained emphasis within the industry and among policymakers on addressing soft costs.

Installed Price Declines Have Been Partially Offset by Falling Incentives. Cash incentives (i.e., rebates and performance-based incentives) provided through state and utility PV incentive programs have fallen substantially since their peak a decade ago. Depending on the particular program, reductions in cash incentives over the long-term equate to roughly 70% to 120% of the corresponding drop in installed prices. This trend is partly a response to installed price declines and the emergence of other forms of incentives, but it has also been a deliberate strategy by program administrators to provide a long-term signal to the industry to reduce costs, and is likely among the many drivers for recent declines in solar soft costs.

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National Median Installed Prices Are Relatively High Compared to Other Recent Benchmarks, Particularly for Residential and Smaller Non-Residential Systems. Across all systems in the data sample installed in 2014, the median installed price was $4.3/W for residential systems, $3.9/W for non-residential systems ≤500 kW in size, and $2.8/W for non-residential systems >500 kW. By comparison, a number of other recent benchmarks for PV system prices or costs range from $2.8/W to $4.5/W for residential systems, and from $1.7/W to $4.1/W for non-residential systems. Differences between national median prices and these other benchmarks reflect the diversity of underlying data sources, methodologies, and definitions. For example, national median prices are historical in nature, represent prices not costs, are heavily impacted by several large and relatively high-priced state markets, and in some instances may be subject to inconsistent reporting practices across installers. These national median prices presented in this report thus should not necessarily be taken as indicative of “typical” pricing in all contexts, and should not be considered equivalent to the underlying costs faced by installers.

Installed Prices in the United States Are Higher than in Most Other Major National PV Markets. Compared to median U.S. prices, installed prices reported for residential systems and nonresidential systems ≤500 kW in size are substantially lower in a number of other key solar markets – most notably Germany, China, and Australia. These pricing disparities are primarily attributable to differences in soft costs.

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Installed Prices Vary Widely Across Individual Projects. Although installed price distributions have generally narrowed over time, considerable pricing variability continues to persist. For example, among residential systems installed in 2014, roughly 20% of systems were priced below $3.5/W (the 20th percentile value), while 20% were priced above $5.3/W (80th percentile). Nonresidential systems ≤500 kW exhibit a similar spread, while the distribution for non-residential systems >500 kW is somewhat narrower. The potential underlying causes for this variability are numerous, including differences in project characteristics, installer characteristics, and local market or regulatory conditions.

Economies of Scale Occur Among Both Residential and Non-Residential Systems. For residential systems installed in 2014, median prices for systems in the 8-10 kW range are roughly 15% lower than for smaller 2-4 kW systems. Among non-residential systems installed in 2014, median installed prices for the largest class of systems >1,000 kW in size were 36% lower than for the smallest set of non-residential systems ≤10 kW. Even greater economies of scale may arise when progressing to utility-scale systems, which are outside the scope of this report.

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Installed Prices Differ Among States, with Relatively High Prices in Some Large State Markets. For residential systems installed in 2014, median installed prices range from a low of $3.4/W in Delaware and Texas to a high of $4.8/W in New York. Some of the largest state markets – California, Massachusetts, and New York – are relatively high-priced, which tends to pull overall U.S. median prices upward; pricing in most states is below the aggregate national median price. Cross-state installed pricing differences can reflect a wide assortment of factors, including installer competition and experience, retail rates and incentive levels, project characteristics particular to each region, labor costs, sales tax, and permitting and administrative processes.

Installed Prices Reported for Third-Party Owned Systems Are Generally Similar to Those for Customer-Owned Systems. This report does not evaluate lease terms or power purchase agreement (PPA) rates for TPO systems; however, it does include data on the dollar-per-watt installed price of TPO systems that are sold by installation contractors to non-integrated customer finance providers. Although prices for these TPO systems are not perfectly comparable to purchase prices paid for customer-owned systems, median prices for the two classes of systems are, in fact, quite similar, at least when comparing nationally. Within individual states, however, median prices for TPO and customer-owned systems can differ, in some cases substantially.

