The best laid plans of state regulators are now aimed at building a better distribution system
Posted by admin on Jan 31, 2018
How many roads must distribution system planning walk down, before it fully values distributed energy resources?
The answer is not blowing in the wind but is elusive, according to a new report from Department of Energy researchers. There is a wide variety of distribution system planning in states that have adopted “advanced elements of integrated distribution system planning and analysis.” And an even “broader array” of approaches in states with more traditional planning methods.
Existing planning tools and procedures “are not adequate” to deal with rising penetrations of distributed energy resources (DER), according to Pacific Northwest National Laboratories Senior Energy Analyst and report lead author Juliet Homer. Methods to accurately and dynamically forecast how quickly DER penetrations will increase and what their impacts will be on the distribution system are lacking.
But what would be considered adequate among the many approaches to distribution system planning depends on each state’s unique drivers and goals, Homer told Utility Dive.
Only New York, California, Hawaii, Massachusetts, and Minnesota directly engage in comprehensive five-year to ten-year planning, the report says. Others have adopted some longer-term but more limited planning requirements for regulated utilities or are considering doing so. In those states, planners are working through policy and markets to grow DER and optimize its value for customers and the system.
Safety, reliability, and affordability continue to be the goals of planning for any utility. But planners considering DER have begun thinking about using planning to assess the locational value of DER, using them as non-wires solutions to distribution system expenditures, and finding opportunities to introduce emerging technologies like electric vehicles and battery storage.
The report recognizes that states’ highly varied system needs to limit any uniformity of approaches to distribution system planning. Initial steps might include making inputs for DER growth more consistent with the inputs for load forecasts and using the same kinds of scenarios and modeling methods, the report suggests.
But it shows there is an opportunity to learn from the many state distribution system planning efforts to meet the challenge of rising DER. It also shows what other challenges states are meeting through more attention to planning at the distribution system level.
DER is not the only reason for distribution system planning, the report adds. Many regulators see such planning as a way to better engage customers, cut costs or improve reliability. Others see planning as a means to achieve cost-effective grid modernization or a way to replace aging infrastructure with new technologies.
Many states have legislatively-mandated or commission-ordered planning requirements that do not represent comprehensive distribution system planning. Other, more limited, planning requirements have been imposed in general rate cases. Some state utility commissions have tied limited distribution planning that includes utility expenditures to cost recovery. Newer planning requirements are for DER forecasting, non-wires solution locational valuations or hosting capacity analysis.
The newest distribution planning ideas are about resource procurement, the report says. Some states, like California, are testing competitive solicitations for DER. New York is expanding its leadership in valuing non-wires solutions and exploring ways to include capital planning in the planning process.
Michael Picker, president of the California Public Utilities Commission(CPUC), told Utility Dive he finds the various approaches to distribution system planning intriguing because “everybody is in such different places.”
PNNL’s Homer said both New York and California are working on long-term distribution system plans to reverse the longstanding sense of the distribution system as a “black box” that only utilities understand. New York is a leader in standardizing procedures and transparent planning methodologies that support DER markets, she said.
One of the key goals of its public service commission-ordered Reforming the Energy Vision (REV) is “market animation and leverage of customer contributions,” the DOE report says.
The REV requires utilities to work together to develop standard tools, processes, methodologies, and protocols, Homer said. As a result, New York is at the forefront of developing the incipient hosting capacity analysis central in distribution system planning to location-specific and time-specific values for DER.
The suitability criteria for non-wires solutions being developed by New York’s utilities may be one of the more advanced efforts to standardize DER valuation in planning, Homer said. “If a utility identifies a location that meets the suitability criteria, it is obliged to make that information publicly available and issue a request for proposals for non-wires alternatives to traditional investments.”
The objectives of California’s distribution system planning, though legislatively-mandated rather than commission-ordered, are similar. One is to “enable customer choice of new technologies and services,” the report says. Another is to “animate opportunities for DERs to realize benefits through the provision of grid services.”
California is also at the forefront of developing hosting capacity analysis and defining locational value for DER in its distribution system planning. It requires all utilities to use the CPUC avoided cost calculator to identify, and make public, granular system-wide locational values for DER, Homer said.
The new attention to distribution system planning extends far beyond New York and California.
