TODAY’S STUDY: Key Numbers On Energy Storage As A Grid Support

Modernizing Minnesota’s Grid; An Economic Analysis of Energy Storage Options

July 11, 2017 (University of Minnesota Energy Transition Lab, Strategen Consulting, and Vibrant Clean Energy)

Executive Summary

Overview

Stakeholders in Minnesota’s power sector convened in two workshops held in September 2016 and January 2017 to discuss a statewide strategy for energy storage deployment.

The first workshop helped identify areas for more in-depth analysis. Preliminary results from this analysis and from real-world case studies were presented at the second workshop and used to guide a broader discussion around recommended next steps. The workshops and analysis made the following key findings: • Under an optimal set of future energy resource investments and operating practices, the leastcost solutions included energy storage.

• Energy storage can be a cost-effective means to help Minnesota meet its state greenhouse gas (GHG) reduction goals.

• The deployment of storage in Minnesota was projected to increase the use of low-cost renewable energy generation dispatched in MISO and to reduce the need for expensive transmission investments.

• Historically, utilities have used gas combustion turbines to meet peak demand. As storage becomes more cost-effective, it will compete with and displace new gas combustion peaking plants (peakers).

• Compared to a simple-cycle gas-fired peaking plant, storage was more cost-effective at meeting Minnesota’s capacity needs beyond 2022.

• Solar + storage was found to be more cost-effective than a peaking plant today, primarily because of the federal Investment Tax Credit (ITC) and additional environmental benefits, including reduced greenhouse gas (GHG) emissions.

• At least one distribution cooperative in Minnesota is already pursuing deployment of a solar + storage facility. Through a series of facilitated discussions, workshop participants generated a set of recommended next steps for immediate action.

• Lead study tours to educate Minnesota stakeholders about existing storage projects.

• Develop a proposal to deploy commercially significant energy storage pilot projects.

• Modify the existing Community Solar Gardens program to facilitate solar + storage projects. In addition, participants recommended the following steps that are ongoing or longer-term and can be pursued in parallel with the immediate actions.

• Direct energy producers to conduct future capacity additions through all-source procurement processes.

• Update modeling tools used by utilities and regulators for resource planning to better capture the costs and benefits of storage.

• Identify utility cost recovery mechanisms for new energy storage investments.

• Develop MISO rules that appropriately consider energy storage as a capacity and grid resource.

• Conduct an assessment to link storage to Minnesota’s system needs.

• Develop innovative retail rate designs that would support a greater deployment of energy storage. • Educate state policymakers through meetings and briefing materials.

• Identify opportunities for large electric customers to host storage projects.

• Host technical conferences for planners, grid operators, and utilities. In addition, workshop attendees suggested system analysis to identify high-impact locations for storage system benefits.

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Background

Minnesota is a leading state in clean energy production and grid modernization. Over the last decade, the renewable portion of Minnesota’s electricity mix has grown from 7% to over 21%.2 The state is also a leader in encouraging new energy technologies from a policy perspective, exemplified by its Grid Modernization and Distribution Planning Law (H.F.3, 2015) and related Public Utilities Commission proceedings (Docket #15-556).

Despite these efforts to date, Minnesota has deployed relatively little advanced energy storage technology and has not included storage in its integrated resource planning efforts. At the same time, other states are experiencing a variety of storage benefits. In California, for instance, utilities have deployed energy storage to provide necessary generation capacity to critical population areas such as the Los Angeles basin. In the PJM market, storage projects have provided ultrafast grid balancing services (fast frequency regulation). In Hawaii, storage integrated with solar PV has provided a cheaper alternative to expensive oil-burning power. In light of these success stories and other recent changes in the storage market, a group of Minnesota energy experts participated in a workshop series to explore the future role of energy storage in the state. This report describes the workshop’s process and its findings, details the supporting analysis that was presented at the meetings, and presents ideas for appropriate next steps…

In the fall of 2016, the University of Minnesota’s Energy Transition Lab (ETL) launched an energy storage planning process with a diverse set of Minnesota energy sector stakeholders, with support from the Energy Foundation, the McKnight Foundation, the Minneapolis Foundation, AES Energy Storage, General Electric, Next Era Energy Resources, Mortenson Construction, and Great River Energy. Additionally, the Carolyn Foundation provided support for the preparation and dissemination of this report. The primary objective was to explore whether and how energy storage could be used to help Minnesota achieve its energy policy goals while enabling greater system efficiency, resiliency, and affordability. All workshop participants were encouraged to come to the table with an open mind and no expectation of a particular outcome…