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Prices Vary Considerably Across Residential Installers Operating within the Same State. In examining four large residential markets (Arizona, California, Massachusetts, and New Jersey), installer-level median prices within each state differ by anywhere from $1.1/W to $1.4/W between the upper and lower 20th percentiles, suggesting a substantial level of heterogeneity in pricing behavior or underlying costs. Low-priced installers in these states – e.g., 20% of installers in Arizona have median prices below $3.0/W – can serve as a benchmark for what may be achievable in terms of near-term installed price reductions within the broader market. Interestingly, however, no obvious or consistent relationship is observed between installer volume and prices – i.e., highvolume installers are not associated with lower-priced systems.

Residential New Construction Offers Significant Installed Price Advantages Compared to Retrofit Applications. Within California, systems installed in residential new construction have been consistently lower-priced than those installed on existing homes, with a median differential of $0.7/W in 2014, despite the significantly smaller size and higher incidence of premium efficiency modules among new construction systems. If comparing among systems of similar size and module technology, the installed price of new construction systems was $1.4/W lower than for retrofits.

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Installed Prices Are Higher for Systems at Tax-Exempt Customer Sites than at For-Profit Commercial Sites. Tax-exempt site hosts include schools, government facilities, religious organizations, and non-profits, and these customers collectively represent a substantial share of the non-residential data sample. Systems at tax-exempt customer sites are consistently higher priced than similarly sized systems at for-profit commercial customer sites. In 2014, the median differential was roughly $0.3/W for systems ≤500 kW and $0.6/W for >500 kW systems. Higher prices at tax-exempt customer sites reflect potentially lower negotiating power and higher incidence of prevailing wage/union labor requirements, domestically manufactured components, and shade or parking structures.

Installed Prices Are Substantially Higher for Systems with High-Efficiency Modules. Roughly one-quarter of the 2014 systems in the data sample have module efficiencies greater than 18%, and installed prices for systems in this class have consistently been higher-priced than those with loweror mid-range module efficiencies (<18%). In 2014, the median differential was roughly $0.8/W within both the residential and ≤500 kW non-residential segments. These trends suggest that the price premium for high-efficiency modules in many cases has outweighed any offsetting reduction balance-of-system (BOS) costs associated with a smaller array footprint.

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Microinverters Have a Seemingly Small Effect on Installed Prices. Microinverters have made significant gains in market share in recent years, representing more than 35% of residential systems and roughly 20% of smaller (sub-500 kW) non-residential systems in the data sample installed in 2014. Microinverter costs are higher than standard string inverters, though the data suggest that the net impact on total system prices is smaller, potentially as a result of offsetting reductions in noninverter BOS and soft costs.

Installed Prices for Large Non-Residential Systems Vary with the Use of Tracking Equipment. Many of the large non-residential systems in the data sample have tracking equipment, including roughly 20% of systems installed in 2014. The median installed price of those systems was $0.4/W (15%) higher than fixed-tilt, ground-mounted systems and $0.5/W (19%) higher than roof-mounted projects. Although these pricing differentials are based on a relatively small underlying data sample, they are generally of a similar magnitude to the increased electricity generation associated with single-axis tracking equipment.

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QUICK NEWS, August 25: SOLAR CHEAPER THAN NAT GAS; WIND TO THE RESCUE; NUKE PLANT COSTS STILL RISING

SOLAR CHEAPER THAN NAT GAS SunEdison Solar Farm Beats Gas With Biggest Colorado Project

Chris Martin, August 20, 2015 (Bloomberg News)

SunEdison, the world’s biggest renewables developer, began construction in Colorado on the 156 MW Comanche solar installation. Its output will go to Xcel Energy subsidiary Public Service of Colorado (PSC), the state’s dominant electric utility. The project’s 25 year power purchase agreement (PPA) with PSC was won through a 2013 open solicitation. SunEdison’s undisclosed bid price beat bids for natural gas generation at $5.90 per million British thermal units (MMbtu) for 20 years and at $5.96 per MMbtu for 25 years. Natural gas was $2.71 on August 21 but forecasted by PSC to be over $6 by 2020. Record low prices for solar are coming in across the country. Austin Energy's most recent bid came in at under $40 per MWh (less than $0.04 per kWh). NV Energy signed a PPA for the 100 MW output of First Solar’s Playa Solar 2 installation at $0.0387 per kWh, which is thought to be the lowest rate for solar yet made public. click here for more

