Originally posted at ilsr.org.
Unfortunately for utilities, new technology and commercial opportunities in the coming years are only increasing the threat to the 1.0 business model.
Solar energy is growing exponentially as costs have fallen 28% per year from 2009-2013, and electricity from rooftops is approaching or passing parity with utility prices.63
This is the third of four parts of ILSR’s Beyond Utility 2.0 to Energy Democracy report being published in serial. Click to see the first or second post, click here. Download the entire report and see our other resources here.
Energy storage, mostly via batteries, already allows utility customers to do “arbitrage” – storing electricity when it’s cheap and minimizing purchases from the grid when electricity is expensive. Commercial customers can use storage to cut demand charges, a substantial portion of their bill. Batteries are even being packaged with rooftop solar arrays by companies like SolarCity.64
Take storage a step further and folks could “cut the cord” by having their own independent power system, or with the ability to separate from the larger grid as a “microgrid.” It’s already happening, influenced by major disasters like Superstorm Sandy in 2012. Many East Coast communities got a firsthand taste of the weaknesses of a centralized, utility 1.0 system. Power outages lasted for days and hit an unprecedented number of people: “8.5 million people [were] without power in twenty-one states.”65 Notably, many microgrids or backup generators were able to remain online throughout the storm and aftermath, including microgrids at a USDA facility in Maryland and a cogeneration plant at New York University.66
Electric vehicles, becoming popular because of much lower mileage costs than gasoline, will become another potential tool for individuals and microgrid operators to manage their electricity use.
From a widely circulated industry study in 2013, it’s clear that utilities now recognize distributed power as an existential threat.67
Fortunately, the future utility business model, commonly called utility 2.0, is already in development. Below, we explore the most common principles and polices for shaping the 21st century electricity system – utility 2.0 – and examine its track record in the few states that have begun implementation.
We also illustrate how utility 2.0 could come up short of the potential for an economic transformation of the energy system, and how Energy Democracy (or utility 3.0, if you prefer) adds a few crucial principles that enable the continued rise of customer-owned power generation and control of their energy future.
Principles, Structure, and Policies of Utility 2.0
Although the future of utilities encompasses many smaller issues – rooftop solar, energy storage, energy efficiency – the fundamental question of utility 2.0 is, “how can we incentivize the electric utility to do what we want?”
“What we want” varies, but most of the utility and energy policy thinkers exploring a version 2.0 electric utility add the following principles to the basic ones of reliable, affordable electricity service:
- Reduced energy consumption, through efficiency and conservation
- Reduced carbon emissions, through a switch from fossil fuels to renewable energy
- Increased grid efficiency via a two-way, networked smart grid that uses demand response, local power generation, and other local resources
- Increased grid flexibility to integrate large quantities of variable (distributed and utility-scale) renewable energy
Notably, these principles do not align with current financial incentives for most investor-owned utilities (or the typical business practices of most utilities; private, public, or cooperative). Furthermore, the principles are indifferent to the economic opportunity. That is, they can be implemented with utility control of the grid and its benefits or with a massively decentralized and democratized electricity economy.
The proposed structural changes to meet these utility 2.0 principles vary in detail, but they have two common themes:
- Planning that integrates local and regional level resources. In other words, ensuring that when planning for new power plants or power lines, utilities (or grid managers) consider how needs can be met with local solutions including rooftop solar, energy storage, electric vehicles, and even non-capital measures like controllable, smart appliances.
- Independent, neutral operation of the distribution system. In other words, removing the conflict of interest that causes incumbent utilities to prefer building new infrastructure to conservation, efficiency, or local power from competitors or even utility customers.
Prominent proposals include proactive system planning (addressing the first point) in Hawaii 68 and New York’s Reforming the Energy Vision (which addresses both).69 The key element of structural change to utility 2.0 can be summed up by this excerpt from America’s Power Plan: “This new kind of distribution system needs a new kind of management.”70
Underneath these structural changes are the core policies of a utility 2.0 framework: separating utility financial health from energy sales (a concept typically called decoupling) and separating utility profits (for investor-owned utilities) from building and owning infrastructure.
