Beyond the MeterTHE POTENTIAL FOR A NEW CUSTOMER-GRID DYNAMIC

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TABLE OF CONTENTS

INTRODUCTION ................................................................. 3

PART ONE: CAN CUSTOMER RESOURCES BECOME TANGIBLE UTILITY ASSETS? ......................... 3

§ Relying on a Fleet of Smart Thermostats in Place of a Coal-fired Power Plant ..................... 4

§ How Does a Distributed Energy “Power Plant” Look, Feel and Function? .............. 5

§ The Case for Owning and Managing Solar from the Customer Rooftop ........................ 7

PART TWO: UNDERSTANDING THE CUSTOMER AS WELL AS YOU UNDERSTAND A POWER PLANT ................................... 8

§ SMUD: Digging Deep into Customer DER Adoption Forecasts ................................................... 8

§ Using Solar as the Carrot to Engage Customers in Reducing Peak Demand ....................................11

PART THREE: REWIRING THE UTILITY— “BEYOND THE METER” SUCCESS DEPENDS UPON INTERNAL CHANGE ...........................................12

KEY TAKEAWAYS ..............................................................14

APPENDIX: KEY RESOURCES FOR FURTHER READING ........................................................16

COPYRIGHT© Smart Electric Power Alliance, 2016. All rights reserved. This material may not be published, reproduced, broadcast, rewritten, or redistributed without permission.

DISCLAIMERThe conclusions in this report draw upon Smart Electric Power Alliance (SEPA) conversations with electric utility industry professionals. The opinions expressed here are SEPA’s and do not necessarily reflect the opinions of the utility executives quoted in the paper.

JULY 2016

AUTHORSBob Gibson, Vice President of Knowledge— Bob is a member of SEPA’s senior team, leading strategic communications and content development. Bob came to SEPA in 2010 from the National Rural Electric Cooperative Association, where he was a senior manager in the Cooperative Research Network, leading NRECA’s analysis of renewable energy and energy efficiency technologies and business models. Bob also worked at ECO, an alternative energy services company, and as a program manager of the Utility Photovoltaic Group, as part of his responsibilities at the Technology Transition Corporation. Bob’s diverse background includes extensive work in international development and journalism.

Vazken Kassakhian, Research Analyst— Vazken joined SEPA as a Research Analyst in August 2015. Prior to that, as an Energy Analyst at the Sierra Club, he analyzed state compliance pathways for the Clean Power Plan (CPP) and completed a national analysis of the impact of mandated state and local policies and voluntary purchases on utility scale renewables and distributed solar for the Sierra Club. He has also held research and analysis positions with the Colorado Public Utilities Commission advising on regulatory policy on Smart Grid and at the National Renewable Energy Laboratory analyzing policy and market impacts in the electric sector. Vazken has an MBA and a certificate in Renewable and Sustainable Energy from CU Boulder and a B.A. in English from UC Berkeley.

ACKNOWLEDGEMENTSSEPA would like to thank all of the contributors to this report, including Obadiah Bartholomy at the Sacramento Municipal Utility District, Syd Briggs at Steele-Waseca Cooperative Electric, Chris Greenwell at Oklahoma Gas & Electric, Caroline McAndrews at Southern California Edison, and Carmine Tilghman at Tucson Electric Power. We would also like to thank the following SEPA staff for their review: Mike Taylor, Tanuj Deora, Erika Myers, John Sterling, Ryan Edge, K Kaufmann, Jennifer Szaro, and Ted Davidovich.

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IntroductionDriven by policy support, customer preferences and rapidly declining costs, the growth of distributed energy resources (DERs) is seen by many industry stakeholders as having the potential to place unprecedented stress on traditional electric utility business models. Most utilities initially responded defensively to this disruption. But senior leaders at power companies across the country are changing their assessments of DERs. They are characterizing these resources not as threats, but as potential assets to the physical power grid, and a means to enhance the financial sustainability of their companies.

At the same time, excitement about this evolution is tempered by the challenges of developing and implementing specific strategies for turning customer-sited DERs into integrated parts of the power grid. This paper draws on the experiences of several utilities working on innovative approaches to engaging customers and launching distributed energy programs. As part of a more holistic approach to resource planning, these utilities are:

n Exploring whether and how distributed energy resources—particularly those owned and controlled by customers—can be relied on to supply power generation and peak-management resources that benefit the utility as a whole.

n Developing a deeper understanding of how customers use energy, including their motivations for acquiring new technology and responding to new price signals.

n Assessing organizational changes—such as cross-departmental communication and collaboration—that will be part of a successful transition to greater reliance on customer-sited and other distributed energy resources.

