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Distributed renewable resources and the utility business model
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The Electricity Journal xxx (2015) xxx–xxx
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The Electricity Journal journal homepage: www.elsevier.com/locate/electr
Distributed renewable resources and the utility business model Cliff Rochlin Loyola Marymount University, Los Angeles, United States
A R T I C L E I N F O
A B S T R A C T
Article history: Received 8 December 2015 Accepted 19 December 2015 Available online xxx
The recent calls for a new utility business model, to avoid a DER-induced death spiral, fail to fully understand the important role the utility business model has played in funding regulatory-driven social programs. Over the past 30 years, as new regulatory demands have been placed on the utility, the utility business model has evolved. The new DER challenge to the utility business model is basically a new form of uneconomic bypass that requires regulators to get utility pricing right, to reflect both the incremental and full cost of utility service. ã 2015 Elsevier Inc. All rights reserved.
1. Introduction Broadly speaking, distributed energy resources (DER) (any form of distributed generation (DG), net metering energy sources, demand-response programs, price-responsive electric vehicles, energy efficiency, and distributed-level storage services) is providing the impetus for developing a new utility business model. Specifically, recent talk of the need for a new utility business model across the country is predicated on the continued technological innovations in metering, communications, and distributed storage, coupled with the rapid growth of customerowned renewable energy self-generation at the distribution level. Such advances allow for non-utility energy interactions at the distribution level, and may ultimately provide for customer independence from the grid. To the extent that customers leave the grid and the utility’s costs do not decrease accordingly, rates to remaining ratepayers will increase. Higher rates will provide incentives for more of the remaining ratepayers to leave the grid. Hence, without a new business model that is not based on the growth in electricity sales, the regulated utility will find itself in a “death spiral.” While this narrative seems rational on the surface, it is based upon three assumptions that are examined in this article. The first assumption is that the 100-year-old vertically integrated utility business model is inadequate to deal with the technology of the 21st century. The second assumption is that independence from the grid is in the customers’ best interest, for both reliability/resiliency and economic reasons. Independence would allow for the continued availability of electricity during extreme weather events, such as the polar vortex and Hurricane Sandy.
E-mail address: [email protected] (C. Rochlin).
Independence also implies that the utility service model, traditionally a natural monopoly, is no longer a “least-cost” option to the customer any longer. A customer who is able to meet her/his energy needs by self-generating may infer that the utility transmission and distribution services are redundant and discontinue contributing to utility fixed costs. The third assumption, an implicit one, is that the utility business model no longer meets regulators’ needs. Regulatory goals have moved beyond the safeand-reliable provision of energy. For the last 30 years, the utility has proven to be both the laboratory and the provider/collector of funds needed to meet the societal energy goals of increased energy efficiency and reductions in greenhouse gas (GHG) emissions. To the extent that the current utility business model can no longer fund these societal goals, regulators will also have to find a new business model. 2. The evolution of the utility business model The assumptions that the vertically integrated business model has remained static and is based on the continued growth in energy sales lead to a strawman model that is easily discredited. However, the utility business has been evolving with changes in technology, business climate, and regulatory mandates for social programs. One of the oldest and most established social programs is energy efficiency: programs specifically designed to mitigate the growth in electricity sales. 2.1. Energy efficiency and integrated resource planning The current calls for a new utility business model are not new. Previous warnings of the need for a new business model initially surfaced in the 1970s and early 1980s to avoid an impending utility death spiral. A slowdown in electric sales coupled with
http://dx.doi.org/10.1016/j.tej.2015.12.001 1040-6190/ ã 2015 Elsevier Inc. All rights reserved.
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unanticipated, high rates of inflation, two oil embargoes, and significant nuclear power plant cost overruns created economic challenges to the vertically integrated electric utility business model. As rate increases failed to keep pace with surging costs, utility solvency became questionable. Regulatory responses such as changes in the timing of rate cases, corrections for financial attrition, and Allowance for Funds Used During Construction (AFUDC), provided some relief to the utility business model based on cost recovery through electricity sales.1 In addition to regulatory relief, another response to high electric rates was elicited. Higher-than-expected costs eventually led to higher electric rates. To mitigate the impact of higher electric rates, it became reasonable to use electricity more efficiently. This behavioral response is predicted by the basic economic theory that higher prices are used to signal the increased scarcity of the resource and provide an incentive to use less of the resource. Changes in electric rate design supported this view as declining block per-kWh rate structures were changed to increasing block rate structures. However, this change in rate design was used to highlight that the efficient use of electricity was somehow different for electricity than for other resources. This uniqueness was embodied in a new term, “negawatt”; the most cost-effective kWh is the one not used. This interpretation led to a new way to plan the electric grid and set the course for the current round of calls for a new business model. Use of the term negawatt redefines the concept of energy efficiency from an attribute describing how electricity is used, to a resource in its own right, one that shifts the derived demand for electricity inwards and can be added to the grid as an independent resource. Energy efficiency was now viewed as a resource that should be used in planning the electric grid.2 Electric grid planning evolved into integrated resource planning (IRP), where energy efficiency/demand response programs are considered to be an equal building block, along with generation resources and transmission facilities, in designing the electric grid. The idea was to build a safe electric grid that would explicitly incorporate a societal goal: slower growth in electricity usage. However, to reach this goal, the utility needed to be compensated for its energy efficiency efforts and meeting its revenue requirements led to decoupling of revenues from electric sales. 2.2. Decoupling Decoupling refers to the disassociation of a utility’s profits from its sales of the energy commodity. Instead, a rate of return is aligned with meeting a given revenue target. Rates are trued up or down between rate cases to meet the revenue target. This makes the utility indifferent to selling less electricity in the short run. That is, decoupling improves the ability of energy efficiency programs, demand response programs, and distributed generation to operate within the utility environment and protects investors from lost margins between rate cases.
1 Financial attrition can result from using historical test years in a rising unit cost environment. Attrition can be mitigated by using forward test years in rate cases, interim rate increases, cost trackers to quickly include new capital projects into ratebase when they become used and useful, higher customer charges, and rate cases for multiple years with escalation rates built in for interim years. When utilities are not allowed to recover in current rates a return necessary to finance construction projects during the construction period, they will generally be allowed to capitalize the financing costs for future recovery from ratepayers. AFUDC represents capitalized interest and equity costs, which will ultimately be included in rate base as a component of plant in service, thereby earning a return and being recovered through depreciation allowances. (Lowry et al., 2010, pp. 55–57) 2 Energy efficiency programs are administered by utilities, state agencies, and other third parties and are paid for by utility ratepayers, typically through a nonbypassable system benefits charge.