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Minnesota Energy Storage Strategy Stakeholder-Recommended Priority Actions

While some states are beginning to deploy grid connected energy storage on a large scale,15 Minnesota utilities and regulators have been hesitant to deploy energy storage widely because of concerns of cost effectiveness, cost recovery, and lack of operational experience with the asset class in general. Modeling data and peer utilities’ experiences can help to identify favorable use cases for Minnesota. However, load-serving entities and regulators eventually need operational experience to link energy storage capabilities to Minnesota’s unique grid needs. While the first deployment of any new technology may entail operational and institutional costs—as energy producers, grid operators, and regulatory agencies adapt to the new development—these costs are often one-off and enable future, lower-cost deployment of the technology. In short, there is simply no substitute for ‘learning by doing’.

Generally, most workshop participants agreed that finding opportunities to deploy solar + storage today was a low risk, “least-regrets” strategy in at least two instances:

1 - on the utility side, as an alternative to new gas peaking capacity, which was found capable of delivering net benefits and achieving nearterm GHG emissions reductions; and

2 – on the customer side, as a mechanism for Generation & Transmission (G&T) utility customers (e.g. rural cooperatives) to reduce their peak load and avoid demand charges, yielding system cost savings.

Because the federal Investment Tax Credit for solar projects is scheduled to phase out over the next four years, a number of stakeholders agreed that solar + storage projects should be identified and deployed in the very near term. A number of stakeholders also expressed that it would be a sensible next step to move forward with a limited, yet commercially significant solar + storage procurement. This would likely yield significant learning benefits for Minnesota’s energy sector and generate lessons for future integrated resource planning efforts. These lessons could outweigh potential near term costs and risks that might arise.

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Recommended next steps for immediate action

To help realize these benefits, based on the system level modeling and individual resource cost effectiveness modeling, and in the spirit of ‘learning by doing’, the stakeholder group identified a series of actions that could be undertaken in MN to further advance energy storage as a viable option in MN’s electric power sector planning toolkit. Several of these actions were identified as discrete, near-term steps while others would be longer-term or ongoing, and complementary to the immediate actions.

1. Host a utility-focused technical conference (or series of conferences) to advance thinking on energy storage to support planning, grid operations, interconnection, measurement and verification and utility training. This conference could also address at a high level alternative contracting mechanisms, including those for utility-owned, third party-owned and aggregated solutions. Recommended leaders for this effort: ETL/MESA, Minnesota utilities and the PUC

2. Identify and clarify potential utility cost recovery mechanisms for prudent energy storage investments. This is critical, as cost recovery risk is a key barrier preventing investor owned utilities from investing in energy storage projects. At the same time, criteria should be established for qualifying pilot projects. Recommended lead: PUC

3. Work with utilities to develop and propose one or more energy storage pilot projects to the PUC with broad stakeholder support. A necessary component of this type of proposal would be an agreed-upon mechanism for cost recovery to be approved by the PUC.

The steps would include the following:

a. Identify particular system needs and locations that could be effectively met with energy storage.

b. Propose a commercial scale Minnesota energy storage procurement process to demonstrate energy storage as a viable alternative to new gas peakers or other appropriate use cases. Such a procurement would help discover current price data and help identify best practices for storage project development (e.g. planning, siting, contracting, permitting, interconnection, etc.).

c. Partner with universities to conduct research and analysis of power control systems, operational integration, economic performance, and other areas of learning, making them explicit goals of these initial pilot projects. This may result in University and other expert partner white papers. These additional research objectives could be optional if they are found to be cost prohibitive.

