Matching Prices and Value for. Proposal

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Matching Prices and Value for

Distributed Solar PV: SRP’s

Proposal

By Ashley Brown1 1

Ashley C. Brown is the Executive Director of the Harvard Electricity Policy Group (HEPG) at the John F. Kennedy School of Government at Harvard University. This document represents solely the author’s opinion, and not that of the HEPG or any other organization with which Mr. Brown may be affiliated.

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Introduction

1

Solar photovoltaic distributed generation (solar PV DG) has some very real benefits 2

and long-term potential. The marginal costs of producing this energy are zero. If 3

one looks at environmental externalities, then the carbon emissions from the actual 4

process of producing this energy itself, without taking the secondary effects into 5

consideration, are also zero. Significantly, the costs of installing solar PV DG have 6

been declining dramatically in recent years, adding to the potential long-term 7

attractiveness of solar.2 Those are very real benefits that would be valuable to 8

capture. In its current, most common configuration, however, it has some 9

shortcomings that preclude electricity consumers from capturing its full value. 10

Solar PV DG is intermittent and thus requires backup from other generators and 11

cannot be relied on to be available when called upon to produce energy. Thus, its 12

energy value is entirely dependent on when it is produced and its capacity value, 13

without solar hosts taking on some downside risk, is, at best, marginal. To fully 14

develop the resource, therefore, it is imperative to provide pricing that will incent 15

solar PV DG to fulfill its potential, by linking itself to storage and embracing more 16

efficient forms of catching the sun’s energy, and/or, perhaps through tight 17

coordination with other types of generation (e.g. wind) that complement its 18

availability. Thus, it is critical that the pricing of solar PV DG provide incentives 19

2

The dramatic decline in the price of solar panels is, of course, in and of itself a compelling argument for terminating any ongoing “need” for continued

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for productivity and reliability and not to simply subsidize it at a decidedly low 1

degree of optimization. Solar has huge potential, but to attain it, it needs to receive 2

the price signals to fully exploit its capabilities. 3

There are, conceptually, four possible approaches to pricing solar PV DG. One is to 4

set the price to reflect the market clearing price in the wholesale market at the time 5

the energy is produced. That is a market approach, and is the approach taken in 6

SRP’s proposed revision to its pricing plan for customer generation. A second 7

approach would be a cost based approach, where the price is set based on a review 8

of the costs or according to standard costing methodology. That would be a 9

regulatory “cost of service” approach. A third approach is retail net metering, 10

discussed at length in what follows. Finally, a fourth approach would be to 11

administratively derive a “value of solar” based on analysis of avoided costs and 12

whatever else the evaluators believe to be worthy of measure. 13

This paper argues that retail net metering and “value of solar” are severely flawed 14

schemes for pricing solar PV DG. Retail net metering overvalues the energy 15

produced as well as the installed capacity, is very heavily cross-subsidized by non-16

solar customers, and is socially regressive in that it transfers wealth from less 17

affluent to more affluent consumers.3 The "value of solar" approach promulgated by 18

3

It is noteworthy that solar PV DG is already heavily subsidized by government through the Investment Tax Credit and the renewable energy credit (REC) and solar renewable energy credit (SREC) markets. Thus, cross-subsidies from non-solar customers are another layer of subsidy for an already heavily subsidized resource.

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solar advocates can, and, as implemented, usually does, artificially inflate the 1

benefits of solar PV DG and discount the costs. In contrast, SRP’s new pricing 2

proposal is a very reasonable, market-based system for pricing customer generation 3

(primarily solar PV DG). Similarly, the proposals for demand and fixed charges as 4

applied to solar PV DG hosts are reasonable ways to assign costs to “cost causers” 5

rather than socializing those costs among all ratepayers, as occurs with retail net 6

metering. 7

This paper, first, examines retail net metering as a pricing system and argues that it 8

is deeply flawed and that SRP’s proposed new rate represents a vast improvement. 9

Because many who may acknowledge the flaws of retail net metering nevertheless 10

argue that electricity pricing should be tailored to reflect the “value of solar,” the 11

paper next turns to a careful examination of the many kinds of value that solar may 12

provide, arguing that there is little that would justify singling out solar PV DG for a 13

substantial subsidy not available to other renewables. Finally, the paper addresses a 14

few remaining arguments for special treatment of solar PV DG, concluding that 15

none of them raise any reasonable challenge to SRP’s proposed new customer 16

generation tariff. 17

Retail Net Metering and SRP’s Proposed Customer

18

Generation Price Plan

19

Definition of “retail net metering”

