It’s been a tumultuous and transformative year on the grid edge.
On the technology side of things, we’ve seen continued progress — and some stumbles — on the part of utilities, energy companies and third-party providers working to integrate distributed resources.
On the policy side of things, the Trump administration’s efforts to bail out the coal industry have failed to overcome the realities of ever-cheaper renewable energy. Meanwhile, states like California, New York, Hawaii, Arizona and many others are upping their commitment to a low-carbon future.
This bigger-picture view was summed up neatly at our Wood Mackenzie Power & Renewables conference in November, where Prajit Ghosh, head of global strategy, pointed out that solar, wind and energy storage are on a cost decline path that puts them in position to beat out not just coal and nuclear power, but potentially natural-gas-fired generation as well. That’s already happening in California, where retiring nuclear plants and proposed new natural gas plants are being replaced by combinations of solar, energy storage, demand response and energy efficiency. But even in Texas, North Carolina and the fracking-gas-rich territory of mid-Atlantic grid operator PJM, “a lot of gas is being replaced by renewables. It’s a reasonable question to ask: Are we already in this new paradigm where solar, storage and wind are the default choice?”
Utility requests for proposals that incorporate more energy storage with renewables are proving out this prediction, according to Ravi Manghani, energy storage research director for Wood Mackenzie Power & Renewables. This year has seen solar-plus-storage systems coming in at merely a $6 to $7 per megawatt-hour premium over their solar-only competition, and over the next five years, falling battery prices and continued federal Investment Tax Credit support for battery-backed solar will drive down costs to ranges that are directly competitive with natural gas, he said.
That’s not to say that natural gas disappears. Bloomberg New Energy Finance sees more than 1,000 gigawatts of new peaker capacity being added globally through 2050, as the world transitions to getting two-thirds of its energy from fossil fuels to two-thirds from renewables. And, of course, this change is not happening at the same pace, with a relative handful of states and utilities are leading the charge, and most still relying on natural gas for decades to come.
But in the increasing number of states setting 100 percent clean energy or renewables targets, the future for natural gas developers is murky.
This shift from fossil fuels to renewables, from centralized to distributed, is set to upend the business of utilities, generators, and the world’s oil majors — and they’ve been responding by busily buying up stables of companies serving these emerging markets. According to Wood Mackenzie Power & Renewables analyst Elta Kolo, over the past 18 months, European energy companies such as Enel, EDF, Engie, Total, Shell, Centrica, E.ON and BP have spent about $1 billion in investments and acquisitions, from energy storage and EV charging startups to established providers like U.S. demand response leader EnerNOC.
In the United States, these types of efforts have seen mixed success, with some such as Duke Energy and Southern Company building ongoing DER business portfolios, and others like Edison Energy and GE’s Current taking a different path. Much of the M&A activity has been driven by the trading of hands of renewables portfolios, diversification into regulated and unregulated lines of business, and potential acquisition or private equity funding targets can be found in the portfolios of utility investment consortiums like Energy Impact Partners and Energize Ventures.
But uncertainties in power markets have made the trajectory of the transition even more opaque, Ghosh said. With conflicts between renewables and traditional generators now taking a front-and-center role in federal energy policy, now is the time for the industry to weigh in and make sure renewables aren’t stuck using rules and regulations built for a conventional supply that doesn’t include them, he said.
Federal policy: Steps backward, steps forward
Arguably the most overhyped energy story of the year has been the Trump administration’s failed attempts to use the power of the DOE and FERC to bail out money-losing coal and nuclear power plants, at a projected cost of tens of billions of dollars to U.S. consumers.
These efforts have all been failures, from FERC’s unanimous rejection of Energy Secretary Rick Perry’s notorious notice of public rulemaking (NOPR), to the apparent shelving of a leaked plan to use DOE’s wartime emergency powers to force utilities to buy power from so-called “fuel secure” power plants. And while the Trump administration was able to confirm Bernard McNamee, one of the architects of DOE’s coal-nuclear bailout plan, to an open seat on FERC, it’s not clear how his single vote might overturn the agency’s otherwise unanimous rejection of his past work.
But beneath the sound and fury of this debate, FERC and the interstate grid operators it oversees took a number of steps this year that could threaten the role of renewable energy, demand response and other cleaner alternatives to traditional power plants.
