Natural-gas peaker plants may soon be under threat in a very real way.
“I can’t see a reason why we should ever build a gas peaker again in the U.S. after, say, 2025,” said Shayle Kann, a senior adviser to GTM Research and Wood Mackenzie, speaking at Greentech Media’s Energy Storage Summit. “If you think about how energystoragestarts to take over the world, peaking is kind of your first big market.”
The data shows a very clear trend.
Today, lithium-ion batteries are competitive with natural-gas peaker plants in select cases. In a few years, competition will intensify across the country. And with costs only headed downward, Kann called overtaking peakers “a sweet spot” for battery dominance across the U.S.
“Peakers are expensive. Energy storage should be really good at displacing a peaker, and also you can use multiple values,” said Kann. “But not even incorporating the multiple values, energy storage is starting to get very close to the point where it can just beat a gas peaker, head-to-head, purely on an economic basis. A decade from now, energy storage always wins.”
Over the next 10 years, the U.S. needs to add 20 gigawatts of peaking capacity to its grid. Over half of that capacity will come on-line in the latter part of the decade: 7,440 megawatts between 2018 to 2020 compared to 12,645 megawatts between 2023 and 2027. That gives energy storage more time to build an economic advantage.
If technology changes faster than expected, the economic argument for storage becomes more compelling.
While the U.S. market includes less than a gigawatt of storage today, it will replace a third of peakers under a base-case scenario in the next decade. If the market grows faster, storage may replace nearly half of those 20 gigawatts of peaking capacity.
“Time and time again in adjacent sectors like solar, and even in energy storage, technology costs have the capacity to fall faster than almost anybody expects,” said Kann. “Including us.”
These changes are catching regulators off guard. The most recent example: the California Energy Commission’s decision to reconsider a gas peaking plant planned for Oxnard.
The California Independent System Operator found the peaker plant would be more expensive than storage — in an analysis that used prices from 2014. After GTM pointed out the discrepancies between those costs and current industry pricing, NRG Energy, the plant’s developer, suspended its construction application.
That project isn’t completely dead, but the suspension leaves an opening for clean alternatives to meet the capacity need instead.
In South Australia, the need for grid stability and renewables integration prompted the installation of a 100-megawatt Tesla battery in record time. Tesla brought that battery on-line last month.
Gas peakers will still get developed in South Australia. But Tesla’s battery could be a sign of things to come.
A report on the two projects from Wood Mackenzie and GTM Research found that batteries — both alone or paired with renewables — are not yet competitive with gas peaking plants in that region. But they’re on their way. In 2025, analysts project that standalone and renewable-hybrid batteries will beat out open-cycle gas turbine plants for meeting peak load.
Every year, said Kann, storage is closing in on that economic “sweet spot” that will allow it to beat out peakers.
California Wildfires Spark Utility Investigations and New Regulations
How much responsibility should utilities bear for fire prevention, and are distributed energy resources part of a grid resilience solution?
Last week, the Thomas Fire — the largest and most destructive fire currently raging in the region — grew to 250,000 acres and claimed the life of a young fire engineer. This week, the blaze continues to spread across Ventura and Santa Barbara counties despite Herculean efforts to contain it.
Governor Jerry Brown called this “the new normal,” speaking at The New York Times’ ClimateTECH conference in San Francisco late last month. “California is burning up,” he said. “The fire season is not a couple of months in the summer; it’s virtually year-round.”
The risk of wildfires, enhanced by the higher temperatures and erratic weather brought by climate change, increases the urgency for California, as well as other state and national actors, to mitigate carbon emissions, according to Brown. Adapting to this riskier future is essential too — especially for California’s electric utilities, which may bear responsibility for fueling the flames.
Southern California Edison reported last week that authorities are investigating the utility’s equipment as a possible source of the Thomas fire. “The causes of the wildfires are being investigated by Cal Fire, other fire agencies and the California Public Utilities Commission,” SoCal Edison said in the press release.
“The investigations now include locations beyond those identified last week as the apparent origin of these fires. SCE believes the investigations now include the possible role of its facilities,” the statement continues. “SCE continues to cooperate with the investigations. The wildfire investigations may take a considerable amount of time to complete. SCE will provide updated information as circumstances warrant.”
SCE isn’t the only utility on the hook. Pacific Gas and Electric Co. is part of a separate investigation by Cal Fire after blazes ripped through the Bay Area earlier this year, destroying California’s wine country and claiming dozens of lives.
Then on November 30, the CPUC issued a landmark decision denying San Diego Gas & Electric’s request to recover costs from the 2007 Southern California wildfires. Regulators determined that SDG&E “did not responsibly operate its facilities linked to the wildfires, which thereby prohibits the utility from recovering those costs in rates.”
SDG&E sought to recover $379 million, which represents a portion of the $2.4 billion in costs and legal fees the utility incurred to resolve third-party damage claims from the Witch, Guejito and Rice wildfires. In all three cases, SDG&E was found guilty of imprudent management.
“There is no dispute that SDG&E facilities caused these fires,” said Commissioner Liane Randolph, in a statement. “The question we had to analyze was whether the costs related to the fires should be paid by customers or shareholders. The CPUC undertook a careful review of the facts of each fire and determined in each case that customers should not have to bear these costs.”
PG&E CEO Geisha Williams said the San Diego case presents a major challenge to utilities in an era of climate change.
“I’m disappointed,” she said of the decision, speaking at ClimateTECH on November 30. “That means San Diego Gas & Electric in this particular case will have to be able to cover those costs. If this was a once-in-20-years event, if this was a once-in-a-lifetime event, I might say, ‘Well, you know, go to it, San Diego Gas & Electric.’ But if these wildfires become the new normal, if these wildfires become endemic and part of the effects of climate change day in and day out, I don’t think it’s sustainable for utilities to afford that on a long-term basis.”
