Tuesday, August 20, 2013 at 12:37 PM
Growing consumer interest in net metering has led to a surge in rooftop solar installations and the use of distributed energy technology. However, potential challenges are developing for some utilities with existing state incentive plans to bolster net metering using traditional rate recovery models they believe do not fully recoup the value of services and reliability provided.
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A unique confluence of challenging and revolutionary factors is occurring in the normally steady and predictable utility industry. Electricity demand plateaued in 2007 after years of stable growth and it may stay flat for several years to come. Increased energy efficiency from both the private sector and state/federal directives, more stringent environmental compliance regulations, planned retirements of coal-fired power plants and the substantial increase in the availability of relatively affordable domestic natural gas have uniquely coalesced at roughly the same time.
Undergirding all these changes in market and regulatory forces is the emergence and utilization of 21st century computing capability via the application of smart grid technology, while the rate recovery mechanisms used in some states to pay for projects and new consumer options is based on a mid-20th century model. These new technological applications and devices offer great promise for utilities, grid managers and consumers by giving them the capability to manage energy use, reduce harmful air emissions and prevent power outages. Policies surrounding things like net metering also have given consumers a financial incentive to harness renewable energy either through owning their own systems or through attractive leasing options to have solar panels installed by third party companies. Rooftop solar installations grew 76 percent between 2011 and 2012 and provide more than 3,000 megawatts of installed capacity.1
Depending on perspective, these can be exciting prospects or ones of potential strategic concern.
Smart grid is a comprehensive term that describes the technological advancements of the transmission and delivery of electric power. In essence, smart grid encompasses the utilization of 21st century information technology and computing processing to remotely monitor and automate aspects of the electric grid. The grid traditionally has been made up of substations, transformers, transmission lines, switches and a variety of other physical components. By applying new technological advancements to the existing grid infrastructure, electronic devices can now have two-way digital communication with a utility to help manage load, voltage and directly monitor outages.2
This automation allows the simultaneous and efficient monitoring of millions of devices that could have significant future ramifications for consumers and the economy. For example, utilities previously had to wait for customers to report outages during a storm, but with smart grid technology, grid managers and utilities can immediately locate problems as they occur. Minimizing outages and quickly repairing storm damage can save money, reduce hardship and delays for customers. It also allows better prioritization of the utility’s assets and personnel. The advanced sensing and computing capabilities of these smart systems also can detect when critical components of the grid may be damaged or near the end of its useful life and indicate repairs before major problems happen.
One of the practical outcomes from the increased use of smart grid technology is the growing expansion of distributed energy technologies. These technologies are referred to as “distributed” because they are typically small, modular devices placed at or near the point of energy consumption, rather than a traditional centralized system, where electricity is produced at a large utility some distance away that transmits power on existing infrastructure through substations and power lines. Examples of distributed energy are found more commonly in photovoltaic systems, localized wind turbines, fuel cells, and combined heat and power systems, which recover heat that normally would be wasted in an electricity generator by using it to produce steam for hot water heaters, heating or cooling. When connected to the electric grid with smart technology, distributed energy can provide utilities options to meet peak power demand, power generation and localized distribution with discrete batches of electricity.3
Another benefit of distributed generation is the ability to help so-called microgrids isolate themselves from disturbances by continuing to provide power during outages with the local utility. The most common example supporters of expanding microgrid development use is the New York University Medical campus, which invested heavily in an efficient cogeneration plant that utilized natural gas and combined heat and power. The medical campus’s system created almost continuous electricity and provided heat when Hurricane Sandy was causing tremendous damage to the New York/New Jersey area.4
