North America stole the spotlight last month when the United States, Mexico and Canada committed to producing 50 percent of their power from "clean" energy resources, including hydropower, wind, solar and nuclear plants, by 2025. The goal could also apply to fossil fuel plants with carbon capture, as well as energy storage and energy efficiency measures.
The initiative is considered ambitious but achievable, and a key part of reaching each nation's pledge under the Paris climate accord. Sierra Club Executive Director Michael Brune said the agreement demonstrates "North American unity behind a consensus for strong global climate action," Bloomberg reports.
How the U.S. clean energy transition plays out depends in large part on policy changes at the state and local level, however. Below we chronicle some of the most significant state-level policy developments from recent weeks on the topics of distributed energy resources, net metering, community solar, grid modernization, renewable portfolio standards, resource planning and mergers (click to jump to a section).
Read our previous state news roundup here.
In June, the Montana Public Service Commission voted to suspend the avoided cost rates for small-scale solar power guaranteed under the federal Public Utility Regulatory Policies Act (PURPA), local news outlet KPAX News reports. Four years ago, Montana’s PSC set the rate for projects 3 megawatts and below at $66 per megawatt hour. NorthWestern Energy argued that that rate is unfair to its customers, and the PSC granted the utility’s request to suspend the state's guaranteed rate in a 3-2 vote.
Solar company FLS Energy of Asheville, North Carolina, which has invested over $700,000 in Montana projects, is now seeking a rehearing of the PSC decision. "Well, if the decision stands as issued, that will be the end of our development activities in Montana. None of our projects will go forward," Steve Levitas, a vice president at FLS, told Montana Public Radio.
On June 9, Texas regulators agreed to open a docket related to distributed energy resources and interconnection agreements. According to Advanced Energy Economy’s PowerSuite, the rulemaking will address which type of entity -- the end-use customer, the owner of the DG facility, the owner of the rights to the energy produced from the facility, or the owner of the location where the DG facility is located -- should sign an interconnection agreement with an electric utility for the operation of on-site distributed generation. Initial comments on the proposal are due by July 29 and reply comments are due by August 12, 2016.
On June 13, the CPUC held a workshop on Commissioner Michael Florio's April 4 proposal to offer utilities a better rate of return for DER projects that replace more expensive capital upgrades. This is the first CPUC proposal to specifically attempt to resolve the "conflict between the commission’s policy objectives and the utilities’ financial imperatives.” Florio leads the CPUC’s distribution resources plan proceeding (14-08-013), which is creating values for DERs as potential replacements for grid investments. Post-workshop comments were due by July 8.
Also in California, regulators recently issued a decision revising the state’s Self-Generation Incentive Program, which has some significant flaws. The new structure seeks to clarify which types of resources qualify for the incentive program and how the incentives are awarded. It also includes a 15 percent carve-out for residential systems.
Separately, on June 23, the CPUC adopted a new model and five-year pilot process to accelerate the interconnection of renewable and distributed energy resources to the electric grid. The proposal is available here.
On June 30, New York's six regulated utilities filed their Initial Distributed System Implementation Plans (DSIPs) as part of the state’s Reforming the Energy Vision (REV) proceeding. The filings, each more than 300 pages, highlight which technologies utilities see as fundamental to remaking the operation of the electric system and integrating distributed energy resources. Among the findings utilities identified the potential to invest in three advanced distribution management systems, 6.8 million smart meters, 14 non-wires alternatives, such as ConEd’s Brooklyn Queens Demand Management Program.
While integral to the REV process, the DSIP filings do not explicitly address how technology investments will combine with price signals in the future to create new markets, which means the end goal of REV is still a long way off.
However, stakeholders have started to grapple with questions around price signals for distributed energy resources in a related proceeding on the value of DERs. In April, a wide array of parties submitted proposals for alternatives to New York’s current retail-rate net metering policy. The filings offered DER valuation proposals that can be adopted before the end of 2016 and a methodology and process for establishing a full value of DERs based on the LMP+D approach -- where “LMP” represents the location-based marginal price of energy and “D” represents the value provided to the electric distribution system.