If visibility of the customer has traditionally ended at the point of the meter, and behind-the-meter technologies have fallen outside the scope of the utility, the new approach will incent both the utility and the customer to look “beyond the meter” to access resources, supply services and efficiently manage an increasingly decentralized grid.

Part One: Can Customer Resources Become Tangible Utility Assets?

Over many decades, electric utilities have developed a deep understanding of the centralized technologies—from baseload power plants to pole-mounted transformers—essential to delivering 20th-century electric service. However, a new suite of distributed technologies has the potential to serve as a part of the utility plant of the future—from solar and storage to smart thermostats and electric vehicles.

The situation is further complicated by a number of factors:

n Overall power demand in many markets remains flat, while peak load demand, especially for residential customers, shifts to later in the day.

n Customer-sited resources can place more stress on the grid, but at the same time open possibilities for deferring or even avoiding the capital expense of major power plant or transmission projects.

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n Distributed resources may also involve investment in customer engagement and cross-department cooperation.

Pilot projects testing out these new customer-grid solutions can strike a balance between innovative thinking about dispatchable power and customer engagement, and utilities’ traditionally prudent approach to new investments.

RELYING ON A FLEET OF SMART THERMOSTATS IN PLACE OF A COAL-FIRED POWER PLANT

When Chris Greenwell, now Senior Product Innovation Manager at Oklahoma Gas & Electric (OG&E), joined the utility’s strategy group nine years ago, the company was facing strong opposition to a plan to build a new coal-fired power plant.

In response, OG&E scaled back coal and expanded natural gas generation. But the more significant move, Greenwell said, was the utility’s decision to consider investing in wind, transmission, and smart grid.

“Traditional justifications for smart grid investments have hinged on operational savings, such as fewer truck rolls, but such reasons alone did not create a compelling business case for OG&E,” Greenwell recalled. Instead, he and his group looked at customer programs that offered additional benefits that could be monetized.

Similar to utilities across the country, OG&E was watching the gap in demand for power between off-peak and on-peak hours grow ever wider, adding cost. A smart grid program that could provide price signals to incentivize customers to reduce peak consumption was promising in concept, but faced skepticism within the company.

“Our experience in load management had been with direct load control, where we put devices on air conditioners,” says Greenwell. “AC contractors would fight us on it; they’d remove them. It wasn’t a good program.”

In 2008, OG&E created a modest, 25-home price-response pilot program testing what was, at that time, bleeding-edge technology. The program helped the utility change its views on the viability of leveraging customer behavior to manage and shift load.

Price-response participants were placed on a time-of-use rate, which could vary from a low of 5 cents per kilowatt-hour (kWh) to as much as 45 cents per kWh, depending on the day. Thermostats supplied by OG&E could be set to automatically optimize the use of lower-priced power, such as precooling a home before the afternoon peak, but customers could override the settings at any time.

The critical difference was not the technology, but how it enabled customer engagement and customer choice, Greenwell said.

“In direct load control, customers get paid a rebate, but they don’t participate,” he said. “Customers in price-response programs do exactly what we want them to, but it is totally their choice. They have all the control, and control is so important.”

Customers also loved the technology, Greenwell said.

When OG&E won an American Recovery and Reinvestment Act stimulus grant in 2011 to help deploy smart meters throughout its service area, the utility won public service commission approval to open the price-response program to all customers. To date, more than 125,000 of the utility’s 650,000 smart meter customers have joined the program, achieving an average coincident peak reduction of 2 kW. Individual customers save on average $175 a year on their power bills, and OG&E has been able to defer 160 megawatts of generation.

“When you have a 10-times price differential, customers will respond, and that’s why we’ve been so successful,” Greenwell said.

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The program has also helped the utility lower its total resource cost—savings that benefit all OG&E customers, he added. It also translated into an observable boost in customer satisfaction ratings, with OG&E at or near the top in the J.D. Power surveys.

But, Greenwell said, one thing has not changed: OG&E’s fundamental business driver of making prudent investments that promise a return.

“We’re a different company today than we were when I came to OG&E,” he said. There is an emphasis on what we can do with new technology.”

HOW DOES A DISTRIBUTED ENERGY “POWER PLANT” LOOK, FEEL AND FUNCTION?

While OG&E was able to shave peak demand to reduce 160 MW of generation, Southern California Edison (SCE) now faces a significantly greater challenge. The closure of the 2-gigawatt San Onofre Nuclear Generating Station in 2013, the impending retirement of other nearby ocean-cooled power plants, and growing demand for electricity in central Orange County have created concerns about reliability.

