California lawmakers have been incredibly busy. Governor Jerry Brown signed a suite of bills on climate change and clean energy into law today addressing renewables, energy storage, energy efficiency, demand response and other technologies. With these bills, California will continue to lead other states and countries in the adoption of progressive energy policies.
"The bills today really are far-reaching and keep California on the move to clean up the environment and encourage innovation and...the environmental resilience Californians expect," Gov. Brown said at a signing ceremony on Thursday.
In this week's roundup, we document several new pieces of legislation in California. We also chronicle other recent state-level policy developments from around the country on the topics of net metering, resource planning, incentives, community solar, third-party ownership, energy storage and electric vehicles (click to jump to a section).
Read our previous state news roundup here.
As the legislative session came to a close, California passed a slew of clean energy and climate bills to be signed by Governor Jerry Brown on Thursday, September 8. In a hard-fought win, California lawmakers voted to extend the state’s efforts to address climate change by cutting the state's output of greenhouse gas emissions 40 percent below 1990 levels by 2030 (SB 32) -- the most aggressive target in North America.
The Senate vote to approve SB 32 came hours after the state assembly passed a related bill to increase legislative oversight of the climate change programs run by the California Air Resources Board (AB 197).
In addition, the legislature passed AB 1550, which guarantees that at least 35 percent of California’s Greenhouse Gas Reduction Fund proceeds from the state’s cap-and-trade program will benefit underserved communities and low-income Californians. California lawmakers also passed AB 1937, which requires utilities to draw on the benefits of clean, renewable power in communities that suffer from significant pollution as part of their procurement plans.
As part of AB 2454, the CPUC is required to use the latest studies of demand response potential in determining the availability of resources that reduce energy demand. “The bill will help bring more high-value demand response to California by ensuring the CPUC makes decisions based on the most up-to-date information regarding the kind of demand response available and what it can do to reduce costs and California’s reliance on fossil fuels,” the Environmental Defense Fund wrote in a blog post.
SB 840 addresses two state solar programs, according to EQ Research. One section of the amended bill eliminates the repeal of the existing law creating California's Green Tariff Shared Renewables on January 1, 2019, therefore making the program authorization indefinite. Another section facilitates the CPUC's June 2016 decision (in R1211005) extending the New Solar Homes Partnership by requiring any funding made available for the program to be deposited in the Renewable Resources Trust Fund and used by the CEC to fund program activities.
California also passed four bills related to energy storage. AB 33 directs the CPUC to consider large-scale pumped hydro facilities as it evaluates utilities’ storage procurement targets. Under current rules, pumped storage hydro facilities larger than 50 megawatts are not eligible to meet storage procurement targets. AB 1637 seeks to double California’s Self-Generation Incentive Program. AB 2868 would allow the state’s three largest utilities to develop an additional 500 megawatts of storage capacity. And AB 2861 directs the CPUC to establish a resolution process to address interconnection disputes within 60 days.
Advanced Energy Economy tracked and supported several other recently approved bills that relate to clean energy, including AB 1613/SB 859, which allocates $900 million of the total cap-and-trade budget for fiscal year 2016-2017 to advanced energy investments and programs. The future structure of California’s cap-and-trade program is among the issues left unresolved, however.
Nevada PUC Chairman Paul Thomsen reversed a controversial decision this week that prevented SolarCity from participating in Nevada’s upcoming dockets on grandfathering existing solar customers onto older, more favorable rates. Nevada put in place new rates at the beginning of the year.
In an order released on August 29, Thomsen determined that SolarCity does not represent the interests of solar customers in the state. “SolarCity is not an association and, therefore, cannot represent the interests of other persons simply because the other persons may have installed SolarCity equipment,” the order stated. Thomsen found that SolarCity’s customers’ interests are already adequately represented by the Attorney General’s Bureau of Consumer Protection.