However, the operative phrase is short-run indifference. While decoupling may be a method to compensate investors for lost margins between rate cases associated with the promotion of DER, it does not necessarily create a long-term, sustainable, investment opportunity for the shareholder. Decoupling does not provide utilities with the incentives to promote energy efficiency, demand response, or the integration of DER at cost-based rates. Importantly, in the long run, decoupling does not provide a solution to the anticipated, systematic, erosion of rate base resulting from DERinduced declines in consumption and peak demand. While the utility may be indifferent to lost sales in a decoupled environment, theoretically no worse off for promoting DER, it does not solve the potential death spiral related to long run DER. 2.3. PURPA and electric restructuring In the late 1970s, the Public Utility Regulatory Policies Act of 1978 (PURPA) demonstrated that generation need not be built and owned by the utility.3 Generation could, in fact, be provided by third parties through the use of cogeneration. Efficient combined heat and power was not new, but to become a viable source of generation that could compete with the vertically integrated utility’s generation assets, PURPA provided both a guaranteed customer (the utility) for excess energy, which was priced at the utility’s avoided cost, and nondiscriminatory access to the transmission grid. The generation segment could be removed from the vertically integrated utility business model. This would eventually lead to a “new” utility business model where merchant generation would compete in a competitive, wholesale energy market with guaranteed nondiscriminatory access to the transmission grid. The regulated utility would build and maintain the network of wires, the decreasing cost transmission and distribution systems. This new business model was formally implemented and extended through electric industry restructuring. In the late 1990s through early 2000s, electric restructuring dominated the electric utility business model in California, New York, PJM, and New England. Restructuring focused on providing incentives for the vertically integrated utility to sell its nonnuclear generating assets, keeping the utilities financially viable by ensuring stranded cost recovery, and providing open access to the transmission grid through the creation of a FERC regulated independent system operator (ISO) or regional transmission organization (RTO). Electric restructuring unbundled generation from utility transmission and distribution and created a competitive, wholesale energy market. With the creation of a competitive, wholesale generation market, the utility would remain the main energy demand aggregator for its service territory ratepayers. The aggregation of the utilities’ hourly demand would intersect with the ISO supply curve to determine the market clearing energy price. Restructuring in California failed for many reasons culminating in the well-known energy crisis of 2000 and 2001, but one of the main reasons was that all the restructuring effort was placed on ensuring competition on the supply side. Hourly energy market
3 The Public Utility Regulatory Policies Act of 1978 (PURPA) was implemented to encourage, among other things, the conservation of electric energy, increased efficiency in the use of facilities and resources by electric utilities, equitable retail rates for electric consumers, expeditious development of hydroelectric potential at existing small dams, and conservation of natural gas while ensuring that rates to natural gas consumers are equitable. One of the ways PURPA set out to accomplish its goals was through the establishment of a new class of generating facilities which would receive special rate and regulatory treatment. Generating facilities in this group are known as qualifying facilities (QFs), and fall into two categories: qualifying small power production facilities and qualifying cogeneration facilities (FERC).
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Table 1 Evolution of the Utility Business Model. Social goal
Regulations
Utility response
1. Reduce pollution (through the decrease in electric usage) 2. Reduce electric rates (bills)
Energy efficiency/demand response
Decouple rates, balancing accounts, utility programs
Electric restructuring
3. Reduce GHG
Increase transmission and distribution infrastructure to support merchant generation Build transmission to renewable energy zones
Renewable portfolio standard, cap & trade Advanced metering infrastructure/Rate Advanced metering infrastructure design DER/EV/storage Investments to facilitate two-way use of distribution system
4. Engage utility customer 5. Reduce utility costs
prices were the result of matching generators’ offers with a vertical demand curve for every hour of the day, since retail rates did not increase to reflect the higher wholesale market energy prices. Thus, the crisis emphasized the need for both long-term power contracts and price responsiveness on the demand side. This was in fact a common denominator in all existing ISOs. 2.4. AMI and new rate designs It was not until the energy crisis that California state regulators took a first step in facilitating active participation by ratepayers and mandated advanced metering infrastructure (AMI) that allows for the two-way communication between the utility and its customers. The next steps of developing and implementing new rate designs in California include higher customer charges (minimum bills) and default time-of-use rates (TOU). California will finally implement its new rate design to take advantage of AMI with a default TOU rate design in 2019. The new TOU rate design moves away from flat kWh charges and closer to prices that reflect the actual cost of producing electricity throughout the day and within a season. One stated purpose of the new rate design is to “allow for more accurate allocation of costs and for energy rates to more fairly reflect the cost of services” (CPUC, 2015, p. 1). This is consistent with the usual interpretation of “just and reasonable” rates as rates based on cost causation and provides more accurate pricing signals and cost allocation. It is also based on sound economy principles: “A consumer does not only have to decide whether to consume additional units of a product; he has also to decide whether it is worth his while to consume the product at all rather than spend his money in some other direction. This can be discovered if the consumer is asked to pay an amount equal to the total costs of supplying him, that is, an amount equal to the total value of the factors used in providing him the product” (Coase, 1946, p. 173). Another aspect of creating a separate wholesale market was the realization that many of the services provided by generation assets within the vertically integrated utility were not priced. To guarantee that the ISO would not become an active player in the market, services like ramping, load following, regulation, and resource adequacy had to be priced separately. In essence, separate markets within the wholesale energy market had to be created that were based on performance. These new markets are exceedingly important for any “new” business model as they can provide an alternative source of utility funding (performance-based regulation) that is not based on capital expenditures and can also potentially provide a source of revenue for DER.
emissions. Initially, renewable portfolio standards mandated that a certain amount of new generation must be renewable. At the time, these mandates required the utility to add renewable generation that was significantly more costly than fossil fuel alternatives. Eventually, the RPS mandates evolved into percentages of energy generated by non-fossil fuel sources, excluding nuclear and largescale hydro projects. In California, the mandates have expanded to include energy storage assets. However, since the most costeffective renewable resources tended to be located outside of load centers, new, large, costly transmission projects were built. Since most of these new transmission lines were not driven by the traditional utility planning concerns of reliability and economic cost savings, a new “policy driven” reason for transmission construction was created. The goal of GHG emissions reduction intensified the role of policy direction in electric grid planning. IRP expanded from the efficient use of energy to mandating the type of generation resources the utility should purchase and the expansion of the transmission grid to gain access to distant sources of renewable generation. As more and more electric planning decisions were removed from the utility’s discretion, energy costs increased and the costs of meeting the GHG emissions reduction goal was paid for by electric ratepayers. Table 1 provides a concise summary of the evolutionary transformation of the electric utility business model over the last 30 years. To achieve the regulator’s policy goals 2–4, utility rate base has increased significantly. One can expect that, even though goal 5 is to reduce utility costs, significant enhancements to the distribution system will be required to accommodate the anticipated large amounts of DER.4 For example, “rooftop solar installations, which are characterized by relatively small size, intermittent power production, widely dispersed deployment in the grid, and the inability of grid operators to monitor and control them. This creates a much more dynamic grid with respect to load, voltage and other parameters, and drives the need to reinforce key parts of the grid to better handle the new hardware and operating characteristics.” (FierceEnergy, 2015) Table 1 shows that, as the social goals of regulators crystallized into policy, the utility was able to continue to build rate base and have the opportunity to earn its authorized rate of return. Simultaneously, the recognition for pricing to reflect full costs, support flexibility, and reflect performance have been enhanced. The flexibility of the utility model is impressive. To summarize, the utility business model has been evolving for over 30 years. The vertically integrated utility business model of the 1970s is not the utility business model of today. Except for the first changes to the business model in the 1970s, the evolution of
2.5. GHG emissions reduction A major change in the electric industry, as well as the utility business model, has been the regulatory mandate to reduce GHG
4 SCE’s expected distribution resource planning expenditures through 2017 are between $347 million to $560 million. From 2018 to 2020, the projected cost grows to between $1.4 billion and $2.6 billion (SCE, 2015).
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the utility business model has been driven by regulatory goals of increased energy efficiency, reduction in the use of fossil fuels, increased customer participation, and energy industry transformation (use of markets and pricing of services). These social goals have not come without increased costs. Notably, the funding for these changes has come within the evolving utility business model and was paid for by utility ratepayers. However, as utility costs have increased and the growth in electricity sales have stagnated by design, electric rates continue to increase. It is the potential to avoid these rising electric costs that has now become the siren call for customers to install DG or rooftop solar PV and leave the grid. 3. Active participation by customers The regulatory pursuit of social goals has led to new technologies, energy efficiency/demand response programs, storage mandates, renewable distributed generation (rooftop solar), electric vehicles, and AMI. All of which are the components that make up the microgrid. The microgrid has the potential to transform the electric industry from a centralized, vertically integrated model paid for by ratepayers to a local distribution centric market that works in real time at the edge of the grid with customers that have options and can respond to price signals. One potential outcome of a microgrid is that its customers are expected to see increased reliability/resiliency and lower energy costs, providing an incentive to leave the utility grid. If this is the case, microgrid customers would no longer contribute to the utility’s revenue requirements. If the associated cost reductions fail to offset revenue losses, then it would lead to the utility death spiral. Hence, the call for a new utility business model to secure revenues to keep the utility financially whole. Another potential outcome of a microgrid is the continued use of a modernized, flexible utility distribution system. In this scenario, the revenues associated with the ancillary services separately priced provides an economic source of funding for the microgrid. The utility distribution system provides a way to connect, coordinate, and fund microgrids. The role of the utility as an integrating force for the wholesale and retail market continues. The microgrid will provide the utility with revenues based upon its use of both the distribution and transmission networks and not on the amount of energy used, mitigating the potential for a utility death spiral. Either scenario assumes active participation through the pricing mechanism will transform the ratepayer into a customer, where customers would have more choices, more control, and foster two-way communication between the utility or energy service provider and the energy user. This transformation is actually a prerequisite for the new vision of the electric industry: IRP through markets that operate at edge of the grid.5 Leveraging off the distribution network, a distribution system platform (DSP) will create an intelligent network for delivering safe, reliable energy by integrating diverse resources to meet customer needs and social goals. It will foster broad market activity that monetizes the electric system and social values. Expanded IRP will continue to be the guiding principle with a major emphasis on markets at the distribution level. DER will lead to greater customer knowledge and actions as they form microgrids. The funding for microgrids will come from the services provided by customers to the utility distribution system. The utility will continue to remain the interface with the wholesale markets. The utility will integrate customer usage and social goals into markets for energy at the wholesale, retail, operations, and planning levels.
