by Julia Pyper
November 23, 2016

Since the election of Donald Trump, there’s been widespread speculation about the future of U.S. clean energy policy. It’s widely believed that the next administration will throw out the Clean Power Plan and disregard the Paris climate agreement (although Trump may be reconsidering).

Whatever happens next, policy action at the state level is expected to intensify -- driven not only by federal policy shifts, but also by local initiatives and market forces.

In this week's roundup, we document recent state-level policy developments from around the country related to demand charges, resource planning, value of DERs, electric vehicles and ballot initiatives (click to jump to a section).

Read our previous state news roundup here.



UPDATE: The Illinois General Assembly passed The Future Energy Jobs Bill on December 1.

Exelon and Commonwealth Edison have stripped several problematic provisions from a comprehensive energy bill, including mandated residential demand charges. The changes are a last-minute attempt to win support for the bill, with just three days remaining in the Illinois legislative session.

ComEd and parent company Exelon introduced a sweeping energy bill in May, after a set of energy bills failed to pass in 2015. A key element of the bill is a program to keep open two of Exelon’s struggling nuclear power plants at a cost to ratepayers of up to $265 million per year. Unless the bill passes, Exelon says its Clinton Power Station will close on June 1, 2017, and its Quad Cities Generating Station will close on June 1, 2018. The two plants have lost a combined $800 million in the past seven years.

An updated version of the bill introduced this month -- dubbed the Future Energy Jobs Bill (SB 2814) -- proposed to also offer credits for coal-fired power plants in southern Illinois owned by Texas-based Dynegy. The provision came as a sort of peace offering to end Dynegy’s opposition to the bill, but it fueled backlash from environmental and consumer groups.

On November 22, ComEd issued a statement proposing to eliminate the demand-based rate provision to reflect feedback received from stakeholders, including Governor Bruce Rauner’s office. The proposed changes also include dropping the requirement for ratepayers to support Dynegy’s two downstate coal plants, as well as reducing the number of utility-owned microgrids from five to three and expanding rebates for solar installations. The plan to preserve Exelon’s Clinton and Quad Cities nuclear power plants remains intact.

Solar companies welcomed ComEd’s decision to drop the demand charges. The latest revisions would also allow retail-rate net metering for solar customers to continue up to 5 percent of ComEd’s peak demand, rather than cutting the net metering credit as the utility initially proposed. Amy Hart, spokesperson for The Alliance for Solar Choice (TASC), said that solar companies were pleased with the changes to the bill, but still have concerns.

“There may still be important tweaks needed to the bill, including ensuring a full stakeholder process at the Commission when the 5 percent net metering cap is reached to guarantee a fair valuation of the benefits of rooftop solar, ensuring distributed solar can continue to thrive, creating job opportunities and improving Illinois’ environment,” she said.

Other stakeholders also have lingering concerns about the bill; however, with most consumer and environmental groups now on board it is at least possible to see a path that allows the legislation to pass before the Illinois legislature’s veto session ends on December 1.


On November 9, Rocky Mountain Power filed a proposal with the Utah Public Service Commission to change the utility’s net metering policy for new rooftop solar customers, which a coalition of solar companies say will severely dampen the market.

The Salt Lake Tribune reports that Rocky Mountain Power is seeking to replace the current NEM rate structure with a three-part rate that would include a $15 fixed charge, a 3.81 cents per kilowatt-hour energy-use charge and a $9.02 peak-demand charge. The proposed demand charges are based on a customer’s highest hour of average electricity usage within a given month.

Under the new rate schedule, Rocky Mountain Power says a typical net metering customer would pay $74 a month, up from the current average bill of $55 a month. The utility says that non-solar customers pay an average monthly bill of $114 per month.

The new rates would affect only new rooftop solar customers applying for a NEM connection after December 9, 2016. All current net metering customers would remain under the existing rules, where they pay a $6 fixed fee and a volumetric rate ranging from 8.5 cents to 14.5 cents per kilowatt-hour. On average, current solar customers are paid 10.6 cents per kilowatt-hour for their excess solar power.

Under the existing policy, Rocky Mountain Power attests each net-metering customer receives a $400 yearly subsidy from non-solar customers. At today’s adoption levels, the cost shift amounts to $6.5 million each year. If left unaddressed, the utility says the cost shift could grow to $667 million over the next 20 years.

The number of net metering customers in Utah has already increased dramatically from about 1,500 in 2012 to 6,700 in 2015. Rocky Mountain Power projects there will be a total of 17,230 customers by the end of 2016. In addition to the shift to a three-part rate, Rocky Mountain Power is also proposing a new $60 application fee for net metering customers to cover the costs of processing the applications.

“Customers partially relying on renewable energy through the net-metering program must still pay their fair share of the costs to serve them,” said Gary Hoogeveen, Rocky Mountain Power senior vice-president and chief commercial officer, in a statement.

Meanwhile, solar advocates say the Utah utility’s proposal would effectively kill the state’s rooftop solar market, similar to the policy changes in Nevada supported by NV Energy -- which is also owned by Rocky Mountain Power's parent company Berkshire Hathaway.