The most notable was FERC’s 3-to-2 vote in July rejecting mid-Atlantic grid operator PJM’s proposed changes to its capacity market, the country’s biggest, and demanding a rewrite that could radically change how state-supported renewables or distributed energy resources play in that market. Clean energy groups hadn’t been happy about PJM’s original plan, but have challenged FERC’s decision on the grounds that it pushes federal authority too far into state’s energy policies by using the Minimum Offer Price Rule (MOPR) — a market mechanism designed to prevent market gaming by utilities that both own power plants and buy capacity — to set a certain minimum price for resources, no matter their actual cost to compete.
ISO New England has also come under fire for its use of the MOPR to price capacity, another proposal that won a bare 3-to-2 majority to pass FERC, with Democratic Commissioners Richard Glick and Cheryl LaFleur decrying the policy in terms similar to those used in their dissents to the PJM decision. And McNamee’s replacement of Republican Commissioner Ron Powelson is likely to maintain the same narrow majority on future decisions on this issue.
Counterbalancing these troubling developments have been some important points of progress at FERC and the country’s grid operators, chief among them the progress on FERC Order 841, which has tasked grid operators to integrate energy storage — namely, batteries — into their energy, capacity and ancillary services markets.
Grid operators filed their Order 841 compliance proposals earlier this month. The Energy Storage Association has already come out with its critiques, including its ongoing opposition to PJM’s10-hour duration requirement for participation in capacity markets, as well as several parts of ISO New England and New York ISO’s plans. Expect this to be the big policy battle at FERC in 2019.
There’s also one outcome of DOE’s failed NOPR effort that’s now an integral part of FERC’s future plans — its docket on grid resilience, which has pushed every grid operator to assess and improve their capabilities to reduce the frequency, intensity and duration of the storm-caused, distribution-level disruptions that make up the vast majority of outages in the U.S. It also includes preparation for natural disasters like hurricanes, fires and floods, or manmade disasters like sabotage or cyberattacks.
That’s important, because natural disasters are arguably the second-biggest grid edge story of 2018. In California, the deadly wildfires from the last two years have pushed Pacific Gas & Electric to the brink of bankruptcy, prompting state lawmakers and regulators to enact a long list of reforms to contain the risk of power lines.
Puerto Rico’s post-Hurricane Maria energy crisis pushed its utility into chaos and compelled policymakers to consider distributed renewables as a viable alternative to rebuilding what was destroyed in the storm. And hurricanes and flooding on the Gulf Coast and Eastern Seaboard have forced the U.S. military to prepare for even more catastrophic inundations as climate change leads to rising sea levels.
State policy developments of 2018
In the absence of a supportive federal government, the lion’s share of policy driving renewable integration, technology modernization and customer energy came at the state level in 2018 — and California was the standout.
Most notable was the passage of SB 100, a first-of-its-kind commitment to 100 percent zero-carbon energy by 2040 across the energy, transportation and built environment, and the enormous implications behind attaining such a goal. At the same time, mistrust of the federal government’s role in energy policy helped defeat a bill that would have authorized California to create a greater Western U.S. grid authority, leaving state policymakers to consider other alternatives to better integrate the trading and sharing of clean energy across the region.
The most contentious legislation of the year, however, was the wildfire legislative package to protect Pacific Gas & Electric from possible bankruptcy if it’s found liable for damages in this and last year’s deadly wildfires. Along with measures to give the utility tools to cover the multibillion-dollar liabilities it may face, state lawmakers and regulators have also launched inquiries into PG&E’s safety practices and corporate structure, as well as the use of controlled power outages to prevent future fires.
Amidst all of this high-profile energy policymaking, California’s distribution resources plan and integration of distributed energy resources proceedings also took some important steps forward, including the first identification of non-wires alternatives, or in CPUC parlance, distribution deferral opportunities). But its flagship DER-energy market integration pilot, the Demand Response Auction Mechanism, was put on hold by the California Public Utilities Commission to investigate the details of the hundreds of megawatts' worth of DER capacity procured by more than a dozen third-party providers over its three years in operation.