4. Because of superior cost effectiveness and lower GHG emissions, solar + storage should be prioritized near term. For example, the PUC could authorize 20 MW of utility owned and 20MW of third party owned (either centralized or aggregated behind the meter) energy storage and or energy storage + solar procurement pilots, to complement the learning from Connexus’ solar + storage procurement underway. Engaging in a commercially significant pilot will shed light on key implementation barriers and issues very efficiently. Recommended lead: PUC, Minnesota utilities

5. Direct future capacity additions to be conducted through technology neutral all-source procurements. This would specify the need in terms of its capabilities, rather than its technology or generation type, and allow all resource types (including energy storage and energy storage + solar, as well as other technologies) to participate. The process and methodology for evaluating the all-source procurement should be established well in advance of its implementation. Recommended lead: Utilities; PUC

6. Update modeling tools used in integrated resource planning process (i.e. Strategist) to allow for appropriate treatment and evaluation of energy storage as a potential resource. Recommended lead: DOC, PUC, utilities.

7. Craft MISO rules, processes and products for energy storage participation. This should encompass not only standalone energy storage, but also behind the meter aggregated energy storage solutions as well as storage coupled with wind and solar. Recommended lead for this effort: MISO Develop innovative rate designs to allow customers to access storage benefits.

8. Conduct an assessment to link storage to Minnesota’s system needs.

9. Develop innovative retail rate designs that would support a greater deployment of energy storage. Recommended lead: utilities, PUC.

10. Lead a study tour of MN stakeholders to existing grid connected and customer-sited energy storage installations. Recommended lead: ETL/MESA

11. Conduct outreach and education for state policymakers. This could include meetings with both state legislators and regulators. Ideally, it would include development of short briefing materials to summarize use cases, opportunities, and challenges for energy storage in Minnesota. Recommended lead: ETL/MESA

12. Engage large customers to identify potential project hosting opportunities. Stakeholders would approach large potential host sites (e.g. large commercial and industrial customers, distribution centers, etc.) to identify potential value propositions. Recommended leads: MN Sustainable Growth Coalition, ETL/MESA.

13. Refine the existing Community Solar Gardens program to include a peak time option for energy storage. This would create a minor modification to existing program structure and methodology to allow for a solar + storage option (credit rate calculation would reflect the additional value of storage). Recommended lead: ETL/MESA, AG’s Office.

Other recommendations highly rated by workshop attendees included innovative rate designs to allow customers to access storage benefits and system analysis to identify high-impact locations for storage system benefits.

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Limitations and Opportunities for Further Analysis

The project team’s analysis was limited in scope due to budget and time constraints. As with all modeling exercises, the quality and usefulness of the results are a direct function of the underlying assumptions and inputs. The following additional analyses could be undertaken to build on this initial work and further inform the path forward. However, it should be noted that there is still no substitute for ‘learning by doing’ and these additional modeling suggestions are not intended to be prerequisites for implementing the action recommendations developed by the stakeholders in this process.

1. Additional system optimization scenarios:

a. Natural gas scarcity and price spike scenarios

b. Storage with longer than four-hour duration (including flow battery technologies)

c. Additional years of weather data

d. More cost trajectories for technology inputs

e. Future scenarios with more GHG reduction

f. Future load scenarios including electric vehicle charging and various heating/cooling and thermal storage scenarios

g. More transmission coordination among MISO, SPP, and PJM

h. Multiple hub heights for wind generators

2. Individual resource use case cost-effectiveness analysis that could benefit from additional sensitivity analyses:

a. Locational benefits: identification of specific locations in Minnesota’s distribution system that are constrained or experiencing other issues energy storage can address. For example, the integration of energy storage with existing fossil generation could immediately improve local air emissions.

b. Installation costs: MISO values used in this study for peaker costs may not be representative of some utilities in the state

c. Frequency regulation: recent experience suggests that frequency regulation values can differ from initial modeling predictions

d. Comparison to or combination with other capacity alternatives such as demand response

e. GHG emissions: additional research into local drivers of marginal generation resources

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QUICK NEWS, July 31: Climate Change Out At EPA Museum; labama Is Starting To Like Solar; Oklahoma Building Nation's Biggest Wind

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Juliet Eilperin and Brady Dennis, July 30, 2017 (Chicago Tribune)

“…In an obscure corner of the Ronald Reagan International Trade Building, a debate is underway about how to tell the story of the EPA's history and mission…A miniature museum that began as a pet project of former EPA administrator Gina McCarthy has come under scrutiny. It features the agency's work over four and a half decades, with exhibits on topics such as regulating carbon dioxide emissions and the Paris climate accord…Now the museum, which opened just days before President Barack Obama left office, is being reworked to reflect the priorities of the Trump administration, an effort that probably will mean erasing part of the agency's history...[A] career official said that these climate displays are slated to be removed, adding that the agency may add a display of coal to the museum…” click here for more

