Distributed Energy Resource Growth

In the U.S. power system's transformation, customers' traditional dependence on utilities is increasingly becoming a utility dependence on customers.

This reversal is driven by diminishing electricity sales caused in part by the rising reliability and affordability of customer-owned distributed energy resources (DER) and energy efficiency technologies. Forward-thinking utilities see billions of dollars in potential new revenue streams in customer demand for these retail market products. But while vendors like Sunrun and Tesla are seeing increasing business with their home solar and storage products, utilities face the challenge of reluctant, or "selectively engaged," customers. 

Over 40% of utility customers are considered selectively engaged because they are unlikely to respond to utilities' online and digital marketing, a January Smart Energy Consumer Collaborative report found. More engaged customers, motivated by environmental or pocketbook concerns,  are increasingly responding to new and traditional forms of utility messaging.

"We are moving away from an industry where the kWh was the commodity and the customer just paid the bill," SECC CEO Patty Durand told Utility Dive. "We are moving into a new world where the utility needs to know what customers value so it can offer them products and services and become their partner."

The monthly bill remains most customers' main contact with utilities, but most would like electricity providers to show them "choices that align with their personal priorities," an August 2018 SECC customer survey found. In response, many utilities are using new digital approaches to customer engagement.

Engaging customers at the retail level with products like smart thermostats and electric vehicle charging stations is expected to drive "at least one trillion dollars" of investment from utilities and other stakeholders in 2030, according to a July 2018 Navigant paper. This shift to retail could be "a billion-dollar market by 2030" for utilities and technology vendors.

To get their share of that opportunity, utilities must overcome the reluctance of the selectively engaged by taking them on a three-step journey:

• personalize messaging;
• provide useful information; and
• deliver customer benefits.

Capturing the new opportunity

The DER and energy efficiency products and services customers want "are increasingly restructuring power markets" and customers are the only stakeholders besides regulators "critical" to this transformation, according to a June 2018 Navigant industry survey.

But it is "the reality" that many customers have not yet been effectively engaged, Navigant Director Aida Hakirevic emailed Utility Dive. "Utilities are still smoothing out digital (or self-serve) customer journeys for basics such as starting or stopping service and outage communications."

More "sophistication" in customer engagement will be necessary, because "gone are the days of the monolithic ratepayer," the Navigant paper reported. But a paradigm shift can create new revenue streams from providing new retail products and services to a new generation of customers that already expects the access they get with Amazon, Netflix and Uber, it added.

"Utilities have catching up to do to meet those expectations," Hakirevic said. Both Google Director of Global Energy and Enterprise Partnerships Jeff Hamel, who focuses on customer engagement, and leading customer engagement technology provider Bidgely's CEO Abhay Gupta agreed.

To win customers' trust, "use data to convince them of the need and the potential savings," Gupta told Utility Dive. "Then tell them they can also get a rebate." 

Google is "leaning in" on identifying "moments that matter" when customers are making energy-related decisions, Hamel told Utility Dive. "That is when utilities can connect with them."

Utilities' traditional focus on safety, reliability and affordability will no longer be enough because their new customers will expect "sustainability, flexibility, autonomy and individualization," the July Navigant paper said. To achieve this, utilities will need to use "digital connectivity."

This can "unlock value" by bringing DER and energy efficiency technologies to homes and smart cities, the paper said. It can also create revenue streams from supplying smart charging infrastructure and electricity for transportation electrification and other new demands.

These assets' "sensors, communications capabilities and distributed computing capabilities" will deliver "a torrent of data," Navigant said. With it, utilities can "offer new products and services through sophisticated insights, and improve the operations of the grid."

Each engaged customer "is a resource for the utility business, and that resource has value to the electrical grid," Google's Hamel agreed. "We are talking about engagement because engagement equals value for the utility and for society."

To engage the newest generation of utility customers and achieve these objectives, utilities must "be obsessed with customers, data, and needs," the July Navigant paper stressed.

"Waiting for customers to come to the utility does not work," SECC Deputy Director Nathan Shannon told Utility Dive. Effective engagement requires personalized messages directed to identified customer segments through channels they prefer.

But SECC's survey found over 40% of utility customers cannot be segmented and reached by a Navigant-type approach that targets the digitally engaged, SECC's Durand said. Those customers also prefer bricks and mortar stores to shopping online and have not been engaged by their utilities' offerings.

The selectively engaged customer

Selectively engaged customers are "more likely to own a single-family home built before 2000" and "tend to be 45 or more years old," SECC reported. They have "average or below-average annual household incomes," typically below $75,000 annually, and "tend to not have a college degree."

They are not among SECC's "Green Champions" segment who respond to environmental messages through digital channels, SECC found. But the selectively engaged are also unlike the "Status Quo" segment because they are "moderately satisfied" rather than disdaining their utilities, and they have "taken steps toward being energy efficient."

But the selectively engaged do not "look to their utility for information" or "financing options" when an energy-related home upgrade is needed, SECC reported. And, like the "Technologically Cautious," "Savings Seekers," and "Movers and Shakers" segments, upgrades become a priority only when the opportunity for savings is made clear, SECC found.

The primary reasons these customers are not engaged are "it's too complicated" and "I don't have the time," Durand said. "And our research suggests the way around those pain points is making participation easier and barrier-free."

They can be engaged through a three-step journey, Durand added. Effective messaging through the right channels can turn the "on the couch" disengaged who have made no energy-related upgrades into "first steppers" making small, unplanned purchases. With effective approaches, they can become "energy investors" who make planned commitments to new technologies.

Reaching the selectively engaged

A common "easy and barrier-free" way to start selectively engaged customers on the journey are home lighting upgrades, Durand said. The offer can be made through in-store presentations or mailings. Education should be included, but lengthy forms requiring customer details should be avoided. Duquesne Light,  PPL Electric Utilities and FirstEnergy have had success with these programs.

PPL Electric Utilities has distributed more than 37,000 free energy efficiency kits through direct mail and community organizations with a 98% customer satisfaction rating, its spokesperson Joe Nixon told Utility Dive via email.

Duke Energy customers have expressed "unsolicited appreciation" for its free LED program, Michael Keller, Duke's customer insights and operations manager, told Utility Dive.

"There are first products, simple things like GE's smart LED lightbulb, that can begin the journey," Google's Hamel agreed. They can lead to the purchase of more advanced integrated devices, like smart thermostats.

Of the barrier-free ways of reaching selectively engaged customers, on-bill financing can be especially impactful, Durand said. "Energy efficiency upgrades like double-pane windows and attic insulation can be expensive and low- and middle-income customers often don't have that cash."

On-bill financing allows utilities to leverage their balance sheets to provide customers with funding to make home improvements, SECC reported. With the Pay As You Save (PAYS) strategy, the monthly bill payment can include the loan repayment, which can be less than the savings from the efficiency upgrades.

Over half of the selectively-engaged customers surveyed by SECC "expressed interest in on-bill financing if the interest rate is favorable," Durand said. "Zero-interest on-bill financing could allow customers to see the utility as a partner and incline them to look to the utility on other energy decisions, like smart thermostats, electric vehicles, rooftop solar or selecting a time of use rate plan."

Except for small-scale programs by electric cooperatives, on-bill financing is a little-used engagement approach, Durand said. 

"No investor-owned utility I know of has enrolled over 3% of members," Environmental and Energy Study Institute program director John-Michael Cross agreed.

Southern California Edison's (SCE) on-bill financing program for energy efficiency improvements has exceeded expectations, with 2,036 zero-interest loans for $78,671,824 and a default rate of less than 1%, SCE spokesperson Ron Gales emailed Utility Dive. It was designed to match the loan repayment amount to the bill savings. But it has not been used by more than 3% of SCE customers, he acknowledged.

"On-bill financing is an effective engagement strategy," Bidgely's Gupta said. "But it can be more effective if it is offered for programs that personalized data shows are valued by the customer."

Google's Hamel disagreed. "It has not gotten traction with utilities because the $50 price of a lighting product or a $150 thermostat do not justify the hurdles and friction it adds to the transaction," he said. "Other ways to help customers afford these products, like direct install programs and manufacturer-supported rebate programs, are bringing prices down so low customers don't need financing."

A utility on the journey

The Sacramento Municipal Utility District (SMUD) does not use the term selectively engaged, but SMUD Marketing Supervisor Jason Cassella immediately recognized the customer type.

SMUD has developed personalized digital communications and social media strategies, radio, TV, print ads and direct mail campaigns, Cassella told Utility Dive. "But we have point-of-purchase displays about our rebates in front of customers shopping at retail outlets, too."

SMUD prefers discounts and rebates to on-bill financing, but its success in engagement was demonstrated by 2018 awards from J.D. Power and Cogent Reports for customer satisfaction, Casella said. "Our holy grail is having personalized messages in the right channel at the right time, and we are constantly testing and adjusting our strategy to accomplish that."

Its engagement strategy matches SECC's journey. "Once a customer engages with us, we see it as an opportunity to engage more," Cassell said. "Depending on the product or service, we may circle back to let them know the impacts of their participation. We first use the channel they engaged with us through, but we might then use associated channels."

The three-step journey is critical, Bidgely's Gupta said. It begins with personal information obtained from a customer purchase or from a utility-initiated online or paper communication. The next step is educating the customer that other technologies can deliver significant returns on their investments.

The third step is a personalized offer of a product or service, Gupta said. "And making that offer without taking the first two steps is hitting your head against a wall."

Engagement and change

"There are a lot of ways to start simple and move the customer to seeing the utility as a partner and advisor," Durand said. "There will be a time when people go to their utilities for energy-related products and services the same way they go to Amazon."

They will be more engaged "partly in response to pressure on the planet from climate change, and partly because of pocketbook issues," Durand said. With 60 million households expected to use voice-enabled technologies by 2022, a potentially idle or random question about a bill can lead to a personalized response from the utility, an interaction about potential savings, and a purchase.

More and more utilities are using voice as an engagement channel, Google's Hamel agreed. But the ongoing challenge for incumbent utilities is to make clear their relevance to their customers, he added. "We value flipping a switch and having the lights come on. But utilities that succeed going forward will demonstrate to customers that they offer value beyond the core commodity of electrons."

Article top image credit: Tendril

Utilities can meet customer demand and reap new revenues by finding ways to deliver distributed energy resources (DER), but there is a more urgent reason for them to buy in.

At present growth rates, five types of DER — distributed solar, combined heat and power, smart thermostats, electric vehicles and battery storage — will provide enough cumulative capacity by the early 2020s to flatten power sector peak demand, according to 2018 data from GTM Research. Capitalizing on this growth of customer-owned generation through their unregulated subsidiaries, utility holding companies can transform their business, according to Boston Consulting Group (BCG).