For investor-owned utilities, the inability to recover costs from a natural disaster presents a fundamental business risk, said Williams, because the equity firms, hedge funds and mom-and-pop shops these utilities rely on have a choice in where they put their money.
“How do we make sure we can continue to attract investment here in California at a time when we are so focused on continuing to drive improvements to our grid, continuing to integrate more and more renewables, and continuing this push toward electrification of really all things, but in particular the transportation sector?” she said. “How can we continue to attract smart investment if there’s a fear in the investment community that…there might be an undue risk associated with their ability to recover a fair rate of return?”
It’s unfair to put the burden squarely on energy companies for this reason, she said — especially because fires are a societal issue. It’s an issue that involves better forest management, more resources and training for the first-responder community, and possible changes to building codes and land-use planning. Utilities also need to come up with new ways to prevent fires and ensure grid resilience.
“As a utility, I’m thinking, ‘What do I need to do different?’” said Williams. “Do I need to go out with steel poles instead of wood poles? Does it make sense to underground certain sections? Do we have to expand our right-of-way for clearing?”
“So it’s a great time for leadership. It’s time for California to take a step back and say: What are the right solutions? What do we need to do to make sure that we’re doing everything possible to prevent and mitigate the impacts of wildfires and other climate change issues?” she added.
Last Thursday, the CPUC adopted new fire-safety regulations designed to do just that. The decision requires the state’s electric utilities to increase clearances between vegetation and power lines, conduct annual patrol inspections of overhead distribution facilities, prepare fire prevention plans, and take other steps to mitigate fires in high-risk zones. It also establishes a High Fire-Threat District map to inform where these actions are needed most.
“This new policy includes significant new fire-prevention rules for utility poles and wires, including major new rules for vegetation management,” said CPUC President Michael Picker. “The map includes a broader definition of fire threat and also shows how dramatically climate impacts are increasing fire risks — land that is covered in the elevated, high and tree mortality fire hazard areas has grown from 31,000 square miles to 70,000 square miles. That’s 44 percent of California’s total land area.”
Responding to this risk isn’t limited to utilities. Amid the ever-growing threat of climate change and the wildfires it provokes, there’s a parallel conversation taking place on how new deployments of distributed energy resources and other grid edge technologies can aid in fire prevention and disaster resilience.
For instance, as fires tore through Northern California, the islanded microgrid at Stone Edge Farm near Sonoma operated independently for 10 days as the flames — which may have been caused by power line neglect and deferred maintenance — knocked out power nearby.
The Stone Edge microgrid features 300 kilowatts of rooftop solar, a microturbine, hydrogen fuel cells and battery storage with real-time monitoring and control, which successfully enabled the system to go into island mode. SimpliPhi Power’s non-toxic batteries were credited for reducing the microgrid’s risk of catching fire, and other takeaways are now informing how the farm can serve as a community shelter in future. Examples such as this offer valuable insights on how energy stakeholders in California, and other parts of the country, can prepare for and manage disasters.
Coincidentally, while SimpliPhi batteries kept Stone Edge Farm in operation up north, SimpliPhi employees recently had to evacuate their headquarters and homes in Ojai, California farther south as the Thomas fire swept through the area. CEO Catherine Von Burg wrote a note to the company’s supporters last week stating that the fires have only strengthened its resolve to deliver robust distributed energy solutions.
“Our experience has only served to renew our commitment to making sure that every person worldwide has the ability to generate his or her own power, store it, and take it with them, on their terms,” she said. “Needless to say, we’re returning to the office with a…greater passion to effect change and create energy security, even in the face of catastrophic fires and ensuing power outages, than ever before.”
The California Public Utilities Commission recently released its annual renewables portfolio standard report showing that large investor-owned utilities have already executed the renewable electricity contracts necessary to exceed their 33 percent RPS requirement for 2020 — and are on track to meet the 2030 RPS requirement of 50 percent renewables a full 10 years early.
Building on this momentum, Governor Jerry Brown recently suggested that the state could achieve a 100 percent renewables energy mix before mid-century.
“We will be at 50 percent by the more restricted measures of renewable energy — that’s basically solar, geothermal, wind and some biofuel — probably in 2025,” he said, speaking at The New York Times’ ClimateTECH conference in San Francisco last month. Reaching “100 percent in 2040 is not out of the question at all.”
But is that target truly within reach?
“California’s energy policies are like driving a car with no seatbelt”
Setting aside the debate on whether or not 100 percent renewables is the optimal way to decarbonize the grid, there a number of very real challenges tied to executing on that goal that are worth addressing. For one thing, California’s investor-owned utilities may not be as close to their renewable energy goals as it may seem. Also, as Governor Brown pointed out in his talk, hitting 100 percent renewables hinges on two big unknowns: “It’ll depend on storage. It’ll depend on a regional grid,” he said.
Energy storage and regionalization are indeed major question marks. Without advancements on both fronts, California’s aspiration to achieve 100 percent renewable electricity could remain a pipe dream.
If the renewable energy transition isn’t managed well, it could create a disaster scenario, according to Gary Ackerman, executive director of the Western Power Trading Forum, a broad-based membership organization dedicated to encouraging competition in Western states’ electric markets.
“The ability to balance the grid, which is a moment-by-moment function of the grid operator, becomes more challenging as you add more renewable energy,” he said. “It’s undeniable you have to provide a certain frequency within a well-defined bandwidth. When renewable energy comes offline, hence the definition of a variable resource, it presents more challenges to people in the control center. “
There can be up to a 13,000-megawatt ramp in demand in California in the evenings, as solar generation falls off the system and people power up their homes after work, Ackerman pointed out. “You just need one transmission line to trip or generation station to go offline while making that ramp and everything becomes super-critical.”