Given the industry trend toward distributed energy resources serving local customer needs, SCE is in the midst of a ground-breaking pilot project to determine if, by 2022, it can deploy a portfolio of clean and diverse DERs as alternative to a more traditional investment in 300 MW of natural gas peaking plants. Covering 13 cities and 250,000 residential customers, the Preferred Resources1 Pilot is testing a suite of distributed resources—including energy efficiency, demand response, solar, and storage—to determine if they can provide the same reliability as a traditional power plant.

“You have to build to the peak; it’s just a question of, are you building a traditional gas-fired plant or are you buying distributed resources that offset those few hours when you might have that peak?” said Caroline McAndrews, Director of the Preferred Resources Pilot. “We really wanted to make sure that when we use these distributed resources that they would perform as we intended them to perform, that they will actually be assets to provide reliability.”

A key challenge for the program, McAndrews said, is DERs’ lack of visibility and control at customer sites, both residential and commercial. Most of the solar in the pilot program region is customer-sited and may not have meters that are visible to the utility, leaving SCE unable to appropriately value and have confidence in the performance of local solar production. A commercial site may make investments, upgrades and improvements in energy efficiency that provide general savings, but could be further optimized for the distribution grid. If utility economics drive calls for demand response that customers find too burdensome, they may choose to opt out at times of critical system need.

McAndrews sees a potential solution for this last issue in the combination of demand response and energy storage, which, she believes, will bring new vitality to demand response programs.

“While most customers can handle the call to drop load . . . if the calls are few and far between, too many calls on a customer are a challenge,” she said. “Energy storage will play an increasing role in demand response because the customer is not impacted as much by a call when their storage makes up for the need for power.”

The first two years of the Preferred Resource Pilot have, so far, allowed SCE to demonstrate that distributed resources can—in look, feel and function—serve the grid in lieu of traditional resources. To date, SCE has:

1 Preferred resources are a prescribed resource loading order by the state of California to meet energy needs. Energy efficiency and demand response are first, followed by renewable sources and clean distributed generation. For purposes of the Preferred Resources Pilot, SCE’s definition of preferred resources includes energy storage, since it is an important enabler to address intermittent resources. https://www.sce.com/wps/wcm/connect/1ac76183-53c2-4762-8db2-4d52345dfa74/SCE_PRPOverview.pdf?MOD=AJPERES

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n Acquired 136 MW of location-specific DERs—including energy efficiency, demand response, solar and storage—with 33 MW of these “preferred resources” already deployed and 103 MW in the queue—and is on track to acquire an additional 100 MW this year; continuing to inform the process of very local procurement.

n Established a methodology, working with Clean Power Research, to better value solar dependability, ultimately doubling the dependability of solar contribution from behind-the-meter solar systems for distribution planning to offset summer load—from 19 percent of installed capacity to 40 percent.

n Developed a circuit-level DER tracking process and methodology to measure the corresponding solar and demand response impact on load.

n Devised new methods to match DER resource attributes to hourly needs on the distribution system.

McAndrews stresses that the pilot is still in progress, with many questions and concerns still unanswered. If the pilot continues to demonstrate that the distributed resources can be effectively managed

Traditionally, when distribution forecasting is done, the peak need is determined by looking at the annual peak from a single point in time from a particular location; for example, on a circuit at the substation. To address a new peak need that could not be served through imported energy, SCE would have sought a peaking plant that is available day and night, every day of the year—but often sits idle. DERs provide an opportunity to more precisely match the supply portfolio with demand. In fact, this type of granular analysis is essential, given the variable output of DERs and the need to use demand response judiciously to avoid customer attrition.

SCE’s solution began with breaking down peak load demand needs by location and hour for a whole year. Distributed resources could then potentially be deployed to meet these energy needs based on the DERs’ availability, dependability and durability:

n Is the resource available when called upon?

n Does it deliver load reduction or production as expected?

n Can it continue to deliver in future years?

In other words, McAndrews said, “DERs have performance capabilities that vary throughout the day. If we have a midday peak at 2 p.m., solar is potentially a good resource to offset that peak. But if the peak is at 6 or 7 p.m., we may want to use energy storage; and, to avoid exacerbating a day peak, we might pair that with solar to charge the storage and use the storage when the peak occurs.”

SCE is looking at distribution planning in a new light, investigating other locations where DERs may defer distribution upgrades or new construction.