5 New York’s Reforming the Energy Vision (REV) proposes this type of distribution platform model.
A central assertion of the need for a new business model is that customers want control, convenience, choices, and two-way communication with utilities when it comes to energy usage. This active role supplants the current passive role of the ratepayer that wants reliability and low energy rates (bills). Numerous pilot projects provide support for the basic assumption that customers will respond to price differentials if they are educated in new rate designs and it is relatively easy or transparent to respond to those signals. That is, once their preferences can be transferred to a computer, appliances and thermostats can be adjusted automatically to respond to price signals. This may be a necessary development in the reformed electric vision, but it is not sufficient. Two additional issues must be determined. First, do customers want to go beyond price responsiveness to actually deal with the complexities of providing and selling energy services to the utility? After all, electricity is a derived demand. Electricity is an input, a requirement, needed to supply the power to deliver services from appliances owned by the customer. Electricity per se, is not the goal. To the extent that third parties can make these complicated options and decisions, made possible by customer investments, transparent at a lower cost than the utility, is speculative at best. Second, is the assumption that the growth in DER is being accelerated because of “the increased financial viability compared to traditional generation because of continuous lower price points to produce and install DER” (Mackinnon et al., 2015 p. 1). This statement seems to be at odds with the reality that even utilityscale renewable generation is still dependent on federal subsides.6 4. Uneconomic bypass Any speculation about customer DER participation at such an involved level is moot until customers face energy prices that reflect the real cost of energy assets (DER, storage, AMI) that are not modified by tax credits, accelerated depreciation, feed-in tariffs, or subsidies embodied in net energy metering. Regulatory capture by the environmental movement to reduce energy usage and GHG emissions through the reduction in the use of fossil fuels has totally distorted energy prices. Mandated RPS created a market for variable energy resources at power purchase energy prices that remain above the cost of fossil fuel production, socialized the cost of building new transmission facilities to fulfill the public policy goals of increased renewable resources (not for reliability or economic reasons), and mandated energy storage requirements have all distorted and increased the cost of utility provided energy. The utility has been used by regulatory agencies to be the financial engine to fund the transformation of the U.S. energy industry. The tendency of energy regulators is to ensure that the utility serves as a vehicle for funding social goals by providing direct subsidies for energy efficiency and rebates for installation of distributed clean energy resources. With regard to subsidies and rebates, while they encourage consumer investments, they prevent consumers from seeing the true incremental cost/avoided cost associated with incremental/decremental usage and distort customers’ ability to value investment decisions according to their willingness to pay.
6 “The report found that power purchase agreements prices for wind costs would need to increase 32–62% for wind developers to maintain profitability on projects. It also found that removing the investment tax credit (ITC)—in a model with a constant PPA price—could reduce a developer’s returns on wind by 68–109%, and on solar by up to 76%.” . . . “In an AWEA statement, ‘After the expiration of the PTC at the end of 2012, wind installations dropped 92% in comparison to the following year,”’ GAO reports. “Collectively, the constraints faced by developers with reduced or eliminated federal supports would likely lead to a reduction in the level of investment in new renewable utility-scale electricity generation projects” (Brandt, 2015).
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Table 2 Comparable PV Costs. PV components
Utility scale PV (>1 MW)
Residential PV (< = 10 KW)
PV module Inverter & other hardware Engineering & construction Installation labor Customer acquisition & PII Sales tax Margin, G & A System cost ($/Watt)
$0.65 $0.40 $0.40 – – $0.05 $0.30 $1.80
$0.65 $0.90 – $0.35 $0.56 $0.05 $0.74 $3.25
If those costs were transparent and directly assigned to them, meeting the intended policy goals would be achieved at a lower social cost, since it would require fewer ex post mechanisms to “fix” the implications of cross subsidies among customers. To claim that a microgrid (conferring the ability to disconnect from the utility grid) can avoid higher utility energy costs, while increasing reliability and resilience, may facilitate uneconomic bypass. That is, since utility energy rates are so distorted, microgrid energy costs may be less than the utility’s energy rates but more than the utility’s energy production costs. All of these additional costs have been paid for by ratepayers. Customers seeking lower energy bills may actually generate energy at a higher cost, but pay a lower bill by avoiding these non-fossil fuel energy related costs. 4.1. Costs of residential PV (renewable DER) The notion that residential PV is an example of uneconomic bypass is supported by Table 2, which compares the cost of installing utility-scale PV with the cost of installing residential PV on a components cost basis.7 While the PV module costs are identical, the balance of system (BOS) costs for the residential PV are significantly higher. What is interesting to note is that, while the utility-scale PV installation cost is very close to the utility cost of PV, the residential cost is much lower than the reported average market price charged for residential PV of about $4.90/Watt (MIT, 2015, p. 81). The differential is due to many factors: (1) at the utility scale either the builder incorporates the solar subsidies into its utility bid or the utility retains the subsidies and passes the cost savings on its ratepayers, for residential lease PV installations subsidies need not be fully passed on to customers because the decision to install solar is based upon the solar lease payment being less than the forecasted electric bills; (2) residential installation costs vary depending on scale of installation, the diversity of the housing stock, and the specifications of the PV systems being installed; and (3) additional costs associated with customer acquisition and marketing, permitting, interconnection, and inspection (PII). Even though BOS will fall with experience and innovation, “some balance-of-system costs for residential systems will likely remain high because of the structure of U.S. political jurisdictions and the diversity of distribution of utilities” (MIT, 2015, p. 100). One major finding of the report is that “Utility-scale PV is likely to remain much less expensive than residential-scale PV, even in the face of foreseeable reductions in the BOS costs associated with residential-scale PV” (MIT, 2015, p. 111). The addition of storage does not make the value proposition of DER more palatable. “But as a number of commentators quickly noted, even at Tesla’s relatively lower prices — $3,000 for a 7 kW (kilowatt) battery and $3,500 for a 10 kW battery homeowners are
7 Table 2 combines the information contained in Figs. 4.7 and 4.8 found on pages 84–85 of the MIT report, “The Future of Solar Energy, an Interdisciplinary MIT Study.”