On September 6, Thomsen went back on his initial ruling and concluded that SolarCity could take part in the discussion. The PUC also set the first hearing date for September 19. Regulators could consider a proposed resolution to the grandfathering issue as early as September 28, Thomsen told the Las Vegas Review-Journal.
NV Energy asked the PUC in late July to allow existing rooftop solar customers to be grandfathered in under the state’s previous, more favorable solar tariff, rather than be required to adopt a contentious new rate scheme introduced at the beginning of the year. The request was filed in two separate dockets, one on behalf of Nevada Power Company (16-07028) the other on behalf of Sierra Pacific Power Company (16-07029), both of which are subsidiaries of NV Energy.
The utility filing came after SolarCity and other solar advocates had already spent months actively campaigning for rooftop solar customers to be grandfathered in under the old rates. The new rates include higher fixed fees and a lower net-metering credit. In February, regulators issued a final decision that adjusted the implementation timeline but upheld the fee changes.
Oregon regulators are delaying the release of a solar policy report from September 15 to late October in response to protests from solar advocates. The Oregon legislature passed a bill last year instructing the Oregon PUC to produce a report evaluating the state’s various solar incentives. Regulators opened a docket (UM 1716) to address the “resource value of solar” based on 10 elements that directly relate to the cost of service for utility customers.
In July, the Oregon PUC released a draft report on the state of Oregon’s solar industry that elicited a strong backlash. The report, which will inform value-of-solar discussions, recommended phasing out the state’s net metering practice in order to avoid the potential for cost shifts.
The report states: “Rather than netting generation against consumption and applying the netted value to the utility’s volumetric rates, as is currently done...in the NEM program, a crediting value of the generation energy would occur on the customer’s bill. A solar metering customer would be charged the volumetric retail rate for energy delivered to the customer. However, the customer would be allowed to offset the charges with the value of the energy the customer generates.”
Solar advocates took issue with the PUC’s characterization of Oregon’s solar industry as “well-supported” and “robust.” The report notes there are 8 megawatts of net-metered solar in the state, which solar groups point out is a fraction of Oregon utilities’ overall load. “That is not a thriving industry; that is still an emerging industry,” the Oregon Solar Energy Industries Association (OSEIA) wrote on its website.
“While it’s true the solar industry is growing and solar costs are coming down, it is also true that even small changes in the current support structure could lead to a significant contraction of the industry with a loss of employees and likely failure of some solar businesses,” the OSEIA stated.
The solar sector mobilized in response to the PUC report, demanding a more thorough analysis. The Portland Business Journal reports that regulators will now submit “a more fully vetted report” to the legislature in late October. Regulators will release a new draft report in the interim. According to OSEIA, comments on the draft are currently due September 30.
On September 8, hearings will begin on Tucson Electric Power’s general rate case (E-01933A-15-0322). The proposal includes a 7 percent (an average of roughly $12) rate increase for residential customers, a doubling of the fixed charge from $10 to $20 for residential customers, a new demand charge for solar customers, and a reduction in the net metering credit for solar customers from the retail rate (11 cents per kilowatt-hour) to the utility’s avoided cost (6 cents per kilowatt-hour). TEP introduced the rate case in November 2015. The application requests that new rates come into effect by January 2017.
Last month, Arizona regulators rejected a request to impose a demand charge on solar customers and reduce compensation under the net metering policy from TEP’s sister utility, UniSource Energy Services. The decision also introduced a new credit scheme and upheld the principle of grandfathering existing solar customers on existing rates, so that they don’t find themselves affected by a change in the regulatory landscape. The commission decided to hold off on addressing future solar rates until they conclude a separate docket on the value of solar, expected in October. That investigation is intended to provide solid data to use as the basis for future rate changes regarding solar.
In response to increasing adoption of home solar and energy efficiency measures, Ohio’s American Electric Power (AEP) is seeking to more than double the fixed distribution charges all customers must pay, Midwest Energy News reports.
