Another year has come to a close, marking the end of another tumultuous year in clean energy policy. It was almost exactly a year ago that Nevada utility regulators approved major changes to the state’s distributed solar rates, triggering a backlash from rooftop solar advocates and action from the governor's office. That decision feels at once like forever ago and just yesterday.
Net metering was a prominent solar policy issue throughout 2016, with 22 states that considered or enacted changes to their net metering policies in the third quarter of 2016 alone, according to the NC Clean Energy Technology Center (NCCETC). Utility proposals to increase fixed charges and introduce residential demand charges were also common this year, and elicited strong pushback from the rooftop solar sector.
There were several other significant policy changes in 2016 that helped to expand the large-scale solar market. There were also robust debates in a handful of states about how to treat utilities’ aging coal and nuclear plants.
In the first State Bulletin article of the new year, we offer a roundup of some of the most prominent state-level legislative and regulatory developments that affected the greentech industry in 2016. Click below to jump to a section.
- Net Metering
- Residential Demand Charges
- Fixed Charges
- Third-Party Ownership
- Renewable Portfolio Standard
- Utility-Scale Renewable Energy Procurements
- Smattering of bonus policy updates from EQ Research!
The year started off with a bang for the rooftop solar industry with the Public Utilities Commission of Nevada’s decision to reduce the credit solar customers receive for net excess generation by three-quarters, and triple fixed charges for those customers over a four-year period. The most controversial aspect of the ruling was the decision to apply the changes retroactively to Nevada’s roughly 32,000 existing solar customers, in addition to new ones. The ruling brought the Nevada solar market to a standstill and sparked outrage among customers who saw their expected savings from investing in solar all but disappear.
The PUCN responded in February by lengthening the rate-change timeline from four to 12 years. In September, following months of public outcry, which prompted Republican Governor Brian Sandoval to take action, the PUCN approved an agreement to grandfather existing solar customers back onto their previous, more favorable rates. The deal was negotiated by SolarCity, the Bureau of Consumer Protection, NV Energy and PUCN staff. The September decision did not affect rates for new home solar customers and did nothing to restore the state’s stalled solar market, but was nonetheless heralded as a victory by rooftop solar advocates who were concerned that the Nevada decision would set a dangerous precedent.
“Ultimately, everybody realized the [decision] was so bad…that even NV Energy got on board with grandfathering,” said EQ Research's Rusty Haynes. “That was a terrible decision that nobody wanted to support. And it was eventually turned around, but not without a lot of drama.”
There are multiple efforts currently underway to restore NEM in the Silver State. While a solar industry-led referendum failed to advance this year, the sector found an ally in Governor Sandoval who convened an energy task force that recommended restoring net metering, along with a minimum bill, in 2017. Sandoval also appointed two new commissioners to the three-member PUCN, replacing David Noble and Alaina Burtenshaw.
Earlier this month, the new group of regulators approved raising the NEM cap in Sierra Pacific territory in northern Nevada, reviving part of the state’s solar market in the near term. In June, the PUCN is expected to address NEM in the general rate case for Nevada Power, NV Energy’s subsidiary serving the southern, more populous portion of the state, where the majority of residential solar customers are currently located. Building on Sandoval’s task force recommendations, Nevada’s Democratic-controlled chambers are expected to support legislation allowing for more net metering in 2017.
“I think you’ll see some kind of restoration for NEM or at least a strong legislative push in 2017 supported by the governor’s office, the legislature and certainly the solar industry,” said Haynes.
NEM was also a hot topic to the south of Nevada, where Arizona utility regulators spent the year working through a value-of-solar proceeding (E-00000J-14-0023). Arizona’s three investor-owned utilities -- Arizona Public Service (APS), Tucson Electric Power and UNS Electric -- have each filed proposals to raise rates on distributed solar customers in order to address the cost shift that utilities claim is created by net metering. Regulators chose to delay ruling on these proposals until the overarching value-of-solar docket (that was triggered by APS last fall) came to a close.
