Author:DATE: 17 JUL 2018 Institute For Self  Reliiance

Reverse Power Flow: How Solar+Batteries Shift Electric Grid Decision Making from Utilities to Consumers

For 100 years, most decisions about the U.S. electric grid have been made at the top by electric utilities, public regulators, and grid operators. That era has ended.

For 100 years, most decisions about the U.S. electric grid have been made at the top by electric utilities, public regulators, and grid operators. That era has ended.

Small-scale solar has provided one-fifth of new power plant capacity in each of the last four quarters, and over 10 percent in the past five years. One in 5 new California customers of the nation’s largest residential solar company are adding energy storage to their solar arrays. Economic defection––when electricity customers produce most of their own electricity––is not only possible, but rapidly becoming cost-effective. As the flow of power on the grid has shifted one-way to two-way, so has the power to shape the electric grid’s future.

The shift of power into customer hands is already having three, unintended consequences:

  1. Legacy, baseload power plants are becoming financially inferior to clean energy competitors.
  2. Electricity sales have stagnated as customers reduce use and produce electricity for themselves.
  3. Communities are reaping greater economic rewards from power generation, as electric customers, individually and collectively, produce more locally.

Almost no utility or utility regulator is adequately planning for this fundamental shift. Dozens of utilities across the country have proposed new gas-powered generation that has little chance of remaining online through the end of its economic life due to stiff competition from solar-plus-storage. Some have been approved despite substantial gaps in the economic analysis.

Utility have also made reactionary moves, or made gestures inadequate to address the magnitude of system change. There tend to be three inadequate utility responses to the reversed flow of decision-making power:

  1. Utilities have damaged their reputations by resisting customer interest in distributed energy resources, sending lobbyists to preempt or curtail policies that reward customer-sited and customer-owned power generation.
  2. Utility investments in large-scale renewable energy have addressed environmental concerns, but these low-cost power purchases have not delivered reduce electricity prices for end users nor assuaged the interest in over 70 cities of reaching 100% renewable electricity more rapidly.
  3. Utilities have deployed utility-owned distributed energy resources, but in ways that withhold much of the economic or financial benefit from customers.

Regulators and state legislators cannot expect incumbent utilities to respond adequately because the rise of economical solar-plus-storage challenges the century-old assumption of a natural electricity distribution monopoly. Instead, electricity market rules should facilitate fair compensation for distributed energy resources and market participants where technology already allows them to compete.

This report details recommendations for changing utility oversight and modifying electricity markets to transition from the dying utility distribution monopoly to a vibrant, democratic energy system where customers have the opportunity to choose distributed energy options that benefit themselves and the greater grid.


Solar + Storage Comes to Market

Utilities don’t have time to prepare for a future with economical, distributed energy storage because it’s on the doorstep. In 2016, the first hints of a storage-driven transformation of the electricity business came as a “postcard from the future” in Hawaii. Sunrun offered their Brightbox, a combination solar-plus-battery product with a price of 19 cents per kWh, almost 50 percent cheaper than grid electricity. Sunrun began offering its Brightbox service in California in December 2016. By 2018, 1 in 5 new residential Sunrun solar customers in California were choosing to add storage.

These early adopter states just scratch the surface of the competitive landscape.

Based on a proxy measure of electricity prices, the combination of on-site solar and energy storage can already compete with the price of serving nearly 26 million residential electricity customers in 19 states.1 The ILSR model compares customers installing a 7-kilowatt-hour Tesla Powerwall and a 5-kilowatt solar array to utility electricity prices, with the percentage of each state’s customers who can generate cheaper power themselves shown on each state:2

ILSR’s analysis isn’t alone. According to McKinsey, within three years an Arizona electric customer would be able to serve 80 to 90% of their electricity needs with solar and battery storage, at a lower price than by buying electricity from the utility company.

Storage prices have fallen remarkably fast, as illustrated by the remarkable price declinesfor battery storage technology in the last three years (measured in the cost of energy averaged over the expected life of the battery).

Customers have responded to the falling costs, with a surge in new installations of residential energy storage in the past year.

Although few residential customers would find it practical, full grid defection––or cutting the cord to the grid—could be at price parity within 10 years.