Net metering is one policy nexus that utilizes the connective, two-way functionality of smart grid technology with distributed energy. According to a renewable energy consortium, the Database of State Incentives for Renewable Energy, managed by the U.S. Department of Energy, 43 states have adopted net metering policies allowing customers of certain electric distribution companies the ability to generate their own electricity, which can be used to offset their electricity usage.5 Net metering is an increasingly attractive option for consumers because it also allows a customer to sell excess power to the utility. Homes and facilities are connected with a smart meter that can communicate directly with a distribution company or utility, which measures the net quantity of electricity that the customer uses. These meters spin forward when the customer uses electricity from the distribution company and spin backward when the customer generates excess electricity. In essence, the excess electricity is exported to the electric grid and used to power other homes or businesses in the area.6
If consumers generate more electricity than they consume, they receive a credit that is typically applied to their monthly power bill. The value of the credit is determined by a methodology approved by the state public utility commission or public service commission. The size and capacity of power loads available for net metering vary from state to state. Overall, the Solar Energy Industries Association, a trade association of solar energy companies, estimated in 2012 that roughly 220,000 customers nationwide utilized net metering—primarily through solar photovoltaic systems on homes and business.7 A July 2013 report published by the advocacy organization Environment America found that Arizona has the most cumulative solar power capacity per person in the country, while California leads the nation with overall installed solar capacity at 1,033 megawatts.8
The U.S. solar photovoltaic systems market can be broken down into three segments: customer-owned, third-party owned and utility-owned. The fastest- growing segment of the residential rooftop solar industry is the third party business model, which grew 76 percent between 2009 and 2011. Many consumers find contracting with a third party an easier way to accrue the benefits of solar power that can reduce power bills, while allowing a private company to shoulder the upfront costs of installation and ownership of the infrastructure.9 The solar installation companies, in return, get the federal tax advantage of the alternative energy investment tax credit, which provides a 30 percent dollar-for-dollar credit against federal tax liability.
The American Recovery and Reinvestment Act of 2009 created a program in the Treasury Department called Section 1603, which allowed developers to receive a direct federal grant in lieu of the 30 percent investment tax credit. The Solar Energy Industries Association said the program has supported more than $7 billion in private sector projects.10 Combining federal tax incentives with state programs, renewable energy mandates, accelerated depreciation schedules and long-term contracts allowed in purchase power agreements or lease scenarios can be financially rewarding for third-party companies. Venture capitalist Nat Kreamer, CEO of Clean Power Finance, estimated that as much as 45 percent of an investor’s expenses can come back through favorable tax treatment in the first year of a loan and the return on investment can be in the high single digits and mid-teens.11
Although the total number of customers utilizing net metering and distributed options is relatively small nationwide (less than 1 percent of the population), the growing consumer interest and anecdotal evidence of its expanded use across the country has some in the utility world seriously questioning the long-term viability of the traditional power delivery system. David Crane, the president and CEO of the utility group NRG Energy, said at a March 2013 conference hosted by The Wall Street Journal that utilities “do realize that distributed solar is a mortal threat to their business” because utilities increasingly will have to split the cost of continued infrastructure upgrades and maintenance with fewer customers.12
The Edison Electric Institute, the largest umbrella organization representing investor-owned utilities, published a report in January 2013 highlighting the strategic challenges ahead for the industry. The report called distributed energy resources and demand-size technologies potential game-changers that could affect the future economic viability of utilities. It found, “While the various disruptive challenges facing the electric utility industry may have different implications, they all create adverse impacts on revenues, as well as on investor returns, and require individual solutions as part of a comprehensive program to address these disruptive trends. Left unaddressed, these financial pressures could have a major impact on realized equity returns, required investor returns, and credit quality. As a result, the future cost and availability of capital for the electric utility industry would be adversely impacted. This would lead to increasing customer rate pressures.”13