AEP claims the increase in net-metered solar customers is creating a cost shift onto non-net metered customers. AEP Ohio currently serves 1.5 million customers, and has seen a jump in its solar net metering customers from 286 in 2011 to 983 customers today. The utility has proposed increasing the fixed charge from $8.40 per month to $18.40. AEP says the proposal is “revenue-neutral,” while clean energy advocates say it cuts the economic attractiveness of efficiency and solar.
On August 18, Arkansas regulators established a working group to address net metering rates as part of a docket launched in April. According to AEE’s PowerSuite, the net metering working group is expected to issue a recommendation to the commission by September 15, 2017. A public hearing on all other aspects of this proceeding (i.e., net metering contracts, rules, and appropriate terms and conditions) is scheduled for October 4, 2016.
In July, as part of a nearly three-year study of the state's policy on distributed generation, the Iowa Utilities Board directed MidAmerican and Alliant to file new distributed-generation tariffs, to be tried on a pilot basis for three years. The utilities’ initial pilots were rejected for being too burdensome for self-generating customers. Regulators requested new tariffs that encourage the adoption of distributed generation and said the revised tariffs must increase the cap on net metering from 500 kilowatts to 1 megawatt for up to 100 percent of a customer's load.
Midwest Energy News reports that the latest proposals have raised red flags for solar advocates. MidAmerican proposed to allow net metering for solar installations financed through a third party; however, Alliant proposed to establish a maximum size for a net-metered system based on peak demand rather than total annual usage. Solar advocates have characterized the proposal as “non-transparent” and “very complex.”
On August 11, PG&E filed an application for approval of a plan to retire the Diablo Canyon nuclear power facility in 2025, accompanied by plans to replace the output of the facility with zero-carbon emission resources. In its application, PG&E identifies three tranches of zero-emission resources that would partially replace the facility’s historic output of approximately 18,000 gigawatt-hours annually. According to EQ Research, the proposal includes the following:
- Tranche #1: 2,000 gigawatt-hours of energy efficiency secured through competitive solicitations for resources installed prior to 2024 in advance of the planned retirement.
- Tranche #2: 2,000 gigawatt-hours of energy efficiency and emission-free energy (including RPS resources) secured through competitive solicitations for delivery from 2025 to 2030.
- Tranche #3: A voluntary RPS commitment of 55 percent renewables beginning in 2031 (which is 5 percent beyond the 50 percent by 2030 state RPS mandate).
PG&E stated that any remaining replacement generation needs would be addressed as part of the CPUC Integrated Resource Plan proceeding. PG&E has requested permission to recover costs associated with energy efficiency procurement through non-bypassable charges, as well as the establishment of a "Clean Energy Charge" to recover costs associated with zero-emission generation resource acquisition under Tranches #2 and #3.
Officials from Connecticut, Rhode Island and Massachusetts have joined with electric utilities to evaluate more than 50 solicitations from companies to build clean energy plants that would serve all three states, Electric Light and Power reports. The states are hoping to leverage their purchasing power for better terms. The aim is eventually to lower consumers' electricity bills, while also meeting each state’s respective clean energy and environmental goals.
Last month, the Iowa Utilities Board approved MidAmerican's $3.6 billion, 2-gigawatt wind farm that will raise the utility’s generation portfolio to over 85 percent renewables.
On August 29, Florida voters approved a constitutional amendment in the statewide primary that clears the way for solar and other renewable energy systems to receive a property-tax exemption, creating the opportunity for distributed solar to expand in the Sunshine State.
Amendment 4 specifically authorizes the Florida legislature to exempt solar projects on commercial and industrial properties from both the tangible personal property tax and the ad valorem real estate taxes. The amendment builds upon existing law that exempts residential customers from paying property taxes on renewable energy systems, including solar PV, wind turbines, solar water heaters and geothermal heat pumps.
On September 7, Floridians for Solar Choice launched a new campaign opposing Amendment 1 -- a utility-backed amendment that ensures consumers can “own or lease solar equipment installed on their property” and that “consumers who do not choose to install solar are not required to subsidize the costs of backup power and electric grid access to those who do.”