"This growing but fragmented market represents a huge opportunity," a March 2019 BCG white paper reported. "With few DER market leaders so far, power companies that strike quickly" through unregulated subsidiaries "can rapidly realize a competitive edge."

The core regulated utility business of selling electrons "is already being eroded by DER growth and the resulting declining loads," BCG Partner and paper co-author Thomas Baker told Utility Dive. "Utilities need to look at the potential value streams in new DER opportunities because those that focus solely on central station fossil fuel generation will not survive."

Utilities are clearly beginning to see the opportunity and the need to seize it. What is not yet clear is whether utilities and DER providers can overcome the cultural differences between innovative startups and cautious institutions to work together effectively.

An unproven strategy

A utility buy-in on DER may be an idea whose time has come, but the best way to do it is far from clear.

Utility holding companies can form unregulated subsidiaries alongside their regulated utilities and use merger and acquisition (M&A) strategies to acquire established DER providers, Baker said. But "it remains to be proven that this M&A strategy will deliver success," he acknowledged.

Using M&A strategies "is not a new idea, but it may be a good idea for utilities," Raj Prabhu, CEO of Mercom Capital Group, which has provided clean energy market research and consulting since 2010, told Utility Dive.

"They can develop technologies on their own, but that has risk," he said. "The alternative is investing in technology providers, either through M&A or by funding a pilot. It is not yet clear which works best."

It is also not clear that DER providers and their customers will welcome utilities.

"If I were a utility shareholder, I certainly would want leadership to make these investments rather than ride last century's business model down in flames," Fortunat Mueller, co-founder of Revision Energy, a DER provider in Maine, New Hampshire and Massachusetts, emailed Utility Dive.

And utilities willing to compete "on a level playing field" are welcome, Mueller said. "But regulated utilities have monopoly thinking deeply embedded in their DNA, and will inevitably crowd out competitive market actors, which is not good for customers or for markets."

The best path for utilities

Utility leaders know their customers want DER, surveys of executives show. Strategic acquisition of DER providers is the surest way for them to deliver DER, according to BCG.

The DER market is "wide-open," BCG reported. About 75% of the roughly $80 billion in U.S. and EU market revenues come from companies other than the leading DER providers. In this "still immature and fragmented" marketplace, utilities can get "first-mover advantages and become dominant in a segment that promises to soon become as palatable to consumers as the traditional power segment."

For most utilities, "acquiring DER players that already have a market footprint is the only option that makes sense," BCG added. Things are changing too much and too fast for "homemade solutions" and most power companies "lack the capabilities" to market and deploy DER technologies.

Through M&A deals, utilities can acquire DER providers with "complementary offerings" that allow them to "aggressively grab market share."

In today's DER marketplace, many of the important innovators "are ripe for acquisition because they don't have the size or maturity to defend against an acquisition," BCG's Baker said. "And most DER providers would welcome an acquisition as an exit for investors at a profit that gives the DER company access to skill, technology and capital they often struggle to have."

Examples that appear to be working are the 2015 Duke Energy Renewables acquisitions of commercial-industrial (C&I) solar installer REC Solar and C&I energy management system provider Phoenix Energy Technologies. 

Duke acquired these companies "to gain knowledge of the DER space" and as a way to get "a foothold in this growing market," and they have "met our objectives," Duke spokesperson Jennifer Garber emailed Utility Dive. 

The distributed businesses have proven "complementary" to the unregulated division's utility-scale renewables business, Garber said. And they have "opened doors with new large corporate customers" to "new opportunities that may not have been available to us."  

Duke continues to look for new opportunities but is not planning further acquisitions, she added. "We believe we have the right portfolio for where and how we want to compete in the DER market."   

Minimal data is available to validate the profitability of M&A transactions in the DER space,  Mercom's Prabhu and BCG's Baker agreed. Once acquired, smaller companies tend to be folded into the larger companies' financials.

"Most DER acquisitions are less than three years old, which is not enough time to make the case" that they will be profitable, BCG's Baker said. But the value is not purely financial. Synergies should allow the acquired company to scale and lower costs through the holding company's balance sheet. And the holding company should gain an understanding of emerging technologies.

REC's partnership with Duke has delivered those synergies, including "better pricing for our parts and services by leveraging Duke Energy Renewables' economies of scale," REC Solar spokesperson Ann Kroll emailed Utility Dive. REC can also now provide "a wider set of solutions," including utility-scale renewables and solar-plus-storage, and can "recruit and retain" top tier personnel.

The best example of success in renewables acquisitions is NextEra Energy's transformation from a holding company for Florida Power and Light, Baker said. As much as 60% of its income now comes through deregulated investments in utility-scale renewables, transmission line development and publicly traded bonds.

But those are not DER acquisitions, they are acquisitions of large-scale renewables generation and the transmission projects to serve them, Mercom's Prabhu said.

"DER M&A is about acquiring new technologies" and it is "not yet clear" that M&A is the most cost-effective way for utilities to deliver new technologies to their customers, he added.

DER M&A

Prabhu offered some data to show the lack of clarity about DER M&A.

Distributed solar M&A deals "are increasing a little every year," Prabhu said. They went steadily up from 68 in 2016 to 82 in 2018, globally. Early 2019 data suggests this will continue.

But M&A deals in battery storage bobbed from 10 to 3 to 16 from 2016 to 2018. Smart grid technology M&As zoomed from 15 in 2016 to 27 in 2017, then flopped to 12 in 2018. In energy efficiency, deals fell steadily from 14 in 2016 to 7 in 2018.

These sectors are made up mostly of new and small companies and few are mature enough or valuable enough to be acquired, Prabhu said. He speculated that the M&A numbers in smart grid technologies and energy efficiency went down as M&As in battery storage increased because deals with potential in the first two areas were exhausted "just as battery companies became ripe for acquisition."

Utilities, like venture capital companies, rarely invest alone, but instead acquire technology providers with other utilities or private equity investors, Prabhu said. "They prefer spreading the risk."

An example is Energy Impact Partners, a multi-hundred million dollar fund created by a group of utilities in 2018, he said. It includes Southern Company, Xcel Energy and many others and has acquired 18 DER providers.

An alternative is to fund, or co-fund, a pilot project, Prabhu said. "Funding a pilot, in partnership with others, to see if the technology works, is low-risk and methodical. For utilities who see themselves as behind the curve, M&A might be a faster way to catch up."

Acquisition doesn't guarantee success, BCG's Baker acknowledged. "The DER market is incredibly competitive and immature and there are winning and losing business models."

The Hawaiian Electric Industries (HEI) plan to market distributed solar at the turn of this century was not a clear example of a winning or a losing business model, according to two people who participated. But it is a clear example of challenges utilities face in the DER space.

Reasons M&As might not work

Differences in culture and market perspectives between utilities and DER providers have often kept mergers from working smoothly. And there is evidence the trend toward greater regulatory oversight will make them more difficult.

Beginning in 2000, HEI added ProVision Technologies, an unregulated subsidiary, to enter the incipient off-grid distributed solar market on Hawaii's big island, according to Marco Mangelsdorf, who helped start the subsidiary. Mangelsdorf is now President of the private sector ProVision Solar, which he acquired from HEI and renamed in 2009.

"The plan was for ProVision to eventually expand into the Pacific Rim area," Mangelsdorf told Utility Dive. "That was before Hawaii offered net energy metering (NEM) in 2001 and before grid-tied solar picked up in Hawaii after 2008."

The subsidiary lost "over $200,000 per year, and after two years, HEI decided to cut its losses," Mangelsdorf recalled. "They did not seem to see that losing money can be part of the path to profitability for acquisitions."

Solar industry consultant Steve Burns was head of integrated resource planning for HEI's regulated utility on the big island and worked with ProVision. Solar in Hawaii "could have been different" if HEI had waited longer, he told Utility Dive. "It is a successful private company today, but it doesn't have the same financial backing. Big things could have been done."

Mangelsdorf's Provision Solar was recently underbid on a project in Hawaii by REC Solar, he said. "I need a certain profit margin to survive but REC has Duke's much larger balance sheet and can afford to make a leaner, meaner bid."

HEI may also learn with Pacific Current, its new deregulated venture, that regulators are now more cautious about the potential for anti-competitive abuses when a company has both regulated and unregulated subsidiaries, he added. "Now, a holding company can bury a subsidiary's losses for some time, but smaller installers may not let regulators give that kind of advantage to a utility in today's highly competitive solar market."

Former utility executive Burns likes the idea of utilities investing in distributed generation. But deals must be scrutinized by regulators because utility subsidiaries "probably have ten times the capital of their private sector competitors," he said. "Finding ways for utilities to participate can be a win-win, but it will be challenging to figure that out."

Another obstacle is that "smaller, newer DER providers with startup cultures may not plug in easily to the 120-year-old utility industry's organizational culture," BCG's Baker said. "That tension can hamper success."

And "there may be something structural about some DER businesses that prevents scaling, because national rooftop solar installers often do not always beat strong local installers," he added. Rooftop solar "may be more like the plumbing and roofing businesses" in that they can be more effective at a smaller scale. And the residential battery storage business "may be like rooftop solar when standardization makes it more plug and play."

Some pitfalls can be avoided. Before an acquisition, both parties should be clear about their goals and have a plan to integrate the DER provider's "innovative spirit" into the acquirer's more rigid culture, BCG said. "Putting a toe in the water of the DER market, as many large utilities and even oil and gas companies are doing, is unlikely to deliver sustainable success in the competitive DER segment."

The biggest obstacle may be the kind of opposition from incumbent private providers during the regulatory process which Mangelsdorf foresees in Hawaii for Pacific Currents.

Customers are better served by free DER market competition because it "leads to more dynamic markets, more creative solutions, and ultimately to superior customer value propositions," Revision Energy's Mueller said. Utilities have "the capital and expertise to move the market," but regulators must "protect markets from their unfair advantages."

The urgency

Until recently, dominant power market incumbents "could afford to be casual onlookers," BCG reported. "That wait-and-see period for large power companies has ended — perhaps sooner than anyone expected."

DER providers interviewed for this story agreed.

Rapid evolution has made DER technologies more capable at lower costs, and "power companies must drastically change their strategic calculus," BCG warned. DER disruption is coming, and M&A is "a weapon that's too powerful for smart, established power companies to ignore."

Article top image credit: Depositphotos

Where do today's load management activities - including demand response, energy efficiency, and renewable energy programs - fit in a distributed energy resource (DER) future of non-wires alternatives, storage and more? A recent publication titled “The Future of Distributed Energy Resources: A PLMA Practitioner Perspectives^TM Compendium” details eight industry initiatives where leading utilities are partnering with their customers and allies to demonstrate the path to a more integrated approach to DERs.