EE DG - PV ENERGY STORAGEDR PRP 2022 MW NEED

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HOUR OF THE DAY

FIGURE 1: EXAMPLE PORTFOLIO OF DER RESOURCES TO OFFSET PEAK LOAD

Source: Southern California Edison, 2016

SHIFT TO HOURLY PLANNING AT THE DISTRIBUTION LEVEL

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and deployed, those resources will play a larger role in the utility planning process. As McAndrews says, “[The pilot] is an opportunity to see if DERs can be used to manage a parameter. In this particular case, the parameter happens to be a 300 MW load

growth—but you could manage a parameter down at a circuit level, where there may be a localized loading concern that distributed resources could ultimately offset.”

THE CASE FOR OWNING AND MANAGING SOLAR FROM THE CUSTOMER ROOFTOP

In late 2014, Tucson Electric Power (TEP) received regulatory approval for a 600-customer residential solar pilot program, in which rooftop installations would be utility-owned and operated. Beyond providing customers with an additional option for going solar, the TEP pilot was also aimed at testing out a different rate structure to mitigate a portion of the cost-shift associated with customer- or third party-owned systems.

TEP also partnered with local installers on the program. The utility provided the capital, but offered a competitive bidding opportunity for Tucson area installers to expand their markets.

The energy generated from the 600 rooftop PV systems is not delivered to the host homes but is fed into the grid. In return, participating customers get a 25-year contract locking in monthly electric bills based on their current average use. The pilot also allows TEP to manage production from the rooftop systems for the benefit of all utility customers, siting and controlling these installations to ensure grid stability and reliability—the same as it would with traditional generation. TEP is installing some PV systems with a west-facing orientation to better match production with system peak demand, as opposed to the southern orientations that provide greater overall daily production. Other benefits include utility management of the smart inverter on each installation to provide ancillary services such as voltage regulation on the distribution system.

“The questions that need to be answered are not whether we control the inverter, but what communication network do we utilize to aggregate all the systems while maintaining a secure network,” said Carmine Tilghman, TEP’s Senior Director of

Energy Supply. “And to what level does the utility need to control the system?”

Customer acceptance of the utility-owned and managed systems has not been an issue, Tilghman said. Ninety-nine percent of the pilot participants are satisfied with the program, he said, and 77 percent report that their opinions of TEP have improved somewhat or greatly based on their participation in the program.

TEP’s Residential Solar Program presents a paradigm shift in utility engagement with customers and DER adoption, while also echoing the approaches of the different DER strategies at OG&E and SCE. Tilghman offers the following takeaways for ensuring DER pilot programs can successfully expand to become a permanent part of a utility’s business:

n The utility must determine that the business case is in the best interests of its customers. This may not be the case with every utility.

n Regulatory approval may well be needed, and the program should be developed to be consistent with the existing regulatory structure.

n Stakeholder involvement can be structured in many ways, but it is critical. If a program is perceived as a “utility power grab,” it will be rejected. Detractors will always look for something to criticize, so the utility must be able to show that the program is in the best interests of ratepayers, stakeholders and regulators.

Tilghman sees the TEP pilot as “the first entry into the customer world of products and services, and will serve as a platform for future opportunities to partner with our customers in implementing DERs in a strategic, efficient and cost-effective manner.”

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Part Two: Understanding the Customer as Well as You Understand a Power Plant

“Customer engagement” has become an industry buzzword, covering a range of utility outreach and communication activities aimed at better understanding customer interests and motivations. But, with DERs in the mix, the term requires that utilities move beyond traditional market research and segmentation strategies. As with technology in general, utility customers—their interests, their technical sophistication and their expectations about the choices they want in energy services— are in transition.

Utilities today must be able to engage younger consumers who expect to control thermostats and other appliances from a cell phone app, as well as older customers who pay their bills with only a quick glance at the details of power usage and rates. Utilities now also have a wealth of customer data from advanced meters and other systems tracking energy consumption patterns, which they are only beginning to mine and leverage for insights into how to plan for the future.

The question of how much energy choice customers want or expect from their utilities is

an open one. Caroline McAndrews of Southern California Edison isn’t sure.

“I know we get lots of feedback from various entities saying the customers want more choice. I think there is a set of customers that do, but a majority? I don’t see or sense it yet,” she said. “We work with a lot of energy managers at commercial and industrial customer sites, and what they want is dependable electricity at the lowest cost.”

But she sees a role for the utility in steering customers to make new energy choices that save them money while adding value to the distribution system. How to develop that role—over different markets and evolving customer demographics—is the challenge utilities such as Southern California Edison and others now face.