Oregon does not have a distribution system planning process but is working on smart grid planning in anticipation of rising DER penetrations, Elaine Prause, a regulatory affairs senior advisor with the Oregon Public Utilities Commission, told Utility Dive.
Oregon could benefit from the more rigorous DER forecasting that distribution system plans provide, Prause said. The public utility commission recently recommended that the state’s utilities work with other stakeholders to develop a set of “best practices” for detailed DER forecasting that could help ready distribution system planning for formal merging with Oregon utilities’ transmission-level integrated resource planning (IRP), Prause said.
Regulators in Hawaii face the U.S.’s fastest rush for DER. It makes planning like “trying to catch up with a train that has already left the station and is picking up speed.”
Former chair, Hawaii Public Utilities Commission
Jeremy Twitchell, Washington Utilities and Transportation Commission (WUTC) energy advisor, told Utility Dive the WUTC initiated an IRP rulemaking at the end of 2016. It is to update the IRP and recognize new technologies and best practices in system planning.
IRP is more widely used and a more standardized process than distribution system planning. Washington’s new IRP would, in addition to considering transmission-level resources, also consider technologies that serve utility needs at the distribution system level.
“Historically, if a utility had a distribution system need, it could only meet it with a very limited set of infrastructure solutions,” Twitchell said. “In this new world, we have a whole universe of resource options.”
The WUTC proceeding will apply “traditional IRP principles” to the full spectrum of options, including distribution system resources, to ensure the utility makes “the least cost, least risk” choice.
The WUTC staff’s technology-neutral draft framework requires regulated utilities, in every IRP, to identify distribution system “hotspots,” Twitchell said. Where there are potential “reliability challenges, aging infrastructure, above average load growth, or other challenges that would require distribution system upgrades, the utility must provide analysis and solutions.”
The new IRP rulemaking was not launched because of any utility’s failure to accurately value resources, Twitchell said. “This is a proactive rather than a reactive effort.”
Mina Morita, former chair of the Hawaii Public Utilities Commission, said regulators there face the U.S.’s fastest rush for DER. It makes planning like “trying to catch up with a train that has already left the station and is picking up speed.”
The state’s vertically integrated utilities are primarily focused on the distribution system, Morita emailed Utility Dive. That will allow “an easier transition and transformation into ‘network systems integrators’ that plan and operate “an advanced distribution system.”
Hawaii’s commission-ordered distribution system plan will lead to the proliferation of cost-effective, reliable, resilient “distribution alternatives,” Morita said. The “optimal” level of DER will improve hosting capacity and potentially lead to non-wires solutions that are cost-competitive with traditional distribution investments, she said.
DER is not always the driver for distribution system planning. Several states, such as Ohio and Pennsylvania, are focused on replacing aging infrastructure and modernizing their grids to improve efficiency and resilience, Homer said. Florida’s focus is storm hardening and recovery.
The process typically starts with an assessment, she said. “From there, states move in different directions.”
Alan Cooke, a PNNL senior research economist, and paper co-author focused on distribution system planning in Midwestern states. He highlighted Indiana’s distribution system planning, which is legislatively mandated to drive “investment in transmission and distribution systems” that can be rate based.
Each of Indiana’s regulated utilities is required to provide a seven-year plan with a “roadmap” to “safe and reliable service and system modernization.” Like many other states, Indiana ties planning to rate recovery for “capital projects” that must be “reasonable” and provide “incremental benefits justifying the cost,” the report says.
One such project, advanced metering infrastructure, has been fully and cost-effectively deployed in Indiana’s next-door neighbor, Illinois. But, the report adds, plans to deploy the infrastructure in Indiana were abandoned because of regulatory details limited cost recovery.
At a high level, states’ planning seems uniform, Cooke said. But in the details, “there are almost as many different approaches as there are utilities.”
Most utilities begin by assessing every option for serving system needs, but they tend to make final portfolio choices based on their unique economic, policy and resource availability circumstances, he added.
In places where DER is farthest along, like California and Hawaii, distribution system planning has drawn much attention. But regulators in some Midwestern states, where DER penetrations are still low, seem inclined to wait and watch outcomes elsewhere, Cooke said.
Some states are not interested in distribution system planning through a formal process.