New York also took important steps forward, with the creation of the country’s largest energy storage mandate, its gigawatt-scale offshore wind power plans, and continued progress on its Reforming the Energy Vision initiative to remake its energy markets and utility practices to integrate DERs at scale. In a crucial set of filings this summer, New York’s investor-owned utilities filed their Distributed System Integration Plans, revealing where they stand on creating the grid, IT and customer systems needed to measure and manage distributed energy resources at scale, and where they’re headed in the coming years.
California, New York and Hawaii haven’t had a lot of company from other states seeking to remake their energy regulations for a distributed energy future, until this year.
In September, Nevada became the fourth state to officially launch a proceeding to ask its biggest investor-owned utility, NV Energy, delve into its medium- and low-voltage distribution grid to discover the hosting capacity, grid needs and potential DER impact and values of each circuit and feeder line across its 1.3-million-customer territory. And Minnesota utility regulators also approved an Integrated Distribution Planning Requirements framework for its biggest utility, Xcel Energy, containing similar distribution grid visibility and forecasting for its 1.3 million customers.
Other state actions of note include Massachusetts’ energy storage mandate and grid modernization rulings, and Illinois’ opening of a proceeding to create a “microgrid as a service” tariff. And Duke Energy’s 15-year integrated resource plans call for deploying about 300 megawatts of energy storage across its service territories, an unusually aggressive stance for a regulated utility, but one backed by Duke’s experience in batteries across its regulated and competitive businesses.
On the other side of the state policy coin, it’s important to highlight that a number of regulators have been pushing back against utility rate cases and integrated resource plans that fail to account for the shift toward cheaper renewables and higher demands for grid resilience.
In May, Massachusetts regulators denied the state’s utilities’ advanced metering infrastructure plans, saying they haven’t proven their cost-effectiveness as compared to broader grid modernization spending it did approve. This summer, North Carolina regulators denied Duke’s multibillion-dollar “grid rider” plan for spending too much on what could be considered traditional infrastructure such as undergrounding circuits, while allowing it to continue its smart metering plans. And this month, Virginia regulators told Dominion Energy to redo its Integrated Resource Plan for 2019 to 2033, which has been criticized for relying too much on new natural-gas peaker plants and failing to consider energy storage as an alternative.
The behind-the-meter universe: Solar-plus-storage, EVs and the voice-connected home
Julian Spector has already covered the highlights of the energy storage industry in 2018, including FERC Order 841, the boom in solar-plus-storage systems, and Tesla’s struggles to maintain its lead in the market against solar competitors like Sunrun or storage competitors like sonnen. But it’s important to highlight that, even when they’re not explicitly tied to balancing solar or wind power, batteries are increasingly being deployed as alternatives to the traditional generation assets that would be called upon to manage the systemwide effects of this selfsame renewable energy growth.
That’s certainly true for PG&E’s record-breaking 567.5-megawatt/2,270-megawatt-hour Moss Landing battery project, meant to help replace the need for buying power at a premium from two gas-fired power plants in Santa Clara County. It’s also set to be true for California’s Self-Generation Incentive Program, which is in the midst of overhauling its methods of calculating the greenhouse gas impacts of the behind-the-meter battery projects it funds, and which won a five-year, roughly $800 million extension in this year’s legislative session.
Indeed, solar-plus-storage has become a leading source of overall energy storage deployments, driven by state policies that either incentivize the combination, as California and Massachusetts do, or create disincentives for not storing self-generated power, as in Hawaii and Australia. Interestingly enough, New England has now emerged as a key region to watch for solar-storage deployments at scale, with Vermont’s Green Mountain Power rolling out more than 500 Tesla Powerwalls to customers so far, and New Hampshire’s Liberty Utilities reaching a settlement last month to proceed with a 500-Powerwall pilot of its own.
But as Ben Kellison, grid edge research director at Wood Mackenzie Power & Renewables, pointed out at our Grid Edge Innovation Summit in June, this behind-the-meter energy storage capacity is still a tiny sliver of the broader “flexibility potential” of far more prosaic and less expensive grid edge assets. The roughly 20 million two-way communicating smart thermostats deployed across the country today, for example, could provide more than 8 gigawatts of flexible capacity, even using conservative estimates of their ability to shift peak air conditioning loads — and this resource can be tapped from existing smart thermostats, as Southern California Edison and Nest proved in their 50-megawatt response to Aliso Canyon last year.