On December 20, following months of discussions, the Arizona PUC approved a proposal to compensate distributed solar exports based on a five-year average of utility-scale solar PPA pricing. Meanwhile, the commission will work on establishing an avoided-cost methodology that could be applied in future rate decisions. The decision also limits rate stability, or grandfathering, to 10 years.
Rooftop solar companies will have to adapt to this new rate environment by shifting their focus to technologies that maximize on-site power consumption. Negotiations on the avoided-cost methodology could result in a favorable outcome for the residential solar sector. However, according to GTM Research’s Cory Honeyman, it will likely be difficult for rooftop solar to pencil out with just 10 years of rate certainty.
While Nevada and Arizona acted to reduce NEM compensation this year, several other states protected or expanded the caps on their retail-rate NEM programs, including Michigan, Utah, Illinois, Louisiana and Rhode Island.
New York and California also acted this year to keep some form of NEM in place for home solar customers. As part of New York’s Reforming the Energy Vision proceeding, the New York Department of Public Service released its long-awaited staff report on the value of distributed energy this fall that called for preserving retail-rate NEM for new residential and small commercial projects through 2020. At that point, staff recommended stepping down the credit until it aligns with the ultimate LMP+D value in the DER docket -- and in line with a settlement agreement reached between several utility and solar stakeholders earlier this year.
For community and commercial-scale solar projects in New York, the transition off of retail-rate NEM is to begin right away in order to address lengthy interconnection queues. The staff’s rather complicated proposal (detailed here) is designed to phase in changes over time.
In California, the CPUC approved a NEM successor tariff in January that upheld retail-rate NEM, but also imposed an “aggressive” move to time-of-use (TOU) rates for net-metered customers. As soon as utilities reach their residential solar cap at 5 percent of peak demand, NEM solar customers will be required to move to TOU rates that charge different prices during different times of the day, to better match real-time costs of generating and transmitting energy across the grid at large. On December 15, California regulators issued a proposed decision on TOU rate reforms.
A common theme in both New York and California is that regulators are seeking to make rates for residential solar customers more time- and location-dependent in order to better reflect the costs and benefits that distributed solar provides. Arizona is also expected to adopt this approach in its avoided-cost methodology. The Nevada energy task force recommended taking this comprehensive approach too. While this type of accounting can be more accurate, it’s also complex and spurs long and detailed conversations about which factors a value or cost of solar analysis should include.
“The beauty of traditional NEM is that it’s really easy to understand,” said Haynes. “I think, honestly, a lot of politicians and regulators and even folks buried in this stuff don’t look forward to massive regulatory and legislative battles on how NEM should be changed.”
“It’s risky to open those conversations because it’s unclear what the outcome will be,” he added. “A value-of-solar analysis might be more accurate if you can get the methodology right, but it is certainly a huge investment of resources by solar companies, commissions and other stakeholders.”
Over the next year, the work being conducted by leading residential solar markets will hopefully help to inform states that are just starting to re-evaluate their NEM policies so that these states don’t make premature or overly simplistic changes that result in another Nevada-style solar market freeze.
RESIDENTIAL DEMAND CHARGES
Mandatory residential demand charges are another state-level policy issue that grabbed headlines this year. Many utilities consider these charges, which are based on a customer’s highest kilowatt demand during a set period of time, as a way to manage peak load and recuperate investments in the grid system.
Arizona Public Service (APS), the largest investor-owned utility in the state, filed a proposal for universal demand charges in June as part of its general rate case. By moving to widespread demand rates, “we can save money on the amount of resources we have to invest in or operate to meet our system peak, [and] our customers save money,” said Greg Bernosky, APS director of state regulation and compliance, earlier this year.
Rooftop solar companies view demand charges as an industry death sentence, however, because the higher rates erode solar customers’ monthly savings. Most consumer groups are also staunchly opposed to the rates because they can be difficult for customers to manage and can result in higher overall monthly bills.
For that reason, lawmakers rejected universal residential demand charges proposed by Commonwealth Edison in Illinois this year, and an administrative law judge issued a report earlier this month rejecting universal demand charges proposed by Oklahoma Gas and Electric (OG&E). Opponents of demand charges point to the Glasgow Electric Plant Board’s rate controversy, where customers have seen huge bill spikes and the attorney general has had to step in.