Illinois Commerce Commission Chair Brien Sheahan emailed Utility Dive that under Illinois’s “restructured” system rules, the commission allows “market mechanisms” rather than planning to drive resource procurement.
The state’s Future Energy Jobs Act (FEJA) addresses the market-based relationship between the distribution network and new technologies in several ways, he added.
FEJA orders the Illinois Commerce Commission to establish a valuation for distributed generation on which mandated rebates can be based and that valuation must include distributed generation’s locational, time-based, and performance-based market benefits, he said. It must also include distributed generation’s present and anticipated future technical capabilities to provide grid services to the market.
The recently opened Illinois NextGrid initiative will take on the grid modernization question, Sheahan said. Both it and FEJA’s rebate program will demonstrate how DER and emerging customer-owned technologies can be advanced through market-based mechanisms and outside traditional IRP, he added.
Some states planning processes have revealed shortcomings that remain to be worked out as distribution system planning matures.
Strategen Senior Consultant Ron Nelson spent four years as a residential ratepayer advocate with the Minnesota attorney general’s office. Minnesota’s legislatively-mandated distribution system planning includes some of the most advanced efforts, including developing hosting capacity analysis.
But without fundamental reform of the traditional vertically-integrated utility business model, Minnesota’s distribution system planning faces the challenge of “opposing incentives,” Nelson told Utility Dive.
The utility “is nudged to build, own and ratebase costs to earn a return” while “the objective of [distribution system planning] is to be super-efficient and integrate DER to cut costs,” he said.
Xcel Energy’s proposed Belle Plaine non-wires solutions pilot demonstrated that a utility can be reluctant to use third-party assets to replace its own. The commission’s rejection of it demonstrated that distribution system planning can make regulators insistent on market access for third-party providers.
The conflicting incentives make it “very difficult for stakeholders to move toward a common goal,” Nelson said.
Performance metrics like hosting capacity analysis that lead to incentive mechanisms might resolve the conflict, Nelson suggested. But regulators must avoid “layering performance incentive mechanisms on an already complex set of incentives that can work against each other.”
“Traditional planning only solved for overall supply and load. Now we’re solving for hundreds of finite locations on the distribution system. Planning needs to allow for growth, emerging best practices and new technologies.”
Senior Energy Analyst, Pacific Northwest National Laboratories
California’s comprehensive distribution system planning has revealed some limitations in the concept.
CPUC President Picker agreed there are good reasons not to include distribution system planning in its IRP. “California is going to see distribution system planning in the general rate cases,” he said. “Our transmission and distribution planning will be separate from procurement of energy.”
The goal is a system that, where possible, can “take advantage of cost avoidance,” he said. “But I’m not seeing that cost avoidance emerging from the use of DER to displace distribution system expenditures.”
An increasing amount of third-party procurement is through private sector off-takers and customer choice aggregators, Picker said. It will likely keep transmission and distribution investments off planners’ agendas.
Those investments will, however, be important to investor-owned utilities’ general rate case proposals for grid modernization, he said. That is where distribution system planning will be important.
Customer demand is creating an opportunity for third-party providers, Picker said. “If DER can play a role, it will be bid in.”
That is driving deployment, though not innovation, of distribution system sensors and communications infrastructure, he added. With those things in place, private sector providers can bring more DER to market “to meet customer needs.”
Much of that is happening independently of a formal planning process and it is moving more slowly than California’s policymakers and DER advocates would like, but “we’re making progress,” Picker said.
PNNL’s Homer said states are beginning to unify on some features of planning. Most stakeholders now realize more granular information is needed about the present and anticipated DER penetrations, she said. They are also realizing extensive stakeholder involvement in planning processes is needed.
Cooke added that more participants in the planning proceedings “are understanding the importance of seeing what’s going on and getting a say.”
Washington Utilities and Transportation Commission’s Twitchell said distribution system planning is not a one-size-fits-all process, but best practices are indeed emerging. “A big one is transparency,” he said. “If utility planning can help DER providers and DER owners understand where their DER will most benefit the system, it can benefit everyone who uses the grid.”
Finally, there is a rising realization that distribution system planning needs flexibility, Homer said. “Traditional planning only solved for overall supply and load. Now we’re solving for hundreds of finite locations on the distribution system. Planning needs to allow for growth, emerging best practices and new technologies.”