Peak Load Management Alliance (PLMA) members, utility companies, consultants, and vendors have deep experience in delivering practical solutions to the operational requirement to balance resources and loads. And while the first 100 years of the energy industry was focused on matching resources (generation) to loads, the next several decades will be focused on flexible loads efficiently meeting generation output at both the Transmission system and Distribution feeder level, incorporating renewable, distributed and intermittent resources. We are moving into the realm of dynamic management of the system every day. The last decade has seen a rapid increase in behind-the-meter solar installations; recent advances in battery and thermal storage, electric vehicle (EV) charging, and load flexibility resources are also indicators of the growing importance of distributed energy resources (DERs).

The PLMA community has a history of sharing experiences that enable others in the industry to understand, learn, and embrace industry change. In keeping with this mission, PLMA asked its membership to share case studies about current DER activities and projects. The initiatives detailed in the Compendium are:

• Planning/Foundational Category – Defined as those utilities taking bold steps to leapfrog pilots/technology straight to integrative planning and procuring, and change management.
  • Hawaiian Electric's Integrated Grid Planning, Hawaiian Electric Company
  • Distributed Resource & Flexible Load Study, Portland General Electric and Navigant
  • Integrating DER Planning, Research and Program Development, Tacoma Power
• “DR Plus” Category – Defined as customer-sited assets (with or without the involvement of an aggregator) to monetize DER operations for utility/grid benefits to a growing spectrum of network problems.
  • Deriving New Wholesale Market Revenue Opportunities and Maximizing Customer Utility Savings with Behind-the-Meter Distributed Energy Resources, Center for Sustainable Energy, Tesla, Conectric Networks, and Olivine
  • Expanding National Grid’s ConnectedSolutions Program to Include Energy Storage, Sunrun, EnergyHub, and National Grid
• Microgrids Category – Defined as customer-sited assets that have great degrees of flexibility and opportunity for monetization.
  • Microgrid Enables Military Facility to Participate in Utility Services, Eaton
  • Energy Storage and Microgrid Performance in Non-Wires Solutions and Other Demand Management Programs, Enel X
• International Category
  • First Movers in DER in Colombia, U.S. Energy Association

If management is asking "where do today's load management activities (including DR, EE, and renewable energy programs) fit in a distributed energy resource (DER) future?" the eight case studies in the Compendium offer a glimpse into the future that is unfolding today. If imitation is the sincerest form of flattery, then now is the time to embrace progress through plagiarism. Here, PLMA members provide the blueprints for utilities, regulators and service providers to follow. Read the Compendium at www.peakload.org/plma-publishes-future-of-der-compendium.

Massachusetts is a leader in the deployment of distributed energy storage in America, due to forward-thinking legislative approaches and other measures aimed at unlocking the full potential of the resource, analysts told Utility Dive.

The state, which is part of ISO New England (ISO-NE), recently became the first in the nation to allow behind-the-meter (BTM) energy storage to qualify for energy efficiency incentives. But the biggest boost to storage deployment in the state came when regulators decided to include storage resources in a new solar incentive program, Solar Massachusetts Renewable Target (SMART).

“Solar projects that participate under our SMART program are eligible to get an additional compensation rate if they pair with energy storage. You get more money if you pair with storage. The bigger the storage is and the longer duration it is, the more money you get,” Michael Judge, renewable energy division director of the state's Department of Energy Resources (DOER), told Utility Dive.

The policy allowed Sunrun to bid into ISO-NE's capacity market with 20 MW of aggregated BTM solar-plus-storage.

First of its kind

As a developer, Sunrun has reaped the benefits of Massachusetts’ aggressive push to expand energy storage deployment. The California-based renewable energy developer earlier this year set a new benchmark when ISO-NE accepted its bid for the 2022-2023 capacity market auction.

The success of Sunrun’s bid was a combination of strong state level policies and favorable wholesale market pathways, Christopher Rauscher, the company's director for policy and storage market strategy, told Utility Dive.

“If we didn't have that rock solid foundation for residential solar, we would not have been able to add on the storage in aggregate and fit into the market. That's really what unlocked this at the state level,” he said. “The New England system operator, they have market access rules that are much more conducive to residential demand side resources than any other market in the country.”

Similar to Massachusetts, other ISO-NE markets, including Vermont, New Hampshire and Rhode Island have policies to encourage the development of residential solar and energy storage. Sunrun anticipates that the contract’s 20 MWs of capacity will be met with roughly 5,000 homes featuring onsite solar-plus-storage, which will be tied together through software to create a dispatchable resource for the system operator.

“It’s super exciting because we were competing head-to-head with traditional centralized fossil fuel resources, like a natural gas peaker plant and an oil plant. And we were able to fit in and win based on price. For us, we really see this as a paradigm shift and a signal of where the energy infrastructure is going to be heading in the future,” Rauscher said.

In addition to providing capacity generation, Sunrun’s bid will increase grid resilience and lower prices for everyone in the market region. All 5,000 homes will be set up to provide indefinite backup power, should the grid go down due to storms or other causes, Rauscher explained.

“It definitely brings an entirely new resiliency component that a natural gas plant, coal plant, or even a solar array off in a field cannot bring,” he said.

Furthermore, the increase in distributed solar means a lower peak load, which in turn keeps the overall amount of resources that a system operator has to secure down. This not only lowered the clearing price in the capacity market auction, but ultimately lowered prices for everyone in the region, according to Sunrun.

Massachusetts state officials welcomed ISO-NE’s decision to award Sunrun with the capacity contract. In order for the state to reach its renewable energy and climate goals, there needs to be an expansion in the pairing of intermittent resources with battery technology, DOER said.

“We're excited to see what Sunrun did and we expect to see a lot more opportunities for that going forward. And we really need to see more of that happening going forward, if we want to achieve our long term goals,” Judge said.

Building a foundation for residential solar

Batteries are now eligible for a much larger piece of Massachusetts' $620 million annual energy efficiency budget. The American Council for an Energy-Efficient Economy (ACEEE) in October named the state the most energy efficient in the nation for the eighth consecutive year. To reach that status, a few years ago, the state began efforts to define storage as a resource.

Massachusetts started looking into the benefits of energy storage in 2015, launching the Energy Storage Initiative. The initiative included a comprehensive study and provided funding for demonstration projects, authorizing the DOER to establish a statewide energy storage target, Judge said.

The state went from less than 2 MW of energy storage to setting a target of 200 MWh by 2020 nearly two years ago, although that now pales in comparison to storage targets set by other states such as New York and New Jersey. Massachusetts' goal was extended to 1 GW last August.

The state continues to craft policy to spur storage deployment and enable full regional participation in residential, commercial and wholesale energy markets.

In 2017, DOER and the Massachusetts Clean Energy Center (MassCEC) teamed up to launch the Advancing Commonwealth Energy Storage (ACES) initiative, which awarded $20 million in grants to 25 energy storage projects, including commercial projects, utilities, hospitals and educational institutions.

The Massachusetts Department of Public Utilities (DPU) in February issued two orders to complement these ongoing energy storage initiatives by specifying net metering requirements for solar-plus-storage facilities and clarifying capacity ownership rights of solar-plus-storage projects.

The orders addressed concerns raised by developers that storage deployment at existing or new solar facilities might negatively impact the economics of those projects. The policies were not developed to the extent they need ed to be for storage to take off, Zachary Gerson, an attorney with Foley Hoag, told Utility Dive last year.

“Now that there's clarity that you can pair those two resources, and there's a path forward to obtaining the capacity rights to both, having that clarity should unlock the ability for people that are looking at solar-plus-storage, or wind-plus-storage or whatever, to move forward with the confidence that they can then monetize those revenue streams in the markets, and that they will be able to continue to net meter if and when that’s applicable,” Judge said.

Continuing to spur storage deployment

Last August, Massachusetts Gov. Charlie Baker, R,  signed An Act to Advance Clean Energy, which includes raising the energy storage target to 1 GW by 2025.

“In our view, the Clean Peak Standard and storage deployment target initiatives put forward by the House and Senate are complementary and critical to ensuring the Commonwealth maintains its position as a leader among states in breaking down the hurdles to energy storage deployment, attracting industry jobs, and achieving the Commonwealth’s ambitious energy and environmental goals,” the Energy Storage Association (ESA) said in a statement.

The Clean Peak Standard, which is currently under development, will be designed to provide incentives to clean energy technologies that can supply electricity or reduce demand during seasonal peak demand periods, DOER said.

“That could be a really big opportunity for energy storage, particularly energy storage that doesn't qualify for the SMART program to receive additional compensation for the value it provides in terms of shifting peak energy use,” Judge said. “Charging energy during periods of low demand, discharging during periods of high demand and flattening out that load curve .... becomes a bigger and bigger challenge as you have more solar and other intermittent renewables on the grid."

Massachusetts’ push to become a leader in storage deployment is not surprising given some of the state’s energy challenges.

“[Energy storage] makes sense for Massachusetts, because [of] some of the specific needs of the New England system in general, and Massachusetts specifically, because they have challenges with capacity. They are trying to figure out how to retire several traditional power plants, they have trouble building new transmission lines, and energy storage is obviously a potential aid or solution to a lot of those issues,” Eric Hittinger, public policy professor at the Rochester Institute of Technology, told Utility Dive.

Hittinger says the commonwealth also is using energy storage as a tool to support local manufacturers and developers, not unlike what Germany did when it became an early adopter of solar.

“Massachusetts is doing things that are maybe marginally cost effective today, but what they're really doing is investing in the future of an entire industry that will pay dividends out into the future. Just like solar might have been 10 or 15 years ago. It wasn't really a good investment,” he said.

The ESA said in a 2017 white paper that market forces will drive the deployment of more than 35 GW of new energy storage systems in the U.S. by 2025, and many states will look to Massachusetts for how to set their regulatory framework.

Article top image credit: Flickr user Tony Fischer

Just in time for the holidays, New Hampshire has given U.S. utilities a template for a groundbreaking utility-owned, customer-sited battery energy storage pilot.

Liberty Utilities has proposed a pilot that will initiate one of the most ambitious tests of a utility's ability to use behind-the-meter battery storage systems. A settlement that will move the 12-month proceeding forward was agreed to Nov. 19 by environmental and consumer advocates.

Because it would be only the second regulator-approved program for utility ownership of behind the meter resources in the country, third-party solar-plus-storage installers Sunrun and ReVision Energy did not sign on to the final settlement. But, appeased by the promise of a major role in the program's phase two, which would be one of the first in the U.S. to include private sector participation alongside the utility, they elected not to oppose it.

"The utility's insistence on owning batteries makes it an outlier nationally, but the program as a whole puts Liberty at the cutting-edge on the battery use case," Sunrun Director for Policy and Storage Market Strategy Chris Rauscher told Utility Dive.