“You might not see renewables as an issue until then, because people will say the lights haven’t gone out,” he added. “But that’s like saying, ‘I didn’t wear a seatbelt and I didn’t get in an accident.’ California’s energy policies are like driving a car with no seatbelt. You’re taking enormous risks that you won’t realize until it’s too late.”
The need for a lot of innovation
Ackerman is not anti-renewables. His organization includes major wind and solar developers including EDF Renewable Energy, Recurrent Energy and NextEra Energy Resources. And he believes that California utilities will be able to reach 50 percent renewables “easily.”
“The real question is [whether] the California ISO can manage a grid like that,” Ackerman said.
Most Californians want the state’s electricity grid to be totally renewable. According to a poll conducted earlier this year by the Public Policy Institute of California, 76 percent of adults and 71 percent of likely voters — including 81 percent of Democrats and 53 percent of Republicans — approve of a 100 percent renewable energy requirement. The question facing policymakers, advocates and industry leaders now is how to fit all of the pieces together to make 100 percent possible.
Natural-gas peaker plants have played a key role to date in enabling CAISO to manage ever-higher levels of intermittent renewable energy generation. Energy storage has and will continue to play a pivotal role as well. But the technology is not where it needs to be to serve as the backbone of the grid, as Brown alluded to.
“California can integrate renewable energy [today] without real challenges because the grid is overbuilt,” said Wade Schauer, research director for the Americas power and renewables market at Wood Mackenzie, referring to the natural-gas plants that are already on the grid. “To get to 100 percent, you have to replace that one for one with storage. Not just any storage, multi-day storage — and there aren’t batteries out there doing that now. There’s going to have to be a lot of innovation, and that’s not going to be cheap.”
Anything can happen in 20 years, Schauer added — who knows what technology will be available in 2040? However, he is certain that if California tries to achieve 100 percent renewables too quickly, “it’s going to be very painful.”
Just getting to 50 percent renewables in California is going to require some major investments. According to a Wood Mackenzie analysis, under a 50 percent RPS with solar making up the majority of incremental additions (43 gigawatts of incremental solar and 2 gigawatts of incremental wind), an additional 10 gigawatts of flexible capacity — a combination of thermal generators, hydropower, demand response and energy storage resources — would need to be procured by 2030 in order to meet the system’s ramping needs during the shoulder months.
Even taking a more balanced approach between solar and wind would increase flexible capacity needs significantly in the longer term.
Meanwhile, the grid will have less gas to rely on, because California’s environmental regulations make natural-gas peakers an unattractive option in the long run. Wood Mackenzie projects the state’s once-through cooling requirements for gas plants will reduce California’s effective flexible capacity by nearly 9 gigawatts before 2030. With renewable energy curtailment increasing, and with the ongoing need to maintain reliability and affordability for customers, the role of grid edge and energy storage technologies will be critical.
And according to some, a regional grid may be essential.
Brown pledges to pass regional grid legislation in 2018
California is already partnered with eight Western states in the Energy Imbalance Market (EIM), where energy is balanced in real time. An integrated Western regional grid would stretch from western Canada to Baja California in Mexico, covering 14 U.S. states and a total of 38 balancing area authorities. And, in contrast to the EIM, it would balance energy supply and demand in a day-ahead market that matches electricity to the projected load over 24 hours. By coordinating power flows across a larger footprint, an integrated regional grid would help to ensure that emissions-free energy is being dispatched efficiently.
“A regional grid is important, because right now with our 30 percent renewable energy [mix], there are many hours on moderately warm days with bright sun where we’re dumping huge amounts of electricity, because we have nowhere to use it,” said Brown. “When we have a bunch of electric cars, we can charge the cars. When we have batteries, we can charge the batteries. But we don’t have that.”
“Renewable energy is not going to really make sense beyond 30 or 40 percent without a regional grid,” he said.
The political challenges tied to reaching 100 percent renewables in California, which include regionalization, are arguably going to be more difficult to overcome than the technical ones.
California lawmakers tried passing a mandate to create a 100 percent renewable grid by 2045 and attempted to remake the state’s grid into a regional system. But those efforts failed, largely because labor unions were worried about losing local jobs in California as the system expands, and because environmental groups were concerned that a regional grid would cause California to lose control of its energy mix.
Brown acknowledged there are a lot of politics involved in the regional grid debate. “That kind of vulgar politics, which I’m so attracted to,” he joked.
“We will get it done,” he added, with sincerity. “There are just…a couple of deals that need to be made.”
The politics are “impossible”
There’s a lot of tension around giving up control of California’s grid through CAISO, and sharing the decision-making power with other regional players, like the Rocky Mountain states utility PacifiCorp. But Brown seemed confident he could allay those concerns.
“The people who sell solar have one view. The utilities have a view. The people in the unions who install [grid technology] have a view. Some of the purists have a view that if we have a regional grid with…coal people, they’ll contaminate us. So we have a few things to overcome,” he said. “I’d say that we have a good chance of doing it. If we don’t do it this year, I’m sure it’ll come through the next year.”
But there’s a problem, said Ackerman. Even if Californians agree to pursue a regional grid, who says other states will want to participate?
“I’m not criticizing Governor Brown. If there’s an adult in the room, he’s it. He knows what he’s talking about. [He] recognizes there is this reliability threat and the best way to try and solve it is to regionalize the California grid,” he said. “The problem is that no one in the rest of the West wants California’s energy, because their energy is already cheap. Plus, they’re not going to integrate with California because of the politics of California.”
“Overcoming the political friction is almost impossible,” Ackerman said.
Tony Brunello, president and founder of More Than Smart, a nonprofit that supports greater integration of distributed energy resources, is in favor of a unified grid linking California with other states in the West. But he believes there needs to be greater focus on near-term wins, starting with California, Washington and Oregon coordinating their resource-planning projections to take advantage of cross-border benefits.