GTM Squared recently chronicled several of the proposals in a multi-part series. Part 1 looked at a landmark agreement between six utilities and three major solar players dubbed the Solar Progress Partnership. Part 2 looked at proposals from the Solar Energy Industries Association and Vote Solar; the Environmental Defense Fund; and the Advanced Energy Economy Institute in partnership with the Alliance for Clean Energy New York and the Northeast Clean Energy Council.
On June 10, stakeholders submitted reply comments, some of which are detailed in Part 3. Rather than have regulatory staff write a report on the proposals, an administrative law judge announced in late May that key players in the docket are to participate in “informal and collaborative talks” on the valuation of DERs and produce recommendations on an interim NEM alternative for regulators to act on before the end of the year.
On June 17, the commission announced the creation of an Interconnection Policy Working Group to explore non-technical issues relevant to the interconnection of distributed generation. According to AEE’s PowerSuite, stakeholders that wish to participate in the working group were asked to provide a brief description of their interest to the commission by June 27.
The Pennsylvania Public Utility Commission continues to weigh changes to the state’s net metering rules after alternative energy regulations were rejected, revised, and then rejected again by an independent review board, the Pittsburgh Post-Gazette reports. The most controversial section of the rules proposes to drop the cap on the size of alternative energy systems that qualify for net metering and can be reimbursed at retail rates for the excess electricity they send back to the grid.
Despite the Independent Regulatory Review Commission’s recent rejection, the rules may not be dead. Pennsylvania’s Regulatory Review Act allows the PUC to proceed with the regulations as they are written, despite the review board’s disapproval. Committees in the state House and Senate could then block the rules, but it’s currently unclear if lawmakers would take action. The PUC has not said what it will do next.
“We will carefully review IRRC’s disapproval order when it is published, and then determine the most appropriate course of action,” PUC spokesperson Nils Hagen-Frederiksen said.
In April, Maine Gov. Paul LePage vetoed a landmark solar energy bill that would have ended conventional retail-rate net metering but provided a significant boost to overall solar development in the state. In January, Central Maine Power, the dominant utility in the state, filed a notice that it had reached its net metering cap (1 percent of peak demand) at the end of 2015. In the absence of legislation governing the next step, the focus now shifts to the state regulators. According to EQ Research, the Maine PUC is currently seeking comments and information regarding net energy billing rules (Chapter 313). Comments on whether the current rules should be modified or whether any other action should be taken are due by July 22. The PUC is specifically seeking comments on the following issues:
- In what respects, if at all, Chapter 313 should be revised, and what objective each such revision is intended to achieve
- In what respects, if at all, should there be revisions to the retail rate components that are netted such that less than the full retail rate would be netted, and what objectives are such revisions intended to achieve
- Whether the PUC should consider changes to the current kilowatt-hour threshold for qualified projects, and what the rationale would be for any change
- Whether existing net metering customers should be grandfathered, and for how long
- How a net metering program can be designed to track changes in the costs of distributed generation facilities
- Whether issues of revenue loss and rate impacts should be addressed through utility rate design, and how rate design should be approached -- through cost of service, avoided cost, or value of solar -- and whether there may be any equity issues
- Whether the structural approach discussed in the PUC's January 2016 report and considered in the legislature needs legislative approval, and if not, whether the PUC should pursue that approach, and the appropriate purchase price
- Whether solar should be treated differently than other eligible resources
- Whether changes will apply to other utilities
- Whether the PUC has authority to regulate or oversee lease arrangements or other customer arrangements that involve net metering, and if so, whether the PUC should consider additional consumer protection standards with respect to distributed generation lease programs or other customer arrangements, including community solar
The New Hampshire PUC has opened a new docket (DE 16-576) to develop alternative net energy metering tariffs pursuant to H.B. 1116, which increased the state’s net metering cap from 50 megawatts to 100 megawatts. Gov. Hassan signed H.B. 1116 into law in early May. In addition to raising the cap, the bill directed regulators to initiate and conclude a proceeding to develop new alternative net metering tariffs or other regulatory mechanisms applicable to customer-sited generation.