Many investor-owned utilities are using batteries to shave peak demand, provide grid services and make utility systems more flexible. But those projects are subcontracted to third-party providers.

Stakeholders in New Hampshire's DE 17-189 proceeding are no longer leaving battery storage to the private sector.

With private sector and utility participants accepting compromises to the original proposal made by Liberty in December 2017, the New Hampshire Public Utilities Commission (NHPUC) is expected to approve the settlement after post-Thanksgiving hearings. Then, Liberty must demonstrate it can cut peak system demand and deliver a positive net present value (NPV) to its customers.

If it can, opportunities may open up for bigger accomplishments in grid modernization and other forward-looking NHPUC dockets.

The settlement

In the pilot's first phase, Liberty Utilities will offer 200 Tesla Powerwalls. Each participant takes two batteries and controller software at a one-time, upfront installed fee of $2,433, or a ten-year $25/month charge. The retail installed price would be $16,500, Liberty Senior Rates and Regulatory Affairs Analyst Heather Tebbetts told Utility Dive. 

Vermont's Green Mountain Power (GMP) currently has the only major U.S. utility-owned, customer-sited battery storage pilot. Its 2,000 Tesla Powerwalls went to customers at a one-time $1,500 or monthly $15 fee, and a second program will be deployed "soon," GMP spokesperson Kristin Kelly emailed Utility Dive.

The higher-priced Liberty pilot includes features absent from the GMP program. Most significantly, the New Hampshire settlement provides for a second phase, in which Liberty can add up to 300 batteries and third parties can install up to 500, according to Tebbetts' agreement summary. But phase two can only proceed if Liberty shows it can cost-effectively reduce system peak demand with customer-sited batteries.

The original proposal's $1,000 or $10/month fee was increased because NHPUC staff "was adamant the program's NPV be positive so it will not increase rates," Tebbetts said.

New Hampshire code allows the utility cost recovery for its expenditures, but because the fee to customers is still far below the retail installed price of the batteries, NHPUC analysts insisted in their testimony on a "conservative" approach to the pilot's cost-benefit assessment.

Agreeing on a positive NPV was "the longest and most difficult part of getting to the settlement," Donald Kreis, the head of the state's Office of Consumer Advocate, told Utility Dive. "But it shows the pilot will not cause higher rates for either participants or non-participants."

NHPUC concluded the 15-year pilot will provide over $800,000 in net benefits to all customers and an NPV "estimated at $8,470," Tebbetts reported.

The battery storage systems' controllers will allow Liberty access when it anticipates system demand will peak. Up to four times per month, the utility can give participants a one-day notice and discharge their stored electricity to avoid high charges from system operators.

There was doubt from NHPUC staff about whether Liberty could accurately identify the peak demand a day in advance, according to Tebbetts and Birchard. The agreement allows for "upward and downward adjustments to the return on equity," depending on Liberty's success. GMP has predicted the regional system peak with 100% accuracy and it has had "about 85% accuracy" in identifying the local peak, according to Kelly.

"There will be a learning curve in analyzing our data and predicting peak demand accurately," Tebbetts acknowledged. "The challenge will be notifying customers a full day before the peak demand event."

The most widely endorsed program feature is the time-of-use (TOU) rate required of participating customers, because its price signals to battery owners will be the most significant customer-facing advance over GMP's program, Tebbetts said.

Peak rate prices will vary according to demand shifts. By adapting their behaviors, participants can reduce their bills by shifting activity to low-priced time periods and using stored low-priced generation during higher-priced periods.

Typically, batteries will be charged nightly by the utility, when rates are lowest, and used by the utility on behalf of customers the next day, when rates are highest, according to Tebbets. Outside the pre-announced peak demand periods, customers will be able to make their own decisions about the stored power.

The TOU plan was meticulously based on "cost causation," according to testimony from former NHPUC commissioner Clifton Below and Office of Consumer Advocate consultant Lon Huber, who co-designed it. The plan is "a progression" from flat rates to "more granular" rates that reflect "strong underlying temporal differences in cost drivers."

A "perfect rate" matched precisely to system cost would require "dynamic pricing, advanced demand price signals and identifying peak events," Huber told Utility Dive. The Liberty pilot TOU rate is a compromise that gives "price signals the customer can manage while requiring the utility to manage the more complex system peaks."

Phase two will begin when the utility shows it can predict 75% or more of its system peaks and reduce system and customer costs. It can then begin adding 300 batteries and working with private sector providers to develop a 2.5 MW "Bring Your Own Device" (BYOD) program with up to 500 third party-managed, customer-sited batteries.   

BYOD

Only third-party battery system aggregators capable of dispatching stored electricity from dispersed systems to meet the utility's peak demand without a signal from Liberty are eligible for the pilot's first phase. None have indicated an interest in participating until they can rely on the utility to predict the peak in the second phase.

Within four months of commission approval of the settlement, a stakeholder working group will propose a BYOD program in which aggregators capable of dispatching with Liberty's signal can participate.

The settlement requires the working group to begin with an open call for input from aggregators. The final commission-approved program will begin with a competitive request for proposals (RFP) through which the utility will select aggregators to work with.

The initial Liberty proposal was "fundamentally flawed" because it did not include private sector participation, according to docket testimony on behalf of solar and storage groups. In accepting the final settlement's BYOD program, "the utility deserves credit for recognizing the behind-the-meter storage opportunity," Sunrun's Rauscher said.

Having both BYOD and utility-led programs "will make this pilot a more valuable experiment because it gives customers more choice," Office of Consumer Advocate's Kreis said.

The key reason private sector providers should be included is that their core competency is selling, installing and managing customer-sited resources, and utilities know their system well enough to accurately predict peak, Rauscher said. "The future should be a partnership between those core competencies."

A BYOD program offers several other advantages, he added, including relieving ratepayers of investment risk, adding solar customers and offering more flexibility.

Both Rauscher and New Hampshire Sustainable Energy Association Executive Director Madeleine Mineau approved of Liberty using the pilot to better understand the impacts of customer-sited DER on its distribution system.

But the settlement could have included the BYOD program in phase one, allowing customers more choice, Mineau said.

It is not clear how the new TOU rate will play out, Rauscher said. "It is ultimately the way forward, but the sales conversation at the kitchen table is much tougher if you are trying to explain both a new rate and a new technology. Getting customer education right will be critical," Mineau added.

And this pilot is only "a first step," she said. "Stakeholders are waiting for the grid modernization docket to move forward and there is ongoing work in the net energy metering successor tariff docket. The hope is that this pilot and those dockets will move towards a more progressive environment for DER."

The path forward

This pilot "is way out ahead of anything bigger utilities are doing in bigger states, but a trend is emerging, and we expect the majority of New England utilities to have BYOD programs by the end of 2019," Rauscher said. Designing Liberty's phase two will be challenging, "but this commission and these docket participants ... are some of the sharpest we have worked with and they will get it right."

The initial proposal to test utility-owned, customer-sited storage as a non-wires alternative (NWA) to distribution system infrastructure investment was eliminated, but the settlement requires Liberty to include a detailed distribution system assessment in its 2019 least-cost integrated resource plan.

"That transparency will allow third parties to see where they can develop lower cost resources that can be aggregated into an NWA," Conservation Law Foundation's Birchard said. "It would be valuable for other utilities to provide that kind of information."

Despite minimal public outreach, Tebbetts already has a waiting list of over 70 interested customers for the pilot's first phase. "We want to see how customers engage with us, how the technology works and whether we want to be behind the meter in the future," she said.

This could be a model for other utilities in New England, but "it is not yet clear to us that there will be both utility-led and BYOD programs over the longer term," she added. "That is one of the things we expect to learn from this pilot."

Stakeholders will begin preparing phase 2 as soon as the pilot is approved and Liberty "has demonstrated it can accurately predict and address peak demand," Birchard said.

A critical subject to be determined in phase two is compensation to participants and aggregators in the BYOD program, she added. Much of that outcome will depend on proposals made in response to the competitive RFP to be designed by the stakeholder working group.

In this settlement, "the utility has shown the path forward and opened doors to third parties and innovation," Birchard said. "The settlement also shows stakeholders can agree on difficult questions dividing utilities and third parties by focusing on sharing access and serving customers."

Article top image credit: Twitter user Tom Randall

U.S. installed solar capacity grew by about a third from 2015 through 2018, but solar policy actions grew by over 50%, according to two recent reports.

In particular, there has been increased policy action in two critical areas: developing more equitable solar compensation and establishing growing community solar programs.

As the solar market continues to grow — estimated to reach 4.3 GW of new utility-scale solar capacity and 3.9 GW of new distributed solar capacity by the end of 2019 — its perceived threat to the utility business model is producing new debates about how to make solar work better for all power sector stakeholders.

"The utility industry continues to react to the low cost and popularity of solar and storage devices with efforts across many jurisdictions to question the benefits," former Maine utility commissioner David Littell, now a principal at the Regulatory Assistance Project, told Utility Dive.

The changes that come with solar and storage are intimidating for utility executives and engineers because they are complicated, destabilize revenue and threaten system reliability, he added. "But they need to realize the world is more complicated."

"Wanting to manage cost is not the same as opposing solar," National Grid Director of Energy and Environmental Policy Tim Roughan told Utility Dive. "Solar should be priced so we can afford to do lots of it for a long time instead of increasing bills so much that no more solar gets built. But these policy debates are not leading to managing the cost or to a new tariff that works."

Some see policy debates as the key to progress. "Every energy sector market is the result of policy debates by nerds in beige rooms who created rules to open up competition," Western Resources Advocates (WRA) Clean Energy Program Deputy Director Erin Overturf told Utility Dive.

"A lot of meticulous and thoughtful work went into creating today's solar policy," she added. "It allowed us to build a solar market that drove prices down. And now we are working on new, more complicated policies to expand that market's impact."

Solar policy evolution

State-level distributed solar policy actions grew from approximately 175 in 2015 to 264 in 2018, according to the annual solar policy review released in January by the North Carolina Clean Energy Technology Center (NCCETC).

Policy actions on community solar, compensation debates and actions on controversial fixed, demand and solar-only charges all remain at the forefront of solar policy debates, according to the report.

With nearly every state now engaged in solar policy, the Center expects "even more activity in 2019," NCCETC Senior Policy Research Manager and report lead author Autumn Proudlove told Utility Dive. "The common thread is increasing complexity, and that complexity will lead to more policy work."

Only "a handful of states" had compensation debates focused on a successor tariff to replace net energy metering (NEM) in 2015, she said. Now, the "entire country" seems to be moving toward a more complex tariff aimed at supporting solar growth but also at protecting non-solar owners from a disproportionate cost burden.