Policymakers have also been hesitant to approve demand charges specifically for residential solar customers. In August, Arizona regulators rejected UniSource Energy Services’ request to impose demand charges on all residential solar customers.
“I think most commissions are deciding that residential demand charges are just too damn hard for customers to handle,” said Haynes. A previous EQ Research analysis pointed out that demand charges aren’t getting as much traction as it might seem.
Demand-charge debates are far from over, however. Rocky Mountain Power, for instance, filed a proposal with the Utah Public Service Commission on November 9 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. Rooftop solar advocates say the changes would effectively kill the state’s rooftop solar market -- similar to Nevada where installations dropped more than 90 percent after the NEM changes were implemented.
In addition to Utah, solar and consumer advocates will be paying close attention to APS’ demand-charge request in Arizona in 2017. Unlike other utilities, APS has had an optional residential demand rate in place for more than a decade, with 120,000 customers currently on that plan. This track record could help the utility win approval.
Increasing fixed charges was another common policy change this year with implications for cleantech, since these rate reforms often diminish the value proposition of DERs and disincentivize energy-efficiency upgrades. According to the NCCETC, 44 utilities in 25 states plus Washington, D.C. had pending or decided requests to increase monthly fixed charges on all residential customers by at least 10 percent, as of the third quarter of 2016.
OG&E, which sought do introduce residential demand charges, also requested to double fixed fees for all residential customers this year. The Oklahoma administrative law judge that rejected the demand-charge proposal also refused the fixed-charge increase in a December report. Furthermore, the judge refused OG&E’s request to introduce a new fixed fee specifically for solar customers.
Taken together, OG&E’s rate request represents one of the most dramatic residential regulatory changes in the country. Haynes called it a “smorgasbord of hell from the solar perspective.” A final PUC decision is expected early in the new year.
While many utilities pushed for fixed-charge increases this year, regulators scaled back the proposals in most cases. In Colorado, stakeholders reached a settlement where Xcel withdrew its proposed grid access fee and agreed to implement TOU rates on a trial basis instead. More than two dozen parties signed on to the deal, which had strong support from rooftop solar companies. The agreement was approved in November.
Connecticut was the outlier in 2016, where regulators actually reduced residential fixed fees. In a recent decision, the Public Utilities Regulatory Authority reduced the monthly service charge from $17.25 to $9.64.
“I’ve never seen a commission lower a utility’s residential fixed charge by anything more than a few cents,” said Haynes. “It’s a huge victory and could possibly set a precedent around the country if consumer advocates go to states that are friendly in this respect.”
Last year was a good year for residential solar in Florida. In November, a bipartisan grassroots coalition successfully defeated a utility-supported measure (Amendment 1) to put restrictions on solar in the state. The coalition opposing the measure, 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. But that initiative ultimately failed.
While solar advocates did not succeed in getting third-party ownership (TPO) approved, defeating Amendment 1 ensured that utilities couldn’t make it even harder to sell residential solar. In August, Florida voters approved a separate measure (Amendment 4) that authorizes the state legislature to exempt residential and commercial solar projects from both the tangible personal property tax and the ad valorem real estate taxes. Because of these changes, and a shift in focus from lease to loans, SolarCity decided to launch a home solar service in Florida late this year.
Rhode Island also saw policy action on TPO this year with legal clarification that TPO is indeed allowed, according to Haynes. The bill included several other goodies for solar as well, including an increase of the net metering cap and an extension of the renewable energy standard.
RENEWABLE PORTFOLIO STANDARDS
In 2015, California passed a bill targeting a 50 percent renewable electricity mix by 2030, and Hawaii set a goal to go 100 percent renewable by 2045. In 2016, New York officially joined the party by setting a 50 percent renewable energy target. Oregon and Washington, D.C. boosted their renewable energy targets to 50 percent, too.
Massachusetts passed a bill this year to boost procurements of offshore wind. Michigan recently raised its renewable portfolio standard from 10 percent to 15 percent by 2021. And Illinois made important changes to its RPS program that caused funds for renewable energy projects to go unused.