Business customers managing larger facilities have it even better. A 2017 analysis of solar and storage for affordable housing facilities in Chicago found that adding energy storage reduces the payback for solar from 20 years to 6 years by helping manage facility demand charges.

A broader report, also from 2017, suggests that commercial storage (alone) could be economic for one in four commercial electricity customers nationwide. Many commercial electricity customers have a demand charge, a portion of the electric bill based on a one-hour window of peak energy use each month, and representing half of many businesses’ bills.3 Solar energy alone is insufficient to avoid this charge, but a relatively small battery can lower that peak. The following map from the report shows particularly robust opportunity in the Southwest (coinciding with excellent solar resources), but also in the Upper Midwest, West Virginia, and much of New England.

The prospects for solar+storage are even more remarkable in the near future. The following chart shows forecast steep declines in battery costs––by half in the next five years, and by two-thirds by 2030.

Batteries aren’t just getting cheaper, they’re doing so at a rate far outstripping predictions. A 2014 report from Rocky Mountain Institute featured several battery price projections, including one from Bloomberg. At the time, Bloomberg projected batteries crossing the $300 per kilowatt-hour threshold in 2022. Three years later, Bloomberg showed that batteries reached that price point in 2016; by 2017, battery pack prices had fallen another 30%.

How do rapidly falling costs change the calculus of solar plus storage?

If the Powerwall cost forecast by GreenTech Media comes true––halving the cost––and solar continues a modest 3-4% reduction in the cost per year, in 2022 nearly half of all residential electricity customers (in all but 4 states) will be able to get electricity as affordably from their rooftop and a battery than from the utility company.4 The following map provides a stunning contrast to the one based on today’s prices (page 3).

Storage costs and forecasts are a clear warning to utilities that customers will be able to leverage batteries (and solar) for much more control of their energy bills than ever before.

Grid Implications

Energy storage increases the value of rooftop solar installations to customers––providing resiliency to utility outages and allowing them to avoid new utility fees. It’s no wonder that, as noted earlier, 1 in 5 Sunrun solar customers in California opted for storage in 2017.

The collective decision of California customers also offers valuable grid services. For example, California residents and businesses already host nearly 6 gigawatts of solar. If half of these existing solar households added a Tesla Powerwall (with 7 kilowatt-hours of storage and a maximum draw of 2 kilowatts) and half of solar businesses added a 50-kilowatt Tesla Powerpack (with 210 kilowatt-hours of storage), California electric customers could provide 1.19 gigawatts of power for 3.5 hours. That’s enough to significantly reduce the state’s evening grid peak during its full duration. The chart below illustrates:

Electric cars, adopted for their ability to cut the cost of car ownership, could do far more. If connected to the grid in a way allowing for their batteries to be tapped, “The 1.5 million electric cars California expects by 2025 would have a maximum energy demand of about 7,000 megawatts, more than double the capacity needed to substantially smooth the current afternoon rise in peak energy demand.”

Batteries can also supplant fossil fuel generators in helping stabilize the grid. An electric grid requires a delicate balancing act of supply and demand, every second of every day. One technological advantage of battery storage over most other grid resources is that batteries act fast, nearly instantaneous. Batteries supply short bursts of power to keep the grid’s voltage and frequency steady at a lower cost than big power plants and turbines operating on standby.5

In the U.S. Mid-Atlantic region, the grid operator PJM requested such “ancillary services” that included markets for frequency and voltage regulation markets for smaller producers (a minimum size of 100 kilowatts). The lucrative prices––$40 to 50 per megawatt-hour––and low threshold for participation supported development of dozens of energy storage projects. Several hundred megawatts of battery storage entered the PJM market in response to the opportunity, many doing double-duty by providing crucial services to their owners, not just the grid.

Changes in market rules and reduced costs for gas competitors have since reduced the financial opportunity in the Mid-Atlantic, but batteries can still provide value to their customers and the grid in other ways. A study for the California market showed no fewer than six value streams for battery operators aiding the grid, as illustrated below. The first two bars represent the value of additional capacity freed up on the transmission and distributed system by storing excess local energy. The third bar is the ability to provide reserve energy on a moment’s notice, and the fourth represents the value of actually delivering that energy. The fifth bar shows the value of helping regulate the grid’s voltage and frequency to keep it stable. The final bar represents the reduced need for power generation capacity that can be supplied by storage.