Compensation reforms include proposals for fixed, demand and solar-only charges, Proudlove said. Proposed fixed charge increases and solar charges are not succeeding, but three demand charges were approved in 2018.

There are also complicated, largely unresolved debates over how to recognize the values of solar generation based on when and where it is delivered, and whether compensation should be lower during peak demand periods or more congested places on the grid. 

In addition, there have been 19 community solar policies passed since 2010, turning the programs "from something fairly hypothetical to something very real," Proudlove said. "Most installed community solar capacity is in states with those enabling policies."

By 2023, "30% of annual non-residential installations will be community solar projects," NCCETC reported. And policy has accelerated, with actions quadrupling from 2015 to 2018.

Newer community solar policies often have more "complicated objectives and complex financial structures," Proudlove said. "Much of the 2018 activity focused on expanding access to low-income customers."

Both compensation reform and new approaches to community solar are part of the policy solution for balancing benefits and protections for solar owners, non-solar owners and utilities, Overturf said. "As the ways we produce and consume energy change, the system will operate in new and different ways and new compensation tariffs will be needed to accommodate and maximize those changes."

Successor tariffs

The growing search for a successor tariff to replace retail rate NEM is "simply because some policymakers see it as too lucrative for distributed solar owners and others say it doesn't compensate fully for the value it delivers," Littell said.

Retail rate NEM "is a crude instrument that imposes costs on all utility customers" and a tariff based on competitive bidding would "more accurately reflect solar's value," National Grid's Roughan said.

In Massachusetts, the Solar Massachusetts Renewable Target (SMART) tariff is higher than the retail electricity rate and impose a cost on all National Grid customers, he said. But New York's Value of Distributed Energy Resources (VDER) tariff has been delayed because policy work found solar's value to the system may be below the retail rate.

"We knew a carbon free future would cost more than the carbon-based economy, but policymakers have an obligation to manage cost," Roughan said. Better policies "can do that in a more nuanced way."

The landmark 2016 Colorado solar settlement protected retail rate NEM but also approved demand charge, time of use rate pilots and a controversial utility-led variation on community solar, WRA's Overturf said. "Solar advocates accepted the new programs because they recognized that rate design and community solar policies are changing."

Community solar

"Where there is a community solar project, a bill was passed to create a program and regulators implemented it," Coalition for Community Solar Access (CCSA) Executive Director Jeff Cramer told Utility Dive. "Community solar is a triumph of detailed policy work."

As the community solar market grows, often with the benefit of retail rate NEM, it is being swept into the compensation debate, he said. "But most states don't get more than 3% of peak demand from solar. It isn't time to think about successor tariffs until solar is over 5% of peak demand."

Not everyone in the debate agrees.

"When all utility customers [are] paying for the system, a large project that can be built on the distribution system for $1/watt should not be compensated the same as a 4 kW rooftop array that costs $5/watt," National Grid's Roughan said.

NEM may still be appropriate for supporting the limited amount of rooftop solar, he said. But in Rhode Island, projects as big as 10 MW get NEM, and over three-fourths of Massachusetts' solar is made up of large distribution system-connected projects.

"For projects that big, there has to be a tariff that pays for the value of solar but doesn't overpay, and it should be set through competitive bidding," he said.

New England policymakers are not moving toward compromise because "there are no easy answers," Roughan said. "It will take hard work by people sitting around a table to figure out how to compensate solar, and rethinking business models will be necessary, but the final policy can create a stable long-term program."

Both Xcel Energy Colorado's 50 MW Renewable*Connect project and Rocky Mountain Power Utah's 20 MW Subscriber Solar project were responses to "huge customer demand" for the alternative, utility-led type of community solar approved in the Colorado settlement, WRA's Overturf said. Both were initiated by utilities, approved by policy processes and quickly fully subscribed.

Minnesota's policy is considered the most successful in the country and allows third party developers to build over 500 MW of community solar, Minnesota Citizens Utility Board Regulatory Director Joseph Pereira told Utility Dive. But policymakers are now revisiting it.

The state's success was built on retail rate compensation, but will go forward with its value of solar tariff (VOST), Pereira said. The VOST's recently calculated below-retail value required policymakers to provide a temporary adder to drive the next tranche of growth.

"Xcel Energy might say the policy is a failure because the $170 million per year our 800 MW of distributed solar is costing ratepayers is about four times what Xcel can build utility-scale solar for," Pereira said. "But distributed solar has policy goals, and they cost more. It's not just about building more solar, it's about getting value from solar."

Policymakers are also working on ways to give residential and low-income customers more access to community solar, he added. "This is a policy success because it catalyzed the market and drove development. But to achieve other policy objectives, policy must evolve."

The big picture

"Two decades ago, when cost was the biggest barrier to decarbonizing the power sector, policies were put in place that built markets that drove prices down," WRA's Overturf said. "Three kinds of policy we are developing now will remove the next barriers."

First, policy solutions can speed the redeployment of stranded fossil fuel investments to low cost renewables instead of "waiting until those assets' book lives end, which is costing customers unnecessarily and causing environmental consequences," she said.

Second, policymakers can find ways to take advantage of over-generation created by high renewables penetrations, Overturf said. "That means reshaping load to serve the economy, which will likely require major changes in the way we consume and produce energy and a major rethinking of the power system."

Third, policymakers are looking at ways "to leverage the decarbonized power sector to further drive emissions out of the economy," she said, such as through electrification.

New tariffs must also recognize the value of solar generation to the market when and where it is produced, Roughan said. "It complicates the compensation question, but addressing it will be necessary as we go to advanced metering."

Business likes stability, but renewables, customer demand and new system needs require change, Littell added. "The point is, are we going to think like we're in the 20th century or are we going to think like we're in the 21st century?"

 

Article top image credit: From Greenwood Energy (used with permission)

As a replacement for natural gas peaker plants, solar-plus-storage is already transforming the power sector. And it is starting to transform the residential solar business, because customers facing new time-based rates and new needs for resilience are demanding storage with their solar installations.

Utilities are reporting rapid growth in the sector. While only 1% of Southern California Edison's (SCE) customers use storage, the utility saw a 197% increase in 2017 and a 341% increase in 2018, Senior Communications Advisor Julia Roether told Utility Dive in an email.

Installations of solar-plus-storage systems are now 10% of leading national installer Sunrun's business and grew faster than solar-only installations in 2018, according to its Q3 2018 earnings report. "But 2018 was just the year of planning," Sunrun Policy and Storage Market Director Chris Rauscher told Utility Dive. "2019 will be the year of deployment."

Five-year forecasts reinforce Rauscher's enthusiasm, but installers and utilities from Hawaii to New England told Utility Dive that barriers remain, citing concerns that demand is outpacing manufacturers' ability to deliver batteries and utilities' ability to process interconnections. But smart devices may help utilities overcome some of these barriers.

Growth in solar + storage

Storage deployment numbers from Q3 2018 saw 2013's 0.5 MW installed residential storage capacity rise to about 80 MW last year, confirming strong five year growth.

The U.S. deployed 61.3 MW of storage overall during Q3, a 44% increase over Q3 2017, according to S&P Global Market Intelligence.

And the pipeline of orders predicts annual additions of approximately 660 MW in 2019, 1,700 MW in 2020 and over 3,850 MW by 2023, putting 6,400 MW of natural gas capacity at risk in the U.S. by 2027, according to S&P Global.

The market’s value is expected to double from 2018 to 2019, reaching $4.5 billion by 2023, according to the most recent Wood Mackenzie/Energy Storage Association update. Behind the meter (BTM) storage made up over 60% of last year's Q3 additions, driven largely by demand for solar-plus-storage, with California accounting for 58%, followed by Hawaii and Arizona, the WoodMac report found.

"Time-of-use rates and new state-level mandates and rebates seem to be preparing the way for a mini golden age of storage and solar-plus-storage," Pace Energy and Climate Center Executive Director Karl Rabago told Utility Dive.

Individual markets tell the same story.

The most recent Hawaiian Electric Companies (HECO) utility-scale solicitation resulted in seven solar-plus-storage contracts for 262 MW of solar capacity and 1,048 MWh of storage, the utility's "largest and lowest cost" renewables procurement.

Adding storage may increase a project's upfront cost, but the higher cost is justified by the increased value the project delivers for the system in reliability and flexibility, HECO Senior VP for Planning and Technology Colton Ching told Utility Dive.

"Over the past year, 60% to 70% of permitted rooftop PV systems in Hawaii have storage, and it is climbing," ProVision Solar President Marco Mangelsdorf told Utility Dive. The number of permitted rooftop PV systems with battery storage on Oahu grew from 40 in 2016 to 1,763 in 2018, he said.

At the other end of the country, the Solar Massachusetts Renewable Target (SMART) program is expected to drive storage growth from 0.9 MW in 2017 to 54 MW this year, WoodMac reported.

Installations that include storage by ReVision Energy, which operates in Maine, New Hampshire and Massachusetts, have grown from 1% in 2016 to about 10% in 2018, ReVision President Fortunat Mueller told Utility Dive.

And SCE projects "residential and commercial energy storage will grow by 49% over the next two years," Roether said.

Applications of storage

The four broad applications for residential storage are, "time-of-use shifting, resilience and backup; self-consumption; and grid and wholesale market services," WoodMac reported.

Time-of-use (TOU) and other time varying rate structures are under development in Arizona, Colorado, Minnesota and New Hampshire, among other states. As those rate structures continue to be adopted, "the economic case for adding storage to solar will become stronger," WoodMac added.

California requires TOU rates for all new solar owners and they will be mandatory for most customers by 2020. Approximately 20% to 25% of installer PetersenDean's California customers installed storage with solar in 2018, VP for Consumer Sales Operations Tim Ramage told Utility Dive.

Self-consumption has become important in Hawaii because compensation for exported off-peak generation is less than the retail rates, Mangelsdorf said. The only way to integrate the forecasted tripling of distributed solar by 2045 "is to have enormous storage growth so solar generation is exported only during peak demand, when the grid needs it."

Rooftop solar was originally "imposed" on Hawaii's utilities through state regulations, but now utilities are seeing the benefits of BTM solar-plus-storage as a way to maintain grid reliability and quality "at a reasonable cost," said Mangelsdorf.

Storage has led to a shift in utilities' focus on distributed resources "from their cost to their value" by helping them cost-effectively lower peak demand, said Rauscher.

Resilience, is also driving solar-plus-storage growth in places that have seen extreme weather-driven power outages. Storage is like "electricity insurance," ProVision's Mangelsdorf said. "If the grid goes down, solar-plus-storage is an insurance policy against being in the dark."

