The top 10 utility regulatory commission issues of 2016
From rate design to grid modernization and storage, state utility regulators had their hands full in 2016
2016 has been a year to remember — or forget.
One polarizing presidential election aside, the power sector has seen a wave of changes in the form of new policies, more consolidation and new energy technologies.
Over the course of 2016, utilities, regulators and other stakeholders debated changes to rate design, cost recovery, grid modernization and data access, just to name a few.
Maryland, for instance, is taking a comprehensive look at ways to integrate new technologies and update aging infrastructure. Other states, like Kansas and California are tackling pilot programs for electric vehicle charging stations. Still others, like Hawaii, New York and Arizona are debating alternative rates for distributed generation.
Because utilities are regulated on the state level, these debates manifest themselves a bit differently in each jurisdiction. Even so, there are a number of broad policy trends occupying regulators and utilities in a number of states nationwide. To help chronicle them, clean energy trade group Advanced Energy Economy compiled what it says are the top ten commission issues of the year.
1. Reforming the Energy Vision
While it did not begin this year, New York’s Reforming the Energy Vision remained a clear choice for a top commission issue this year, AEE experts said during a webinar earlier this month.
Since it was rolled out in 2014, the proceeding has captured the attention of sector observers nationwide with its plan to reform utility revenue models to encourage more adoption of distributed resources.
Under the REV, regulators aim to remove disincentives in the utility regulatory model toward deploying customer-sited solutions like rooftop solar and storage instead grid-scale infrastructure like a new transmission line.
Similar to an air traffic controller, utilities will be transformed into Distributed System Platform Providers that coordinate the interconnection and management of various distributed resources. Instead of earning revenue on their expenditures for the grid, utilities would move toward a model of performance-based ratemaking that would reward them for efficiency gains, customer engagement and a variety of other metrics.
New York regulators split the REV docket into two tracks. Track 1 focuses on the development of distributed resource markets and the utility as the DSP providers. Track 2 of the REV docket focuses on reforming utility ratemaking practices (evolving from traditional cost-of-service) and revenue streams to support the DSPP model.
New York utilities have proposed a variety of pilot projects to test various aspects of DER integration, customer data sharing and third party partnerships.
This year, the REV docket moved out of its theoretical stage, with utilities filing their distribution service plans in June and reporting on the operation of a number of pilot programs, from virtual power plants to online marketplaces for building efficiency.
"We've certainly have laid the groundwork, and this year we're really working on the execution,” Zibelman told Utility Dive this summer.
The PSC issued the Track 2 Order in May of this year. Under the order, the regulators outlined how utilities can earn returns linked to meeting system demands with alternative methods, such as using customer-sited solar and demand management instead of new central station capacity.
The order also recommended time-of-use rates — a rate design popular for its precise targeting of pricing, and Earnings Mechanism Adjustment, which allows utilities to also earn a rate of return if they target four areas, such as energy efficiency, system efficiency, interconnection (of DERs) and customer engagement.
It remains to be seen how regulators will evaluate utility distribution system plans and their pilot program performance, but already the idea behind REV is spreading to other states. Commissions in Illinois and Ohio, for instance, have expressed desire to open up similar dockets to explore grid modernization and performance-based regulation.
2. California reforms
While all New York’s power sector reforms are folded up in REV, California is the hodgepodge of utility reform, with proceedings ranging from EV charging pilot programs to alternative rate designs and programs designed to test the impact of DER incentives on utilities.
Last year saw a wave of changes in the Golden State. Regulators preserved the retail net metering rate, will try to move to default time-of-use rates by 2019 and boosted the renewable energy standard.
This year, the California Public Utilities Commissioner Michael Florio introduced a draft proposal that outlines a framework to align utility ratemaking processes with increasing demand for distributed energy resources. While it doesn’t call for an overhaul of the cost-of-service proceeding, it does share many of the same goals as New York’s REV.
Under the proposal, California’s investor-owned utilities would deploy DERs at a cost-effective rate. But unlike REV, the proposal would reshape the utility regulatory model to apply incentives for traditional infrastructure to DERs as well.
3. Mergers and acquisitions
After a two-year struggle, the utility sector’s biggest merger story appears to be coming to a close.
With its acquisition of mid-Atlantic utility Pepco, Exelon is now the largest utility holding company in the U.S. by customer base. Its completion over raucous protests in Washington is symbolic of a wave of consolidation in the sector, according to Coley Girouard, a utility program associate at AEE.
The consolidation trend is in part spurred by “financial struggles driven by low prices in wholesale markets and increasing penetration of DERs,” Girouard said during the webinar.
For the most part, regulators have given the proposed mergers a warm reception. Examples of other successes include Cleco Corps. takeover by a group of international investors and Emera’s takeover by Teco Energy.