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WIND TO THE RESCUE A mighty optimistic wind estimate fuels EPA rule

Peter Behr, August 7, 2015 (E&E Publishing)

The Clean Power Plan relies on obtaining its 32% reduction in U.S. greenhouse gas emissions by 2030 through increasing to 28% the share of total U.S. power generation from wind and other renewables. Wind’s capability for meeting its share of that generation hinges on Congress renewing the $0.023 per kWh federal production tax credit (PTC). A recent National Renewable Energy Laboratory analysis showed that despite wind’s falling price, the tax incentive is vital to its growth. The EPA’s analysis shows wind can meet the CPP need without it. If the PTC is not renewed and wind’s growth falters, each state’s CPP implementation will have to find a way to replace it with natural gas, solar, energy efficiency and/or conservation. A Senate subcommittee recently passed a two-year extension of the PTC and its companion investment tax credit 23-3 but prospects in the full Senate are not promising for the $10.5 billion (over 10 years) budget item. click here for more

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NUKE PLANT COSTS STILL RISING Fitch: 'Failure' of new nuke construction means fewer plants

Matthew Bandyk, August 20, 2015 (SNL)

The under-construction Vogtle nuclear facility in Georgia and V.C. Summer nuclear facility in South Carolina are both about three years behind schedule and each is expected come in billions of dollars over their original budgets. These poor performances are expected to discourage further U.S. investment in nuclear power in the near term. The U.S. Energy Information Administration forecast of nuclear generation falling by 10,800 MW through 2020 could be understated because political pressure and the higher-than-expected cost of operations and maintenance is forcing plant retirements. Longer term hope for nuclear advocates comes from The EPA Clean Power Plan’s assignment of compliance to states that use new nuclear plants and existing facility upgrades that add new capacity. And the Department of Energy last year announced it would accept applications from nuclear developers for $12.5 billion in loan guarantees. click here for more

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TODAY’S STUDY: TOWARD A 21ST CENTURY ELECTRICITY SYSTEM IN CALIFORNIA

Toward A 21st Century Electricity System In California; A Joint Utility and Advanced Energy Industry Working Group Position Paper

Executive Summary

On February 25, 2015, Advanced Energy Economy Institute (AEEI) hosted a meeting of senior executives from advanced energy companies and California’s investor-owned utilities (IOUs). This California 21st Century Electricity System CEO Forum was an opportunity for energy industry leaders to come together to develop a common inventory of the drivers of industry change and to start to examine utility business models and regulatory concepts that can adapt to and thrive in the emerging energy market environment.

Out of that meeting came a desire by the participants to advance the ideas and concepts discussed at the CEO Forum. This document summarizes that effort. It presents a broad vision of how stakeholders in California can move forward together in a more integrated fashion to achieve the state’s ambitious and important energy and environmental policy objectives.

California’s portfolio of policies, statutes and regulatory actions, whether existing or proposed, has set the state on a path to significant de-carbonization of its energy sector. When coupled with broader industry and societal trends, a transformation of the grid is underway at both the wholesale and retail levels.

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A Vision of the Grid in 2030

The Working Group developed a collective vision for the grid in 2030 to guide its work. In this vision, California continues to be a world leader in the use of clean energy resources and the adoption of innovative technologies. The legislature, governor, principal regulatory agencies, utilities, generators, technology and service providers and other key stakeholders are aligned in working to meet the State’s overarching policy objectives in a cost-effective and efficient way while maintaining core values of reliability, safety, affordability and universal access. The roles and functions of the grid have changed, driven by changes in customer expectations, environmental and other policy objectives and the rapid advancement and deployment of enabling technologies. The utility business model has also evolved to accommodate these changes to enable a more integrated, “plug-and-play” electricity system.