unlikely to save money by shifting their power consumption from the grid to a solar-plus-battery system. With the cost of solar plus storage penciling out, in some cases, at more than twice as much as power from the grid, the gap between the two is simply still too wide” (Gibson, 2015).8 Also, the cost (cents/kWh) of utility-scale PV is significantly higher than the cost of a natural gas-fired combined cycle plant.9 This is an example of the additional costs associated with regulatory social programs that have led to the rising utility rates. 4.2. Net metering Currently, most distributed solar generation enjoy the benefits of net metering. “Net metering charges the homeowner for the net quantity of electricity consumed—in other words, total consumption less total generation. This means, in effect, the utility is paying for electricity generated by the homeowner at the retail rate, in contrast to utility-scale generation facilities, which receive the wholesale price. Because the wholesale price includes charges for the transmission and distribution systems (on top of a charge for the power consumed), net metering pays distributed generators a much higher price for power than gird-scale generators receive” (MIT, 2015, p. 111). Another interesting fact related to net metering is that with a steeply tiered rate structure, net metering can result in an additional incentive to install solar that is equivalent to as much as 30% of the federal tax credit.10 Even though utilities’ net metering schedules generally impose system size restrictions so that DG facilities are smaller than the customer’s typical maximum demand, customers’ solar systems end up “over-generating” significantly at times of low demand, and are compensated for the excess energy generated at more than avoided costs. Thus, the utility is not fully compensated for maintaining the distribution infrastructure for either the customer’s purchase or sale of electricity. In addition, as solar generation tails off in the late afternoon, a significantly steep ramp is created for the early evening hours, which may increase the need for utilities to increase their ramping capabilities. The facts seem to contradict the claim that distributed solar PV is cost effective; in essence, it represents uneconomic bypass. That is, customers seeking lower energy bills may actually generate energy at a higher cost, but pay a lower bill by avoiding these nonfossil-fuel energy-related costs. From a social welfare perspective, DER bypass may be inefficient unless energy tariffs are corrected.
8
See Helman (2015) for calculations. “Adding a charge of $38 per metric ton of CO2, consistent with the ‘social cost of carbon’ used in recent federal-level regulatory analyses, increases the levelized cost of energy (LCOE) for the natural gas plant by 1.47 cent/kWh, bringing its LOCE to 8.08 cents/kWh—still well below the estimated LCOE for both the residential and utility-scale solar projects. . . . In order for the LCOE for the utility-scale PV to be equal to the natural gas-fired generation, the CO2 charge would have to rise to $104 per ton” (MIT, 2015, p. 109). 10 Severin Borenstein’s May 26, 2015, blog “What Put California at the Top of Residential Solar?”, at https://energyathaas.wordpress.com/2015/05/26/what-putcalifornia-at-the-of-residential-solar/. 9
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The success of DER today seems to be a classic example of uneconomic bypass. 5. The Role of the Regulator What may not be obvious in this new view of the interactive electric world is that, as the new technologies transform passive ratepayers into active customers, customers will have alternatives. Once customers become aware of rate designs that reflect the cost of providing energy and have the ability to respond to the pricing signals, they will seek to reduce energy costs. Once the additional costs related to tax investment incentives and cross subsides needed to fund social programs embedded in utility rates become explicitly known, customers will seek to bypass them. To the extent these costs can be avoided, the creation of microgrids will provide an incentive to leave the utility grid. This view of the new, active customer posits a different reason to leave the grid: uneconomic bypass. It is not the anticipated production cost savings associated with the microgrid. Instead, it is taking advantage of the ability to avoid the costs embedded in utility rates that are associated with funding energy efficiency and GHG emissions reduction programs. If this were to occur to a significant degree, it would not only be that the utility is in need of a new business model, but so would regulatory agencies need a new way to fund their social goals. While not explicitly noted, this could be a motivating force for regulators to acknowledge that the incentive for microgrid customers to leave the grid is socially undesirable. One option for regulators is to concentrate on making adjustments to utility compensation models. The regulator can redefine how utilities are compensated for providing services traditionally provided to ratepayers. Another option is that regulators could foster the development of the microgrid within the context of developing a modernized, flexible distribution network. The transformation of the radial distribution system into a distribution network, one that is dependent on the two-way use of the distribution local network, will need a source of revenue to survive since the cost of self-generation (DER) is more than the cost of utility-scale renewable generation. Revenues to support the microgrid or the local market are expected to come from the services provided to the local utility and the local utility will, in turn, earn revenues by providing integrating services to microgrid customers. With changes in utility rate design that are no longer based solely on energy consumption, both the utility and microgrids can both be economically viable. The key to either option is for regulators to get utility pricing right. 6. Conclusion The utility business model has evolved over the last 30 years and will continue to do so because it is in the regulator’s interest. It is to all stakeholders’ benefit to ensure that the network of transmission lines and distribution circuits remain reliable, flexible, and safe. This implies a continued role for the utility in providing integrating and operational services on both the wholesale and retail levels. The incentive created by uneconomic
bypass to leave the grid, leading to the utility death spiral, is neither an economically nor a socially viable alternative. Customers leaving the grid do not only cause concern for utilities. Current costs of microgrids seem cost-effective because their costs are less than current utility rates. However, utility rates include much more than the cost of energy production. As a result, microgrids represent the latest form of uneconomic bypass that not only undermines the economic viability of utilities, it raises the cost to society of producing electricity. Undermining the economic viability of the utility also calls into question the continued viability of regulators to use the utility as a source of funding for its social goals. Regulators are facing a dilemma: microgrid funding will rely on selling ancillary services to the utility; however, the microgrid may undermine the economic viability of the current utility business model. The call for a new business model is not to just avoid a utility death spiral, but to continue to provide regulators with a funding mechanism to meet their social and environmental goals. To the extent that microgrids make economic sense in limited circumstances like hospitals, military bases, airports, campus like environments, and isolated communities at the end of a radial transmission line, remaining attached to a new, vibrant distribution network still makes economic sense. The utility business model can continue to evolve to meet the needs of its customers and regulators. The first step in this evolution is to address the uneconomic bypass incentive by getting utility pricing right. References Coase, R., 1946. The Marginal Cost Controversy. Economica 13 (August), 169–182. CPUC Proposed Decision (Rev 2.), Rule Making 12-06-013, July 13, 2015. FERC. http://www.ferc.gov/industries/electric/gen-info/qual-fac/what-is.asp. FierceEnergy, June 17, 2015. EPRI: Reinforcing Distribution Systems for Increased Renewables. Gibson, Bob, Solar Electric Power Association (SEPA)—Utility Solar Blog, Energy Storage: Finding the Value Proposition in a Growing Market, June 4, 2015. Helman, Christopher, 2015. (Forbes Staff), Energy, Why Tesla's Powerwall Is Just Another Toy For Rich Green People, 5/01/2015 @ 11:36AM. Brandt, Jaclyn, 2015. Is a Production Tax Credit Essential for Wind Growth?, Fierce Energy, June 2, 2015, Summary of GAO Report to Congressional Requesters— Electricity Generation Projects: Additional Data Could Improve Understanding the Effectiveness of Tax Expenditures, GAO-15-302, April 2015. www.gao.gov/ assets/670/669881.pdf. Lowry, Mark Newton, David Hove, Lullit Getachew, Matt Makos, 2010. Forward Test Years for Electric Utilities, prepared for EEI, August 2010. http://www.eei.org/ whatwedo/PublicPolicyAdvocacy/StateRegulation/Documents/EEI_Report% 20Final_2.pdf. Mackinnon, Lawrence, and Woods, Eric, 2015. The Energy Cloud: Emerging Opportunities on the Decentralized Grid, Navigant Research, June 2015. MIT. Energy Initiative, The Future of Solar Energy: An Interdisciplinary MI T Study, 2015, MI T ISBN (978-0-928008-9-8). SCE, 2015. Distribution Resource Plan Overview, July 1, 2015, Slide 3. http://www. edison.com/content/dam/eix/documents/investors/events-presentations/EIXSCE-DRP-Presentation-07-01-15.pdf. Borenstein, Severin, May 26, 2015, blog. What Put California at the Top of Residential Solar? https://energyathaas.wordpress.com/2015/05/26/what-put-californiaat-the-of-residential-solar/. Cliff Rochlin has over 35 years of experience in both the electric and gas industries. He currently lectures in Economics at Loyola Marymount University in Los Angeles. The author acknowledges the contribution to this article made by many hours of discussion with Amparo Nieto, Vice President at NERA Economic Consulting. The author remains solely responsible for any errors in the article.