In addition to the Mid-Atlantic and California examples, markets are likely to open in other regions soon. A 2017 directive from the Federal Energy Regulatory Commission requires all grid operators to adopt rules recognizing the many values of energy storage and allowing firms to aggregate many small storage projects into large ones.

If customer-sited distributed energy resources can access the financial compensation for their value, customers will likely take opportunities to reduce their energy costs through greater self-reliance. The implication for utilities is clear: be wary of making substantial, centralized infrastructure investments when decentralized technology has significant advantages, can be online sooner, with decisions made by folks outside your boardroom. The following section explores the implications of the competition from distributed energy resources.


An Inadvertent Triple Threat

Locally generated power from solar-plus-storage can undercut the century old utility model––centralized power plants sending electricity long distances over high voltage transmission lines––in three ways.

First, it has higher value. If the cost of delivering electricity to the ultimate customer is 10 cents per kilowatt-hour, a typical utility’s costs are split between generation (about 3 cents), transmission (about 3 cents), and distribution (about 4 cents). Power produced at the power plant is worth far less than energy delivered into the customer’s home or business. The following graphic offers an approximation of the typical utility’s cost structure for delivered electricity.

Second, distributed energy resources can be deployed more quickly, in months rather than years, and the price often decreases in the time it takes to plan and finance a centralized power plant.

Third and most striking, the decision to deploy distributed resources is relatively independent of centralized power plant development. Utilities don’t do distribution planning and customers don’t consult utilities when installed distributed energy resources, despite clear effects on one another.

California provides a powerful illustration of how the combination of thousands of individual actions presents the collective triple threat. Over 700,000 solar arrays in California were installed because of simple economics––rooftop energy generation from sunshine costs customers less than utility power and customers and third party marketers were given a chance to access that value. Most of these arrays were built in the last 10 years, less than a typical utility’s 15-year resource plan and in much less than the average power plant lifespan (40 years or more). Unused to competition or planning on such a short timescale, California utilities were caught flat-footed.

Death of “Baseload” and Fossil Fuel Power Plants

The economics of coal and nuclear power plants have for years relied on operating at high capacities around the clock. But with energy efficiency and distributed energy lowering demand; utility-scale solar and wind cutting into sales with cheaper, cleaner electricity; and now, with the advent of energy storage, these power plants struggle to compete. Utilities operating non-competitive plants in Ohioand Illinois have sought subsidies to keep these “baseload” plants operating. Some power companies have even lobbied the federal government to provide a backdoor subsidy by rewarding power plants with on-site fuel storage (a backhanded swipe at wind and solar that could misfire as these systems add battery storage). The competitive threat also applies to new power plants, where the rapidly falling costs of distributed energy make slow-to-build, long-term investments very risky.

A Nuclear Plant Retires

The Diablo Canyon nuclear power plant, in San Luis Obispo County, Calif., is a prime example of threat to incumbent power plants and the potential for innovative solutions.

Completed in 1985 and 1986, the Diablo Canyon facility provides close to 9% of the electricity used in California. Operating licenses for the two reactors expire in 2024 and 2025, with the utility seeking license renewals. However, as the state’s electricity market has become increasingly dominated by low-cost wind and solar resources (with very low operating costs), the nuclear plant’s electricity was no longer competitive (five other nuclear reactors were shuttered nationwide in 2013 and 2014 alone). The combination of poor revenue outlook and pressure from environmental organizations led the utility to a settlement agreement in 2016. Per the proposed settlement, the utility would retire both units and replace their capacity with “a combination of renewable energy, efficiency and energy storage.”

Unfortunately, the settlement agreement was undercut by an early-2018 order from the Public Utilities Commission. Commissioners removed community transition funds (focused on replacing lost property tax revenue) and employee retention; instead, the state legislature has taken up these issues. The Commission order also deferred the replacement power decision to the utility’s next resource planning process. It’s an illustration of how siloed decision-making in the electricity business makes it hard to plan for an orderly retirement of legacy power plants.

The following map provides some indication that this case study is more than a California problem for legacy power plant owners. It shows the cost of a 100% electricity supply overlaid with nuclear power plants Bloomberg has identified as having marginal economics.6 In today’s grid, with significant reserves of on-demand power plant capacity, solar and wind can entirely replace a retiring baseload power plant like Diablo Canyon.