“Why are we not spending more time discussing near-term wins with equal passion, like selling California’s oversupply of natural-gas electricity generation to Oregon and Washington instead of them building new natural-gas plants facilities,” he said. “Or using Northwest hydropower in California as a flexible resource that can be used when we need it most.”
“In essence, we need to get a few base hits while we also go for the multistate regional grid home run,” Brunello said.
Near-term wins could be key as stakeholders work through other complex challenges tied to a larger expansion. For instance, creating a truly regional grid that’s open to all utilities west of the Rockies will require building a lot of new transmission lines (although not everyone agrees about this), and those projects can take up to 20 years to complete, said Schauer.
Then there’s the issue of other states boosting their renewable energy penetration at the same time as California, he said. If surrounding states continue to add solar because it’s cost-competitive, then the steep evening ramp, known as the duck curve, will hit the entire regional grid.
“Neighboring states are ramping up solar as well over next few years. So California’s ability to lean on those states during over-production hours will go away,” said Schauer. “California won’t be able to sell its surplus solar to Arizona because they also have a surplus problem.”
A regional grid “sounds good on paper, but actually making it happen will be a challenge,” he said, which increases the pressure to deploy advanced energy storage and other grid tech.
The added complexity of community choice aggregation
In the thick of California’s 100 percent renewable electricity debate, there is the rise of community-choice aggregators, or CCAs, where cities or counties ditch their utility to purchase their own energy generation directly from independent suppliers.
Between 2010 and 2015, two CCAs formed serving approximately 135,000 customer accounts statewide. Between 2016 and 2017, CCA formation accelerated and 12 more communities launched or submitted CCA implementation plans. The CPUC estimates that up to 85 percent of California’s retail load could be served by CCAs or direct access providers by 2025.
CCAs add complexity to reaching a 100 percent renewables for a few reasons. First of all, CCAs have been wary of regionalizing the Western grid. Regionalization could result in higher exit fees to form CCAs and longer-term energy contracts between utilities could make CCA energy procurement tricky, among other things.
The rise of CCAs also obscures how much progress investor-owned utilities (IOUs) have made in reaching their renewable energy mandates and makes resource procurement more complex.
The CPUC’s latest RPS report found that Pacific Gas & Electric’s electricity mix is 32.9 percent renewable, Southern California Edison’s is 28.2 percent renewable and San Diego Gas & Electric’s is 43.5 percent renewable. According to Schauer, the IOUs have made so much progress toward their goals because 1) they rushed to take advantage of federal tax credits for solar and wind before those expire; 2) the utilities procured renewables assuming a certain level of retail load that has failed to materialize or that they are no longer responsible for serving; and 3) this has generated a surplus of renewable energy credits (RECs) above RPS requirements for the past several years. Those surplus RECs can be banked for use in future years when there would otherwise be a RPS deficit, he explained. Pacific Gas & Electric has accumulated a REC bank large enough to meet its renewable requirements through 2030 without any new renewable procurement.
Point 2 is where the CCAs come in.
“IOUs are losing customer load to CCAs, but still have all of the renewable energy contracts they procured to serve those customers,” Schauer said. “That load didn’t go away, but now the CCAs will need to either buy the surplus RECs from the IOUs and/or contract with new renewable resources. Meanwhile, the IOUs can claim they are meeting future-year renewable goals that in reality are much lower targets than they once were in absolute terms.”
This point is fleshed out in the CPUC’s RPS report, which states that the three large IOUs are positioned to meet the 50 percent mandate a decade early thanks to “excess procurement” through the REC banking provisions. “The IOUs’ excess procurement is based on the current forecast of bundled electricity load and additional CCA departures will result in increased amounts of excess,” the report states.
Because of that departing load, PG&E projected RPS energy requirements (in terawatt-hours) barely grow from today’s levels, even though the RPS requirements increase from 33 percent in 2020 to 50 percent in 2030. Falling electricity sales combined with the increased renewables is squeezing conventional generation out of the system, which is why PG&E decided to close the Diablo Canyon nuclear plant.
While IOUs cope with retirements, CCAs will need to procure additional renewable energy resources to ensure they comply with the RPS. Plus, most California CCAs have their own longer-term goals to reach 100 percent renewables for all customers. The cumulative volume of utility-scale PV driven by CCAs in development or operating is currently 1.2 gigawatts, according to GTM Research.
As this transition takes place, it creates an issue around resource planning.
A recent CPUC report questions the commission’s authority over CCAs, which has “somewhat reduced the most optimal procurement and coordination of resources and utilization,” staff reported. The shift to localized decision-making adds complexity to system-level procurement plans, which could make it harder — or at least more expensive — to meet a 100 percent renewable energy target statewide.
To help get all players on the same page, the CPUC recently issued a proposal that, if adopted at the commission’s meeting on Jan. 11, 2018, would require CCAs to fully comply with CPUC Resource Adequacy rules before they can start serving customers. The move is designed to ensure sufficient energy generation is under contract, by the appropriate utility, to meet peak demand for the coming year.
“Community choice aggregator participation in the Resource Adequacy program ensures that the community choice aggregator is procuring enough energy for its customers while relieving the customer’s prior utility of that responsibility,” a CPUC release states. “This helps prevent over-procurement or under-procurement and cost-shifting.”
Uncertainty surrounding the expansion of CCAs, regionalization and the pace of energy storage technology development will surely persist into 2018 — which is Brown’s last year in office. Amid all of this, getting to 100 percent renewables by 2040 is not “out of the question,” as Brown said — but it raises a lot of them.