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The Electricity Journal xxx (2015) xxx–xxx
Contents lists available at ScienceDirect
The Electricity Journal journal homepage: www.elsevier.com/locate/electr
Distributed renewable resources and the utility business model Cliff Rochlin Loyola Marymount University, Los Angeles, United States
A R T I C L E I N F O
A B S T R A C T
Article history: Received 8 December 2015 Accepted 19 December 2015 Available online xxx
The recent calls for a new utility business model, to avoid a DER-induced death spiral, fail to fully understand the important role the utility business model has played in funding regulatory-driven social programs. Over the past 30 years, as new regulatory demands have been placed on the utility, the utility business model has evolved. The new DER challenge to the utility business model is basically a new form of uneconomic bypass that requires regulators to get utility pricing right, to reflect both the incremental and full cost of utility service. ã 2015 Elsevier Inc. All rights reserved.
1. Introduction Broadly speaking, distributed energy resources (DER) (any form of distributed generation (DG), net metering energy sources, demand-response programs, price-responsive electric vehicles, energy efficiency, and distributed-level storage services) is providing the impetus for developing a new utility business model. Specifically, recent talk of the need for a new utility business model across the country is predicated on the continued technological innovations in metering, communications, and distributed storage, coupled with the rapid growth of customerowned renewable energy self-generation at the distribution level. Such advances allow for non-utility energy interactions at the distribution level, and may ultimately provide for customer independence from the grid. To the extent that customers leave the grid and the utility’s costs do not decrease accordingly, rates to remaining ratepayers will increase. Higher rates will provide incentives for more of the remaining ratepayers to leave the grid. Hence, without a new business model that is not based on the growth in electricity sales, the regulated utility will find itself in a “death spiral.” While this narrative seems rational on the surface, it is based upon three assumptions that are examined in this article. The first assumption is that the 100-year-old vertically integrated utility business model is inadequate to deal with the technology of the 21st century. The second assumption is that independence from the grid is in the customers’ best interest, for both reliability/resiliency and economic reasons. Independence would allow for the continued availability of electricity during extreme weather events, such as the polar vortex and Hurricane Sandy.
E-mail address: [email protected] (C. Rochlin).
Independence also implies that the utility service model, traditionally a natural monopoly, is no longer a “least-cost” option to the customer any longer. A customer who is able to meet her/his energy needs by self-generating may infer that the utility transmission and distribution services are redundant and discontinue contributing to utility fixed costs. The third assumption, an implicit one, is that the utility business model no longer meets regulators’ needs. Regulatory goals have moved beyond the safeand-reliable provision of energy. For the last 30 years, the utility has proven to be both the laboratory and the provider/collector of funds needed to meet the societal energy goals of increased energy efficiency and reductions in greenhouse gas (GHG) emissions. To the extent that the current utility business model can no longer fund these societal goals, regulators will also have to find a new business model. 2. The evolution of the utility business model The assumptions that the vertically integrated business model has remained static and is based on the continued growth in energy sales lead to a strawman model that is easily discredited. However, the utility business has been evolving with changes in technology, business climate, and regulatory mandates for social programs. One of the oldest and most established social programs is energy efficiency: programs specifically designed to mitigate the growth in electricity sales. 2.1. Energy efficiency and integrated resource planning The current calls for a new utility business model are not new. Previous warnings of the need for a new business model initially surfaced in the 1970s and early 1980s to avoid an impending utility death spiral. A slowdown in electric sales coupled with
http://dx.doi.org/10.1016/j.tej.2015.12.001 1040-6190/ ã 2015 Elsevier Inc. All rights reserved.
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unanticipated, high rates of inflation, two oil embargoes, and significant nuclear power plant cost overruns created economic challenges to the vertically integrated electric utility business model. As rate increases failed to keep pace with surging costs, utility solvency became questionable. Regulatory responses such as changes in the timing of rate cases, corrections for financial attrition, and Allowance for Funds Used During Construction (AFUDC), provided some relief to the utility business model based on cost recovery through electricity sales.1 In addition to regulatory relief, another response to high electric rates was elicited. Higher-than-expected costs eventually led to higher electric rates. To mitigate the impact of higher electric rates, it became reasonable to use electricity more efficiently. This behavioral response is predicted by the basic economic theory that higher prices are used to signal the increased scarcity of the resource and provide an incentive to use less of the resource. Changes in electric rate design supported this view as declining block per-kWh rate structures were changed to increasing block rate structures. However, this change in rate design was used to highlight that the efficient use of electricity was somehow different for electricity than for other resources. This uniqueness was embodied in a new term, “negawatt”; the most cost-effective kWh is the one not used. This interpretation led to a new way to plan the electric grid and set the course for the current round of calls for a new business model. Use of the term negawatt redefines the concept of energy efficiency from an attribute describing how electricity is used, to a resource in its own right, one that shifts the derived demand for electricity inwards and can be added to the grid as an independent resource. Energy efficiency was now viewed as a resource that should be used in planning the electric grid.2 Electric grid planning evolved into integrated resource planning (IRP), where energy efficiency/demand response programs are considered to be an equal building block, along with generation resources and transmission facilities, in designing the electric grid. The idea was to build a safe electric grid that would explicitly incorporate a societal goal: slower growth in electricity usage. However, to reach this goal, the utility needed to be compensated for its energy efficiency efforts and meeting its revenue requirements led to decoupling of revenues from electric sales. 2.2. Decoupling Decoupling refers to the disassociation of a utility’s profits from its sales of the energy commodity. Instead, a rate of return is aligned with meeting a given revenue target. Rates are trued up or down between rate cases to meet the revenue target. This makes the utility indifferent to selling less electricity in the short run. That is, decoupling improves the ability of energy efficiency programs, demand response programs, and distributed generation to operate within the utility environment and protects investors from lost margins between rate cases.
1 Financial attrition can result from using historical test years in a rising unit cost environment. Attrition can be mitigated by using forward test years in rate cases, interim rate increases, cost trackers to quickly include new capital projects into ratebase when they become used and useful, higher customer charges, and rate cases for multiple years with escalation rates built in for interim years. When utilities are not allowed to recover in current rates a return necessary to finance construction projects during the construction period, they will generally be allowed to capitalize the financing costs for future recovery from ratepayers. AFUDC represents capitalized interest and equity costs, which will ultimately be included in rate base as a component of plant in service, thereby earning a return and being recovered through depreciation allowances. (Lowry et al., 2010, pp. 55–57) 2 Energy efficiency programs are administered by utilities, state agencies, and other third parties and are paid for by utility ratepayers, typically through a nonbypassable system benefits charge.
However, the operative phrase is short-run indifference. While decoupling may be a method to compensate investors for lost margins between rate cases associated with the promotion of DER, it does not necessarily create a long-term, sustainable, investment opportunity for the shareholder. Decoupling does not provide utilities with the incentives to promote energy efficiency, demand response, or the integration of DER at cost-based rates. Importantly, in the long run, decoupling does not provide a solution to the anticipated, systematic, erosion of rate base resulting from DERinduced declines in consumption and peak demand. While the utility may be indifferent to lost sales in a decoupled environment, theoretically no worse off for promoting DER, it does not solve the potential death spiral related to long run DER. 2.3. PURPA and electric restructuring In the late 1970s, the Public Utility Regulatory Policies Act of 1978 (PURPA) demonstrated that generation need not be built and owned by the utility.3 Generation could, in fact, be provided by third parties through the use of cogeneration. Efficient combined heat and power was not new, but to become a viable source of generation that could compete with the vertically integrated utility’s generation assets, PURPA provided both a guaranteed customer (the utility) for excess energy, which was priced at the utility’s avoided cost, and nondiscriminatory access to the transmission grid. The generation segment could be removed from the vertically integrated utility business model. This would eventually lead to a “new” utility business model where merchant generation would compete in a competitive, wholesale energy market with guaranteed nondiscriminatory access to the transmission grid. The regulated utility would build and maintain the network of wires, the decreasing cost transmission and distribution systems. This new business model was formally implemented and extended through electric industry restructuring. In the late 1990s through early 2000s, electric restructuring dominated the electric utility business model in California, New York, PJM, and New England. Restructuring focused on providing incentives for the vertically integrated utility to sell its nonnuclear generating assets, keeping the utilities financially viable by ensuring stranded cost recovery, and providing open access to the transmission grid through the creation of a FERC regulated independent system operator (ISO) or regional transmission organization (RTO). Electric restructuring unbundled generation from utility transmission and distribution and created a competitive, wholesale energy market. With the creation of a competitive, wholesale generation market, the utility would remain the main energy demand aggregator for its service territory ratepayers. The aggregation of the utilities’ hourly demand would intersect with the ISO supply curve to determine the market clearing energy price. Restructuring in California failed for many reasons culminating in the well-known energy crisis of 2000 and 2001, but one of the main reasons was that all the restructuring effort was placed on ensuring competition on the supply side. Hourly energy market
3 The Public Utility Regulatory Policies Act of 1978 (PURPA) was implemented to encourage, among other things, the conservation of electric energy, increased efficiency in the use of facilities and resources by electric utilities, equitable retail rates for electric consumers, expeditious development of hydroelectric potential at existing small dams, and conservation of natural gas while ensuring that rates to natural gas consumers are equitable. One of the ways PURPA set out to accomplish its goals was through the establishment of a new class of generating facilities which would receive special rate and regulatory treatment. Generating facilities in this group are known as qualifying facilities (QFs), and fall into two categories: qualifying small power production facilities and qualifying cogeneration facilities (FERC).