Achieving the Vision

To achieve the vision, the Working Group identified three areas that must be pursued in parallel in order for an effective transition to occur:

1. Innovation in product and service delivery

2. System design and technology

3. Regulatory framework, incentives and revenue mechanisms

Innovation in Product and Service Delivery

While customers have historically had some tools to help them manage their electricity consumption, the options that have become available within the past several years have begun to change the role of customers from consumers to, in a growing number of cases, generators (including exporters of power at certain times). Customers now have more options to manage their energy costs and where their electricity comes from. These options include energy efficiency, demand response, distributed generation, electric vehicles, on-site batteries, control technology for air-conditioning or lighting, programmable controllable thermostats, and building energy management systems. In fact, many customers are employing multiple forms of these technologies. Enabled by these technologies, customers, on their own or working through their energy service provider(s), can also provide services to the grid in response to several types of grid conditions, so that supply and demand are more interactive than was previously possible and management of customer load becomes an asset for grid reliability and affordability.

In short, the information age has arrived in the energy sector and customers have an increasingly important role to play. With the expectation of policies for higher renewable energy and energy efficiency, and deeper greenhouse gas reductions, customer engagement will be critical for achieving these goals. Third-party companies, utilities and customers are expending significant capital to develop, provide and use products and services in this new age of energy information. Many third-party providers of various on-site generation and storage services have already been successful in developing novel ownership and financing models to expand their markets and are competing to offer innovative products and services both to utilities and their customers.

As a result of the changing role of the customer and the information that is now available, the relationship between central planning, utility planning and Distributed Energy Resources (DER)2 deployment is an area of active investigation. As part of this effort, utilities will need analytical constructs to determine the locational value (benefit-cost) of DER and customers will need innovative products and services to realize their ability to provide grid services. In addition, data, data access, privacy and security are becoming increasingly important.

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System Design and Technology

Meeting California’s energy and environmental policy goals requires an evolution in electricity system design and operation using advanced technology and software analytics. The 21st century grid includes significant amounts of utility-scale renewables, more holistic integration of DER with the grid, and increasing third-party solutions that together help to maximize value to customers. The grid must be designed to accommodate rapid evolution in available technologies as well as emerging technologies.

The grid architecture must consider the physical assets of the distribution grid including poles, wires, sensors, and customer devices as well as the communications, forecasting, control and other advanced algorithms that enable the collection of devices to work together. Utilities will need to increase investment in hardware and analytics, as well as to develop tools that optimize the contribution of customer-side resources.3 Regulators will need to facilitate this change by designing policies that support the necessary infrastructure investments, allow experimentation, and require the development of standards and open protocols to ensure interoperability and integration, while addressing cyber security. In addition, utilities and regulators need to recognize that certain types of grid equipment and infrastructure can no longer be amortized over 20-30 years due to the shorter technology lifecycle.

The growth of new DER interactions at the “grid edge” creates a much more complex operating environment for the distribution grid including two-way power flow, power production controlled by the customer, in addition to the utility, and unexpected variations in power quality. These conditions drive the need for greater visibility, digital intelligence (monitoring as well as predictive maintenance) and control as well as the ability to measure and manage power flow and power quality. Ideally, the very DER that is changing the grid environment can be utilized to optimize the grid. In essence, DER can serve the dual purpose of providing greater customer choice and control, and grid power quality and reliability benefiting both customers and utilities, provided that the necessary enabling technologies and adaptive regulatory frameworks are implemented.

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This environment is already being recognized on specific circuits and areas within California. Utilities and grid operators are in the process of adapting to it, with investments in grid modernization and modifications to traditional distribution planning processes.

A portfolio of enabling technologies will be necessary to support the envisioned products and services. The emerging capabilities of the 21st century electricity system include real-time granular system monitoring and visualization, failure prevention through predictive diagnostics, robust communications, advanced software applications such as outage management systems, advanced control systems such as advanced distribution management systems, advanced grid infrastructure such as distribution automation and advanced forecasting tools incorporating the capability of DER assets.

Regulatory Framework, Incentives, and Revenue Mechanisms

The current regulatory construct will be challenged to keep pace with changes that support the principles of universal service and how to equitably cover and share the costs of essential grid services, while also supporting individual customer-level options and the achievement of state policy objectives. There are several possible pathways, models and options that could be reviewed and evaluated for how they could be applied in California, covering utility organizational models, market operations/pricing models and potential future revenue models.