Not surprisingly, the challenges public utilities commissions are grappling with are wide-ranging and diverse: utility business model reforms, distribution system planning, grid modernization, rate-design changes, large investments in renewables, transportation electrification, energystorage wholesale market changes, and data access, to name a few. Here is a roundup of the top 10 matters before PUCs in 2017.
1. Rewarding utilities for performance against policy objectives
In 2017, we have seen an uptick in conversations about the suitability of the traditional cost-of-service regulatory model as the energy landscape changes. Many states have already begun to move toward a system that better reflects new market conditions, allows utilities to take advantage of the growing service economy, and rewards for performance against established goals. At AEE, we have been a part of the conversation (see our 21st century electricity system issue briefs on performance-based regulation and optimizing capital and service expenditures for more information) to develop new utility business models that better meet the changing expectations of consumers and society.
In January, after a seven-month investigation, the Public Utility Commission of Texas issued a report to the state legislature on alternative ratemaking mechanisms which, among other things, recommended the adoption of performance-based regulation (PBR). In March, the New Mexico Public Regulation Commission initiated an investigation into its ratemaking policies, considering new financial incentives and re-examining how regulated assets should be defined and their costs recovered. Also in March, the Pennsylvania Public Utility Commission pushed forward in its alternative ratemaking investigation, asking for feedback on experiences with different methodologies, including PBR (AEE Institute filed comments here).
In April, staff of the Illinois Commerce Commission filed a report recommending that the commission initiate a rulemaking (which opened in December) to clarify the accounting rules around cloud-based solutions, particularly around whether utilities can earn a return on them. New York and the joint utilities have been engrossed in a process to implement their earning adjustment mechanisms (EAMs), with the utilities proposing a framework in May.
Over the past year, the New Hampshire Public Utilities Commission has been investigating utility cost recovery and financial incentives, and in March, a working group submitted its final report to the commission, recommending, among other things, implementation of PBR. In June, the Vermont Public Utility Commission opened an investigation and has held three workshops to review emerging trends in the utility sector and to examine alternative regulation approaches.
In August, staff of the Michigan Public Service Commission issued a report with recommendations on a new regulatory framework that allows demand response (DR) investments to be recoverable with a rate of return. In addition, the MPSC held a kickoff meeting on July 24 to begin a broader PBR study, with a report due to the state legislature in April 2018. In September, the Minnesota Public Utilities Commission opened an investigation to identify and develop performance metrics and potentially financial incentives for the largest utility in Minnesota, Xcel Energy.
In November, National Grid filed a rate case in Rhode Island on the heels of the state’s Power Sector Transformation Process (AEE Institute and NECEC submitted joint comments), which included a suite of performance incentive mechanisms and plans to fully deploy advanced metering infrastructure (AMI). Also in November, the California Public Utilities Commissionissued a draft resolution (final decision expected before the end of the year) beginning the competitive solicitation process for utilities to start former Commission Florio’s regulatory incentive pilot.
2. Reconsidering how utilities undertake distribution system planning
Several states in 2017 have started to expand their distribution planning, which has traditionally focused on just poles and wires investments, to more fully consider new advanced energy technologies and DERs that can provide similar (or even better) performance, potentially at lower cost.
The New York Public Service Commission has been busy refining the state’s utilities’ distributed system implementation plans (DSIPs), which were filed last summer (by Con Edison, Central Hudson, National Grid, Orange and Rockland, and New York State Electric and Gas and Rochester Gas and Electric). In March, the utilities jointly filed a report and in May jointly filed a supplement on the identification and sourcing process for non-wires alternative projects.
In late September and early October, the utilities filed status reports (by New York State Electric & Gas Corporation and the Rochester Gas and Electric Corporation, Central Hudson Gas and Electric, Con Edison, Orange and Rockland, and Niagara Mohawk Power) on progress so far on hosting capacity analyses (i.e., estimating the load that the grid can accommodate without requiring grid upgrades) and implementation of interconnection portals (i.e., automating the application management process) — both key steps to integrating a higher share of DERs on the grid.
In April, the Rhode Island Public Utilities Commission, Division of Public Utilities, and the Office of Energy Resources started a modernization initiative called Power Sector Transformation, with a workstream focused on distribution system planning (AEE Institute and NECEC submitted joint comments). In November, the agencies issued a joint phase 1 report to the governor with recommendations on key steps Rhode Island should undertake to modernize its electricity system, including improving distribution system planning.
In April, the Minnesota Public Utilities Commission issued a distribution system planning questionnaire in its grid modernization proceeding. The questionnaire sought input from stakeholders (AEE Institute submitted comments) to identify potential improvements in utility planning processes, especially with regard to the growth of DERs.
In Michigan, the two largest utilities — DTE Electric Company and Consumers Energy — filed draft five-year distribution system maintenance and investment plans. Keep an eye out for their final distribution system plans emphasizing near-term priorities and investments, which are due by the end of January 2018. The commission staff is also ordered to begin a stakeholder process after the final plans are filed and develop a report by September 2018 on future iterations of the distribution planning process (AEE Institute held a forum in Michigan in August to discuss best practices).
In June, the main Connecticut utilities — United Illuminating Co. (approved on December 7) and Connecticut Light and Power Co. (approved on October 4) — submitted DER integration pilot plans that include hosting capacity analysis maps to provide customers and third parties more transparency into their distribution systems. They also both included DERs and load forecasting to inform distribution system planning, and a DER portal and management system to facilitate the two-way sharing of information between customers and the utility (see trend 10 for more on data access).
The California Public Utilities Commission has also made significant progress in its Distribution Resource Plan (DRP) proceeding. In September, the Commission issued a final decision on demonstration projects for an integration capacity analysis (similar to the hosting capacity analyses described earlier) and locational net benefits analysis and directed the states’ utilities to implement the approved methodologies across their service territories. Most recently, in October the Colorado Public Utilities Commission opened a proceeding to consider various rule changes including potential new rules around distribution system planning.