In practical terms, here is the long-term potential financial problem for the utility sector. As distributed generation and energy demand gain market share and consumer acceptance or utilization through numerous federal and state incentive programs, utilities are facing a declining loss of revenue. Utility projects themselves are very long-lived assets that rely on a financial rate-recovery model set by state public utility commissioners or public service commissions that spread costs to consumers out over a lengthy period of time, usually over several years. Utilities, however, must continue to keep pace by providing integrating technology for distributed energy and metering, as well as maintaining the existing fixed costs of power generation, transmission and distribution infrastructure for customers when they need to reconnect to the grid. But on cloudy days, evenings or during times of particularly high demand, distributed customers still need power and the utility is obligated to provide it instantaneously to maintain reliability.14 Further, many states like California and Massachusetts require utilities to pay net-metering customers at the higher retail rate for the power they generate rather than the wholesale rate regardless of if or when the utility needs excess peaking load. This potentially can lead to a significant drop in future revenue for a utility, and without revenue, it is difficult to attract capital in the private market to pay for future infrastructure or make the new technology investments to enable enhanced distributed options that customers desire.15
The Growing Debate in States
A growing dispute between utilities and solar energy providers and advocates is playing out across the country over the most appropriate way to continue incentivizing net metering and distributed technology. High-profile rate cases in Arizona, California, Idaho and Louisiana are largely centered on arguments raised by power providers that net-metering customers are not paying the full cost of the electric services and system maintenance being provided to them because of generous incentive programs in place. The utility Arizona Public Service estimates that each of the roughly 18,000 residential rooftop solar homes in its service territory shifts about $1,000 in costs annually to other ratepayers.16 Solar industry and installation companies and renewable energy groups argue these systems provide significant economic value to all consumers by reducing their power bills and household energy consumption, as well as providing numerous economic and clean air benefits by reducing the need for future power generation and transmission costs that most likely would come from less environmentally friendly sources.
Those who support net metering believe much of the utility pushback is a result of the potential threat net metering and distributed options could have to the utility industry’s bottom line. A January 2013 study conducted by an advocacy group called Vote Solar estimated that California’s net metering program provides electricity consumers $92 million a year in economic benefits and that it “does not produce a cost shift to nonparticipating ratepayers; instead it creates a small net benefit on average across the IOUs’ (investor owned utilities) residential markets.”17 In an interesting turn, conservative groups not normally associated with the promotion of alternative energy have spoken out against plans in Arizona and Georgia to change the incentive structure to promote rooftop solar at their respective state public service commissions. Barry Goldwater Jr. has formed an organization in Arizona to represent solar installation companies decrying reductions in net-metering incentives in TV and radio commercials claiming such changes will “extinguish” the use of household solar power for the benefit of utilities.18
In solar friendly California, with the nation’s most aggressive renewable energy targets of 33 percent by 2020 and the nation’s leader in installed solar capacity, the issue of cost-shifting prompted legislators to pass Assembly Bill 2514 in 2012, which directs the state Public Utilities Commission to complete a study analyzing the full costs and benefits of the state’s net energy metering program. The bill, sponsored by Assemblyman Steven Bradford, also requires the Public Utilities Commission to examine the extent to which ratepayers across different regions of the state are receiving service under the net energy metering program and the extent to which those customers are paying the full cost of the services being provided to them by utilities.19
“We need to get an understanding of the costs and benefits of net metering,” Bradford said in an April 2013 ClimateWire story. “Utilities say it is expensive, while the solar industry says it benefits the ratepayers. A.B. 2514 simply requires the PUC (public utility commission) to do the accounting and let us know the results so the Legislature and the public get a better understanding of how to design and implement sustainable programs to promote clean generation.”20
Some state utility commissions, however, already have taken action against attempts to change net metering programs. State utility commissions in Louisiana and Idaho both ruled in late June and early July 2013 against petitions made by utilities to raise monthly fees for residential and business customers that use metering. In a July 2013 Wall Street Journal article, the Idaho commission raised concerns that Idaho Power’s proposal would “discourage investment in distributed generation” and it suggested that while customers may not be paying the full cost of services, “more work needs to be done to establish the correct customer charge.”21 The utility proposed doubling the current cap on power generation from net metering customers to 2.9 megawatts in return for lowering the credit rates it pays in addition to requiring customers to give up extra generation credits they earn by the end of the year. The commission, in its rejection of the plan, criticized the utility for not trying to resolve its specific disputes with customers before seeking a rate increase.22