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Alabama Is Starting To Like Solar Solar energy growing in popularity

Jennifer Edwards, July 30, 2017 (Times Daily)

“...[The conversation about solar in Alabama is now more often about how consumers can use solar energy than about how it works, according to Energy Alabama CEO Daniel...He said the shift in consumer questions indicates solar energy has a stronger foothold than it did two years ago…The technology is familiar, and people are buying in, he said…TVA, the area's power supplier, has incorporated various forms of renewable energy into its power portfolio…Private installations tie into the TVA system through TVA's Green Power Providers program with municipal electricity departments…” click here for more

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July 26, 2017 (Invenergy via PRNewswire)

“…[Invenergy and GE Renewable Energy will partner on] a 2,000-megawatt wind farm that will be the largest in the U.S. and second-largest in the world, once operational. The Wind Catcher facility is currently under construction in the Oklahoma panhandle and will generate wind electricity from 800 state-of-the-art GE 2.5 megawatt turbines…The wind facility is part of the $4.5 billion Wind Catcher Energy Connection…[The approximately 350-mile dedicated, extra-high voltage power line proposed by American Electric Power (AEP) utility subsidiaries Public Service Co. of Oklahoma (PSO) and Southwestern Electric Power Co. (SWEPCO)…is expected to save SWEPCO and PSO customers more than $7 billion, net of cost, over 25 years. AEP estimates that the project will support approximately 4,000 direct and 4,400 indirect jobs annually during construction and 80 permanent jobs once operational. It also will contribute approximately $300 million in property taxes over the life of the project…” click here for more

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When The Duck Quacks And Why

It sounds silly but it isn't: the Duck Curve is the biggest new challenge to the U.S. power sector. From U.S. Department of Energy via YouTube

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The Climate Clock Is Ticking

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Scott Waldman, July 25, 2017 (E&E News via Scientific American)

“… [The preindustrial level of atmospheric CO2 used in the Paris agreement, based on temperature records from the late 19th century, doesn't account for a potential century of rising temperatures caused by carbon dioxide emissions…[and accounting] for those gases, released from about 1750 to 1875, would add another one-fifth of a degree to the baseline temperature, [according to Importance of the pre-industrial baseline for likelihood of exceeding Paris goals…[T]he research suggests there's less time than previously believed to address global warming…[It] estimates that there may have already been 0.2 degree Celsius of warming, or 0.36 degree Fahrenheit, built into Earth…[which] means the Paris Agreement would have to be more aggressive…Before the age of industrialization, the amount of atmospheric carbon dioxide was about 280 parts per million (ppm)…The early decades of industrialization, fueled by economic growth in Europe, may have added 30 to 40 ppm of carbon dioxide to the atmosphere…Now, atmospheric CO2 is rising at a record pace and is already at 410 ppm. It's expected to climb for decades…” click here for more

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Wind Is Too Good A Deal For UK To Refuse

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Adam Vaughan, 23 July 2017 (UK Guardian)

“Onshore windfarms could be built in the UK for the same cost as new gas power stations and would be nearly half as expensive as the Hinkley Point C nuclear plant…[Engineering consultant Arup found that the technology has become so cheap that developers could deliver turbines for a guaranteed price of power so low that it would be effectively subsidy-free in terms of the impact on household energy bills…France’s EDF was awarded a contract for difference – a top-up payment – of £92.50 per megawatt hour over 35 years for Hinkley’s power, or around twice the wholesale price of electricity…By contrast, Arup’s report found that windfarms could be delivered for a maximum of £50-55 per MWh across 15 years…ScottishPower, which commissioned the analysis, hopes [use it] to persuade the government to reconsider its stance on onshore windfarms…” click here for more

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Solar Lights Burundi Streets

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19 July 2017 (African Review)