The California Public Utilities Commissions (CPUC) has already embarked on several parallel paths, via individual proceedings, to address a range of issues emerging from the changes taking place in the electricity sector. This has set the State of California on the path to achieving important state policy objectives and has also set the stage for the industry to evolve to a new structure. As the changes become more profound, it will become necessary to consider more fundamental changes, in particular on restructuring/aligning incentives to achieve the desired outcomes while maintaining the long-term viability of the utility. This should be done via an open and transparent process to consider all the options available. This would include:

• Identification of the regulatory issues that currently impede – or could enable – evolution from existing business models to new ones.

• An assessment of what is most appropriate for the regulated market versus the competitive market, and how the two would interact as the market evolves.

• A focus on regulatory process, in particular an assessment of how to best integrate/coordinate the various regulatory proceedings that are each addressing some aspects of the evolving industry structure into a comprehensive framework. This could help reduce the effort and time required to run all these proceedings and also lead to better results by considering issues more holistically.

The companies engaged in this effort encourage the CPUC as well as the California Energy Commission (CEC) to consider the above as they work to accelerate the transition to a high-performing electricity system in California for the 21st Century.

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Conclusions

California has been, and continues to be, a national and global leader in advancing energy efficiency, renewable resource development, greenhouse gas reduction, grid modernization, and new technology adoption. The continued deployment of low-carbon distributed energy resources, technological and financing innovation and rapidly changing customer needs and expectations support the need for a 21st century electricity system, and by starting with these ten recommendations, the State can continue to blaze a trail forward. Even as the state is set to achieve its 2020 goals, even more aggressive policy goals are being set for 2030 and beyond. These policies are changing not only the way that energy is delivered to customers, but also the way customers make decisions to consume or generate electricity with the attendant impacts on the grid. Electrification of transport using electric vehicles extends the implications of the changes taking place on the grid into the transportation sector that has traditionally been dominated by petroleum-based fuels.

A key enabler to achieving 21st century electricity system goals for the State of California is a set of policies that spur technological and market innovation along with a modern regulatory framework that recognizes the potential for new business models (at a company and industry level) to better align the incentives and opportunities for all actors to more effectively contribute to the achievement of these goals. At the same time, utilities will need to maintain safety, reliability, universal access and reasonable cost of service.

The transition to a more agile and flexible platform that supports high levels of DER, bi-directional services and differentiated customer options will impact all areas of the electricity system. Such a 21st century electricity system must accommodate a higher rate of technological change and incorporate that technology into existing, legacy systems. New market entrants have the potential to address new customer needs and develop products and services that also support the role of the utility. Utilities should be encouraged to participate in research and innovation and to partner with new market entrants.

Underlying the technical capabilities of the 21st Century electricity system are business process and workforce changes needed to ensure integrated planning and operations across generation, transmission and distribution. This will require a well-defined process and workforce strategy that accommodates shifts in resource availability/ planning, transformation of existing roles and creation of new system planning and operational roles, as well as field workforce transformation.

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To summarize, the Working Group offers these 10 key recommendations to help the State of California achieve a 21st Century Electricity System:

1. Develop a comprehensive framework that integrates/coordinates the existing regulatory proceedings

2. Restructure/align/create new incentives to achieve the desired outcomes while maintaining the long-term viability of the utility and recognizing the value of the grid

3. Develop new market structures that enable two-way market signals to allow customer participation

4. Encourage data exchange and circuit-level coordination of available grid and customer resources

5. Utilize standards and protocols, ideally drawing from National standards, to ensure interoperability of devices located on the utility side of the meter and on customer premises

6. Assess what is appropriate for the regulated vs. competitive market and how the two would interact as the market evolves

7. Encourage training of the workforce that will develop the skills needed for the 21st Century Electricity System

8. Accelerate the pace of regulatory review and allow utilities to take reasonable risks to encourage innovation and entrepreneurship and accelerate commercialization of new products and services

9. Examine the role of rate design in helping to achieve the long-run financial integrity of the grid as a platform

10. Examine the functionality and enabling technologies that will be integral to the distribution grid of the 21st century

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