Decoupling precedes the recent focus on utility 2.0, having already been adopted in 7 states (with a dozen other states either piloting decoupling or using alternative policies with similar outcomes). This policy breaks the connection between electricity sales and utility revenue, to remove the dis-incentive for energy efficiency. Some ten states have gone further, completely removing energy efficiency program responsibility from the utilities to a third party.71 However, regulators in New York warn that while decoupling makes utilities indifferent to sales losses from energy efficiency and distributed generation, it does not shield ratepayers from the risk of widespread revenue loss should distributed generation grow substantially.72
The other substantial policy change is shifting from shareholder returns based on infrastructure investments to performance-based returns; returns based on a flexible, low-carbon, efficient electricity system. Some states, like New York, have layered financial penalties for non-attainment on top of the existing return on equity formula. In other words, for-profit utilities can lose money when they fail to accomplish objectives related to clean energy. But as of yet, no U.S. state has transitioned to a business model that rewards utilities solely for their ability to meet utility 2.0 benchmarks.
Should Incumbent Utilities be the New distribution System Operator?
When Pope Julius II wanted the Sistine Chapel’s ceiling painted, he didn’t hire the house painter. He went for the best. Somewhere out there is a Michelangelo of distribution system design and operation. It might be the local utility. We won’t know unless we look.
– Scott Hempling, June 2014
Rising Utility 2.0 Models?
A few states have begun moves toward a new utility business model and their experiences are instructive. We include one international example, since it’s illustrative of the open distribution marketplace that many Utility 2.0 advocates desire.
It’s rare that a report from the Department of Public Service can become a banner for the transformation of the energy system, but the April 2014 release of “Reforming the Energy Vision” (REV) from New York’s Department of Public Service has set the standard for the meaning of Utility 2.0.73
The report is notable because it challenges two of traditional paradigm’s core principles: “that there is little or no role for customers to play in addressing system needs…and that the centralized generation and bulk transmission model is invariably cost-effective, due to economies of scale.”
The REV report is clear that while it prioritizes expansion of a distributed energy system, “it is not intended to replace central generation, but rather to complement it in the most efficient manner, and to provide new business opportunities to owners of generation and other energy service providers.”
The regulators of New York’s electricity system have already made many moves toward Utility 2.0 and have learned several lessons.74 Commission efforts include basic Utility 2.0 strategies like revenue decoupling and performance-based rates (with penalties for poor performance), as well as incentives for energy efficiency and distributed renewable energy, demand response, simplified interconnection, robust net metering, and a Green Bank to finance advanced energy projects.
Some lessons from these reforms indicate that the transition to Utility 2.0 isn’t without its challenges. For one, it’s been hard to determine, in advance, if utilities are spending enough money on grid maintenance, with utilities and regulators having to come back for supplementary rate cases when estimates have been inaccurate. Additionally, the performance-based incentives need to be improved with more frequent re-evaluation, higher penalties that are sufficient to win compliance, and some allowances to encourage learning through trial and error.
Utility regulators have also realized that removing the link between utility revenue and energy sales (decoupling) is not sufficient. Utilities often retain an incentive to build and own their own infrastructure at the expense of alternatives such as customer-owned solar. Without new policy, “in the long term, utilities still have an incentive to maximize their capital expenditures, and little incentive to optimize system efficiency to reduce capital needs.”75
New York’s efforts toward a Utility 2.0 model aren’t alone. The state has also been leader in many energy democracy policies like net metering, a set-aside in its renewable energy standard for customer-sited energy, and incentives for distributed solar power. It’s performance is middling, ranking 11th in state wind power capacity, and 9th in solar (despite having the third largest population).76 In energy efficiency, ACEEE ranks New York 7th in the nation.77 It may begin climbing the ranks, however, as the governor recently announced a $1 billion commitment to distributed solar energy development.78
With oil-fired power plants reliant on costly oil imports, Hawaii’s electric utilities are on the front lines of the threat to the 1.0 business model. They sell the most expensive electricity in the United States, causing utility customers to stampede to less costly rooftop solar. In 2013, more than 1 in 5 of distribution feeders (neighborhood power lines) already had more than 15% of peak demand provided by distributed solar.79
Prior to the crush of customer solar, the state had already implemented decoupling to insulate the utilities’ bottom line from the loss of sales. However, the utilities planned poorly for the surge in distributed renewable energy installations and responded with caps on customer-owned power generation.