3. Investments to enable a dynamic and flexible grid
A key first step to realizing a 21st century electricity system is making foundational investments in technologies that can facilitate the seamless integration of distributed assets into the grid. In 2017, many utilities have proposed broad grid modernization plans or advanced metering roll-outs to set the foundation for a modern grid (see our recent post on the leaders and laggards). The graph below shows the most recent data on residential smart meters installed by state.
In February, the Public Utilities Commission of Ohio (PUCO) approved AEP Ohio’s Phase 2 gridSMART project, which among other things includes the installation of almost 900,000 smart meters by 2021 and a $20 million investment in voltage optimization technology. In April, PUCO also opened an initiative called PowerForward to review potential regulatory policies and technological innovations that could modernize the grid and enhance the customer electricity experience. Also in February, Orange and Rockland Utilities in New Yorkfiled an application that included an expansion of its existing AMI roll-out to a full deployment for an additional $98 million.
In April, the Missouri Public Service Commission opened an investigation into emerging issues in the electricity sector including the installation of advanced metering infrastructure (AMI) and a review of what new customer-sited technology and distribution system upgrades are needed to facilitate DER integration.
In Colorado, the Public Utilities Commission approved a settlement agreement in July that, among other things, initiates full AMI roll-out in Xcel Energy’s service territory commencing in 2020. And Entergy — one of the largest utility holding companies in the South — has been seeking approval for AMI roll-outs in several jurisdictions in 2017, including recent affirmative decisions in Louisiana,Mississippi and Arkansas, and a pending application in Texas.
In August, Hawaiian Electric Co. filed a revised $205 million grid modernization plan that includes a targeted smart meter deployment, investments in a wireless communications network and enhanced distribution technology, and the installation of advanced inverters to enable private rooftop solar adoption. In September, Vectren in Indiana received approval for a $446 million, seven-year grid modernization plan that includes investments in distribution automation technology, AMI, and an advanced distribution management system. And most recently, Duke Energy Florida received approval in November for a settlement agreement, resolving issues with its Levy Nuclear Project tat included the installation of AMI, a new Shared Solar program, and the installation of 500 electric-vehicle (EV) charging stations.
4. Successors to retail net energy metering
Net energy metering (NEM) has been widely successful in spurring the adoption of distributed solar across the country. However, as the number of NEM customers increases, pressure has been building in various jurisdictions to consider alternative rate designs and successor tariffs for NEM customers. Over the past 12 months, we have seen a flurry of activity.
The Maine Public Utilities Commission kicked off the changes in January by approving revisions to its NEM rules, grandfathering in existing customers under current rates for 15 years and establishing a 10-year transition period, with new DG customers in each subsequent year compensated slightly less than those who signed up the year before.
March was also a very busy month. Arizona Public Service filed a settlement agreement that follows the same general principle, grandfathering existing NEM customers for 20 years and establishing a transitional step-down rate for new customers. Arkansas adopted changes to its net metering rules, adding a 25-kilowatt cap for residential customers and a 300-kilowatt cap for non-residential customers, with longer-term changes to net metering still to come. And the New York Public Service Commission adopted an interim methodology for valuing DERs (AEE Institute filed comments). Specifically, the order maintains net metering for existing solar customers until January 2020, and then slowly reduces the compensation for new solar users from the retail rate toward a “value stack” methodology that is based on the utility’s avoided costs and other DER values.
In June, the New Hampshire Public Utilities Commission lifted its 100-megawatt NEM cap, grandfathered existing customers through 2040, and reduced the NEM credit for new customers to full retail energy and transmission rates but just 25 percent of the distribution rate. In May, Indiana passed a bill reducing its NEM rate for new customers over the next five years until it is close to the utility avoided-cost rate. And in June, Nevada passed a net metering bill (AB 405) that immediately restored net metering, albeit at a slightly lower rate (and with compensation declining, ultimately to 75 percent of the retail price, as adoption increases). The decision finally put to rest a contentious debate that raged throughout 2016. In July, Idaho Power jumped into the mix when the utility filed a petition to close its net metering tariff for new residential and small general service customers beginning January 1, 2018 (grandfathering customers on their existing rates).
This fall, we continued to see significant revisions to existing rates. In September, the Utah Public Service Commission approved a stipulation filed by PacifiCorp and Vivint Solar that grandfathered existing net metering customers on their current rates through 2035 and set a three-year transition period when net metering customers would receive export credits slightly below the existing retail rate until the completion of a final order in a new proceeding to investigate a long-term export credit.
In November, the Public Utilities Commission of Ohio amended its net metering rules, reducing the excess generation rate utilities are required to offer net metering customers from the unbundled generation rate (which includes some capacity-related riders) to the energy-only rate, ultimately reducing the credit by about 30 percent. Most recently, theLouisiana Public Service Commission proposed modified net metering rules compensating new DG customers at the avoided-cost rate, which includes the commodity rate plus any locational, capacity-related, or environmental benefits.
5. Electric-vehicle integration
EV adoption and integration have risen to the fore in many jurisdictions, as states are looking to electrification to reduce carbon emissions and utilities are looking for new ways to increase electricity sales. Actions have included widespread electrification programs, statewide EV investigations, and targeted pilots or demonstration projects.
In January, the three big investor-owned utilities in California (San Diego Gas & Electric, Pacific Gas & Electric, and Southern California Edison) filed transportation electrification proposals with the California Public Utilities Commission (CPUC) totaling over $1 billion in investments. At the end of November, the CPUC issued a proposed decision approving $43 million in funding for pilots in phase 1 of the plans (a final decision on phase 1 is expected December 14 and on phase 2 in Q2 2018).