But other proposed mergers haven’t encountered such success. Earlier this year, two very large, high-profile deals were rejected by their respective regulators.
In 2014, NextEra proposed to take over Hawaiian Electric Industries, Hawaii’s dominant utility. But after nearly two years of wrangling and concerns over NextEra’s commitment of renewable energy, the Public Utilities Commission rejected the deal, saying it wasn’t in the public’s best interest and failed to meet the state’s long-term climate goals.
And in 2015, real estate firm Hunt Consolidated filed for approval to acquire Texas’ largest transmission and distributed utility, Oncor, as part of a $17.6 billion deal to spin its parent company Energy Future Holdings out of bankruptcy.
If approved, Hunt would have converted Oncor into a real estate investment trust (REIT). But the deal was dogged by concerns over its impact to ratepayers, and whether a portion of the tax savings would go to ratepayers.
Eventually regulators approved the deal, but attached conditions. As a result, Hunt later withdrew its application and Oncor returned to the auction block.
Now NextEra, after Hawaii’s rejection, is pursuing the Texas utility, offering over $18 billion in a proposal insiders say is on steadier ground than either company’s earlier courtships.
Other pending mergers include Great Energy Plains $8.6 billion takeover of Westar, which still awaits state and federal regulatory approvals.
4. Customer access to analytics
More and more utilities are turning to data analytics as a means to quantify energy usage. Driven in large part by deploying smart meters, utilities are harnessing the information for input and insight into distributed energy technologies. But some regulators are also searching for ways that customers could leverage the same information for their own energy edification.
In Pennsylvania, Robert Powelson, a commissioner on the Public Service Commission, opened a docket to explore opening access to such data analytics for customers.
“I think the competitive markets in Texas and Pennsylvania have shown we embrace competition and disruptive technologies,” Powelson said during AEE’s webinar. “And behind that is emerging data analytics and how it’s empowering customer’s appetite to take a holistic view of energy usage.”
How to manage the manage the deluge of data is key to new revenue streams and improved grid operation. But utilities need to find the necessary software tools to integrate multiple grid technologies and handle ever-escalating quantities of information.
AEE noted a number of states undergoing similar discussions. The Illinois Commerce Commission created Green Button Connect, an automated delivery system that allows third parties to access customer data. Also in May, Xcel Energy reached a settlement in Colorado to address issues over customer data access, while agreeing to implement its version of Green Button Connect down the road.
In Texas, the Public Utility Commission opened two dockets for third party authorization to access data and the other on how to govern the web portal, Smart Meter Texas, that would open up data access for customers.
5. Alternative rate designs
Few topics in the power sector get more contentious than rate design debates.
As DERs proliferate, utilities and regulators are battling it out in hearings to come up with the most precise way to align price signals with peak demand to curb usage during those times.
In 2019, California utilities will move to default time-of-use rates after a regulatory order last year. Colorado and Arizona are also debating major rate design changes regarding distributed solar.
Colorado’s Xcel Energy hashed out a settlement with solar interests, which included a provision to test two pilot time-of-use projects that would eventually result in default TOU rates for all customers.
Other alternative rate structures are not so popular. Nevada is probably the most notorious example after utility regulators raised fixed charges and slashed retail rates for both existing and new net metering customers. Though the decision was eventually reversed, debates over the proper solar compensation mechanism occupied the commission throughout 2016.
In Arizona, debates have long swirled over how to best compensate rooftop solar users for their excess energy. After Arizona regulators approved a small fixed charge on solar customers in 2013, utilities have repeatedly proposed to slash remuneration rates and increase the fixed charge. Now regulators have opened a docket to examine the value of solar, and among the findings would be a new solar rate.
Meanwhile, some Arizona utilities are mulling mandatory residential demand charges as a more palatable option than even time-of-use rates. Demand charges typically charge customers for their highest usage in a short period during the month. These are more commonly seen with commercial and industrial customers, but lately more companies have proposed them for residential customers.
6. Residential demand charges
Fixed charges continue to be a favorite utility rate reform, with 44 proposals filed in the third quarter alone. But many of these requests have met hefty pushback from regulators and stakeholders, pushing some utilities to turn to a new option: residential demand charges.
In Arizona, two rate cases seeking to implement mandatory demand charges on solar customers and all residents captured the national spotlight this year.
UES Electric filed a rate case last year seeking to implement demand charges on all customers. After solar advocates protested, the utility scaled back its proposal to make demand charges an option for non-rooftop solar customers and mandatory for solar.
In another rate case, Arizona’s largest utility, Arizona Public Service Co. is also seeking to apply residential demand charges for its entire service territory. Regulators have staved off a decision until the value of solar docket concludes, but already the proposals have garnered heavy opposition.