“…[S]olar-powered ‘light islands’ started appearing in the heavily congested central bus station and nearby marketplace, extending commercial hours and improving personal safety…Gigawatt Global is now in discussions to scale the solar-powered ‘light islands’ programme throughout the city and in other major Burundian towns…Gigawatt Global, which provides 100 per cent financing for its projects, pioneered commercial scale solar power plants in sub-Saharan Africa, launching the first one in Rwanda in 2014, which is supplying six per cent of the country's generation capacity. Gigawatt Global will complete a 7.5 MW solar field in the Gitega region of Burundi in the next six months, which will supply 15 per cent of the East African country's generation capacity. Similar projects are currently being developed in 10 African countries…” click here for more

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Brittany Bedi, July 18, 2017 (WCTV-Tallahassee)

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Richard Walters, July 23, 2017 (Financial Times)

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ORIGINAL REPORTING: The Best Way To Do Community Solar

Subscriptions or sales: Which community solar approach promises the best growth? Private developers are getting ambitious and utilities are eyeing the opportunity

Herman K. Trabish, Jan. 19, 2017 (Utility Dive)

Editor’s note: Community solar continues to grow and open new state markets.

Community solar markets are starting to snowball as developers pick apart different strategies to find the best approach. New numbers show what policies make community solar markets thrive. Nnew community solar capacity reached over 206 MW by the end of 2016, a 400% increase over the same period the year before, bringing the national cumulative capacity to 331 MW, according to the latest market report. Markets in Massachusetts, Minnesota, and Colorado, and New York are implementing policy, and individual private sector providers have dozens of projects online, in development, and under construction. SoCCme may have hundreds of projects in their pipeline.

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Community solar, also known as community shared solar and solar garden, allows customers to purchase a share in a large central station solar array in exchange for a bill credit for any excess energy exported to the grid. Community solar’s biggest appeal lies in opening access to solar energy for all customers regardless of income or their possession of a roof. A 2015 report said 49% of households and 48% of businesses are currently unable to host a rooftop solar system. By reaching those customers, the National Renewable Energy Laboratory estimates community solar could compose 32% to 49% of the distributed solar market by 2020, while attracting up to $16.3 billion in investment. In some states, untouched markets could be as high as 85% of residential customers and more than 50% of commercial customers, according to the Coalition for Community Solar Access… click here for more

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ORIGINAL REPORTING: What U.S. DER Can Learn Down Under

What Australia's DER revolution can teach US utilities about the age of Trump; When federal support for clean energy faltered, Australian states took the lead on the power sector transformation. Sound familiar?

Herman K. Trabish, Jan. 24, 2017 (Utility Dive)

Editor’s note: Australia continues to set the pace for DER integration.

Policy uncertainty caused by the new administration’s initiatives and lack of them is unsettling a power sector in a profound, market-driven transition. But whether it will choose to harness or hamper the clean energy transition remains unclear. For power sector insiders looking for answers, Australia’s recent experience could provide some constructive lessons. From 2007 to 2013, federal support for renewables in Australia allowed wind and solar to significantly cut into the power mix down under. That growth stalled after 2013, when the election of a conservative government undercut federal support for utility-scale solar and wind. Even so, policies and market supports from the nation’s six states allowed distributed energy resources (DER) to reach transformative penetrations on Australia’s grid.

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Australia does not have all the answers but its distribution system operators have been pushed by unique policy and economic factors and have shown how using new technologies and new policy designs can be workable. Though polls show a majority of Australians believe in human-caused climate change, power prices averaging as high as $0.30/kWh gave traction to arguments from conservative Abbott and Turnbull governments, like those made by President Donald Trump, for coal and natural gas consumption. By the end of 2015, Australia’s resource mix was nearly 15% renewables, but Turnbull’s administration continues to lower incentives put in place by previous governments for utility-scale wind and solar. Discouraged developers have left or are thinking of leaving the country. But the high rates, along with tariff reforms, drove DER penetrations to new highs. Advocates say new ways of more accurately valuing DER, like valuation concepts being developed in the U.S., will open the door to still more opportunity…

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ORIGINAL REPORTING: Solar’s Newest Arizona Challenge

The lurking surprise for solar in Arizona's recent ruling to end net metering; The landmark decision in the state's value of solar proceeding could end up slashing rooftop compensation in half

Herman K. Trabish, Jan. 26, 2017 (Utility Dive)

Editor’s note: Arizona Public Service and other stakeholders reached a settlement in the rate case but the threat to solar owners still lurks in the new rates.