The main challenge for utilities has always been to get customers to sign up for these home automation offers. But the rise of voice-activated and -controlled devices like Amazon’s Alexa and Google Home have fundamentally changed their approach to that market. Wood Mackenzie Power & Renewables estimates that 65 million homes in the U.S. will own at least one standalone voice assistant device by 2023, and that 48 million households will consider them the brain of a smart home, controlling multiple devices like webcams, smart door locks, networked light bulbs, smart thermostats, and the like.
And while home security, entertainment, shopping and other services may be the chief driver for Amazon and Google, they’ve also formed partnerships with utilities and smart thermostat technology providers, rolling out initial trials of voice-activated home energy controls, such as BC Hydro’s partnership with Ecotagious and Indiana & Michigan Power’s partnership with Tendril and Google.
Electric vehicles are an increasingly important part of this behind-the-meter energy mix, and 2018 has been a big year for EV charging infrastructure development. As California continued to lead the country in EV sales, it also led in utility-funded charging deployments, with charging plans totaling more than $750 million approved by the CPUC in May. It also saw one of the first EV charging networks bid into wholesale energy markets, and a $240 million venture capital investment for home-state charging infrastructure startup ChargePoint.
Other companies involved in this behind-the-meter energy management and optimization field that won funding in 2018 include Bidgely, Stem, AutoGrid and OhmConnect, while Tendril saw its VC investors bought out by a private equity firm, and NRG Energy spun out its Station A software platform to manage distributed clean energy resource deployment and optimization at commercial and industrial buildings
VPPs, microgrids, DERMS and non-wires alternatives
Integrating everything we’ve been talking about is the subject of this final portion of our roundup — technologies that can monitor, manage, control and forecast the interoperation of all of these disparate DERs. When these aggregations are capable of islanding from the grid at large and keeping themselves running during an outage, they’re called microgrids. When they’re operated as part of a running grid, they’re usually called virtual power plants, as with Australia utility AGL’s 1,000-home solar-storage project (although the Rocky Mountain Institute prefers the term “clean energy portfolios” to describe the concept).
When DERs are being aggregated with the specific purpose of deferring or avoiding more traditional grid upgrades, they’re called non-wires alternatives, or NWAs — a term that includes a host of legacy energy-efficiency projects, but also the latest DER combinations. We’ve closely covered New York's and California’s efforts on this front, but the concept is also being extended to other states, such as with Arizona Public Service and AES Energy Storage’s Punkin Center battery project.
And when all of these assets are being coordinated alongside a utility’s distribution grid operations and broader energy market interaction, they’re called a distributed energy resource management system, or DERMS. The DERMS moniker can be used to describe demand response platforms that don’t have much integration to the grid, or advanced distribution management system capabilities that don’t have much connection to behind-the-meter DERs. But according to Wood Mackenzie Power & Renewables research, no utility has yet deployed a true “enterprise DERMS” platform that incorporates all levels of this integration challenge.
But many of the most notable DER integration projects underway in the country are aimed at delivering such a system. In California, Southern California Edison saw its 125-megawatt Preferred Resources Pilot, an important part of its broader DER integration efforts, first threatened and then rescued by the CPUC, giving it a chance to collect more third-party solar, storage and demand response to manage the grid challenges caused by the closure of the San Onofre nuclear power plant. We’ve also covered PG&E’s work on solar-battery-smart inverter integration in its San Jose and Fresno County projects, which have helped guide similar work underway in other states.
Importantly, these projects are tied into California’s leading role in smart inverters. Phase 1 autonomous features have been required for all new California solar systems since September 2017, and two-way communications capabilities will be required of all new solar installations starting in February 2019. The potential for more advanced features, like tapping fleets of rooftop solar systems for real-time reactive power balancing, are part of utility plans, and on the roadmap of inverter makers like SolarEdge.
Arizona Public Service, which has also done significant work on smart inverters through its Solar Partner Program, has also recently launched a pilot project to test EnergyHub’s DERMS platform to control a host of grid resources, including connected thermostats, water heaters, battery energy storage and solar inverters.