In Oregon, PacifiCorp and Portland General Electric have been negotiating settlement agreements in their 2016 transportation electrification proposals. In August, PacifiCorp filed a joint settlement agreement in its application and Portland General Electric in June filed a non-unanimous settlement in its application.
In April, the Michigan Public Service Commission began a collaborative to address plug-in EV issues (AEE submitted comments). In May, the Pennsylvania Public Utility Commissioninitiated an investigation to review the statewide rules and utility tariffs pertaining to third-party EV charging stations (AEE submitted comments). In September, Nevada opened a rulemaking to implement SB 145 which, among other things, created an Electric Vehicle Infrastructure Demonstration Program. In November, the Colorado Public Utilities Commission opened a proceeding to investigate electrification of its transportation sector.
Several other utilities have also proposed pilots. In April, Pepco, in the District of Columbia, proposed a $1.6 million EV pilot program through 2019 to test incentives and evaluate and obtain information on potential EV impacts on the distribution system. In April, Gulf Power Co. in Florida received approval in its recent rate case for a revenue-neutral EV pilot program. In June, the Utah Public Service Commission authorized an EV incentive and time-of-use pilot program for Rocky Mountain Power. In November, Eversource received approval in its Massachusetts rate case for a $45 million EV infrastructure program to increase the availability of charging stations and lower the barriers to EV adoption in the state.
6. Investment in renewables goes big
As in previous years, 2017 continued to see large investments in renewable energy, with over $30 billion through the first three quarters, according to Bloomberg New Energy Finance. Large investments have largely been driven by the falling cost of renewables and increased appetite from residential and corporate customers for 100 percent renewable energy offerings.
Several utilities have proposed building or procuring ambitious amounts of renewables this year. In March, Southwestern Public Service Co. filed an application to build a 522-megawatt wind plant in New Mexico and a 478-megawatt wind plant in Texas for $1.63 billion and to enter into a 30-year power-purchase agreement for an additional 230 megawatts of wind. In April, PacifiCorp in Oregon filed its 2017 integrated resource plan (IRP), which called for the retirement of 3,650 megawatts of coal-fired plants by 2036 and the addition of 1,959 megawatts of new wind (1,100 by 2020), 905 megawatts of repowered wind (i.e., upgrading aging turbines with modern units, by 2020), and 1,040 megawatts of new solar.
In May, Dominion Energy in Virginia filed its 2017 IRP, which included the closure of a 790-megawatt oil-fired facility by 2022 and a 261-megawatt coal-fired facility by 2022, along with the development of at least 3,200 megawatts of solar by 2032 (including 990 megawatts owned by non-utility generators by 2022) and 12 megawatts of offshore wind by 2021. In August, Interstate Power and Light in Iowa filed an application for 500 megawatts of new wind generation on top of the 500 megawatts that were approved in October 2016.
In July, Public Service Company of Oklahoma (PSO) requested approval to enter into an agreement with Invenergy Wind Development and its $4.5 billion, 2,000-megawatt wind facility (with an expected 51 percent capacity factor) in Oklahoma. If approved, PSO would own 30 percent of the project (with Southwestern Public Service Co. in Arkansas and Texasowning the other 70 percent). In August, Xcel Energy in Colorado, in phase II of its 2016 IRP, filed a settlement agreement that included the retirement of two coal plants (totaling 660 megawatts) by 2025 and the addition of 1 gigawatt of wind and 700 megawatts of solar by 2023.
Utilities in vertically integrated markets have increasingly turned to renewable energy tariffs to give customers more choice over their energy sources. In February, Xcel Energy in Minnesota received approval for two pilot programs — Renewable*Connect and Renewable*Connect Government — aimed at large businesses and government entities, respectively. In May, Dominion in Virginia filed an application for six voluntary renewable energy tariffs, collectively called Schedule Continuous Renewable Generation (AEE has been a party to this proceeding), and in October Dominion proposed an additional experimental and voluntary companion tariff (Schedule RF).
In June, Alliant Energy in Iowa petitioned for a voluntary renewable energy tariff, giving customers three subscription options: 1) a 100 percent solar option; 2) a 50 percent solar and 50 percent wind option; and 3) a 25 percent solar and 75 percent wind option. In August, Consumers Energy Co. in Michigan received approval for a three-year, voluntary large-customer renewable energy pilot program. In November, Westar Energy and Kansas Gas and Electric Co. (jointly known as Westar) filed an application for a Direct Renewable Participation Service tariff and Ameren Missouri filed an application for a new Renewable Choice Program, both targeted at large commercial and industrial customers.
7. New opportunities for energy storage
The energy storage market has continued its recent momentum into 2017. Driven by improving economics, a changing grid, and business model and rate design changes, energy storage is increasingly being recognized as a valuable and necessary asset for a 21st century grid.
More and more states are requiring energy storage to be evaluated in their IRPs. In August, the New Mexico Public Regulation Commission amended its IRP rules to include energy storage as a commercially feasible alternative supply and demand-side resource and requiring utilities to consider them in their planning. In October, the Washington Utilities and Transportation Commission laid out a framework for utilities to consider energy storage on a more level footing with other resources in future planning and procurement proceedings. The UTC will further develop specific rules around evaluating storage investments in its ongoing integrated resource planning proceeding.
A few other states have opened broader rulemakings to refine their energy storage frameworks or policies. Oregon continued progress in meeting its legislative requirements to consider utility energy storage project proposals submitted by January 2018, and to implement an energy storage procurement program by January 2020. In July, the Public Utilities Commission of Nevada opened a rulemaking to investigate setting energy storage procurement targets. Meanwhile, the California Public Utilities Commission released a decision in April to fine-tune its storage framework and policies, which the three large IOUs must use when filing their storage procurement applications in March 2018.