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Table 1 Evolution of the Utility Business Model. Social goal
Regulations
Utility response
1. Reduce pollution (through the decrease in electric usage) 2. Reduce electric rates (bills)
Energy efficiency/demand response
Decouple rates, balancing accounts, utility programs
Electric restructuring
3. Reduce GHG
Increase transmission and distribution infrastructure to support merchant generation Build transmission to renewable energy zones
Renewable portfolio standard, cap & trade Advanced metering infrastructure/Rate Advanced metering infrastructure design DER/EV/storage Investments to facilitate two-way use of distribution system
4. Engage utility customer 5. Reduce utility costs
prices were the result of matching generators’ offers with a vertical demand curve for every hour of the day, since retail rates did not increase to reflect the higher wholesale market energy prices. Thus, the crisis emphasized the need for both long-term power contracts and price responsiveness on the demand side. This was in fact a common denominator in all existing ISOs. 2.4. AMI and new rate designs It was not until the energy crisis that California state regulators took a first step in facilitating active participation by ratepayers and mandated advanced metering infrastructure (AMI) that allows for the two-way communication between the utility and its customers. The next steps of developing and implementing new rate designs in California include higher customer charges (minimum bills) and default time-of-use rates (TOU). California will finally implement its new rate design to take advantage of AMI with a default TOU rate design in 2019. The new TOU rate design moves away from flat kWh charges and closer to prices that reflect the actual cost of producing electricity throughout the day and within a season. One stated purpose of the new rate design is to “allow for more accurate allocation of costs and for energy rates to more fairly reflect the cost of services” (CPUC, 2015, p. 1). This is consistent with the usual interpretation of “just and reasonable” rates as rates based on cost causation and provides more accurate pricing signals and cost allocation. It is also based on sound economy principles: “A consumer does not only have to decide whether to consume additional units of a product; he has also to decide whether it is worth his while to consume the product at all rather than spend his money in some other direction. This can be discovered if the consumer is asked to pay an amount equal to the total costs of supplying him, that is, an amount equal to the total value of the factors used in providing him the product” (Coase, 1946, p. 173). Another aspect of creating a separate wholesale market was the realization that many of the services provided by generation assets within the vertically integrated utility were not priced. To guarantee that the ISO would not become an active player in the market, services like ramping, load following, regulation, and resource adequacy had to be priced separately. In essence, separate markets within the wholesale energy market had to be created that were based on performance. These new markets are exceedingly important for any “new” business model as they can provide an alternative source of utility funding (performance-based regulation) that is not based on capital expenditures and can also potentially provide a source of revenue for DER.
emissions. Initially, renewable portfolio standards mandated that a certain amount of new generation must be renewable. At the time, these mandates required the utility to add renewable generation that was significantly more costly than fossil fuel alternatives. Eventually, the RPS mandates evolved into percentages of energy generated by non-fossil fuel sources, excluding nuclear and largescale hydro projects. In California, the mandates have expanded to include energy storage assets. However, since the most costeffective renewable resources tended to be located outside of load centers, new, large, costly transmission projects were built. Since most of these new transmission lines were not driven by the traditional utility planning concerns of reliability and economic cost savings, a new “policy driven” reason for transmission construction was created. The goal of GHG emissions reduction intensified the role of policy direction in electric grid planning. IRP expanded from the efficient use of energy to mandating the type of generation resources the utility should purchase and the expansion of the transmission grid to gain access to distant sources of renewable generation. As more and more electric planning decisions were removed from the utility’s discretion, energy costs increased and the costs of meeting the GHG emissions reduction goal was paid for by electric ratepayers. Table 1 provides a concise summary of the evolutionary transformation of the electric utility business model over the last 30 years. To achieve the regulator’s policy goals 2–4, utility rate base has increased significantly. One can expect that, even though goal 5 is to reduce utility costs, significant enhancements to the distribution system will be required to accommodate the anticipated large amounts of DER.4 For example, “rooftop solar installations, which are characterized by relatively small size, intermittent power production, widely dispersed deployment in the grid, and the inability of grid operators to monitor and control them. This creates a much more dynamic grid with respect to load, voltage and other parameters, and drives the need to reinforce key parts of the grid to better handle the new hardware and operating characteristics.” (FierceEnergy, 2015) Table 1 shows that, as the social goals of regulators crystallized into policy, the utility was able to continue to build rate base and have the opportunity to earn its authorized rate of return. Simultaneously, the recognition for pricing to reflect full costs, support flexibility, and reflect performance have been enhanced. The flexibility of the utility model is impressive. To summarize, the utility business model has been evolving for over 30 years. The vertically integrated utility business model of the 1970s is not the utility business model of today. Except for the first changes to the business model in the 1970s, the evolution of
2.5. GHG emissions reduction A major change in the electric industry, as well as the utility business model, has been the regulatory mandate to reduce GHG
4 SCE’s expected distribution resource planning expenditures through 2017 are between $347 million to $560 million. From 2018 to 2020, the projected cost grows to between $1.4 billion and $2.6 billion (SCE, 2015).
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the utility business model has been driven by regulatory goals of increased energy efficiency, reduction in the use of fossil fuels, increased customer participation, and energy industry transformation (use of markets and pricing of services). These social goals have not come without increased costs. Notably, the funding for these changes has come within the evolving utility business model and was paid for by utility ratepayers. However, as utility costs have increased and the growth in electricity sales have stagnated by design, electric rates continue to increase. It is the potential to avoid these rising electric costs that has now become the siren call for customers to install DG or rooftop solar PV and leave the grid. 3. Active participation by customers The regulatory pursuit of social goals has led to new technologies, energy efficiency/demand response programs, storage mandates, renewable distributed generation (rooftop solar), electric vehicles, and AMI. All of which are the components that make up the microgrid. The microgrid has the potential to transform the electric industry from a centralized, vertically integrated model paid for by ratepayers to a local distribution centric market that works in real time at the edge of the grid with customers that have options and can respond to price signals. One potential outcome of a microgrid is that its customers are expected to see increased reliability/resiliency and lower energy costs, providing an incentive to leave the utility grid. If this is the case, microgrid customers would no longer contribute to the utility’s revenue requirements. If the associated cost reductions fail to offset revenue losses, then it would lead to the utility death spiral. Hence, the call for a new utility business model to secure revenues to keep the utility financially whole. Another potential outcome of a microgrid is the continued use of a modernized, flexible utility distribution system. In this scenario, the revenues associated with the ancillary services separately priced provides an economic source of funding for the microgrid. The utility distribution system provides a way to connect, coordinate, and fund microgrids. The role of the utility as an integrating force for the wholesale and retail market continues. The microgrid will provide the utility with revenues based upon its use of both the distribution and transmission networks and not on the amount of energy used, mitigating the potential for a utility death spiral. Either scenario assumes active participation through the pricing mechanism will transform the ratepayer into a customer, where customers would have more choices, more control, and foster two-way communication between the utility or energy service provider and the energy user. This transformation is actually a prerequisite for the new vision of the electric industry: IRP through markets that operate at edge of the grid.5 Leveraging off the distribution network, a distribution system platform (DSP) will create an intelligent network for delivering safe, reliable energy by integrating diverse resources to meet customer needs and social goals. It will foster broad market activity that monetizes the electric system and social values. Expanded IRP will continue to be the guiding principle with a major emphasis on markets at the distribution level. DER will lead to greater customer knowledge and actions as they form microgrids. The funding for microgrids will come from the services provided by customers to the utility distribution system. The utility will continue to remain the interface with the wholesale markets. The utility will integrate customer usage and social goals into markets for energy at the wholesale, retail, operations, and planning levels.
