As utilities face the rise of distributed resources and face stagnant load growth, a number of states are looking to alter the traditional sector business model through regulatory dockets.
Under the traditional model, utilities make a rate of return for investments in the bulk power system — plants, transmission lines and the like. But those revenues can be threatened in a world where customer efficiency and DER adoption slows load growth.
In response, a number of jurisdictions have adopted regulatory approaches to expand utility earning opportunities and broaden DER adoption through non-wire alternatives, data sharing and other initiatives. New York and California have long held the nation’s spotlight for their efforts, but other states are following suit.
Maryland last year launched its proceeding modeled after New York’s Reforming the Energy Vision Initiative. And Illinois and Ohio are beginning their own efforts to boost reliability and speed the deployment of DERs.
Other states, meanwhile, are taking a more cautious approach, opening narrower proceedings on modernizing the utility distribution system to prepare it for distributed resources. As these efforts continue, Utility Dive takes a look at the top five states where action is taking place and what it means to the power sector.
New York’s Reforming the Energy Vision captured the nation’s imagination three years ago. An ambitious undertaking, regulators sought to remake the utility business model to incentivize deployment of DERs and demand management as an alternative to traditional infrastructure.
To make this goal palatable to utilities—used to collecting a hefty rate of return on massive infrastructure projects—regulators are devising a framework allowing them to earn a rate of return tied to investing in DERs and achieving societal and energy goals.
Eventually, regulators envision the new performance incentives and market-based earnings to facilitate the development of distribution system-level electricity markets — often referred to as transactive energy — where consumers could receive locational and temporal valuation for their customer-sited resources in real time.
Regulators divided the proceeding into two tracks: Track 1 focuses on developing DER markets and the utility as Distributed System Platform provider — akin to an air traffic controller that will interconnect and facilitate the DERs. Track 2 focuses on reforming ratemaking practices for utilities and revenue streams for the DSP provider model.
For the past three years, regulators, utilities and other stakeholders concentrated on filing proposals for the DSIP (Distribution Service Implementation Plans) process and rolling out pilot programs. Within the first three months of 2017, regulators issued a series of orders to find a new compensation structure for DERs, guide the development of DSIPs and deploy two grid-scale battery storage systems.
In particular, the new compensation scheme is a first step toward a gradual transition from retail net metering—a policy crediting rooftop solar users for excess energy sent to the grid.
The proposed pricing mechanism, called the Value Stack, proposes four separate pricing components for DERs and gives utilities 45 days from its filing (March 9, 2017) to outline locational pricing that reflects the stack's components.
“Obviously the DSIPs and more information around that will be very valuable,” said Lisa Frantzis, vice president of Advance Energy Economy.
Frantzis hopes the conversation will also turn to other technologies like storage and fuel cells instead of just focusing on solar.
“I think making sure all the technologies are treated on an equal footing is going to critical.”
These conversations will play out into 2017 as the REV continues to tackle grid modernization and rate reforms.
New York might have captured the spotlight with its utility business model reforms, but California has hammered away its own efforts to integrate DERs since 1998.
A plethora of dockets make up the state’s grid modernization proceedings. Some efforts are aimed at rate reforms and the valuation of distributed energy resources. Others are more comprehensive efforts aimed at easing the integration of renewable energy and distributed energy.
Out of all the dockets, two stand out as the biggest proceedings designed to bolster DERs on the grid: The Distribution Resource Plan (DRP) proceeding and the Integrated Demand-side Resource Proceeding (IDER).
The DRP proceeding guides California’s three investor-owned utilities in finding opportunities to site, value and integrate renewable energy. Throughout the process, utilities will continue to delineate their roles and business opportunities on the distribution grid, likely setting precedents for other states to follow suit.
The IDER proceeding, on the other hand, directs utilities to manage DERs on the grid through demand-side management. Other proceedings bolstering these dockets include rate reform efforts, a DER incentive proposal and numerous filings for electric vehicles, energy storage and distributed energy resource management (DERMS).
And the Chairman of the California Public Utilities Commission Michael Picker recently released his Action Plan summarizing the complex tangle of proceedings neatly into seven pages.
“The Action Plan is a roadmap for where we want to go with DER, the ways we can get there, and what we have to do to achieve the vision that we’ve laid out through 2018,” Picker told Utility Dive.
Going forward, utilities are looking to increase DER deployment in the distribution system through pilot programs designed to allow utilities to collect 4% annually on expenses, as long as they show the investments can defer traditional infrastructure expenses, Frantzis said.
“The goal will be they will get the 4% annually as long as they are able to defer the more traditional infrastructure investment aspects,” Frantzis said.
It’s unclear when, or if, California will wrap up its grid modernization efforts, but 2017 promises many more developments as utilities deploy DER pilot projects and prepare to shift their customers to default time-of-use rate structures in 2019.
Minnesota, not a state known for its high solar penetration, found itself entangled in a familiar policy battle over net metering compensation rates three years ago.