In another significant move, Ohio Governor John Kasich vetoed a bill to extend a freeze on the state’s renewable energy and efficiency standards, just days before the end of the year.
Utility-Scale Renewable Energy Procurements
While residential solar often steals the spotlight when it comes to cleantech policy, it’s important to note that utility-scale solar also saw major gains this year thanks to policy approvals. In July, Georgia regulators approved Georgia Power and Light’s integrated resource plan, which includes procuring 1,200 megawatts of renewables, including 150 megawatts of distributed generation and no more than 300 megawatts of wind generation.
In Florida, regulators approved a new rate plan that allows Florida Power & Light to invest in 1,200 megawatts of utility-scale solar (subject to a cost-effectiveness test). American Electric Power agreed to develop 900 megawatts of renewables as part of a compromise deal to salvage the utility’s aging power plants. Utilities in Tennessee, North Carolina, South Carolina and elsewhere in the Southeast also continue to make significant investments in solar and wind.
Another important policy story of 2016 was how regulators and legislators dealt with utilities’ aging generation assets. In Illinois, where clean energy advocates saw wins on net metering and fixes to the state’s renewable portfolio standard, lawmakers also agreed to direct $235 million in annual ratepayer subsidies to Exelon’s uneconomic nuclear plants as part of the Future Energy Jobs Bill (SB 2814). Had the bill failed, Exelon planned to close the Clinton Power Station on June 1, 2017, and shutter the Quad Cities Generating Station a year later. The two facilities have lost a combined $800 million in the past seven years.
In New York, policymakers approved subsidies for three nuclear power plants as part of the state’s clean energy plans, although critics say the credits will ratepayers $7.6 billion over the program's 12-year lifespan.
In Ohio, after years of negotiations, regulators approved a customer surcharge of up to $204 million per year to support FirstEnergy’s struggling nuclear and coal plants, despite strong opposition. The decision is expected to be litigated. Ohio regulators also approved a pared-down version of American Electric Power's request to receive profit guarantees for its coal-fired power plants.
Illinois, New York and Ohio are all deregulated electricity markets, which has caused critics to label the power plant deals “bailouts” that run counter to free market principles. FirstEnergy CEO Chuck Jones recently said he plans to exit the competitive energy business unless Ohio and Pennsylvania return to regulated market structures.
“Both FirstEnergy and AEP in Ohio are pushing for legislative change to push the market to be reregulated,” said EQ Research analyst Benjamin Inskeep. “I would be surprised if the legislature was amendable to backtracking on this. They’ve gone through a major restructuring over last decade, so this would be a dramatic reversal in that policy for the state.”
“It’s an uphill push, but the utilities do have a lot of swing in the states,” he added.
Nevada, meanwhile, is going in the opposite direction. In November, voters overwhelmingly approved a ballot initiative to deregulate the state’s electricity market. Several Nevada casinos supported the initiative, as well as Switch and Tesla. The proposal must also pass on the 2018 ballot and will require legislative action in order to become law, but the vote sent a strong signal that is the direction Nevada’s biggest customers want to go.
Some utilities are also taking a different approach when it comes to their aging generation assets. In Michigan, Entergy announced earlier this month that it plans to shut down its Lake Michigan nuclear plant in 2018 -- taking a notably different path than Illinois and others. The decision is subject to regulatory approval. In California, meanwhile, PG&E announced a plan this summer to replace Diablo Canyon’s 2.3 gigawatts of generation capacity with a host of zero-carbon emissions resources.
On a related note, President-elect Donald Trump’s team is reportedly looking at ways for the Department of Energy to help stave off additional premature power plant closures.
“I think it’s definitely an issue we’ll see more of in 2017 and 2018. What do we do with those nuclear facilities that might not be economic to operate in deregulated wholesale power markets?” said Inskeep. “It’s an important policy question in terms of whether or not it’s a good idea to let those facilities retire versus continue to operate, particularly from a climate perspective. Some people argue we shouldn’t let them retire because they will be replaced by natural gas."