5 New York’s Reforming the Energy Vision (REV) proposes this type of distribution platform model.
A central assertion of the need for a new business model is that customers want control, convenience, choices, and two-way communication with utilities when it comes to energy usage. This active role supplants the current passive role of the ratepayer that wants reliability and low energy rates (bills). Numerous pilot projects provide support for the basic assumption that customers will respond to price differentials if they are educated in new rate designs and it is relatively easy or transparent to respond to those signals. That is, once their preferences can be transferred to a computer, appliances and thermostats can be adjusted automatically to respond to price signals. This may be a necessary development in the reformed electric vision, but it is not sufficient. Two additional issues must be determined. First, do customers want to go beyond price responsiveness to actually deal with the complexities of providing and selling energy services to the utility? After all, electricity is a derived demand. Electricity is an input, a requirement, needed to supply the power to deliver services from appliances owned by the customer. Electricity per se, is not the goal. To the extent that third parties can make these complicated options and decisions, made possible by customer investments, transparent at a lower cost than the utility, is speculative at best. Second, is the assumption that the growth in DER is being accelerated because of “the increased financial viability compared to traditional generation because of continuous lower price points to produce and install DER” (Mackinnon et al., 2015 p. 1). This statement seems to be at odds with the reality that even utilityscale renewable generation is still dependent on federal subsides.6 4. Uneconomic bypass Any speculation about customer DER participation at such an involved level is moot until customers face energy prices that reflect the real cost of energy assets (DER, storage, AMI) that are not modified by tax credits, accelerated depreciation, feed-in tariffs, or subsidies embodied in net energy metering. Regulatory capture by the environmental movement to reduce energy usage and GHG emissions through the reduction in the use of fossil fuels has totally distorted energy prices. Mandated RPS created a market for variable energy resources at power purchase energy prices that remain above the cost of fossil fuel production, socialized the cost of building new transmission facilities to fulfill the public policy goals of increased renewable resources (not for reliability or economic reasons), and mandated energy storage requirements have all distorted and increased the cost of utility provided energy. The utility has been used by regulatory agencies to be the financial engine to fund the transformation of the U.S. energy industry. The tendency of energy regulators is to ensure that the utility serves as a vehicle for funding social goals by providing direct subsidies for energy efficiency and rebates for installation of distributed clean energy resources. With regard to subsidies and rebates, while they encourage consumer investments, they prevent consumers from seeing the true incremental cost/avoided cost associated with incremental/decremental usage and distort customers’ ability to value investment decisions according to their willingness to pay.
6 “The report found that power purchase agreements prices for wind costs would need to increase 32–62% for wind developers to maintain profitability on projects. It also found that removing the investment tax credit (ITC)—in a model with a constant PPA price—could reduce a developer’s returns on wind by 68–109%, and on solar by up to 76%.” . . . “In an AWEA statement, ‘After the expiration of the PTC at the end of 2012, wind installations dropped 92% in comparison to the following year,”’ GAO reports. “Collectively, the constraints faced by developers with reduced or eliminated federal supports would likely lead to a reduction in the level of investment in new renewable utility-scale electricity generation projects” (Brandt, 2015).
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Table 2 Comparable PV Costs. PV components
Utility scale PV (>1 MW)
Residential PV (< = 10 KW)
PV module Inverter & other hardware Engineering & construction Installation labor Customer acquisition & PII Sales tax Margin, G & A System cost ($/Watt)
$0.65 $0.40 $0.40 – – $0.05 $0.30 $1.80
$0.65 $0.90 – $0.35 $0.56 $0.05 $0.74 $3.25
If those costs were transparent and directly assigned to them, meeting the intended policy goals would be achieved at a lower social cost, since it would require fewer ex post mechanisms to “fix” the implications of cross subsidies among customers. To claim that a microgrid (conferring the ability to disconnect from the utility grid) can avoid higher utility energy costs, while increasing reliability and resilience, may facilitate uneconomic bypass. That is, since utility energy rates are so distorted, microgrid energy costs may be less than the utility’s energy rates but more than the utility’s energy production costs. All of these additional costs have been paid for by ratepayers. Customers seeking lower energy bills may actually generate energy at a higher cost, but pay a lower bill by avoiding these non-fossil fuel energy related costs. 4.1. Costs of residential PV (renewable DER) The notion that residential PV is an example of uneconomic bypass is supported by Table 2, which compares the cost of installing utility-scale PV with the cost of installing residential PV on a components cost basis.7 While the PV module costs are identical, the balance of system (BOS) costs for the residential PV are significantly higher. What is interesting to note is that, while the utility-scale PV installation cost is very close to the utility cost of PV, the residential cost is much lower than the reported average market price charged for residential PV of about $4.90/Watt (MIT, 2015, p. 81). The differential is due to many factors: (1) at the utility scale either the builder incorporates the solar subsidies into its utility bid or the utility retains the subsidies and passes the cost savings on its ratepayers, for residential lease PV installations subsidies need not be fully passed on to customers because the decision to install solar is based upon the solar lease payment being less than the forecasted electric bills; (2) residential installation costs vary depending on scale of installation, the diversity of the housing stock, and the specifications of the PV systems being installed; and (3) additional costs associated with customer acquisition and marketing, permitting, interconnection, and inspection (PII). Even though BOS will fall with experience and innovation, “some balance-of-system costs for residential systems will likely remain high because of the structure of U.S. political jurisdictions and the diversity of distribution of utilities” (MIT, 2015, p. 100). One major finding of the report is that “Utility-scale PV is likely to remain much less expensive than residential-scale PV, even in the face of foreseeable reductions in the BOS costs associated with residential-scale PV” (MIT, 2015, p. 111). The addition of storage does not make the value proposition of DER more palatable. “But as a number of commentators quickly noted, even at Tesla’s relatively lower prices — $3,000 for a 7 kW (kilowatt) battery and $3,500 for a 10 kW battery homeowners are
7 Table 2 combines the information contained in Figs. 4.7 and 4.8 found on pages 84–85 of the MIT report, “The Future of Solar Energy, an Interdisciplinary MIT Study.”
unlikely to save money by shifting their power consumption from the grid to a solar-plus-battery system. With the cost of solar plus storage penciling out, in some cases, at more than twice as much as power from the grid, the gap between the two is simply still too wide” (Gibson, 2015).8 Also, the cost (cents/kWh) of utility-scale PV is significantly higher than the cost of a natural gas-fired combined cycle plant.9 This is an example of the additional costs associated with regulatory social programs that have led to the rising utility rates. 4.2. Net metering Currently, most distributed solar generation enjoy the benefits of net metering. “Net metering charges the homeowner for the net quantity of electricity consumed—in other words, total consumption less total generation. This means, in effect, the utility is paying for electricity generated by the homeowner at the retail rate, in contrast to utility-scale generation facilities, which receive the wholesale price. Because the wholesale price includes charges for the transmission and distribution systems (on top of a charge for the power consumed), net metering pays distributed generators a much higher price for power than gird-scale generators receive” (MIT, 2015, p. 111). Another interesting fact related to net metering is that with a steeply tiered rate structure, net metering can result in an additional incentive to install solar that is equivalent to as much as 30% of the federal tax credit.10 Even though utilities’ net metering schedules generally impose system size restrictions so that DG facilities are smaller than the customer’s typical maximum demand, customers’ solar systems end up “over-generating” significantly at times of low demand, and are compensated for the excess energy generated at more than avoided costs. Thus, the utility is not fully compensated for maintaining the distribution infrastructure for either the customer’s purchase or sale of electricity. In addition, as solar generation tails off in the late afternoon, a significantly steep ramp is created for the early evening hours, which may increase the need for utilities to increase their ramping capabilities. The facts seem to contradict the claim that distributed solar PV is cost effective; in essence, it represents uneconomic bypass. That is, customers seeking lower energy bills may actually generate energy at a higher cost, but pay a lower bill by avoiding these nonfossil-fuel energy-related costs. From a social welfare perspective, DER bypass may be inefficient unless energy tariffs are corrected.