“Once the resources are there—I think it’s a win-win for the customer and the utility,” McAndrews said. “The challenge on the customer side is how do we really engage them to participate. ... The biggest challenge is aligning the utilities and developers with a common message that is helpful to the customer and then determining what will it take for the customers to actually participate.”

SMUD: DIGGING DEEP INTO CUSTOMER DER ADOPTION FORECASTSThe Sacramento Municipal Utility District (SMUD) has been a national leader in groundbreaking advances in the use of solar and many other energy technologies and strategies. In 1984, SMUD energized PV1, the first utility-owned solar power plant in the world, built almost in the shadow of the cooling towers of the Rancho Seco nuclear plant, which was shut down five years later. By 1994, SMUD was installing PV systems on 500 homes and businesses under its PV Pioneers I program, which within four years had created a 5 MW “fleet” of utility-owned distributed solar resources.

Still, like a growing number of utilities, the public power utility serving 1.3 million customers in Central California has recently seen a dramatic rise in customer—and third party—owned distributed energy resources. Near-term forecasts suggest that SMUD customer investments in energy efficiency and behind-the-meter distributed technologies, such as rooftop solar, could soon outrun the utility’s own investments in new energy resources and grid infrastructure.

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Instead of viewing these trends as a business risk, SMUD has approached them as an opportunity to strategically leverage and optimize future customer investments in behind-the-meter DERs to provide grid benefits for all its customers. In 2015, SMUD began to seriously study the future of customer-sited energy resources, recognizing that it did not have a sufficient understanding of its customers. How and when would customers “organically” adopt solar, storage and other distributed resources, outside of a utility program?

SMUD had some visibility on customer adoption, based on interconnection applications and agreements, and an incentive for PV production meters. But as the utility’s and other customer incentives for rooftop solar started to dwindle, SMUD began to look at what it would need to do to integrate, manage and leverage this rapidly growing resource, beyond approving interconnections.

As a first step, earlier this year, SMUD undertook a comprehensive forecast of DER penetration in its service territory through 2030.

“We really need to understand what we expect the market to do on its own without our intervention, and to determine the full resource value we can expect to get from each of the distributed energy resources,” said Obadiah Bartholomy, Manager of Distributed Energy Resources at SMUD. “We also want to understand what value we might get from programs that . . . leverage these DERs. The simple motivation is that we want to understand both the market context and resource value to develop a robust DER strategy.”

At a minimum, this comprehensive analysis was aimed at helping SMUD get a better understanding of what’s going to unfold as customers make their own choices and invest behind the meter. Equally important, said Bartholomy, are “the opportunities that are not going to be realized without an intervention by us”—for example, demand response and distributed storage.

To answers these questions, SMUD, working with Black & Veatch, analyzed how multiple DERs might interact and where geographically on the grid these

resources might appear, looking at impacts at the meter, circuit and system-wide levels.

SMUD’s study of its customer base also included modeling and simulating customer profiles and expected DER choices across its service territory for a look at where resources might show up under real-world conditions. SMUD incorporated standard methods—such as modeling paybacks and the economics of adoption—but also went beyond traditional demographic and economic analysis to gather data on customers and the factors that influence their decisions to adopt technology.

“What we’ve added is really trying to understand the beliefs, habits and preferences of our customers, and using that to understand the relationship to DER adoption,” Bartholomy said.

Basing geographic distribution of DERs on simulated customer choices allows SMUD to get more realistic insights into the estimated cost impacts DERs could have on its distribution system. For voltage impacts, for example, SMUD was able to incorporate customer data into its model for forecasting DER adoption, which yielded a lower

The main purpose of SMUD’s comprehensive study of its entire customer base has been to analyze which customers might adopt multiple DERs and the geographic patterns associated with such adoptions. Larger, system-level questions included:

n What are the aggregate impacts of increasing PV adoption?

n What are the costs to the utility and grid? n Where might electric vehicle (EV) clustering raise issues?

n Can EV load growth mitigate revenue losses from PV?

n Can PV help alleviate EV clustering issues?

DER ADOPTION: LOOKING AT THE BIG PICTURE

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Source: Sacramento Municipal Utility District and Black & Veatch, 2015

estimate of cost impacts versus random adoption. Similarly, a forecast incorporating the likelihood of actual customer adoption of electric vehicles (EVs) helped assess the impacts of EV clustering on transformer overloads, which were more severe

than in forecasts based on random distribution. The following charts simulate customer adoption of DERs at each meter along with the net impact on load on a system-wide level.

GEOGRAPHIC DISTRIBUTION OF FORECASTED CUSTOMER ADOPTION OF DERS—BY METER & CIRCUIT

Figure 2: Different symbols and colors represent different DER technologies. Sizes are proportional to DER output. Concentric circles represent sites with multiple DER technologies.