Throughout the Northeast, utilities are offering or proposing "bring your own battery" programs, said Rauscher. Private sector providers of solar-plus-storage systems will sell to customers, delivering the benefits of lower bills and resilience to customers and the benefits of cost-effective, reliable power to utilities.

California's utilities have been "exploring" the use of the grid services application "for demand response, ancillary services, and local capacity," WoodMac reported. SCE's 262 MW Preferred Resources Pilot program includes extensive storage capacity. Other utilities are beginning to consider storage as non-wires alternatives to grid upgrades.

But solar-plus-storage will not continue growing without overcoming remaining barriers.

Barriers to growth

Constraints on battery supply slowed storage growth last year, but those restrictions are expected to ease halfway through 2019, WoodMac Storage Analyst Mitalee Gupta emailed Utility Dive.

Plans to create a 2018 revenue stream by addressing Hawaii's over 82,000 rooftop PV systems without storage went awry because "Tesla was not able to meet demand for Powerwalls," Mangelsdorf said. ProVision continues to expect months-long delays in installations "which means the jury is still out on growth in 2019."

About 85% of PetersenDean's Hawaii installations now include storage "but getting batteries from Tesla is a problem," Ramage agreed.

The impact of the supply constraint has been "largely felt on the energy products," Tesla CTO JB Straubel acknowledged in the company's most recent earnings call.

The big challenge, which may face installers across the country for some time, is complexities in solar-plus-storage interconnections.

Interconnection delays, which can be six to twelve months for a large system, are "a major issue in California," Brad Heavner, the California Solar-plus-storage Association Policy Director, told Utility Dive.

Streamlining the interconnection process may take time because of a dispute between installers and utilities over how to evaluate the grid impact of the solar-plus-storage system, Heavner said.

"Solar-plus-storage interconnections are taking months instead of the days that solar-only systems take," said Jeanine Cotter, cofounder of solar installer Luminalt.

Standards released January 7 will begin to ease delays in California, but a final resolution may not come for another year, Heavner said.

At high levels of penetration, storage and smart inverters can support grid stability, but "the caveat is that interconnection and metering issues are resolved through time-consuming regulatory processes," Rauscher said. A better solution is for utilities to develop protocols for using digital technologies "to obtain and verify the system data they need."

New national rules from the Federal Energy Regulatory Commission and standards from the Institute of Electrical and Electronics Engineers are landmarks, Interstate Renewable Energy Council Policy Director Sara Baldwin told Utility Dive. But "state commissions must be proactive in addressing interconnection standards and only a few are."

In Nevada, a recent regulatory settlement between utilities and developers clarified that a technical review should be "based on real operational characteristics," she said. But in Massachusetts, "explicit interconnection rules" are necessary because the "sheer volume" of solar-plus-storage applications through the SMART program "is putting a lot of pressure on the interconnection process."

The SMART program "does not require developers to specify how they will use the systems" for which they file applications, National Grid Director of Energy and Environmental Policy Timothy Roughan told Utility Dive. "Because of that uncertainty, we have no choice but to protect our system by basing the review on the maximum output of the solar and the battery together."

"Assuming the impact is the total output of the two results in more time intensive and costly reviews and more costly projects," Baldwin said. "Nevada also clarified that the impact to be reviewed is the peak net capacity, which is determined by the inverter and is less than the total of the two."

These are not "insurmountable complications and we are working through them," Roughan said. "We have proposed operational characteristics for interconnection agreements that would minimize processing time and costs, but the developers have so far not been amenable."

Interconnection is "a linchpin to distributed energy resources' growth and providers must prioritize it as part of the core business model and market growth strategy," Baldwin said.

Smart devices could, if combined with solar and storage, resolve these barriers and help utilities, their customers and private providers reap the benefits

The missing piece

The full impact of storage on the solar business will come with the incorporation of smart devices to manage customer loads, both installers and utility executives agreed.

Storage is a gamechanger, Rauscher said. It is becoming "a unified proposition to meet customer needs and goals and, at some point, we will stop talking about individual technologies and start talking about how to help customers manage their energy and costs."

"Controllable devices at the grid edge are potential grid assets," said Mueller. "Solar only goes so far, solar-plus-storage goes much farther and solar-plus-storage plus smart devices goes even farther."

Companies that offer solar-plus-storage "now see themselves as energy solutions providers" and that "broadens the value they offer," HECO's Ching agreed.

With the growing penetrations of variable distributed generation on so many systems, "the load management piece is what has been missing and it is where the future is," National Grid's Roughan said. "Managing customer load is where the solar-plus-storage players who will be successful are moving. The ones who stay with solar-only will be left behind."

 

Article top image credit: Lockheed Martin

Gasoline-fueled vehicles would not get far without easy-to-access gas stations and, for the same reason, electric vehicles (EV) will need easy-to-access charging stations for the U.S to transform its transportation system.

Transportation electrification is widely seen as crucial to decarbonizing the U.S. economy. But charging vendors say avoiding utility interconnection delays is necessary to maximize EV deployment. Such delays remain common, they add, but best interconnection practices are emerging.

Best interconnection practices begin with the utility making clear what information it needs to prepare the site, charger builders told Utility Dive. Utilities must also be clear about when the site will be ready for installation of the charging infrastructure. Finally, charger builders and utilities must have clear channels of communication throughout the process.

Interconnection challenges

"One of the first things EV buyers want to know is where charging stations are," EVgo Executive Vice President of Business Development Julie Blunden told Utility Dive. With 1,100 chargers in 66 metropolitan markets, EVgo has seen "tremendous uptake" in both EVs and public charging, but resolving utility interconnection issues is "critical" to maintaining that pace, she said.

"Bottlenecks" in interconnection have delayed projects anywhere from six months to "well over a year," said Blunden.

But it's not just charging station vendors who want more build-outs sooner. Some utilities are also pushing for quicker deployment.

"California needs 7 million electric vehicles by 2030 to meet its climate goals, and we need to move faster to make charging infrastructure available for that transportation electrification," Southern California Edison (SCE) Director of eMobility Katie Sloan told Utility Dive.

Though some utilities have been obstructive, SCE's interconnection procedures "have evolved into best practices," according to Blunden. Its procedures include clear application requirements, predictable timelines and access to utility authorities when clarifications are needed.

As EV penetrations rise, other utilities "can leapfrog some of the trial and error by using those best practices," said Ram Ambatipudi​, vice president of business development and utility engagement at EV Connect, an EV charging company.

The streamlining of distributed solar interconnections demonstrated the problem-solving potential of utility-private sector collaborations, utility spokespeople and charger vendors told Utility Dive, and stakeholders could take those lessons and apply them to current EV charging challenges.

Though EV charging interconnections can be more complicated, the opportunity for new utility revenue streams makes collaboration "a win-win," Blunden said. More charging will allow the EV industry to thrive and utility involvement could mean growth in electricity demand.

The need

EV sales momentum is accelerating. By the end of January this year, the U.S had sold over 1.1 million plug-in vehicles and California had sold over half a million, according to tracking from industry trade organization Veloz.

A 2018 Executive Order from California Gov. Jerry Brown, D, set a goal of 5 million zero emission vehicles (ZEVs) and 250,000 public chargers, including 10,000 direct current fast chargers (DCFCs), by 2030.

The state had 14,000 public charging stations, including 1,500 DCFCs, by the end of 2017, according to a 2018 National Renewable Energy Laboratory (NREL) report.

Most public charging stations have multiple level two (L2) ports, which provide charging at twice the rate of home ports that deliver a full charge in about eight hours. DCFCs draw current even faster and can charge an EV battery in 30 minutes.

The market needs both L2 and DCFC charging stations much sooner than Brown proposed, NREL reported to the California Energy Commission (CEC) in March 2018. To reach just 1.3 million EVs in 2025, California needs between 229,000 and 279,000 chargers, including 9,000 to 25,000 DCFCs.

For the 7 million EVs SCE sees as necessary by 2030 for California to achieve its climate goals, the utility estimates the state will need about 350,000 'away-from-home' ports located in public areas.

California's U.S.-leading EV growth made it one of the first to discover the challenges of charging station interconnections. With the growth of demand for EVs, emerging markets are now beginning to look at their interconnection procedures. An example is the Washington, D.C. metro area.

Exelon subsidiary Pepco, which serves parts of D.C. and Maryland, is now piloting a charging station program with 187 L2s and DCFCs, PEPCO Manager for Smart Grid and Technology Rob Stewart told Utility Dive. It will soon add 1,000 chargers in support of Maryland's 2025 goal to deploy 300,000 EVs and 5,000 charging stations, and is "actively developing best practices," Stewart said.

Charger providers and utilities need to work as "allies," EVgo's Blunden said. "We added six stations in six weeks in SCE's territory because it has become very competent in the process elements, but not all utilities make that possible."

Delays impose financial pain on charger vendors when revenues are held up until the utility completes and electrifies the station, EV Connect's Ambatipudi added. "It is more from inexperience than irresponsibility, but learning best practices can prevent repeating the same mistakes."

Best practices

Only SCE and Pacific Gas and Electric (PG&E) "are dealing with interconnections at scale today," EVgo's Blunden said. "What is needed is basic transparency about the process steps, the timelines and what is needed from the charger company. SCE has a published a flowchart that is explicit about those elements."

Transparency cannot eliminate inevitable delays in construction, but it can reduce charger vendor-utility tensions, she added.

EVgo asked PG&E for an equivalent version of SCE's flowchart, but didn't feel the timeline was as well laid out, something "critical" to their operations, said Blunden, while acknowledging PG&E is currently tied up in a bankruptcy proceeding that has put it in a "legitimately difficult situation."

EV Connect's Ambatipudi agreed, but added that PG&E has "retooled its program" and expects to deploy "a lot more charging stations this year."

Since September 2017, PG&E has installed 644 public L2 ports and 446 DCFCs and has over 2,800 L2 ports and over 1,300 DCFCs queued, PG&E spokesperson Paul Doherty emailed Utility Dive. 

When there was less charging on PG&E's distribution system, safe interconnections were often possible without hardware upgrades, Doherty said. To meet new demand for chargers requiring system upgrades, PG&E is working "to standardize interconnection procedures" but also "to balance the speed of interconnection" with "safety and reliability."

Charger providers who are "fully prepared with site details often are interconnected the most quickly," he said. Unplanned changes made during construction, like relocating chargers to be nearer substations or nearer handicapped-accessible parking, can "set the interconnection timelines back considerably."

Both SCE and PG&E have effectively engaged with the transportation electrification industry "to expedite interconnections," Ambatipudi said. EV Connect's installation of over 3,000 ports in the course of a decade also "went smoothly" with ConEd and National Grid in New York, as well as Sacramento and Imperial County public utilities in California.