Arizona regulators concluded a closely-watched proceeding on the value of solar by ending retail rate net metering and, to the frustration of solar advocates, siding with utility companies on most key issues. The 4 to 1 Arizona Corporation Commission (ACC) vote at the end of December began a transition away from retail net metering and introduces a replacement rate design. Some solar advocates say the changes undermine the residential solar value proposition. Other advocates and stakeholders say the changes will make Arizona solar better. Few have noticed a surprise hidden in the plan.

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The ACC ruling postponed decisions on the exact value of solar incentives for future utility rate cases. But the commission did act to make rooftop solar customers a separate rate class — a change some in the industry say bodes ill for the solar sector when new utility rate proposals are considered. With increasing solar penetration on their systems, Arizona utilities have rebelled against what they perceive as an unsustainable shift of costs to non-solar owning customers caused by net metering. The December hearing sought to address that. The ACC order clarified how two different valuation methodologies prescribed by commission staff will be applied. They synthesize stakeholder-proposed methodologies made during the VOS proceeding. But the final rate will be determined in each utility’s rate case… click here for more

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NO QUICK NEWS

TODAY’S STUDY: A Plan To Help Utilities Perform Better

State Performance-Based Regulation Using Multiyear Rate Plans for U.S. Electric Utilities

Mark Newton Lowry, Matt Makos, and Jeff Deason, July 2017 (Grid Modernization Consortium/Lawrence Berkeley National Laboratory/U.S. Department of Energy)

Executive Summary

Berkeley Lab published a report in 2016 that discussed two approaches to performance-based regulation (PBR) of electric utilities: multiyear rate plans (MRPs) and performance incentive mechanisms (PIMs).1 The authors described these approaches at a high level and in the context of growing levels of demandside management (DSM), distributed generation and other distributed energy resources (DERs).

This report presents a more in-depth analysis of the multiyear rate plan approach to PBR for electric utilities, applicable to both vertically integrated and restructured states. The report is aimed primarily at state utility regulators and stakeholders in the state regulatory process. The approach also provides ideas on how to streamline oversight of public power utilities and rural electric cooperatives by their governing boards.

We discuss the rationale for MRPs and their usefulness under modern business conditions. We then explain critical plan design issues and challenges and present results from numerical research that considers the extra incentive power achieved by MRPs with different plan provisions. Next, the report presents several case studies of utilities that have operated under formal MRPs or, for various reasons, have stayed out of rate cases for more than a decade. In these studies we consider the effect of MRPs and rate case frequency on utility cost, reliability and other performance dimensions. Appendices present further information on MRP plan design and some details of the technical work.

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What Are MRPs?

MRPs are a comprehensive approach to PBR designed to strengthen general incentives for good utility performance. Two key provisions of MRPs strengthen cost containment incentives and streamline regulation:

1. A rate case moratorium reduces the frequency of rate cases, typically to once every four or five years.

2. An attrition relief mechanism (ARM) escalates rates or revenue between rate cases to address cost pressures such as inflation and growth in number of customers independently of the utility’s own cost.

Loosening the link between its own cost and revenue gives a utility an operating environment more like that which competitive markets experience.

Most MRPs feature a performance metric system that includes some PIMs. These PIMs provide awards or penalties, or both, for performance in targeted areas. PIMs are most commonly used in MRPs to strengthen incentives for utilities to maintain or improve reliability and customer service quality. Some plans also include earnings sharing mechanisms, efficiency carryover mechanisms and marketing flexibility.

Provisions are often added to plans to strengthen utility incentives for DSM. For example, utility expenditures on DSM programs are usually tracked, and PIMs can be added to reward utilities for successful DSM programs. Revenue decoupling can mitigate a utility’s incentive to boost retail sales and reduce risks of revenue losses from rate designs that encourage DSM.

How Prevalent Is This Approach?

MRPs were first widely used in the United States in the 1980s to regulate railroads and telecommunications carriers, industries beset by rising competition. Early adopters of MRPs in the U.S. electric utility industry included California and several northeastern states. Use of MRPs has recently grown among vertically integrated electric utilities in diverse states that include Arizona, Georgia and Washington. Greater use of MRPs for power distributors has been slowed by their requests for accelerated system modernization, which complicate plan design. MRPs are much more common for electric utilities in Canada and countries overseas. The impetus for adopting MRPs in these countries has often come from policymakers rather than utilities.