State regulators intended that to change with a stakeholder process in early 2013 that proposed the islands’ largest utility, Hawaiian Electric Company, adopt a proactive approach to planning. The new process meant to integrate the utility’s interconnection and distribution planning functions, requiring the utility to forecast distributed solar growth and to plan infrastructure upgrades to the distribution grid accordingly.80 Despite the proposed changes, permits for new rooftop solar installations fell by 44 percent from 2013 into 2014.81
In May 2014, the state’s Public utilities Commission took further steps. Issuing a white paper on the future of the state’s electricity system, Commission orders also required Hawaiian Electric Company to re-do its resource plan to improve its planning for distributed generation, to “expeditiously” retire older power plants, and increase grid flexibility with demand response and storage. The Commission also specifically ordered the Maui-based utility to stop curtailing renewable energy generation in favor of power purchases from its own fossil fuel power plants.82
The Commission orders are already making a difference. In October 2014, Hawaiian Electric, Maui Electric and Hawaii Electric Light released a revised integrated resource plan to achieve 65% renewable energy by 2030; and for the island of Hawaii specifically, 92% renewable energy by 2030.83 The plan also allows for a tripling of rooftop solar installations.
These improvements are not final, as the dockets and Commission orders are still open for review.
In 2009, the Maine legislature got a jump on New York’s Reforming the Energy Vision by initiating an investigation by the state’s Public utilities Commission into a “smart grid coordinator.” The proposed entity would manage utility and non-utility distributed generation and infrastructure to achieve many of the utility 2.0 principles, including:84
- Increased use of digital information and control technology…and provision to consumers of timely energy consumption information and control options
- Deployment…of [distributed] renewable capacity resources
- Deployment…of demand response technologies, demand-side resources and energy-efficiency resources
• Deployment of smart grid technologies, including real-time, automated, interactive technologies
• Deployment and integration into the electric system of advanced electric storage and peak-reduction technologies, including plug-in electric and hybrid electric vehicles
In 2012, the PUC approved the launch of a pilot project by distributed generation company GridSolar to implement a local alternative to a new transmission line serving the coastal community of Boothbay Harbor.85 Using energy efficiency, rooftop solar, and Battery storage, GridSolar says their non-transmission alternative cost one-third what a new transmission line would have. In 2014, they returned to the PUC to take their project statewide, as the envisioned “smart grid coordinator.”
Despite the purported success, the incumbent utility is pushing back against the notion. In April 2014, Central Maine Power returned to the PUC to request a redesign of electricity rates that would penalize rooftop solar producers.86 Fortunately the Maine Public utilities Commission rejected the substantial standby fees and fixed charges proposed by Central Maine Power, and deliberations over the smart grid coordinator are ongoing.87
The vision of a massively decentralized energy marketplace (the second prominent structural change of utility 2.0) is already in place in the Netherlands, according to the Rocky Mountain Institute:
“A Dutch company called ‘Van de bron’ (‘From the source’) allows Dutch consumers to see which solar, wind, combined heat and power, or other energy source exists in their vicinity and buy their energy from there. Balancing services are provided by the network operator. No traditional retailer sits between the consumer and the producer. Energy generation becomes as sharable as lodging through AirBnB or cars through LyI.“88
Vermont: Utility 2.0 in Action?
Vermont’s regulatory environment most closely approximates many utility 2.0 principles, with the exception of largely retaining utility control over the distribution system. Although the state has shifted toward this new utility model over 15 years, recent policy moves were triggered by the anticipated 2014 closure of the Vermont Yankee nuclear power plant that has supplied 35% of the state’s electricity.
In 1999, the state’s Public Service Board awarded the first energy efficiency utility contract to the Vermont Energy Investment Corporation. This new initiative pooled the energy efficiency investments of all the state’s utilities into a single and single-purpose entity to save energy, Efficiency Vermont. In 2013, Vermont was one of seven states with a non-utility manager of the state’s energy efficiency programs, as shown in this graphic from the Regulatory Assistance Project.89
Over time, the savings from the agency’s efficiency programs have risen steadily, to approximately 2% of electricity sales.90
In 2007, Efficiency Vermont successfully saved enough energy to drive total energy sales down for the first time, and the energy efficiency utility has maintained that high level of savings in the years since. Cumulatively, since 2000 energy efficiency has supplied 12.3% of electricity services, contributing to flattening electricity demand.91 The chart below shows how Vermont’s relatively stable electricity demand hasn’t hampered economic growth.92
In 2003, the Vermont Electric Company requested a permit for the first new high voltage transmission line to be built in Vermont in 30 years. Although the project received its permit in 2005, “the Public Service Board (PSB) concluded that…with earlier planning, the reliability problems in question might have been addressed with less costly, non-transmission solutions.”93
Thus the Vermont System Planning committee was formed (with members of distribution utilities, the public, and energy efficiency suppliers like Efficiency Vermont) to identify alternatives to transmission to meet grid reliability needs. The Legislature enacted changes to Vermont law requiring the Vermont Electric Co. to produce a long-range transmission plan and update it every three years.94
The committee has already had notable success. In 2011, the regional grid planner ISO-New England identified a “Central [Vermont] deficiency.” A 2013 study by the state’s Planning committee found that distributed generation and energy efficiency are closing the reliability gap, removing the project from the regional ten-year plan, and saving ratepayers $157 million in transmission upgrades.95
Standard Offer Program for Distributed Generation
In 2009, the Vermont legislature adopted a standard offer or “feed-in tariff” program to encourage small-scale renewable energy generation. The program provides 15-to-25-year contracts for power generation from biomass, wind, hydro, landfill and agricultural methane, and solar energy. The program originally had fixed and published prices, with a total program size of 50 megawatts (MW), and projects limited to 2.2 MW or smaller.