Figure 3: Maps display aggregated impacts of adoption on circuits and feeders. Contains summary-level information of total change in load (GWh) on a circuit due to DERs (+ or -). All parcels served by circuit shaded same color.

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One of the pleasant surprises from this analysis, Bartholomy said, “was that the cost to the utility and the grid from the impacts of [customer-sited] PV and EVs were not higher” than originally expected.

The utility had assumed that clustering of distributed technologies would raise operational costs. While further analysis will be needed to provide a definitive answer, SMUD believes that the deployment of multiple technologies may have a mitigating effect, such as the net impact of PV production overlapping with workplace EV charging.

Better forecasts using customer propensity to adopt DERs also provide deeper insights into where these technologies might have the most value. Similar to Southern California Edison, SMUD is investigating the opportunity for DERs to defer capital investments. The utility is currently identifying capital projects planned in the next

three to four years and is using the analysis to propose portfolios of DERs that could defer those projects. The portfolio will, ideally, leverage natural adoption by customers, supplemented by direct program spending, focused marketing and direct procurement by the utility.

“We’ll calculate whether a program encouraging customer DER adoption might be a lower-cost solution than, for example, the utility adding energy storage in a given location,” Bartholomy said.

One of the next steps will be to identify areas for demonstration projects aimed at building internal confidence that SMUD will be able to meet the same reliability standards with DERs as with traditional investments. Part of the exercise, he said, is figuring out how to assess the value of deferring these investments, based on the timing and location of DER adoption.

USING SOLAR AS THE CARROT TO ENGAGE CUSTOMERS IN REDUCING PEAK DEMAND

Like most electric cooperatives, Steele-Waseca Cooperative Electric, a consumer-owned utility serving fewer than 10,000 meters in rural southeastern Minnesota, believes it knows its members pretty well. But co-op officials were a bit surprised when a vocal segment of their membership began asking for solar power. Responding to that interest, Steele-Waseca found a way to offer members a great deal on solar, and meet two traditional utility goals: building electric load and reducing costs for all customers by moving energy use from peak to off-peak hours.

When member interest in a solar option began to rise a couple years ago, the co-op considered following the lead of many other co-ops across the country by starting a community solar project. But even with the economies of scale of a larger system, the per-panel price to the co-op penciled out at more than $1,000 a panel—a price that wouldn’t fly with many of Steele-Waseca’s members, said Kristi Robinson, the co-op’s

distribution system engineer. The program had to fit in with customers’ own local economics, she said.

“Our goal was to bring the price in under $200, roughly the amount people have become accustomed to spending on a trip to Wal-Mart or Target without even thinking about it,” she said.

Robinson and her colleagues came up with a solution that benefitted both customers and the grid: Co-op members could buy a 410-watt PV panel in the utility’s community solar project for only $170, on the condition that they also accept a free, super-insulated Marathon electric water heater, with a retail value of $1,000.

The co-op controls the heating elements, which consume electricity only in off-peak hours (between 11 p.m. and 7 a.m.). The bottom-line benefit, operational and economic, is that 20 percent of the co-op’s electric demand moves

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off-peak, providing significant savings in the rates shared by all members.

Giving away water heaters has been a staple of load management programs at co-ops in Minnesota and other states, but Steele-Waseca’s solar offer allowed it to leverage members’ interest in solar to reinvigorate the load management program.

“We’ve been promoting the water heaters for a long time, but I think people stopped noticing

the program,” said General Manager Syd Briggs. “Community solar was a new way to put the water heater offer in front of people. The solar panel drew the main interest, but what made it affordable was pairing it with the water heater.”

In addition, many of the electric water heaters are replacing propane-fueled units, which helps Steele-Waseca build electric load at a time when many U.S. utilities are losing load. Load growth helps utilities cover long-term investments in power plants, poles and wires.

Part Three: Rewiring the Utility— “Beyond the Meter” Success

Depends Upon Internal ChangeThe pilots and programs described thus far in this paper are providing information to individual utilities, which in turn is helping them to change long-standing assumptions about customers, accessible resources and how utilities should plan for the future.

But the next step may be the hardest: accepting the need to change from within. As SEPA heard from many of the utility leaders we interviewed, the status quo is not an option.

“Most utilities believe that once they have a customer, once they have a program, they’ll always have it,” said Syd Briggs of Steele-Waseca. “That’s not true. You can lose customers, you can lose load.”