“In response to Rocky Mountain Power's filing, Utah policymakers must establish fair and appropriate rates for solar customers,” a group of 20 local and national solar companies issued a collective statement to Utah policymakers. “We encourage the Public Service Commission to foster a collaborative, transparent process and to recognize all the benefits rooftop solar generation provides to the power system.”

In Nevada, rooftop solar applications dropped by more than 90 percent after the state imposed higher fees on solar customers, and more than a dozen local and national solar companies were forced to go out of business, cut jobs, or leave the state, according to the solar consortium. 

“Policymakers should protect solar jobs and consumers and reject efforts by Rocky Mountain Power to similarly undercut energy competition in Utah,” the statement says. 

Michele Beck, director of the Utah Office of Consumer Services, told The Salt Lake Tribune that the solar industry's concerns might fall outside the scope of the regulatory discussion. "The question is, is it a fair allocation of costs," not whether the policy change is going to impact solar, she said.

Rocky Mountain Power has requested the PSC to approve the proposed rate schedule by December 10.



After three years of negotiations, Ohio regulators have approved a pared-down version of American Electric Power's request to receive profit guarantees for its coal-fired power plants.

Initially, AEP proposed to buy 3,100 megawatts of power from nine of its own coal plants as well as its contractual share of Ohio Valley Electric Corp’s fleet through a PPA. On November 3, regulators approved a profit guarantee provision that only applies to AEP's 440-megawatt share of Ohio Valley Electric Corp., The Columbus Dispatch reports.

The November decision also includes a provision that requires AEP to add 900 megawatts of renewable energy in Ohio by 2020, half of which can be owned by an AEP affiliate and recovered through a long-term PPA. The plan to build 500 megawatts of wind power and 400 megawatts of solar stems from a major settlement deal between AEP and the Sierra Club, signed in December 2015. 

The final agreement will give Ohio’s renewable energy market a major boost. Ohio currently has 444 megawatts of wind farms and 119 megawatts of solar projects. But while it's a significant win for environmentalists, Asim Haque, the Public Utilities Commission of Ohio chairman, expressed hesitation over the design of the deal.

"I have asked myself many times, by allowing AEP cost recovery for utility-scale renewable development, [will we] actually hinder overall development, as this is not a fully market-based solution," he said in a statement. "Eventually, would the large-scale projects being contemplated by AEP be constructed through purely competitive forces? Perhaps."

The November 3 decision comes after a series of revisions since AEP first submitted the case in 2013. The plan initially faced strong opposition from consumer and environmental groups, and was challenged by the Federal Energy Regulatory Commission.


The Missouri Public Service Commission has established a list of contemporary policy issues that major electric utilities -- Ameren, KCP&L, KCP&L GMO and Empire District Electric -- must address in their integrated resource planning (IRP) filings or annual IRP update reports. According to EQ Research, the requirements include:

  • Evaluating the potential demand and energy load associated with EVs in their service territory.
  • Reviewing the options available to provide customer financing for energy efficiency.
  • Discussing plans to expand DG deployment.
  • Describing and documenting the roles which energy storage and conservation voltage reductions could play in system planning, particularly regarding DSM and DERs.
  • Evaluating the need to upgrade and enhance delivery infrastructure in order to ensure and advance system resiliency, reliability and sustainability.
  • Describing and documenting how investments in grid modernization, DSM, and renewables will ensure that the public interest is adequately served and that other state policy objectives are met.
  • Describing and documenting how standby rates, tariffs and interconnection standards facilitate the development of customer-owned DG resources and microgrids.
  • Reviewing plans to make TOU rates available to all customers.
  • Analyzing and documenting the future capital and operating costs faced by each coal-fired generator in order to comply with environmental standards.



On November 15, stakeholders filed a new round comments in Arizona's high-stakes value of solar proceeding (E-00000J-14-0023). The comments address an administrative law judge's recommended order and opinion (ROO) that states net metering “should eventually be eliminated."

Judge Teena Jibilian supported two rate proposals in the ROO that were initially put forward by commission staff. The first proposal, the Resource Comparison Proxy (RCP) methodology, would use a five-year rolling average of a utility’s solar PPAs and utility-owned solar projects as a proxy for the valuation of distributed solar exports, to be reassessed every few years in each electric utility’s rate case. The second proposal, the Avoided Cost Methodology, would use five-year forecasting to evaluate eligible costs and values of energy, capacity and other services delivered to the grid from distributed generation.

In last week's filings, Arizona Public Service wrote in support of a plan to adopt the RCP methodology in the near term, and transition to an avoided-cost methodology over time. An avoided-cost approach is APS' preferred solution, said Greg Bernosky, APS director of state regulation compliance, in a recent interview. However, he acknowledged that more time and study is needed to determine which inputs would be used to get the avoided-cost calculation right.

Rooftop solar advocates took issue with specific elements of the ROO in their comments. For one thing, utility-scale solar projects should not be used as a proxy in the RCP methodology for rooftop solar, said Vote Solar's Briana Kobor. Vote Solar also objected to the judge's five-year forecasting proposal in the avoided-cost methodology. Solar advocates believe the benefits of solar should be evaluated over a longer period of time.