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What Is the Rationale for These Plans?

America’s investor-owned electric utility industry was largely built under cost of service regulation (COSR). This regulatory system traditionally adjusted rates that compensate utilities for costs of capital, labor and materials only in general rate cases. The scope of costs eligible for tracker treatment, which expedites cost recovery, has gradually enlarged and sometimes includes capital costs as well as energy expenditures.

The efficacy of COSR varies with external business conditions. When conditions favor utilities (e.g., are conducive to realizing at least the target rate of return), rate cases are infrequent. Performance incentives are then strong and the cost of regulation is quite reasonable. When conditions are less favorable, rate cases are more frequent and more costs are tracked. Performance incentives can then be weak and regulatory cost can be high. These attributes of COSR are worrisome because business conditions today are often less favorable to utilities than in the past.

MRPs are a different approach to regulation that is especially appealing when the alternative is frequent rate cases or expansive cost trackers. The regulatory process is streamlined and better utility performance can be encouraged due to stronger performance incentives and increased operating flexibility. Benefits of better performance can be shared with customers. Recent advances in MRPs such as efficiency carryover mechanisms and statistical benchmarking can “turbocharge” their incentive power and ensure benefits for customers.

What Are Some Disadvantages of MRPs?

MRPs are complex, and their adoption can involve extensive change to the regulatory system. It can be challenging to design plans that strengthen incentives without undue risk and share benefits fairly between utilities and their customers. Some kinds of business conditions (e.g., brisk inflation and declining average use) have proven easier to address using MRPs than others (e.g., capital spending surges). MRPs can invite strategic behavior and controversies over plan design.

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Case Studies

This report discusses six case studies of utilities operating under MRPs:

1. Central Maine Power operated under a sequence of MRPs from 1996 to 2013. The plans afforded the company unusual marketing flexibility which it used to develop special contracts with large-volume customers. These contracts helped the company retain their contributions to fixed costs of the system, for the benefit of all customers.

2. California has the nation’s longest history with MRPs for retail services of electric utilities. The Public Utilities Commission has limited rate case frequency and staggered plan terms to avoid simultaneous rate cases. Plan provisions have provided strong incentives for utilities to embrace DSM.

3. New York has regulated electric utilities using MRPs since the 1990s. The state’s Reforming the Energy Vision proceeding has considered how rate plans should evolve to regulate the “utility of the future.”

4. MidAmerican Energy operated under a rate freeze in Iowa from 1997 to 2013. This freeze extended to charges for energy procured as well as for capital, labor and materials.

5. Ontario, Canada, has used MRPs to regulate the dozens of power distributors since the late 1990s. Capital spending surges have posed special plan design challenges. Innovations in Ontario regulation also include incentive-compatible menus and extensive use of benchmarking.

6. Great Britain also has a long history with MRP regulation. The current “RIIO” approach to regulation of energy utilities there has attracted the attention of many North American regulators.

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Impact on Cost Performance

This report also addresses the impact of MRPs (and, more generally, rate case frequency) on utility cost performance using two analytical tools: incentive power analysis and empirical research on utility productivity trends. An Incentive Power Model uses numerical analysis to assess the incentive impact of alternative stylized regulatory systems. For North American case studies, we compared productivity trends of utilities operating under MRPs to U.S. norms. We also considered productivity trends of utilities that operated under unusually frequent and infrequent rate cases.

Both lines of research suggest that the frequency of rate cases can materially affect utility cost performance. For example, the multifactor productivity (MFP) growth of the electric, gas and sanitary sector of the U.S. economy was materially slower than that of the economy as a whole from 1974 to 1985, when rate cases were frequent due in part to adverse business conditions, than in the early postwar period, when favorable business conditions encouraged less frequent rate cases. We also found that the MFP growth of utilities that operated for many years without rate cases, due to MRPs or other circumstances, was significantly more rapid than the full sample norm. Cumulative cost savings of 3 percent to 10 percent after 10 years appear achievable under MRPs.