The stunning result is that renewable replacement power is very low priced, at 3 to 4 cents per kilowatt hour or lower, in every state with a nuclear power plant operating on the margins. Replacement power from new renewables is likely cheaper than most existing generation in all but eleven states (bordered in red).7 Even in those states, the difference is less than a penny per kilowatt-hour.

As the grid shifts toward renewables, wind and solar energy alone won’t suffice to provide round-the-clock supply. But as subsequent sections of this report reveal, the past and future cost declines for storage make renewables a potent threat to existing (and planned) centralized power plants.

A Gas Plant Evaporates

In 2015, NRG Energy asked California state regulators to certify the need for a new 262-megawatt gas power plant in response to a request from Southern California Edison. The Johnson City, Calif., combustion turbine “peaking” power plant was meant to replace existing capacity from power plants that could no longer comply with new state water use rules. By early 2018, it looked like the power plant proposal was dead. What happened in those three years?

In short, a dramatic drop in the cost of storage.

Even at the time of its proposal, the Johnson City gas plant was up against low-cost renewable energy, as was the Diablo Canyon nuclear plant. This chart, from the 2015 annual cost of energy analysis by investment bank Lazard, shows that solar PV was much cheaper than a gas peaking plant like the one proposed by NRG. Peaking plants run infrequently but are used to fill in power supply during periods of high demand. Even rooftop scale projects were competitive with the proposed peaker on a cost of energy basis, but utility-scale solar electricity was half as expensive.

Given the relative costs, the state’s grid operator, CAISO, ordered an analysis of alternatives to the gas plant including distributed energy and energy storage. The report came back with dramatically negative conclusions: the cost of alternatives was as much as three times higher to fulfill the capacity need at the nearby Moorpark substation. But analysts from Greentech Media pounced on the results, noting that the cost estimates were as much as three years old, in a market that changes rapidly. Their analysis was more nuanced and much better for the alternatives to the gas peaking plant: If the upfront cost of electricity storage could hit $175 per kilowatt-hour or lower (depending on the cost of solar), the non-gas alternatives including solar would actually be the less expensive resource. The following chart illustrates:

Lower costs for both solar and storage contributed to Greentech Media’s results. In its 3rd quarter 2017 report, the Solar Energy Industries Association reported utility-scale solar costs of $1.10 per Watt or less, and costs for non-residential solar (think large rooftops) of $1.55 per Watt. The cost of solar has been falling and falling faster than the cost of gas-produced electricity. A 2017 update to the Lazard cost-of-energy illustrates.

Energy storage is also relatively inexpensive and becoming even more so. In a late 2017 update, a Bloomberg analysis priced battery packs at $209 per kilowatt-hour, less than half as expensive as the CAISO model for the Johnson City Plant.

A new study published in Nature by professors from University of California Berkeley lent more fuel to the fire, skewering prior battery price forecasts as too conservative and suggesting that by 2018 battery packs would already be inexpensive enough––well under $175 per kilowatt-hour––to affordably supplant the Johnson City gas plant. The prices below indicate the upfront cost per kilowatt-hour of capacity.

Given the new data, in October 2017, CAISO recommended a new request for proposals to allow for renewable energy and storage to bid in at more current prices. NRG has suspended its application for the plant.

The Johnson City plant may be the “canary in the gas plant” for the economic threat of “preferred resources” (renewables and storage) to replace gas peakers. In Minnesota in 2015, state regulators gave the green light to a solar project rather than a utility-proposed expansion of gas. In January 2018, the California Public Utilities Commission ordered Pacific Gas & Electric to seek storage and renewable energy replacements for three existing gas peaker plants. Combination wind or solar plus battery storage systems responding to an Xcel Energy Colorado request in early 2018 had levelized cost offers far less than $100 per megawatt-hour (although storage duration was not disclosed).  In February 2018, Bloomberg reported on another bid won by solar plus storage:

In just the latest example, First Solar Inc. won a power contract to supply Arizona’s biggest utility when electricity demand on its system typically peaks, between 3 p.m. and 8 p.m. The panel maker beat out bids from even power plants burning cheap gas by proposing to build a 65-megawatt solar farm that will, in turn, feed a 50-megawatt battery system.