Collaboration

SCE has built and interconnected 1,000 public charging ports as part of its Charge Ready pilot, most of which are L2s, Sloan said. About 300 private vendor interconnections are completed or pending. Its $760 million proposal for a four-year infrastructure build-out of 48,000 more charger ports awaits regulatory approval.

SCE has a planning team that works directly with customers' engineers on location, design and construction, giving them "one single point of contact at the utility," Sloan said.

Collaboration is critical "because the customer's focus is on their needs and aesthetics, while our focus is the utility infrastructure requirements," she said. The utility is focused on the least-cost project, but "if the customer wants a more expensive choice, we do it if it is technically feasible."

The Sacramento Municipal Utility District's (SMUD) process also begins with utility-vendor collaboration. "Working with the utility often results in savings for the charging company because we know where electrical access is cheapest," SMUD Supervisor of Electric Transportation Bill Boyce said.

SCE operates under a three-stage process: project design, construction and energization. A similar process of collaboration is described across multiple power providers Utility Dive spoke to, including SMUD, PG&E and San Diego Gas and Electric (SDG&E).

Interconnection times vary, but "best-case scenarios" may take three to six months, Doherty said. With complications, that timing could double or triple, he added. SDG&E interconnections generally take between six and 12 weeks, said SDG&E spokesperson Helen Gao.

Coordination is the key, said EV Connect's Ambatipudi. "Like SCE, utilities need to be properly staffed and have processes in place. Charger companies can make the process better by using standard specifications that meet utility requirements."

The main thing charger vendors can do is "engage early and often with the utility about the plans it is making," SCE's Sloan said. "The sooner the utility knows what and where the charger provider wants to build, the sooner we can be ready."

But other delays are beyond the control of utilities or vendors.

The solar solution and beyond

Siting and interconnection issues can create tension between the utility and the vendor, but "delayed permit approvals from [authorities having jurisdiction] are a much bigger factor in project implementation," EV Connect's Ambatipudi said.

SCE sped up this part of the process by understanding how to "navigate" permitting agencies and meet their requirements, "and our experience with solar may show how to do even better," SCE's Sloan said.

"Rooftop solar interconnections initially took a few months and now take a few days," she said. "We cannot complete charger installations in a few days, but we can make interconnections more routine, which is something that we learned in solar."

The California Solar Initiative guidebook "includes timelines for solar installers and utilities," Blunden said. "Utilities can use that example to reduce interconnection and permitting delays, as they did for solar."

The solar industry accelerated permit approvals by convincing key agencies to adopt a comprehensive standard policy, Ambatipudi said. "That kind of coordination between [authorities having jurisdiction] and the private sector can happen again."

Residential rooftop solar interconnections got much faster at SMUD when they became "standard and repetitive," Boyce said. "But an EV charger interconnection is more like a 2 MW solar array. And interconnecting DCFCs will be an order of magnitude more challenging."

Pepco is transferring its utility industry-leading solar interconnection process to charger interconnections, Stewart said. "But we'll have to get engineering involved for the bigger loads that come with fast charger interconnections."

SMUD and SCE are also anticipating challenges from interconnecting the much bigger loads from medium- and heavy-duty vehicle fast-charging. An SCE medium- and heavy-duty vehicle pilot will launch this year and the utility is working with fleet operators now "to better understand the significant differences in the bigger loads," Sloan said. "We expect a lot of learning."

Article top image credit: Wikimedia Commons

Policy-driven, ground-breaking, electric vehicle-specific rate designs from California's top utilities could break down cost barriers to driving electric and support grid stability while protecting ratepayers.

In September 2018, California lawmakers enacted Senate Bill (SB) 1000 to advance the state's U.S.-leading transportation electrification effort. In December, the California Public Utilities Commission (CPUC) opened a proceeding to develop a formal transportation electrification framework. Both called for rate design solutions to market barriers.

SB 1000 ordered the CPUC to, within an existing proceeding, consider rate designs that shift the EV charging load away from peak demand and address the demand charges in commercial and industrial (C&I) rates now impeding electric vehicle (EV) growth, CPUC EV Program staffer Carolyn Sisto told Utility Dive.

The demand charge in C&I rates covers the utility's cost for being able to meet the customer's highest kW usage but can significantly increase a C&I bill when a customer adopts EVs, Sisto said. It has become a barrier to EV growth in the commercial-industrial sector because the disproportionately high spike from charging an EV fleet can make driving electric more expensive than using a traditionally fueled vehicle.

The commission was already working toward the transportation electrification objectives in SB 1000, but in the new rulemaking, the CPUC directs the state's IOUs' focus on those objectives as well, said Sisto. In 2017, the CPUC approved a San Diego Gas and Electric (SDG&E) trial rate to shift residential EV charging as well as a new Southern California Edison (SCE) EV-specific rate to address demand charges.

The commission was already working toward the transportation electrification objectives in SB 1000, but in the new rulemaking, the CPUC directs the state's IOUs' focus on those objectives as well, said Sisto. 

A precedent-setting Pacific Gas and Electric (PG&E) demand charge solution would create a new rate class to address C&I customers' EV load​. It was introduced in November 2018 and will be considered by the commission this year. Like the SCE and SDG&E rates, it proposes time varying pricing that acts as a signal to shift usage. Uniquely, it replaces the demand charge with a monthly subscription charge.

This is a hybrid version of the energy subscription concept introduced by Navigant Director Lon Huber.

"PG&E's proposal is a step toward the full subscription concept," he told Utility Dive. "Electrifying transportation has to be easy for customers, but cannot impose cost shifts, and a monthly subscription charge that replaces the demand charge, but covers fixed costs, is a simple way to do both."

The innovative rates so far brought forward by California's IOUs are an early — but important — indication of what rate design can do.

The law and the order

SB 1000's first objectives are to drive planning and investment for charging infrastructure deployment that is "in the best interests of ratepayers." To do so, a CPUC proceeding should explore rate strategies that "reduce the effects of demand charges" and that encourage charging "when there is excess grid capacity."

To further clarify the role of the regulatory process in transportation electrification, the commission developed an order that calls for a "Transportation Electrification Framework" (TEF) based on legislative guidance that enables utility-private sector engagement.

In the state's legislative directives, "there is no clear definition of what the electric utilities' overall role should be," Sisto said. The TEF is to identify new metrics or targets that can guide new utility proposals, and to clarify that "ratepayers cannot be expected to pay for all the needed infrastructure."

It's also meant to define the role and responsibilities of the IOUs in transportation electrification and ensure that IOUs and private providers work together to develop a robust private sector, the order said. A draft from Energy Division Staff, which will draw on stakeholder input, is due in October.

The new rates

IOUs were already working on EV-specific rates, the rulemaking aimed at creating a TEF and advancing transportation electrification acknowledged. But there is no "standardized method" or single rate design for accomplishing the SB 1000 objectives. It therefore orders California's IOUs "to submit a joint proposal" for new rate designs.

The final proposal, which will be part of the TEF development process, could incorporate time-of-use (TOU) rates that shift usage away from the peak. And, based on the commission's orders, it is to address demand charge barriers facing direct current fast charger (DCFC) site hosts, transit agencies running electric buses and C&I customers with EV fleets.

Rate designs must be cost-based, avoid cross-subsidies and keep the cost of driving electric "well below" the cost of driving with conventional fuels. 

Each IOU is approaching the objectives differently.

SDG&E

The SDG&E vehicle grid integration (VGI) pilot is being implemented for 3,000 customers. It is one of three EV-specific TOU rates expected to shift SDG&E's EV charging load toward periods of midday solar over-generation, SDG&E EV Customer Engagement Manager Natasha Contreras told Utility Dive.

TOU rates are for residential and workplace light duty vehicle charging and do not address the demand charge barrier, Contreras acknowledged. Customers are notified a day ahead of hourly prices. The utility's "TOU 5" plan offers a super off-peak $0.09/kW midnight to 6 a.m. rate with a $16 monthly fee. Its "TOU 2" plan has a super off-peak price of $0.28/kWh but requires no monthly fee.

SDG&E analytics show high volume EV drivers can easily offset the $16 monthly fee with the discounted electricity rate and save significantly over conventional fuel vehicles, Contreras said.

SCE

SCE's new C&I rate plan, to be implemented March 1, offers a five-year demand charge holiday, SCE Director of Pricing Design and Research Russ Garwacki told Utility Dive. It will be followed by a five-year demand charge phase-in to a new demand charge 40% below the current charge.

The demand charge normally covers utility costs to meet a C&I customer's highest demand spike, he said. But early-stage EV fleets often have very low loads except during the charging spike. With the demand charge holiday, we are "migrating a portion of our distribution costs toward energy and becoming less demand charge focused," Garwacki said. Incremental costs can be absorbed through the energy charge until charging loads grow.

SCE's EV-specific TOU energy charge has an off-peak $0.13/kWh price for all hours except the 4 p.m. to 9 p.m. peak demand period, when it is as high as $0.38/kWh, he said. Off-peak charging will make driving electric significantly more cost-effective because $0.13/kWh roughly converts to $1.30/gallon, he added.

Several utilities proposed limited demand charge holidays in 2018, according to North Carolina Clean Energy Technology Center Senior Research Manager Autumn Proudlove, including National Grid, Orange and Rockland Utilities, NV Energy, PECO Energy and Pacific Power.

PG&E

The main innovation in the PG&E commercial EV (CEV) plan is replacing the demand charge with a fixed subscription rate to make C&I customer bills simpler and more certain, spokesperson Paul Doherty emailed Utility Dive. With TOU rates and the subscription charge, customers can pay a per-kW charge for the charger capacity they want to use and charge at a per-kWh rate that fits their need.

For charging sites of up to 100 kW, there would be a "CEV-Small" subscription fee of $25/month for each 10 kW of charging capacity, according to a PG&E filing. For fleets and high-volume sites with over 100 kW charging capacities, there would be a "CEV-Large" $184/month subscription fee for each 50 kW of charging capacity.

The 4 p.m. to 10 p.m. peak demand charging price would be $0.30/kWh, and super off-peak 9 a.m. to 2 p.m. hours charging would cost $0.09/kWh. Other hours range from $0.11/kWh to $0.12/kWh. These "price signals" will lower customer costs and shift usage to support the grid, Doherty said.

The subscription innovation

The CPUC only recently began reviewing the PG&E subscription proposal but it appears to be unprecedented in California, CPUC's Sisto said. "The subscription fee and energy charges fully cover system fixed costs for the new rate class, and there will be no cost shift because all costs go to the new rate class."

SCE has said its plan "could reduce C&I customers' charging costs as much as 50%," NRDC Clean Energy Legal Fellow Miles Muller told Utility Dive, adding that PG&E has shown "its plan could reduce customer costs between 30% and 50%."