According to EQ Research, the PUC must consider numerous issues in this proceeding, including:
- The costs and benefits of customer-generator facilities
- An avoidance of unjust and unreasonable cost-shifting
- Rate effects on all customers
- Alternative rate structures, including time-of-use rates
- Whether there should be a limitation on the amount of generating capacity eligible for such tariffs
- The size of facilities eligible to receive net metering tariffs
- Timely recovery of lost revenue by the utility using an automatic rate adjustment mechanism
- Electric distribution utilities’ administrative processes required to implement such tariffs and related regulatory mechanisms
In June, San Diego Gas & Electric became the first investor-owned utility in California to meet its net metering cap. SDG&E will now move to NEM 2.0, in which PV customers will continue to receive a net metering credit, but they will be required to transition to time-of-use rates in 2017. Customers who installed rooftop solar prior to the limit being reached are grandfathered in under the existing rules for 20 years from the date they installed solar.
The Colorado PUC approved a community solar proposal from the state’s largest utility, Xcel Energy, and three solar companies last month, after rejecting the plan earlier this year.
The PUC reversed its initial ruling following a hearing on June 1 and the submission of further evidence. Regulators determined that the parties had successfully demonstrated that the proposal was in the public interest, and found that the scheme would benefit low-income individuals and businesses that wished to promote solar energy, PV Tech reports.
The approved proposal will add 60 megawatts of community solar through a request for proposals this year. It also includes a carve-out for Xcel to own up to 4 megawatts of community solar, exclusive to serving low-income customers and nonprofit organizations.
The agreement stemmed from criticisms that Xcel has been slow-rolling Colorado’s community solar program, and that the program structure led to negative renewable energy credit prices in a bid for 29.5 megawatts of solar 2015. With the commission’s recent approval, development of the 29.5 megawatts -- to be built by SunShare, Clean Energy Collective and Community Solar Energy, the three winners of Xcel’s 2015 tender -- can progress.
Nearly every proposed solar garden project in Minnesota has faced delays under Xcel Energy’s community solar program, The Minneapolis Star Tribune reports. A year and a half after the program launched -- and with more than 900 active applications pending -- only three gardens are on-line, generating a total of less than 1 megawatt of power. Solar developers blame Xcel for the delays and have filed a complaint with regulators over Xcel’s high interconnection costs. An independent engineering report backed up some of the solar companies’ claims. The utility, meanwhile, says it has attempted to speed up the program rollout, and that some delays are the fault of developers.
Commonwealth Edison has introduced comprehensive and controversial legislation with its parent company, Exelon, that the utilities say is intended to enhance the grid and drive the adoption of clean energy technologies. The utilities launched the Next Generation Energy Plan (SB 1585) in May after a previous version of the bill failed to win support. The new bill contains a controversial provision providing assistance to Exelon’s struggling nuclear power plants, but includes a number of other alternative energy measures that the utilities hope will help it pass.
The utilities claim the new bill will help to jump-start the Illinois clean energy market by doubling energy-efficiency programs, creating roughly $4.1 billion in energy savings for customers, including $650 million in efficiency savings for low-income customers. The bill also includes a smart inverter rebate and more than $140 million per year in new funding for solar development, $250 million to develop five microgrids around critical infrastructure, and calls for strengthening and expanding the state’s renewable portfolio standard.
ComEd is hopeful that the Illinois General Assembly will take up and pass its energy plan when the new session begins this fall, but that outcome is not assured. The bill still faces pushback on the nuclear income guarantee issue. In addition, solar companies and advocates have been critical of the proposal because it would end net metering, introduce universal demand charges, and allow ComEd to own community solar projects and compete with other developers. These critics allege a new solar advocacy group founded by ComEd was created specifically to advance the utility-backed legislation.
“We don’t see that there needs to be a competing nonprofit to do this work,” Lesley McCain, executive director of the Illinois Solar Energy Association, told Midwest Energy News. “It appears they would be starting this group during bill negotiations to advance their own agenda.”