Floridians for Solar Choice introduced its own ballot initiative last year to allow for third-party ownership of solar projects. The initiative failed as a utility-supported group, Consumers for Smart Solar, advanced an opposing initiative to block a policy change. This week, Republicans, Democrats, Libertarians, Greens and non-partisan advocacy groups launched the “Vote No on 1” opposition efforts.
“In true ‘David and Goliath’ form, this grassroots campaign must compete against the nearly $19 million contributed by utilities and their supporters to date,” Floridians for Solar Choice wrote in a statement. Opponents of Amendment 1 claim that the ballot initiative will stifle Florida’s solar market because:
- Amendment 1 is funded by Florida’s big utilities to protect their monopoly markets and limit customer-owned solar
- Amendment 1 paves the way for barriers that would penalize solar customers
- Amendment 1 misleads Florida voters by promising rights and protections that Florida citizens already have
A Virginia State Corporation Commission hearing examiner has rejected a claim from Appalachian Power that customers in its area are forbidden from entering into PPAs with third parties, according to the Southern Environmental Law Center. The hearing examiner determined that third-party financing for residential solar installations is legal under state law while evaluating Appalachian Power's request for an experimental rider for nonresidential customers to purchase renewable generation from a third party developer, but keeps the utility as a middleman.
In 2013, the Virginia legislature set up provisions for a pilot program that allowed PPAs in Dominion Virginia Power’s service area. In 2015, regulators approved the first PPA in the state under that program. Appalachian Power attempted to argue that PPAs were only allowed under approved utility pilot programs like Dominion’s. The hearing examiner’s ruling must still be accepted by the full utility commission, but if upheld, solar advocates believe it will further open Virginia markets to new solar businesses and jobs.
On August 23, Southern Maryland Electric Cooperative (SMECO) and Choptank Electric Cooperative filed a petition for a declaratory order with FERC, requesting that FERC find that the Maryland PSC’s newly promulgated community solar regulations do not comply with PURPA and the Federal Power Act. According to EQ Research, the petitioners argue that the cost of purchases of excess or unsubscribed energy for a community solar facility do not align with express requirements of Maryland statutes because the arrangements involve virtual net metering, where subscribers are provided retail-rate credits.
Specifically, the cooperatives requested that FERC determine: 1) to the extent that community solar regulations require Maryland electric companies to purchase energy from community solar facilities at a particular price, Maryland regulations are pre-empted by federal law unless such facilities are qualifying facilities under PURPA; and 2) community solar regulations that require payment to community solar facilities at prices higher than avoided costs violate, and are pre-empted by, PURPA.
On August 19, 2016, the Oregon PUC issued draft energy storage project proposal guidelines, competitive bidding requirements and proposed storage potential evaluation requirements, according to AEE’s PowerSuite. The guidelines were mandated by the state legislature under HB 2193 and are due by January 1, 2017. Utility-scale energy storage project proposals are to be submitted by January 1, 2018. Comments on the evaluation requirements are due by September 16, and comments on the proposal guidelines and competitive bidding requirements are due by September 30, 2016.
In January 2016, Nevada opened an investigation into electric-vehicle charging infrastructure (16-01018). The PUC held a workshop on August 23, 2016. Participating parties may submit supplemental comments by October 3, 2016.
On August 15, 2016, Ameren Missouri proposed a three-year, nearly $600,000 pilot program to install and operate six electric-vehicle charging stations along Interstate 70, according the St. Louis Dispatch. All of the charging stations would be open to the general public for a flat fee per fixed interval of 15 minutes, the value of which is to be determined by the commission. Ameren Missouri claims that a majority of the costs for the pilot project would be borne by shareholders, and not the rate base. The utility has asked for a final decision by October 15, 2016.
Policy developments are tracked in partnership with EQ Research, which offers in-depth subscription services covering regulatory developments, legislation and general rate cases in all 50 U.S. states.