Conclusions

The case studies and incentive power and productivity research presented in this report have important implications. First, utility performance and regulatory cost should be on the radar screen of U.S. regulators, consumer groups and utility managers. Our research shows that key business conditions facing utilities today are less favorable than in the decades before 1973 when COSR worked well and was becoming a tradition. Today’s conditions encourage more frequent rate cases and more expansive cost trackers. MRPs can produce material improvements in utility performance which can slow growth in customer bills and bolster utility earnings.

Notwithstanding the potential benefits of MRPs, they are still not used in most American states. COSR is well established and there are many accomplished practitioners. It can be difficult to design MRPs that generate strong utility performance incentives without undue risk, and that share benefits of better performance fairly with customers. MRPs invite strategic behavior and controversies over plan design. Continuing innovation of COSR will occur, and this will slow diffusion of MRPs.

However, MRPs are also evolving and remedies to problems encountered in early plans have been developed. MRPs are well suited for addressing conditions expected in coming years, such as rising input price inflation and DER penetration and increased need for marketing flexibility. For these and other reasons, we foresee expanded use of MRPs in U.S. electric utility regulation in coming years.

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QUICK NEWS, July 25: Climate Change In The Not-So-Funny Funnies; The Truth About Wind, Birds, And Bats; How Goes For 100% New Energy

Climate Change In The Not-So-Funny Funnies A Comic Strip Mirrors the Ravages of Climate Change

George Gene Gustines, July 23, 2017 (NY Times)

"The newspaper comic strip 'Arctic Circle,' by the environmentally minded cartoonist Alex Hallatt, is about talking penguins and their fellow creatures living in the north…[Now], under a caption that says ‘An Inconvenient Truth,’ the menagerie will find their world shrinking and their conversations will be about global warming. Readers will see the drawings diminish to nothing by Friday as a snow bunny muses, ‘Climate change will lead to habitat loss and the extinction of many species.’ Miss Hallatt created the strips to observe the arrival of the documentary ‘An Inconvenient Sequel: Truth to Power,’ in theaters on Friday. The film is a follow-up to the 2006 Oscar-winning documentary featuring Al Gore. Miss Hallatt has no official connection to the film…” click here for more

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The Truth About Wind, Birds, And Bats Bat, bird deaths focus of wind farm study

Karl Puckett, July 21, 2017 (Great Falls Tribune)

“Montana Fish, Wildlife and Parks is leading a study of how a NorthWestern Energy-owned wind farm called Spion Kop is affecting bats and birds…One of the initial findings is that the project has been harder on bats than a pre-construction study predicted, with bats possibly mistaking the turbines for trees…But no raptor carcasses have been discovered, with NorthWestern crediting upfront investigation into the location of raptor nests prior to the siting of giant turbines with blades that can spin up to 190 miles per hour…It’s the first time a state agency, as opposed to a private developer, has conducted a so-called post-construction study, and the data on the number of birds and bats killed, usually closely guarded, will be made public when it’s completed…Utility and FWP officials say the study will lead to better understanding of how wind farms affect wildlife that could lead to improve siting and layout of future wind projects…” click here for more

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Hawaii Goes For 100% New Energy Hawaii's Push to 100% Renewable Energy Presents Opportunity for Solar Energy Hawaii continues to push the envelope in renewable energy, providing a path for the rest of the country.

Travis Hoium, July 22, 2017 (Motley Fool)

“Hawaii has long been the U.S. leader in solar energy deployment, despite the fact that the state's renewable energy efforts rarely get national attention. Solar energy, in particular, makes sense in Hawaii because of the state's abundant sunshine and high electricity prices (otherwise utilities burn imported fossil fuels). Even energy storage is an area where Hawaii is charging ahead of most other states…Hawaii will be the first state to take a real crack at being powered 100% renewable energy…The Hawaiian Public Utilities Commission wanted Hawaiian Electric to reach 100% renewable energy by 2045 and had twice rejected plans it didn't feel went far enough. This month, it approved the company's plan, which is actually to reach 100% renewables by 2040…The next five years will be a key transition…As more renewable energy is built in high penetration states like California and Iowa, utilities and regulators will be looking for solutions to build a stable grid with a lot of renewables. And if Hawaii can push past 50% in five years on its way to 100% renewables in 2040 it'll be a big proving point…” click here for more

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