Subsequent changes (in 2012) to the program have raised the program cap to just over 127 MW (11-12% of year 2008 peak electricity demand),96 but changed the pricing mechanism to a reverse auction that favors the largest size projects that fit under the cap. With a 5 MW annual limit on new capacity, this has resulted in just 2-3 projects developed per year, largely by out-of-state developers.97
So far, the program has resulted in 39 MW of new distributed renewable energy generation, 75% from solar, 13% from farm-based methane, and the remainder split between hydro, biomass and landfill methane. By the end of 2014, the total is expected to rise to about 45 MW.98
Net Metering & Value of Solar
Adopted in 1997, Vermont’s net metering law allows individuals or groups of utility customers to offset their energy use with a 500 kilowatt or smaller renewable energy system. Solar producers receive an “adder” to their net metering credit, sufficient to award them 20¢ per kilowatt-hour.
Until recently, the net metering program was capped at 4% of the state’s energy sales, but with the support of the largest electric utility, Green Mountain Power, the program cap was recently raised to 15%. “Green Mountain Power was confident that it can both encourage distributed solar and maintain a healthy financially strong utility,”99 because solar is a “hedge against increased transmission costs; and as insurance against costly spot-market purchases during summer spikes in demand”100
Green Mountain Power isn’t the only Vermont utility benefiting from net metering. Darren Springer, deputy commissioner at the Vermont Public Service Department, says “net metering allowed the Vermont Electric Power Company (VELCO) to avoid a $250 million transmission line upgrade.”101
Not all Vermont utilities support net metering, because of differences in their electricity demand. While Green Mountain Power has its peak energy demand in the summer (when solar production also peaks), other Vermont utilities have their peak demand in the winter.
The recently raised net metering cap also launched a net metering 2.0 stakeholder process to assess how customer-generated power will work technically and economically in the utility of the future.102 It also includes an estimate of the “value of solar” where the Public Service Board will annually review the “costs and benefits incurred as a result of any single net metering installation installed in 2015 or a later year” to ensure the policy remains a good deal for ratepayers.103
Vermont instituted partial decoupling policy for its two largest investor-owned utilities in the mid-2000s.104 As in many other states, it has helped insulate these utilities from the substantial energy savings produced from energy efficiency programs.
Vermont has a mix of utility 2.0 policies, particularly decoupling, integration of distribution and transmission planning, and the separate oversight of energy efficiency programs. It also has two key energy democracy policies – net metering and a feed-in tariff – that are among the most ambitious in the country (as a percentage of potential load and peak demand served). In contrast, its renewable energy requirement is remarkably weak in contrast with other states, showing a greater dependence on distributed generation to achieve renewable energy growth.
Vermont may have traveled farther along the path toward utility 2.0 than most states (excepting Hawaii or California, perhaps), but the regulatory model falls short on some key structural changes. The distribution system remains firmly in control of incumbent utilities, far from the independent distribution operator envisioned by New York’s Reforming the Energy Vision and others.
On the other hand, the state is achieving many of the principles of the 2.0 electric utility system. Its energy efficiency achievements rank among the best in the country. Close to 15% of its electricity comes from renewable energy in 2013, putting it among state leaders. It even has elements of energy democracy because the combination of the net metering and feed-in tariff programs mean as much as 25% of the state’s peak energy demand will be met by distributed generation, far more than most other states.
Vermont is definitely a state to watch.
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