The Indiana Utility Regulatory Commission has approved a settlement agreement allowing Duke Energy to advance its $1.4 billion modernization plan. The utility reached a consensus with industry, consumer and environmental groups on the seven-year plan in March after regulators denied Duke’s original proposal the previous year, citing a lack of specifics.
As part of the settlement, Duke Energy will reduce the level of capital investments recovered through the plan's customer bill tracker by approximately $400 million. Part of the reduction comes from $192 million earmarked for new advanced digital meters. Duke will not recuperate smart meter costs through the monthly bill tracker, but retains the ability to pursue the meters and defer their costs for consideration in a future rate case. If the utility decides to pursue smart meters, as part of the settlement, it has committed to exploring energy-efficiency pilot programs made possible with smart meter technology.
Consumer benefits from the plan include updating and replacing aging energy grid infrastructure and installing “self-healing” systems to allow for fewer and shorter power outages. New equipment such as line sensors will enable the company to provide customers more information about power outages affecting them and estimated restoration times. The grid system will also see energy savings from technology that optimizes voltage and reduces overall power consumption by about 1 percent on upgraded power lines. As a result of the plan, customers will see a gradual rate increase averaging 0.75 percent per year between 2017 and 2022.
Stakeholders in the settlement included the Indiana Office of Utility Consumer Counselor, the Duke Energy Indiana Industrial Group, Companhia Siderurgica Nacional, Steel Dynamics, Wabash Valley Power Association, Indiana Municipal Power Agency, Hoosier Energy Rural Electric Cooperative and the Environmental Defense Fund.
The District of Columbia City Council unanimously approved legislation to increase the city’s renewable portfolio standard from 20 percent by 2020 to 50 percent by 2032, and to increase D.C.’s solar requirements by 5 percent by the same year. The bill now awaits the signature of Mayor Muriel Bowser.
The Chesapeake Climate Action Network (CCAN) expects the legislation to create incentives for 1.5 gigawatts of new solar and wind power and to quadruple the number of jobs in D.C.’s solar industry, which currently employs 1,000 people, Solar Industry reports.
According to the summary of the bill, the legislation also “increases financial penalties for electricity suppliers who fail to comply with the renewable energy portfolio standard for the applicable year; and establishes a program within the Department of Energy and the Environment to assist low-income homeowners with installing solar systems on their homes.”
In late June, the Rhode Island legislature passed a bill (S.2185/H.7413) to increase the state's renewable energy target from 14.5 percent by 2019 to 38.5 percent by 2035. Governor Gina Raimondo is expected signed the bill into law.
Rhode Island’s original RPS target was for 16 percent renewable energy by 2019. However, in December 2014, the PUC decided to delay the program for one year, reducing the 2019 goal from 16 percent to 14.5 percent. An amendment attached to new legislation allows the PUC more flexibility to delay the RPS if there is a shortage of renewable energy credits.
The wind industry praised the legislation. Wind farm investment in Rhode Island has already attracted $20 million in total capital investment to the state economy, according to the American Wind Energy Association. According to the Wind Energy Foundation, growing wind power in Rhode Island could result in $240 million in electricity bill savings by 2050.
On June 30, National Grid announced it had brought a 20-mile-long, 5-million-pound underwater cable between the Rhode Island mainland and Block Island to shore. The cable will bring power from the five-turbine Deepwater Wind Block Island Wind Farm project to the mainland power grid, Renewable Energy World reports via Generation Hub.
On June 30, the Massachusetts State Senate passed a bill (S.2372) that would require utilities to purchase 2,000 megawatts of offshore wind and a minimum of 12,450,000 megawatt-hours (roughly 1,800 megawatts) of hydropower and onshore wind by 2027. Environmentalists and clean energy advocates praised the passage, while power generators expressed concern, MassLive reports.
"We are extremely disappointed and concerned about key provisions in this energy bill, which carves out nearly 50 percent of Massachusetts' electricity market in the form of subsidized long-term contracts," said Dan Dolan, president of the New England Power Generators Association, said in a statement. "Not only will this lead to a dramatic increase in electricity costs for Commonwealth businesses and consumers, it will hurt local energy innovation and undermine billions of dollars in new investments being made here today."