The process of organizational change may be so woven into the design and development of new programs, a single case study cannot fully capture the shifting perspectives and close, cross-departmental collaboration involved in such efforts. Rather, this section presents the insights, experiences and strategies for organizational change that emerged from our interviews.

At Southern California Edison, Caroline McAndrews observed that “cross-functional engagement (within the utility) is a key. The Preferred Resources Pilot takes an integrated approach, rather than patching (together) a bunch of separate actions from various silos.”

Teams actively engaged in the pilot include transmission and distribution (to right-size systems); customer service (to educate customers about new programs); and procurement (to tap local resources for behind- and in-front-of-the meter contracts). The involvement of regulatory affairs and communications has also been critical, McAndrews said.

Briggs said his co-op’s experience bundling solar and water heaters has provided a key, not only to engaging customers to become a part of the utility resource base, but to surviving in a challenging business environment.

“You take any other business and you talk about bundling, they know the value of it immediately,” he said. “But to utilities, it’s an unusual thought. We are currently looking at ways to take this idea and advance it with more than just renewables.

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Basic bottom-line assumptions may also need rethinking, he said.

“Even if we were to discount the program enough that we didn’t make as much money on the water heater program as in the past, we are retaining customers, we are retaining market share,” Briggs said. “That’s foreign to a utility; but a utility should get into that line of thinking.”

At Oklahoma Gas & Electric, past experience with direct load control created internal resistance to the notion that a residential demand response program would yield good results. Success with a small pilot opened the door for a commercial roll-out, which has been both well-received and highly effective, but has not completely changed long-ingrained ways of thinking about system change and risk.

OG&E is not ready to deploy demand response—or other DERs—as a substitute for investing in poles and wires and other traditional distribution system upgrades, Chris Greenwell said.

“The way to address deferring T&D assets is price response (using time-variant rates), and I haven’t seen anyone achieve a level of success with price response that we have,” he said. “But the real reason utilities haven’t done it is that the incentive structures aren’t there. There is too much risk, and it’s too easy to build infrastructure.”

In Sacramento, SMUD’s intensive analysis of customers, DER adoption and the impact on utility investments is aimed at changing the way the utility plans for the future. But Obadiah Bartholomy noted that it will be a process of developing confidence and breaking down some internal silos.

For example, he said, SMUD is aware that over the past five years, energy efficiency investments have reduced peak demand by about 25 MW a

year, helped along by about 100 MW of behind-the-meter solar—contributing about 40-50 MW on peak—installed in the same time frame. That adds up to about 175 MW, or 5 percent of the utility’s overall peak demand.

But the utility has not yet determined exactly where on the system those reductions have had measurable impacts. To provide this analysis, SMUD has drawn together staff from distribution, customer service and resource planning groups to assess the data—a process that has shifted perceptions and thinking.

“Our resource planners don’t typically care about distributed resources except in aggregate, and distribution planners haven’t typically cared about wholesale market evaluation and how that might influence dispatch of distributed resources,” Bartholomy said.

As a result of the collaboration, he said, “Our resource planning group is recognizing that the sheer scope of distributed resources will drive a greater focus on the implications of annual adoption of DERs.” To meet localized system needs, SMUD will need improved forecasting, as well as dispatch signals for resources such as distributed energy storage.

At Tucson Electric Power, setting up and launching the utility’s residential solar pilot involved cooperation from almost every department and division across the company, Carmine Tilghman recalled.

“Owning and operating a residential product at the customer’s premise is a fundamental shift away from traditional utility service,” Tilghman said. “This must be accepted from top to bottom and embraced as a possible path to the future of what a distribution services company could provide under the ‘utility of the future’.”

BEYOND THE METER SERIES

14 SEPA | A BEYOND THE METER SERIES REPORT

Key TakeawaysThis paper presents examples of the evolving and different ways utilities are working to better understand and engage customers in new partnerships that provide benefits to both. It poses the questions, what is this emerging customer-grid dynamic, and how is it going to impact and change the utility?

The customer-grid dynamic is where the utility goes beyond the physical meter to develop a partnership with its customers in providing resources and services to the grid.

Utility action to enable and embrace this new dynamic of mutual support can be looked at in three parts:

1. Evaluating DERs as Grid Assets: Increasing sophistication of grid planning and operations tools to account for potential system benefits from DERs on a temporal and locational basis.

2. Integrating Customer Insights: Increased segmentation of load profiles, propensity to adopt, and behavioral drivers combined to better evaluate economic and achievable potentials.

3. Rewiring Standard Operating Practices: Opening up planning processes across functional areas (system planning, resource planning, marketing, regulatory) to incorporate more robust and holistic deployment strategies.