8
See Helman (2015) for calculations. “Adding a charge of $38 per metric ton of CO2, consistent with the ‘social cost of carbon’ used in recent federal-level regulatory analyses, increases the levelized cost of energy (LCOE) for the natural gas plant by 1.47 cent/kWh, bringing its LOCE to 8.08 cents/kWh—still well below the estimated LCOE for both the residential and utility-scale solar projects. . . . In order for the LCOE for the utility-scale PV to be equal to the natural gas-fired generation, the CO2 charge would have to rise to $104 per ton” (MIT, 2015, p. 109). 10 Severin Borenstein’s May 26, 2015, blog “What Put California at the Top of Residential Solar?”, at https://energyathaas.wordpress.com/2015/05/26/what-putcalifornia-at-the-of-residential-solar/. 9
Please cite this article in press as: C. Rochlin, Distributed renewable resources and the utility business model, Electr. J. (2016), http://dx.doi.org/ 10.1016/j.tej.2015.12.001
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The success of DER today seems to be a classic example of uneconomic bypass. 5. The Role of the Regulator What may not be obvious in this new view of the interactive electric world is that, as the new technologies transform passive ratepayers into active customers, customers will have alternatives. Once customers become aware of rate designs that reflect the cost of providing energy and have the ability to respond to the pricing signals, they will seek to reduce energy costs. Once the additional costs related to tax investment incentives and cross subsides needed to fund social programs embedded in utility rates become explicitly known, customers will seek to bypass them. To the extent these costs can be avoided, the creation of microgrids will provide an incentive to leave the utility grid. This view of the new, active customer posits a different reason to leave the grid: uneconomic bypass. It is not the anticipated production cost savings associated with the microgrid. Instead, it is taking advantage of the ability to avoid the costs embedded in utility rates that are associated with funding energy efficiency and GHG emissions reduction programs. If this were to occur to a significant degree, it would not only be that the utility is in need of a new business model, but so would regulatory agencies need a new way to fund their social goals. While not explicitly noted, this could be a motivating force for regulators to acknowledge that the incentive for microgrid customers to leave the grid is socially undesirable. One option for regulators is to concentrate on making adjustments to utility compensation models. The regulator can redefine how utilities are compensated for providing services traditionally provided to ratepayers. Another option is that regulators could foster the development of the microgrid within the context of developing a modernized, flexible distribution network. The transformation of the radial distribution system into a distribution network, one that is dependent on the two-way use of the distribution local network, will need a source of revenue to survive since the cost of self-generation (DER) is more than the cost of utility-scale renewable generation. Revenues to support the microgrid or the local market are expected to come from the services provided to the local utility and the local utility will, in turn, earn revenues by providing integrating services to microgrid customers. With changes in utility rate design that are no longer based solely on energy consumption, both the utility and microgrids can both be economically viable. The key to either option is for regulators to get utility pricing right. 6. Conclusion The utility business model has evolved over the last 30 years and will continue to do so because it is in the regulator’s interest. It is to all stakeholders’ benefit to ensure that the network of transmission lines and distribution circuits remain reliable, flexible, and safe. This implies a continued role for the utility in providing integrating and operational services on both the wholesale and retail levels. The incentive created by uneconomic
bypass to leave the grid, leading to the utility death spiral, is neither an economically nor a socially viable alternative. Customers leaving the grid do not only cause concern for utilities. Current costs of microgrids seem cost-effective because their costs are less than current utility rates. However, utility rates include much more than the cost of energy production. As a result, microgrids represent the latest form of uneconomic bypass that not only undermines the economic viability of utilities, it raises the cost to society of producing electricity. Undermining the economic viability of the utility also calls into question the continued viability of regulators to use the utility as a source of funding for its social goals. Regulators are facing a dilemma: microgrid funding will rely on selling ancillary services to the utility; however, the microgrid may undermine the economic viability of the current utility business model. The call for a new business model is not to just avoid a utility death spiral, but to continue to provide regulators with a funding mechanism to meet their social and environmental goals. To the extent that microgrids make economic sense in limited circumstances like hospitals, military bases, airports, campus like environments, and isolated communities at the end of a radial transmission line, remaining attached to a new, vibrant distribution network still makes economic sense. The utility business model can continue to evolve to meet the needs of its customers and regulators. The first step in this evolution is to address the uneconomic bypass incentive by getting utility pricing right. References Coase, R., 1946. The Marginal Cost Controversy. Economica 13 (August), 169–182. CPUC Proposed Decision (Rev 2.), Rule Making 12-06-013, July 13, 2015. FERC. http://www.ferc.gov/industries/electric/gen-info/qual-fac/what-is.asp. FierceEnergy, June 17, 2015. EPRI: Reinforcing Distribution Systems for Increased Renewables. Gibson, Bob, Solar Electric Power Association (SEPA)—Utility Solar Blog, Energy Storage: Finding the Value Proposition in a Growing Market, June 4, 2015. Helman, Christopher, 2015. (Forbes Staff), Energy, Why Tesla's Powerwall Is Just Another Toy For Rich Green People, 5/01/2015 @ 11:36AM. Brandt, Jaclyn, 2015. Is a Production Tax Credit Essential for Wind Growth?, Fierce Energy, June 2, 2015, Summary of GAO Report to Congressional Requesters— Electricity Generation Projects: Additional Data Could Improve Understanding the Effectiveness of Tax Expenditures, GAO-15-302, April 2015. www.gao.gov/ assets/670/669881.pdf. Lowry, Mark Newton, David Hove, Lullit Getachew, Matt Makos, 2010. Forward Test Years for Electric Utilities, prepared for EEI, August 2010. http://www.eei.org/ whatwedo/PublicPolicyAdvocacy/StateRegulation/Documents/EEI_Report% 20Final_2.pdf. Mackinnon, Lawrence, and Woods, Eric, 2015. The Energy Cloud: Emerging Opportunities on the Decentralized Grid, Navigant Research, June 2015. MIT. Energy Initiative, The Future of Solar Energy: An Interdisciplinary MI T Study, 2015, MI T ISBN (978-0-928008-9-8). SCE, 2015. Distribution Resource Plan Overview, July 1, 2015, Slide 3. http://www. edison.com/content/dam/eix/documents/investors/events-presentations/EIXSCE-DRP-Presentation-07-01-15.pdf. Borenstein, Severin, May 26, 2015, blog. What Put California at the Top of Residential Solar? https://energyathaas.wordpress.com/2015/05/26/what-put-californiaat-the-of-residential-solar/. Cliff Rochlin has over 35 years of experience in both the electric and gas industries. He currently lectures in Economics at Loyola Marymount University in Los Angeles. The author acknowledges the contribution to this article made by many hours of discussion with Amparo Nieto, Vice President at NERA Economic Consulting. The author remains solely responsible for any errors in the article.
Please cite this article in press as: C. Rochlin, Distributed renewable resources and the utility business model, Electr. J. (2016), http://dx.doi.org/ 10.1016/j.tej.2015.12.001