As lawmakers sought to resolve this familiar conundrum, a group of stakeholders embarked on a collaboration effort to reform the utility business model in preparation for a changing energy landscape. While many of these reforms are taking place in deregulated states, Minnesota marks the first time a vertically-integrated market entered the grid modernization challenge.
In contrast to deregulated states, tackling grid reforms in vertically integrated markets— where the utilities own the transmission, distribution and generation systems—is an even harder challenge.
Divided into three phases, the first part of the e21 initiative drafted a blueprint for regulating utilities. The first phase report was released at the end of 2015. And the stakeholders just released the report from the second phase, which concluded at the end of 2016.
In that report, stakeholders crafted a series of white papers on integrated system planning, grid modernization and performance-based regulation. The third phase will focus on regulatory and business model implementations, but details have been sketchy beyond that description.
The PUC opened a grid moderization proceeding separate from e21, and outlined the points of contention and agreement in the e21 Initiative in a report titled “the Minnesota Public Utility Commission Staff Report on Grid Modernization.
The PUC also launched an alternative rate-making effort to address time-of-use rates. The state has largely been quiet this year after releasing their reports, but its efforts are expected to continue with more workshops from the e21 Initiative and both PUC proceedings. In particular, the e21 initiative plans to move into the third phase by starting smaller pilot projects.
“Now in 2017, they (e21) are going to move toward the third phase —their focus there is learning by doing in these little pilot programs,” said Frantzis.
Massachusetts battles with some of the highest electricity prices in the Lower 48, while staring down reliability threats from storms and frigid winters. To deal with these persistent issues, regulators directed investor-owned utilities to file grid modernization plans and time-varying rate proposals, stopping short of setting actual targets and settling for 10-year and 5-year short-term blueprints for infrastructure investments.
In contrast to New York, Massachusetts is taking a more piecemeal approach, focusing on making the system more efficient and resilient through a number of separate dockets, rather than one overarching utility reform proceeding.
One avenue is expanding its incentive programs for energy efficiency to encompass more technologies.
“I think Massachsuetts has had a lot of success with its incentives for energy efficiency,” Frantzis said, which set targets for utilities to earn a certain amount of money if they hit a specific efficiency goal. “I think you know this is something because it’s done well, I think there’s an interest in expanding this program beyond energy efficiency.”
The three IOUs filed their grid modernization plans in 2015, but the PUC has yet to approve them. The three dockets can be found here. While utilities await a decision, some are tackling grid modernization as part of their rate cases.
Eversource filed a $400 million grid modernization plan with state regulators, proposing a substantial investment in energy storage, electric vehicle infrastructure, and an extensive grid management and resource integration system over a five-year span. The utility plans to invest $100 million in energy storage, which comes as the Department of Energy Resources prepares to set a storage target for the state by July.
As 2017 progresses, Massachusetts is set to roll out an energy storage mandate target and prepare the proceeding for Eversource grid modernization request.
The smallest U.S. state joined the ranks of Minnesota, New York and Massachusetts last year for grid modernization.
The state stepped into the spotlight after it extended its renewable energy portfolio standard from 14.5% by 2019 to 38.5% by 2035 with the goal of growing its hefty wind potential. Seeing an increase of renewable energy on the horizon, regulators are now tackling broad questions designed to ease the integration of the resource.
One proceeding is designed to look into four streams of change: utility business models, the distribution system, grid connection and functionality and strategic electricification of transportation and heating system, Frantzis said.
The proceeding—called the Power Sector Transformation—is expected to introduce a straw proposal following a series of technical workshops set between April and May.
“We will see [Rhode Island] take lessons learned in New York and leverage that and because they are a smaller state, they could be more nimble and agile state to implement things,” said Liza Frantzis Maybe because a smaller state more nimble ….I think it will be an interesting state to watch because they have a lot of factors aligning….and a desire to move things forward.”
The state is also in the midst of three-part rate design process. Regulators plan to discuss the costs and benefits of DERs and rate reforms. Frantzis said they are supposed to produce a document in 2017, but other than that, the proceeding has somewhat stalled.
More to come
More states have these five in launching grid modernization proceedings. Maryland’s efforts are just beginning, with the focus zeroing on specific technologies and policies, rather than a comprehensive business model overhaul.
Ohio is also exploring options to upgrade the grid and boost resilience. Dubbed “PowerForward,” the proceeding departs slightly from the REV in that regulators do not have an end goal in mind, instead using information collected in a series of workshops and technical meetings to come up with a final result.
And Illinois is the most recent state to announce efforts to modernize its grid last week, launching its 18-month “NextGrid” study. By 2018, the study will result in a final report for Illinois regulators and lawmakers containing “tangible recommendations” for the grid of the future.
This trend is unlikely to stop anytime soon. How each one will take shape differs state by state, but it’s clear utilities, regulators and other stakeholders are planning for a new energy landscape. In Utility Dive's January 2017 survey of more than 600 sector professionals, only a quarter of respondents indicated they do not want a proceeding in their state to reform sector business models.