The Senate will now conference with the House, which passed its own clean energy bill (H. 4385) last month. The House bill would require utilities to enter into 15- to 20-year contracts for 1,200 megawatts of offshore wind and roughly 1,200 megawatts of hydropower. Talks are expected to begin immediately and to wrap up before the legislative session ends July 31.
On June 28, the Vermont Public Service Board announced the implementation of the state’s renewable energy standard (RES) that requires utilities to procure 55 percent of the electricity sold to customers from renewable sources in 2017, increasing gradually to 75 percent in 2032. In 2017, at least 1 percent must come from new, distributed renewable resources, such as net-metered solar systems, rising to 10 percent by 2032.
According to the release: “The RES also establishes an energy transformation category under which utilities can either invest in projects that directly reduce the fossil-fuel consumption of their customers, through measures like weatherization, the installation of cold-climate heat pumps, or clean vehicle technologies, or procure additional distributed renewable generation. To meet the requirements of this category, utilities must demonstrate fossil-fuel savings equivalent to 2 percent of their annual retail sales or procure an equal amount of additional renewable generation. This amount will increase to 12 percent by 2032.”
The RES officially takes effect on January 1, 2017.
Georgia Power plans to add 1,200 megawatts of renewable energy to its electrical generation portfolio over the next five years under an agreement with the state's Public Service Commission, The Atlanta Business Chronicle reports. Georgia Power agreed to add 1,050 megawatts of utility-scale renewable power through two separate requests for proposals -- the first 525 megawatts would go into service in 2018 and 2019, and the other 525 megawatts would go into service in 2020 and 2021. Most of the renewable commitments will come in the form of solar power, but the initiative calls for up to 300 megawatts of wind energy. In addition, Georgia Power agreed to make its biggest commitment to distributed generation to date, with 150 megawatts of renewable distributed energy resources installed by the end of 2018. The PSC is scheduled to vote on the agreement in late July.
Last month, Pacific Gas & Electric announced a plan to replace Diablo Canyon’s 2.3 gigawatts of generation capacity, about 8.6 percent of the state’s electricity production, with a host of zero-carbon emissions resources over the next nine years. Diablo Canyon, the state’s last working nuclear reactor, will close by 2025. The nuclear capacity will be replaced by lots of new solar and wind power, as well as other greenhouse-gas-free energy resources such as energy efficiency, demand response, energy storage, and other reliable demand-side resources.
This is the first time a U.S. nuclear reactor closure has come with the guarantee of promoting carbon-free resources. It represents an enormous opportunity for the renewable energy sector, but advocates for climate action argue that keeping the carbon-free nuclear plant on-line is actually the best thing the utility could do to mitigate emissions. Critics say the plan diverts money from climate change and is really designed to make PG&E money. Others argue that closing the plant will save money and carbon.
Last month’s proposal will now go to the California Public Utilities Commission for review and possible approval. The proposal can be read in its entirety here.
Virginia Gov. Terry McAuliffe issued an executive order on June 28 directing the creation of a state climate commission to advise the governor on how to reduce greenhouse gas emissions and incorporate clean energy into the state’s power grid. Virginia Secretary of Natural Resources Molly Ward will convene the workgroup and recommend concrete steps to reduce carbon pollution from Virginia’s power plants.
Gov. David Ige announced the appointment of attorney Thomas Gorak to the Hawaii PUC on June 29, just days before the three-member regulatory body is expected to rule on NextEra Energy’s $4.3 billion acquisition of Hawaiian Electric Co. Analysts believe Gorak is skeptical of the deal, which could affect the outcome. Some are calling the appointment illegal and unethical, but the attorney general’s office says the appointment is valid, KHON News reports. Gov. Ige said he waited to announce a replacement because he thought a decision on the NextEra-HECO merger would have been issued by now.
Meanwhile, billionaire Warren Buffett may be interested in purchasing HECO if state regulators don't approve of NextEra’s acquisition, Pacific Business News reports. MidAmerican Energy Services LLC, owned by Buffett’s Berkshire Hathaway Energy Company, was recently registered as a new business in Hawaii, according to public records.