However, the PG&E plan eliminates a concern of SCE's plan: that at the end of the phase-in, the load at some necessary but low volume charging sites may not support even a reduced demand charge, Muller noted in a blog.

Both proposals have been described as subsidies for EV charging, but because the costs of incremental EV loads are covered by energy charges, they are not, Utility and Grid Services Director James Tong of fleet EV truck provider Chanje told Utility Dive. 

The way PG&E addresses system costs makes PG&E's plan "a step forward for all EV charging," Regulatory Assistance Project Senior Advisor Jim Lazar emailed Utility Dive. "Each customer pays for the final connection to the grid on a ‘subscription' basis," but the plan "puts all the shared costs — generation, transmission, and distribution substations and circuits — into the TOU energy part of the rate."

PG&E's subscription rate "is a type of demand charge that is understandable for customers," SCE's Garwacki said. There are questions about how it will work, "but the solution in the final joint proposal will probably be a combination of the proposals from the IOUs and other stakeholders."

Subscriptions can be a "win-win-win" for utilities, customers and technology providers, Navigant's Huber said. "Using a subscription in an EV-specific rate to address the demand charge, and coupling it with TOU energy charges, is a good hybrid application to advance the concept."

Demand-based pricing for EV infrastructure "requires utilities to estimate the revenue collected from charging to cover their fixed costs," Huber said. "A subscription rate can be set to cover these costs and eliminate guessing."

An electricity subscription "appeals to customers in the same way cell phone plans and online home entertainment plans appeal to them," he added. "And it is easy for EV drivers to compare the subscription's cost to their gasoline costs."

Significant EV adoption will require "customer-friendly rates that also provide predictability to investors," Huber said. "A customer-centric subscription rate is a clear pricing strategy that both sophisticated private providers and utilities can base investments on."

Other versions of the subscription rate are being tested by utilities in EV-specific rates for residential customers, he added. In Texas, Austin Energy offers unlimited public charging for $4.17/month and unlimited off-peak home and public charging for $30/month. Vermont's Green Mountain Power offers unlimited off-peak charging at $29.99/month.

Shifting residential charging to off-peak is important, but rates should drive EV adoption, Chanje's Tong said. "More public charging and DC fast charging will drive the EV market and those sites pay C&I rates that face demand charges, which is why both SCE and PG&E are on the right track."

But the California IOUs' proposals do not get at the CPUC Staff's biggest goal, a performance-based metric​, which will hopefully be developed in the joint utilities proposal or the TEF process, Sisto said. The metric "would replace utility compensation for infrastructure investments with compensation for shifting load, including EV charging load, to when there is excess generation, and especially to when there is excess renewables generation, on the system."

 

Article top image credit: Flickr; National Renewable Energy Lab

Dive Brief:

• Vermont's only investor-owned utility, Green Mountain Power (GMP), introduced a pilot on Tuesday to use battery storage systems as meters, in order to provide a clean back-up power source and energy savings.
• GMP, which has partnered with Tesla for years, has a vision to have batteries in every home. The pilot includes 250 customers enrolled with the utility and 250 customers enrolled with third-party vendors, using GMP's Bring-Your-Own-Device incentives, to add two Tesla Powerwall battery systems per customer.
• The utility is working on testing the Resilient Home pilot for 18 months, filing updates along the way. GMP aims to test other batteries to use as meters in the future.

Dive Insight:

Energy storage batteries have a lot of capabilities and using them as meters helps to increase their value, justify their costs and ultimately advance their deployment.

States like Massachusetts and New York have set storage deployment targets as part of wider clean energy goals. For GMP's part, the potential of adding batteries to every residence and include capabilities to measure energy usage, which the utility is attempting to patent, would help them manage peak loads while enabling the deployment of renewable resources onto the grid.

"All of these things are in concert with [GMP] moving toward our goal of being 100% carbon free by 2025 and 100% percent renewable by 2030," Mary Powell, GMP's CEO, told Utility Dive. "It's been many years that we've been working on what we call a complete energy transformation to a community-, home- and business-based energy system versus the bulk delivery system that we've known for ... over a hundred years."

The GMP offer, which has received calls requests from more than 1,000 customers for participation since the April 30 launch, would charge customers $30/month for two Powerwall batteries. For comparison, Liberty Utilities' battery program is $25/month per battery for 10 years.

Depending on the success of this program, GMP will craft a tariff and offer Resilient Home to all customers, according to Kristin Kelly, GMP spokesperson.

The program comes amid multiple utility efforts to get costly grid modernization plans approved by regulators. Public utility commissions in states like Virginia and Kentucky have rejected plans for adding smart meters or advanced metering infrastructure (AMI), citing concerns about cost and net benefits.

GMP began to look at battery systems as a means to upend the current metering model, Powell said.

"I felt like I had an 'a-ha' moment when we were talking about all the functionality of what a storage device in a home could do," she said. Given its metering capabilities, "why would we even want all this extra equipment on homes and businesses?"

GMP's patent-pending system could be applied by other utilities and help make meters moot, Powell said. GMP worked to develop the capability to read energy consumption data through the Powerwall system.

"We still need AMI to move forward with a lot of innovative things," Lon Huber, energy director at Navigant Consulting, told Utility Dive. Huber helped design Liberty's Tesla residential storage program.

Participants also receive the option of a monthly flat fee locked in for up to a year for their energy usage, which the utility measures through the battery systems.

The flat fee is based on nine fixed price levels, reset annually based on your usage in the previous year. The price is designed to encourage efficiency and energy savings while countering the volatility of monthly pricing driven by heat waves and cold weather in the state. Vermont has up to three months of predictable energy use per year, during fall and springtime, according to Powell.

Tesla is one of GMP's longest-standing partnerships, since the announcement of the Powerwall, Powell said. The utility has already installed Powerwall batteries in its service area, in part for peak shaving. Green Mountain Power said it saved ratepayers $500,000 by reducing peak demand during a heat wave last July by calling on about 500 Powerwall batteries.

That program is expected to save customers up to $3 million across its lifetime.

Article top image credit: Green Mountain Power

The Santa Rita Jail in Alameda County, California, houses 4,000 inmates and has an electric load of about 3 MW, partly served via a smart microgrid, installed as a field demonstration of an autonomous and decentralized control concept.

As more clean and distributed resources come onto today's utility grids, critical loads are increasingly turning to microgrids to ensure power stability. New control technologies can help keep costs down, while allowing for increasing penetration of renewables.

The Santa Rita system includes solar, wind, battery storage and a fuel cell. And once assembled, "it just worked," said Robert Lasseter, an engineering professor at the University of Wisconsin and a principle investigator of the CERTS MIcrogrid Concept.

Typically, a microgrid will require expensive control components, along with site-specific commissioning that can also add time and expense. But the Santa Rita Jail system was largely a plug-and-play setup using the new concept.

"That was the biggest compliment I've ever gotten on this," Lasseter told Utility Dive. "You don't have to fine-tune in the field. If [components] test out in the factory, that's it."

CERTS stands for the Consortium for Electric Reliability Technology Solutions, and was multi-year collaboration funded by the U.S. Department of Energy's Office of Electricity. It brought together several national laboratories, universities and industry partners, including American Electric Power, which operated the test bed.

The basic idea was to develop a microgrid capable of operating using decentralized, autonomous control algorithms in order to allow active elements to operate in coordination. The approach can reduce the costs of some microgrids, a final report on the project concluded, by eliminating the need for a master controller or central storage unit to set voltage and frequency.

Microgrids rising

Microgrid deployment is on the rise — in the fourth quarter of 2018, Navigant Research identified 2,258 projects representing more than 19.5 GW of planned and installed power capacity around the world.

At the same time, data from the National Renewable Energy Laboratory shows controller costs per megawatt range from $6,200 to $470,000, with a mean of $155,000. That's a wide range, but NREL also noted that controller costs "show a generally downward trend as capacity increases for projects with capacities of 2 MW or more."

"I hear more and more complaints that microgrids are too expensive," Lasseter said. But the CERTS approach to grid control can help lower costs, particularly for smaller systems.

The research focused on developing new methods for coordinating the operation of both directly-coupled distributed resources (like synchronous generators) and inverter-coupled sources (often solar, wind and energy storage).

"As a result of these innovations, autonomous control lowers the total cost of a microgrid compared to other designs because autonomous control greatly reduces the site-specific costs of commissioning and maintaining grid-independent operations," according to the project report, which was published in September.

Those costs are "significant," the report found, particularly for smaller microgrids with an aggregate installed generating capacity up to 20 MW. "Lowering these costs greatly improves the economics of smaller-scale microgrids," the report found.

Most inverters today are grid-following, he explained, meaning they need another source to provide voltage and frequency. Grid-following current source control, and grid-forming voltage source control, are two techniques that microgrids utilize to coordinate DERs behind an inverter and the grid.

The AEP test bed was located near Columbus, Ohio, and consisted initially of three Tecogen generators, four load banks and inverters with CERTS algorithms embedded.

The CERTS Microgrid Concept "entails operating each source as a grid-forming voltage source device," DOE's final report explains. "This may seem like a simple idea, but, historically, most inverter-based sources (such as PV and wind) have been designed to operate as grid-following current-source devices."

In simpler terms, said Lasseter, when using the CERTS control concept, "if you have a certain source and you change your load, you don't have to tell the source to do anything."

Commercializing the concept

The test bed was active from 2006 to 2017, though the research predates even that. Along with field projects, the collaboration also resulted in the commercialization of the concept. A company called Tecogen developed a gas combined heat and power system that utilizes the CERTS concept — and four of its units kept the lights on for five days, for a Greenwich Village, New York, luxury co-op building during Superstorm Sandy. 

The final CERTS report notes that commissioning of both pre-commercial prototypes and commercial units for the project was "important for facilitating commercial adoption of successfully demonstrated innovations." To date, researchers say Tecogen has licensed CERTS algorithms for their InVerde 100 engine-generator, while Princeton Power Systems is using CERTS-compatible techniques on multiple energy storage product lines.

Lasseter has moved on from the CERTS project and is now working with Sandia National Laboratories on grid issues in Hawaii, where a high penetration of renewables has created frequency issues. The state is rapidly adding solar, but as more intermittent resources come onto the grid, there is a growing potential for instability. 

"As more and more inverter-based small generators are put into our power system, how can we make sure it is stable?" asked Lasseter. Storage is one solution, but cost is often prohibitive, he Lasseter. New control ideas like the CERTS concept can allow for a greater renewables penetration and at a lower cost.

Utilities have thousands of distributed resources on their systems, he said. "You can't control them, it's too complicated. But you need them to behave appropriately," he said. "I think this will turn out to be a very good solution."

Article top image credit: Jackie Snow