Critics say residential demand charges are too complex for the average ratepayer to understand and indirectly punish the customer for scaling back on energy usage. Conversely, they argue time-of-use rates are a more easily understood and more refined way to align pricing with peak demand. How the regulators in Arizona rule on the issue could set the stage for proceedings in other states.
7. Grid modernization
As regulators confront aging infrastructure and a changing energy landscape, ways to modernize and shore up the grid in the wake of natural disasters have never been so pressing.
Several states have opened dockets to take a comprehensive look at grid modernization reforms.
Rhode Island is one state contemplating such measures, and Massachusetts is set to hear proceedings over its utilities’ plans this month. And in March, Minnesota released a report outlining its steps to move toward more distributed energy resources while hardening the grid system. The state is also looking at advanced metering infrastructure, time-varying rates and third party aggregation.
With the exception of Minnesota, all the other states contemplating grid modernization are deregulated. Minnesota is vertically integrated, which means utilities own generation as well as transmission and distribution. If regulators can come up with a replicable model for modernization, it could help lay the groundwork for similar proceedings in the Southeast and other vertically-integrated states.
8. Energy storage
As more states demand more renewables from their utilities, the opportunity for energy storage technology grows. California, for instance, passed bills requiring utilities to ramp up their use of energy storage. And Massachusetts has recently implemented a mandate for energy storage as well.
But who will own energy storage? Mateo Jaramillo, vice president of products at Tesla, said in the webinar that the biggest regulatory debate surrounding energy storage is ownership.
“It’s its own asset,” Jaramillo said. “[Utilities] are deploying storage as generation device and storage device.”
Take Texas, he said. The PUCT classified it as a generation resource, making it illegal for a transmission and distribution utility to own it in the state’s deregulated market. For California, the question lies with whether or not utilities can access behind-the-meter storage, a proposition that has historically worried third party developers.
One of the bills, AB 2868, would allow utilities to own an additional 500 MW of storage capacity behind customers' meters, using ratepayer money to finance the investments, in addition to the required 1,325 MW.
Private developers opposed the bill, but it was approved earlier this year. As more states consider energy storage mandates and the technology continues to proliferate, continued debates over storage ownership are expected.
9. Electric vehicle charging stations
Electrifying the transportation sector will do more than just reduce emissions. For utilities, the new electricity demand can post revenues, while cars on the grid can open new demand-side management opportunities.
Utilities have noted the opportunities and some regulatory states are contending with proposals by utilities to build the EV charging stations with ratepayer money.
But those proposals have been met with a lukewarm reception at best. In California, the Public Utilities Commission has allowed the three biggest investor-owned utilities to move forward with pilot charging programs, but later scaled back Pacific Gas and Electric’s initial proposal amid worries that the utility could squeeze private developers out of the market.
In Kansas City, Missouri, Kansas City Power & Light requested to ratebase more than 1,000 charging stations as part of its ambitious rollout program. But Kansas regulators nixed the proposal in the parts of the metropolitan area that fell into Kansas.
Even so, utilities have still expressed interest in other states to buildout charging stations. And this month, the U.S. Department of Transportation designated roughly 85,000 miles of highway corridor as a national EV charging network.
10. Renewable portfolio standards
Last but not least, the trend for aggressive renewable portfolio standards has only strengthened.
This year, other states set equally ambitious targets: Oregon pledged to source 50% of its renewables by 2050 and phase out exports of coal generation. Rhode Island and the District of Columbia also expanded their RPS, with the New York regulators adopted a mandate to source 50% of its electricity from renewables by 2050 and support aging nuclear generation.
Other states are now examining their own standards in aims of expanding them.
For example, Arizona Corporation Commissioner Doug Little proposed revisiting the standard and looking at broadening its scope to include DERs. How other states will follow remains to be seen.
Far from being static, each of these commission debates will bleed over into 2017. AEE’s Girouard offered some insight into the big commission issues for next year.
One will likely be REV. “In the past, it’s been setting theoretical framework. It will be interesting to see how REV moves into implementation,” Girouard said.
California will also inevitably make headlines — likely related to how Florio’s proposal will move forward, even though he will leave the commission at the end of the year. Girouard said it could be leverage for a more comprehensive review of the utility business model. And for grid modernization efforts, Girouard pointed to Ohio and Illinois as likely hotspots. Washington D.C. also has a staff report for its grid modernization due in December.
As ever rate design “will continue to be important,” he said. Especially interesting will be “to see if utilities will look at other things aside from demand charges and fixed charges … to see if they will look at time-of-use rates and performance based regulation.”
Correction: An earlier version of this piece said Iowa would be a likely hotspot for grid modernization efforts. That is incorrect. An earlier version of this piece also said that the Fortis-ITC Holdings merger is pending, but the deal actually closed in October.
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