An open meeting for the Arizona Corporation Commission to vote on the value-of-solar docket is scheduled for December 19 and 20.

New York

Staff of the New York State Public Service Commission recently issued a report on how to fully value DERs and consumer-driven technologies and for compensating consumers, third-party developers and utilities for that value. Among the recommendations, the long-awaited Phase 1 report states that retail-rate net energy metering for new residential and small commercial projects should remain in place through 2020, and existing solar projects should receive the full retail-rate net energy metering credit for 20 years from the date of installation. Meanwhile, the report recommends rate changes for community-scale and C&I projects that would go into effect in January.

C&I and community-scale projects currently underway but which won't come into service until January can be compensated under the current net metering policy, if they pay 25 percent of the interconnection costs or execute an interconnection contract within 90 business days of the Phase 1 order being issued. The report recommends other projects move to a new rate that includes a market transition credit (MTC), which is expected to make compensation for a project equal to the existing net metering policy in the first tranche, 10 percent less than net metering in the second tranche and 20 percent less in the third tranche. Stakeholders are still evaluating how the MTC is designed and how it will affect solar projects in the state.

Additional comments are expected on the MTC and how energy, capacity and environmental values for community and C&I solar are calculated in the Phase 1 rate, as outlined in previous GTM Squared reporting. Initial comments on the PSC report are due December 5, 2016, with reply comments due December 19, 2016. Action on the Phase 1 recommendations is expected in January. Work on a Phase 2 proposal will start immediately, and it will be filed in December 2018.



An administrative law judge has issued a ruling on Pacific Gas & Electric’s EV charging program that will support the deployment of 7,500 Level 2 EV charging stations at a total cost of $130 million. The November 14 ruling settles months of debate by limiting utility ownership to no more than 35 percent of the ports.

PG&E initially filed a proposal last year to build 25,000 charging stations at cost of $650 million, which was denied over concerns about the high price tag and “unfair competition.” In March, PG&E put forward a scaled-down version of its plan, asking for $160 million for 7,500 charging stations.

For both proposals, a group of technology providers -- including ChargePoint, EV Connect, NRG Energy’s eVgo -- took issue with the level of control PG&E would have over which type of charging equipment is used, which companies can be involved in operating the units, and how their services will be priced.

The latest ruling addresses those concerns by limiting utility ownership of the EV infrastructure to 35 percent with a focus on multiunit and low-income dwellings. Also, where PG&E owns the charging station, the site hosts will still be responsible for choosing the infrastructure vendor, which is intended to help ensure innovation in market products and services.

The site host may also determine the rate structure charging cost, subject to the obligation to implement a load management plan reflecting best practices. As a condition of participation, hosts will need to make a meaningful contribution to the project.

Where PG&E does not own the charging stations, the utility will still provide varying levels of site host rebates. It will also provide “make ready” infrastructure, such as wiring and metering, so the space is prepared to host a charger.

“This proposed decision accelerates the adoption of EV charging in Northern California in a way that preserves innovation and competition,” said Pasquale Romano, CEO of ChargePoint, in a statement.

Earlier this year, the CPUC gave unanimous approval to two EV charging programs – San Diego Gas & Electric’s plan to develop a pilot program to deploy 3,500 EV charging stations in the San Diego area, and Southern California Edison’s plan to deploy 1,500 charging stations across its territory. The CPUC will consider the proposed PG&E program at its December 15 meeting.



Nevada voters have approved a measure that is designed to break up NV Energy's legal monopoly on electricity sales and customers. The Energy Choice Initiative was backed by the data center company Switch and the Las Vegas Sands casino company. The initiative was launched as companies sought to ditch NV Energy and find their own providers, but were blocked by high exit fees.

The ballot measure will require the Nevada legislature to create a plan for deregulating the state's electrical market and opening it up to competition. The initiative must be approved again in 2018 in order to amend the state constitution.


A bipartisan grassroots coalition successfully defeated a utility-supported measure to put restrictions on solar in the state of Florida on election day.

Amendment 1 was voted down on November 8, failing to win the 60 percent support it needed to pass. The loss comes despite more than $25 million in backing from large energy companies. Major contributors include Florida Power and Light, the state’s largest electric utility, and Duke Energy, the second-largest utility.

The coalition opposing the measure, Floridians for Solar Choice, is made up of solar companies, environmental organizations, Tea Party groups and elected officials. Floridians for Solar Choice was the first Florida group to launch a solar ballot initiative for the 2016 election, in which the group sought to allow for third-party solar power agreements. That measure failed to collect the necessary number of signatures in time to advance, while the utility-sponsored measure was able to proceed.

The defeat of Amendment 1 comes after Floridians voted overwhelmingly in favor of Amendment 4 in the August statewide primary. Amendment 4 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. Pro-solar groups in Florida now plan to shift their attention to ensuring that Amendment 4 is implemented swiftly.


Voters in Washington state rejected a ballot measure in the November 8 election that would have created the nation’s first carbon tax on fossil fuels. Initiative 732 would have imposed $15 per metric ton levy on carbon emissions starting in July 2017, and increasing in the following years. The initiative was defeated amid conflict between green groups.


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.