Johnson City may also hint at problems for recently built gas power plants. Over 5 gigawatts of gas peakers were recently deployed in states that have, or will have soon, economical competition from solar and energy storage. Customers in California, Nevada, Arizona, and New Mexico can already access solar and storage combinations competitive with utility power prices. Regulators in two of these states, California and Arizona, have recently slowed or halted gas peaker deployment in response to these cost-competitive threats from distributed and centralized renewable energy plus storage.

The long timeframe for planning, constructing, and operating large-scale power plants doesn’t do the industry any favors. The Johnson City, Calif., plant wouldn’t have started producing electricity until 2022 and would have saddled electric customers with expenses for 40 years. Alternatives––including distributed solar, demand response, and energy storage––can be constructed in a much shorter timeframe (months, instead of years), and have been getting cheaper every year.

Pain for Utility Balance Sheets

Competition from distributed energy may also sharply reduce sales. High electricity prices drove nearly 20% of Hawaiian Electric customers to install solar arrays by late 2017. With help from public regulators, the utilities won a reduction in compensation for rooftop solar producers. But within months, third parties started offering island customers combination solar and energy storage packages capable of providing electricity cheaper than the utility offered.

With competitive solar plus storage, Hawaiian electricity companies could be reluctantly mailing “postcards from the future” about the financial challenges of accommodating customers with less expensive options.

If just 2 in 10 Hawaiian residential and commercial electricity customers exercised their choice and had solar plus storage (either by retrofitting a battery onto their existing solar or buying a bundled system) it could cause a net reduction in Hawaiian Electric Company electricity sales of nearly 950 gigawatt-hours per year, or just over 10% of total sales. At today’s electricity prices (and ignoring many other benefits of avoiding oil-based power generation) it would cost the company over $250 million per year in lost revenue (about 11% of total revenue and more than the utility’s $167 million net income for 2017).

Bigger Local Economic Returns for Communities

Distributed solar and storage not only undercut the economics of centralized utility power plants, they can boost local economies in ways utility-built power plants don’t. The failed Puente gas plant provides a powerful example.

The proposed gas peaker would have supplied 271 megawatts of peak power for an upfront cost of $250 million dollars (and millions more for fuel consumed). The cost of energy from the plant would have been above $150 per megawatt-hour, with at least half of that energy cost leaving the community to pay for imported fuel.

ILSR modeled distributed solar and storage replacement options for the Puente gas plant and found a solar and storage hybrid with a higher upfront cost but much lower lifetime cost, and substantial local economic benefits.

The key element is replacing the peak energy supply from the proposed Puente plant. To understand what is needed, the following chart from Southern California Edison illustrates their peak energy demand on a summer afternoon, shown below in green. The tiny black triangle shows the area, up to 271 megawatts, at the peak of the curve, that the Puente gas project would likely have fulfilled.

ILSR modeled three, combined strategies to meet the 271-megawatt peak: demand reduction, solar energy, and battery storage.

We assumed there were sufficient opportunities to reduced energy demand by about 11 megawatts, equivalent to 4% of the Puente capacity. This is based on ILSR’s research on peak demand opportunity and is certainly conservative (this model only factors in residential demand response, despite commercial demand response opportunities being much larger). Demand reduction was priced at $300 per kilowatt, based on California utility demand response programs.

Of the remaining 260 megawatts of capacity, solar energy can only fulfill 30 megawatts of the peak energy use during the peak hours, because south-facing panels have limited production at that time of day. So, we modeled the installation of 292 megawatts of solar using the low sun angle to provide 30 megawatts of peak-time power as well as 230 megawatts of solar energy that could be stored for later use. ILSR assumed a split of 80% non-residential solar arrays and 20% residential solar, with a weighted average solar installed cost of $1.88 per Watt ($1.60 per Watt non-residential, $3.00 per Watt residential). The total cost for this distributed solar power plant is about $550 million.

The final piece for this modeled scenario is 230 megawatts of battery storage, assumed to cost $175 per kWh, for a total cost of approximately $40 million. Given the favorable economics under California’s “Net Metering 2.0,” it’s assumed that energy storage is co-located with all non-residential solar projects (about 64 megawatts). If half of residential solar customers also opted for storage (e.g. a Tesla Powerwall), it would account for a further 11 megawatts of storage.