Some utilities will find some of these activities relatively straightforward to incorporate into their operations, but most may find such a significant set of changes challenging. Each organization, like the five profiled here, will need to determine the

role of technology partners in evaluating, designing and implementing any potential changes. Such a determination will not be straightforward, and will be the subject of future SEPA research.

Utilities’ successful transition to a grid with optimal levels of DER deployment will also require consideration of additional issues, such as how business models, rate designs, market structures and regulatory oversight may or may not need to change. These issues are the focus of other Smart Electric Power Alliance (SEPA) efforts, such as our 51st State Initiative (www.sepa51.org).

FIGURE 4: NEW CUSTOMER-GRID DYNAMIC

REWIRING STANDARD

OPERATING PRACTICES

INTEGRATINGCUSTOMERINSIGHTS

EVALUATINGDERS AS

GRID ASSETS

THE POTENTIAL FOR A NEW CUSTOMER-GRID DYNAMIC 15

The Smart Electric Power Alliance (SEPA) sees a new customer-grid dynamic emerging. If visibility of the customer has traditionally ended at the point of the meter and behind-the-meter technologies have fallen outside the scope of the utility, the new approach will incent both the utility and the customer to look “beyond the meter” to access resources, supply services and efficiently manage an increasingly decentralized grid.

This new dynamic is supported by incorporating DERs as grid assets, integrating customer insights and rewiring standard practices in utility operations and planning. SEPA’s forthcoming Beyond the Meter series of papers will investigate each of these domains. The series will be supported by additional studies, both existing and in process.

EVALUATING DERS AS GRID ASSETS For an in-depth discussion of distributed resource applications and capabilities, see SEPA’s forthcoming “Distributed Energy Resource Capabilities Guide.”

SEPA’s forthcoming joint paper with Nexant, “Addressing the Locational Valuation Challenge for Distributed Energy Resources: Establishing a Common Metric for Locational Value” provides a methodology for quantifying the locational value of DERs for distribution capacity.

INTEGRATING CUSTOMER DATA AND INSIGHTSSEPA’s forthcoming work on customer insights will include information about how utilities are using customer data and analytics for more informed infrastructure investment planning decisions, more efficient program marketing, and enhanced customer satisfaction.

REWIRING STANDARD OPERATING PRACTICES

n SEPA’s joint paper with Black & Veatch, “Planning the Distributed Energy Future,” presents a discussion of DER planning challenges, trends, methodologies, tools, and industry gaps. The paper also outlines a process for utilities to proactively plan for DER integration.

n Two SEPA publications provide an in-depth discussion of how distributed resources are affecting utility business practices and operations:

§ SEPA & ScottMadden’s “Benchmarking Utility Organizational Structures: How Renewable Energy is Reshaping the Utility Hierarchy”

§ SEPA and the National Renewable Energy Laboratory’s “The Flexible Solar Utility: Preparing for Solar’s Impacts to Utility Planning and Operations”

SEPA’S BEYOND THE METER SERIES AND RELATED STUDIES

Appendix: Key Resources for Further Reading

Advanced Energy Economy Institute (AEEI) and Synapse Energy Economics, Inc., Benefit-Cost Analysis for Distributed Energy Resources: A Framework for Accounting for All Relevant Costs and Benefits, 2014

Analysis Group, The Value of “DER” to “D”: The Role of Distributed Energy Resources in Supporting Local Electric Distribution System Reliability, 2016

Black & Veatch and The Solar Electric Power Association (SEPA), Planning the Distributed Energy Future: Emerging Electric Utility Distribution Planning Practices for Distributed Energy Resources, 2016

EPRI, The Integrated Grid: A Benefit-Cost Framework, 2015

Electric Power Research Institute (EPRI), Time and Locational Value of DER: Methods and Applications, 2016

Greentech Media Research (GTM Research), Unlocking the Locational Value of DER 2016: Technology Strategies, Opportunities, and Markets, 2016

Kevala, Geography Dependent Valuation: Quantifying the bias in statewide averages in PV valuation methodologies in California

National Renewable Energy Laboratory (NREL) and the Solar Electric Power Association (SEPA), The Flexible Solar Utility: Preparing for Solar’s Impacts to Utility Planning and Operations, 2015

RMI, The Economics of Battery Energy Storage, 2015

RMI, The Economics of Demand Flexibility, 2015

Solar Electric Power Association (SEPA and ScottMadden), Benchmarking Utility Organizational Structures: How Renewable Energy is Reshaping the Utility Hierarchy, 2014

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