We have also continued to see utilities propose new energy storage projects. In July, the Kauai Island Utility Cooperative received approval for a power-purchase agreement with AES Lawai Solar for the largest combined solar and storage facility in Hawaii — a combined 28-megawatt solar PV plant and 100 megawatt-hour battery storage system to help with ramping toward the afternoon/evening peak, shaving the evening peak, offsetting nighttime oil-fired generation, and assisting in grid stabilization.
In October, Duke Energy Indiana filed a petition for a new 2-megawatt solar and 5-megawatt/5-megawatt-hour storage microgrid (Camp Atterbury Microgrid) and a 5-megawatt/5-megawatt-hour energy storage facility (Naab Battery). And in October, the Public Utility Commission of Texas issued a proposed decision approving AEP Texas North Co.’s proposed installation of two utility-scale lithium-ion batteries on its distribution system (one would cost $700,000 in lieu of a $5.3 million traditional investment and one would cost $1.6 million in lieu of a $6 million to $17.2 million traditional investment).
8. Rate design for a DER future
New technologies, especially the rise in customer-sited distributed generation such as rooftop solar, have led many utilities to propose new rate designs and many PUCs to initiate alternative rate design investigations.
Back in January, the Public Utility Commission of Texas issued a final report to the state legislature on new rate designs and recommended phasing in alternative ratemaking mechanisms over three to five years. In April, the Missouri Public Service Commission began to explore and gather information on five emerging issues in the utility sector, including the implementation of alternative rate designs, the installation of AMI, and establishing a competitive EV market. And in October, New York Public Service Commission staff issued a scope-of-study report to examine bill impacts of a range of mass-market rate reform scenarios.
A few other states have begun the move toward time-varying rates. The big three California utilities have been conducting time-of-use (TOU) pilots throughout 2017 in order to gather information and aid in their transition to default TOU rates in 2019. In February, Tucson Electric Power in Arizona received approval for a new optional TOU rate with a plan to make the rates default for new customers starting in January 2018.
In November, Xcel Energy in Minnesota filed a petition for an innovative two-year opt-out residential TOU rate design pilot. If approved, the pilot would include three different rates, an on-peak rate (average of 23.82 cents per kilowatt-hour), a mid-peak rate (average of 11.07 cents per kilowatt-hour), and an off-peak rate (average of 5.68 cents per kilowatt-hour). At the end of November, National Grid in Rhode Island filed a grid modernization plan as a supplement to its rate case that included full advanced metering roll-out to all of its 790,000 customers, coupled with an opt-out time-varying rates program by 2022.
9. Wholesale market issues and changes
The last few months have been overshadowed by Energy Secretary Rick Perry’s grid review study and the Department of Energy’s subsequent proposed bailout of uneconomic coal and nuclear plants now pending before the Federal Energy Regulatory Commission. PUCs across the country have certainly taken notice, with NARUC commenting: “This proposal contravenes the States’ authority.” At least one state has opened its own inquiry. In September, Commissioner Andy Tobin of the Arizona Corporation Commission requested an investigation into Arizona’s changing energy mix and to identify considerations that should be made to maintain a reliable and secure baseload energy portfolio in the future.
A few other states have opened slightly different investigations into their wholesale market rules. In August, Connecticut’s Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority opened a proceeding to examine the role of existing nuclear, large-scale hydro, demand-reduction measures, energy storage, and renewable energy in helping the state meet its carbon emissions targets; the best mechanisms to ensure progress toward those targets; and the compatibility of such mechanisms with competitive wholesale and retail electricity markets.
Also in August, the New York Independent System Operator and the Department of Public Service initiated a process to examine the potential for carbon pricing in New York’s wholesale energy market in order to align New York state policy and wholesale electricity market rules.
Texas and its exclusive wholesale market operator the Electric Reliability Council of Texas (ERCOT) — have been engaged in several different wholesale market rule changes in 2017. In May, the Public Utility Commission of Texas staff filed a report presenting possible changes to its operating reserve demand curve, which was created to ensure reliability and promote scarcity pricing in ERCOT’s energy-only market design. And in March, the PUCT adopted an amendment allowing Emergency Response Service resources such as demand response to participate as alternatives to reliability must-run contracts, which traditionally have relied on coal plants to ensure the grid stays operational during emergency events.
10. Unlocking access to customer and system data
The rapid deployment of smart meters — and the granular customer and electricity system data they provide — has led many states to revisit their data access rules in the past year. Timely and convenient access to energy data can help customers track and manage their energy use, empower third-party companies to animate the market for DERs, and enable utilities to transition to a more customer-focused culture and business model.
Over the past year, the Public Utility Commission of Texas has been investigating changes to Smart Meter Texas (SMT) — a web portal that provides data access to customers and authorized competitive service providers — through several dockets (42786, 46204 and 46206). Most recently, commission staff filed a formal petition on August 16 to open a new docket (47472) to determine what changes, if any, should be made to existing SMT requirements. In July, the Illinois Commerce Commission issued an order encouraging utilities to consider adopting an Open Data Access Framework to enable a marketplace for new products and services and utilize investments made in AMI.
In an August resolution (E-4868), the California Public Utilities Commission approved a new click-through authorization processes that streamlines, simplifies and automates the process for customers to authorize their utility to share their energy-related data with third-party demand response providers. The Minnesota Public Utilities Commission has also been refining its data-access rules, particularly related to customer privacy. In June, the PUC approved a model form for utilities to use for obtaining customers’ consent to release their energy usage data to third parties.
Utility commissions across the country have been busy this year adjusting regulatory frameworks to a changing electricity marketplace. To advance the conversation, AEE has prepared a series of seven issue briefs that address how the power sector can successfully transition to a 21st-century electricity system. Also, to keep up to date on energy policy developments across the country, check out AEE’s PowerSuite and start a free trial.
This post originally appeared on blog.aee.net and was republished with permission from Advanced Energy Economy.