Many utilities facing a surge of net metering customers believe conventional rate recovery methods used by state public utility commissions may need a fresh look. In states like New Jersey and Virginia, utilities can impose standby charges to recover the costs associated with having backup power ready and available for customers utilizing distributed generation. Typically, the biggest expense for a utility is not the power itself but the cost to maintain the infrastructure necessary to deliver energy to customers. Virginia’s State Corporation Commission in 2011 approved a request to allow Dominion Energy to add a standby charge estimated to be about $30 a month for a 10 kilowatt solar system, which is roughly three times larger than the average size of solar systems (three kilowatts) on residential homes in the state.23
Representatives from the utility Southern California Edison have suggested California’s existing tiered electricity rate structure, which was intended to charge customers more based on total consumption to help reduce energy demand, is flawed when accounting for growing customer use of rooftop solar. The utility contends that the largest consumers of energy also have installed rooftop solar panels. Thus, when taking into account the credits they can accrue from net metering, these large consumers are not paying the top-tier prices envisioned by state regulators. Instead, the utility believes the commission should expand the existing flat fee of roughly 80 cents per month on existing net metering customers to ensure that standby infrastructure is being maintained.24
In Arizona, the state’s largest utility has proposed grandfathering in existing customers under the current incentives program, but has proposed that the Corporation Commission create a separate structure for new metering customers that would include service charges based on the times standby power is used during peak usage.25 This and other increased usage fees have been strongly rejected by solar advocates as a punitive step that hurts consumers' bottom line and provides a disincentive from using solar panels at all.
One potential option that has generated at least partial acceptance by many solar and net metering organizations is the voluntary option to use a rate structure similar Austin Energy’s value of solar tariff, or VOST. In 2012, the Texas utility became the first in the country to adopt this hybrid approach, which separately meters a residential customer’s energy consumption from the power a homeowner’s solar system may generate. A solar customer in its service territory is automatically signed up for the program and receives monthly bills for the power the home consumes. Customers receive a credit of 12.8 cents for every kilowatt hour their systems may generate; that credit is subtracted from the monthly bill, instead of the customer's energy meter rolling back when it generates power for the grid like conventional net metering program. The credit’s valuation methodology was developed in conjunction with a California alternative energy consulting firm called Clean Energy Research by utilizing an algorithm that accounts for the value and benefits of distributed solar. The algorithm is updated annually and examines the following benefits to the utility:
Avoided fuel costs, which is valued at the marginal costs of the displaced energy;
Avoided capital cost of installing new power generation due to the added power capacity;
Avoided transmission and distribution expenses;
Line loss savings;
Fuel price hedging values; and
The solution developed by Austin Energy and its valuation of distributed solar in many ways reflect local conditions in its service territory. Its supporters note that, in theory, there should be no revenue loss for the utility nor an undue burden placed on other customers lacking rooftop solar systems because the utility would only pay for the value it receives.
Solar advocates have examined the VOST tariff and have generally viewed it as a complementary policy or alternative that should not be used to replace net metering, which has an established and measurable track record in dozens of states as well as enthusiastic customer interest.
The answers for state policymakers will not be simple or easy. The growing implementation of smart grid technology and grid modernization efforts, as well as customer interest in distributed energy options, likely will increase over time. What is certain is that rate methodologies and incentive programs created in the 20th century must keep pace with an ever-changing technological world.
2. “Smart Grid 101
.” Smart Grid Information Clearinghouse, Virginia Tech Advanced Research Institute.
11. Trabish, GreentechSolar, June 19, 2012.
16. Bernstein, Washington Post. June 9, 2013.
24. Mulkern, ClimateWire. April 2, 2013.
Net Metering, Disruptive Change and Emerging Rate Policy Issues