Several states made policy changes this year to advance community solar -- a market that GTM Research expects to total half a gigawatt each year by 2020. Maryland finalized community solar rules. Massachusetts is in the process of restructuring its SREC program, which could boost the community solar market depending on how the program is structured. Pacific Gas & Electric launched a community solar program early in the year.
New York sought to tackle a backlog of community solar applications with a new formula for compensating customers for their excess power generation. Minnesota also continues to struggle with a backlog of applications two years into the state’s program. The state dealt with 12 formal interconnection disputes filed by solar companies against Xcel Energy this year. However, stakeholders are reportedly making progress on the issues. Minnesota also became the first state to adopt a value-of-solar rate for community solar earlier this year, which is designed to increase transparency and reduce risk for program participants.
The community solar trend is expected to continue gathering momentum in 2017 as more utilities see it as an opportunity to serve customers in different ways.
BONUS POLICY UPDATES FROM EQ RESEARCH!
Minnesota (Grid Modernization, Interconnection): On December 1, Xcel filed a Distribution-System Study, as required by the PUC in a June 2016 order in this proceeding. The study includes the discrete hosting capacity of more than 1,000 individual feeders on the Xcel distribution system, but without any analysis of the cumulative effects of DER additions to substations or the transmission system. Xcel stated that as DG penetration increases, system constraints are likely to limit hosting capacity in various geographical areas. For example, a substation may have three feeders with 3 MW of available capacity, but the substation or transmission systems may not have 9 MW of available capacity. Xcel stated that it will need to further analyze upstream ramifications as DG penetration increases, that it has also not been able to factor in the impacts from the existing and proposed DG on the grid (778 MW) in this initial analysis, and that more work needs to be done to address the limitations of the initial study. The determination of exactly where and how much DG can be added to the system will be determined through the interconnection process.
Missouri: On December 21, the state's PSC issued a report and order that approves Ameren’s proposed Solar Partnership Pilot Program, subject to the conditions and terms contained in a non-unanimous stipulation and agreement filed in August, despite numerous objections from Public Counsel. The order allows Ameren to construct, install, own, operate, maintain and otherwise control and manage various small distributed PV systems at different locations in its service territory. The PSC noted in its decision that in granting this application, it “is not making any policy determinations regarding the preferred structure of distributed solar generation programs in the future.” Under the Solar Partnership Pilot Program, Ameren may own, operate and maintain PV system equipment on a customer’s premises under a 25-year lease agreement. Notably, Ameren would retain and own all electricity and associated renewables attributes from these facilities. Capital investment is limited to $10 million and the cost of each PV facility is capped at $2.20/W (DC).
Also in Missouri, another legislative effort to overhaul Missouri’s electric-utility sector has been proposed.
In Vermont, GMP announced that it will offer customers the option to go completely off-grid with a new suite of products including PV, battery storage and home automation. GMP’s Off-Grid Package allows customers to use backup generation for short periods of time if needed. Customers will pay a flat monthly fee. GMP states that the off-grid option will allow it to retire line sections over time, reducing maintenance costs and lowering costs for customers.
New Jersey regulators have laid the foundation for a microgrid push in the state. A new report on microgrids, published by the staff of the New Jersey Board of Public Utilities (BPU), has found that 50 microgrids are currently operating in the state. Six of these microgrids utilize renewables, and 12 have islanding capability. Notably, none of New Jersey’s 50 microgrids are Level 3 (i.e., advanced) microgrids, which serve multiple buildings and/or customers, although two Level 3 microgrids are currently under development.
The report is intended to inform the BPU on microgrids so that it can make better policy decisions. The report includes several recommendations, while noting that it is likely, due to declining costs of DER technologies, that New Jersey could see a migration of customers from the electric distribution system to DER systems.
California regulators approved electric-vehicle charging infrastructure programs for all three investor-owned utilities this year. The California Energy Commission also initiated a rulemaking this fall to address municipal electric vehicle infrastructure in response to SB 350, which requires the commission to produce guidelines for and to review integrated resource plans from publicly owned electric utilities. SB 350 also requires POUs to include procurement for transportation electrification, among other new requirements, in integrated resource planning by January 1, 2019. Specifically, this docket will address the electric transportation elements of IRPs required of California’s POUs.
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.
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