20

In this report, the terms "retail net metering" and “RNM" are used interchangeably. 21

What these terms mean is that the meters run forward when solar PV DG customers 22

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are purchasing energy from the grid. When those customers produce energy and 1

consume it on premises, the meter simply stops, and when the customer produces 2

more energy than is consumed on premises, the meter runs backwards. Thus the 3

solar PV DG customer pays full retail value4 for all energy taken off the grid, pays 4

nothing for energy or distribution when self-consuming energy produced on 5

premises, and is paid the fully delivered retail price for all energy exported into the 6

system. At the end of whatever period is specified, the meter is read and the 7

customer either pays the net balance due or the utility pays the customer for excess 8

energy delivered. The reconciliation is made without regard to when energy is 9

produced or consumed. Perhaps of more economic significance, it is also, in most 10

cases, made without regard to the fixed costs that are incurred to provide service to 11

4

In some jurisdictions the full retail value includes the entire bill, while in others, it refers to the variable portion of the bill, but does not include any fixed charge that may be assessed. It should be noted, of course, that, as a general rule historically, not all fixed costs are recovered through fixed charges, so in RNM, that critical distinction between fixed and variable costs is lost. In reality, most forms of payment under any regime for solar PV DG are netting something. This paper argues it should be an energy netting. Many solar advocates prefer full retail price netting, and as noted, there may be variations in between. To be clear, SRP’s proposal is not to get rid of netting, but simply to focus on those things that in fact have an economic justification for netting, particularly energy.

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the solar host. This is how transactions between owners of DG and utilities have 1

traditionally been handled. 2

There are other forms of net metering such as wholesale net metering, where 3

exports into the system are compensated at the wholesale price, but in this report, 4

the terms “RNM” or “retail net metering” will refer to the retail variety. 5

Origins of retail net metering

6

Although RNM has become the prevalent form of tariff for solar PV DG in the 7

U.S. today, it was not developed as part of a fully and deliberatively reasoned 8

pricing policy. RNM was simply never a conscious policy decision. It is basically a 9

default product of two no longer relevant considerations, one practical and the other 10

technological. The practical reason was that distributed generation had such an 11

insignificant presence in the market that its economic impact was marginal at best. 12

Thus, no one was seriously concerned about “getting the prices right.” The second, 13

technological reason, was that the meters most commonly deployed, especially at 14

residential premises, until recently have had very little capability other than to run 15

forward, backward, and stop. Thus, for technical reasons, RNM was simple to 16

implement and administer, and, as a practical matter, given the paucity of DG, there 17

was no compelling reason to go to the trouble of remedying a clearly defective 18

pricing regime. Many states have recognized the problems with RNM, but seeing 19

no alternatives to it, have put in place production caps to limit any harm caused by a 20

clearly deficient pricing regime. 21

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Problems with retail net metering

1

RNM, as practiced, significantly over-values distributed solar generation in ways 2

that have serious negative impacts on the efficiency and fairness of the electricity 3

pricing system. Using RNM to reimburse solar PV DG hosts for the energy they 4

export into the grid creates a cross-subsidy from non-solar to solar customers which 5

is socially regressive. It distorts the energy market by advantaging solar PV DG 6

relative to other forms of generation, including alternative renewable resources, and 7

by failing to account for the fact that the value of energy varies widely depending 8

on when it is actually produced, with the result that it distorts price signals for 9

energy efficiency. Finally, if unaddressed, the pricing inequities caused by net 10

metering run the risk of prompting federal preemption of the pricing. 11

Cross subsidies

12

Solar PV DG is the most expensive form of renewable generation widely used 13

today, in large part not only because of the nature of RNM but also because of the 14

low capacity factor it shares with utility-scale solar PV. Since 2008, as the chart 15

below from the United States Energy Information Administration (“EIA”) points out, 16

solar PV has had the lowest capacity factor of any commonly used renewable energy 17

resource in the U.S. While the overall costs of installing solar panels has declined, the 18

productivity of solar PV has remained constant at consistently low levels. 19

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1

The chart above compares only “utility scale” projects. However, distributed solar 2

shares the capacity problems of utility-scale solar—overall, in fact, it is considerably 3

less cost effective than utility scale solar. In a recent update to its analysis of the 4

levelized cost of electricity (excluding the impact of subsidies), Lazard shows 5

residential solar PV DG as costing in the range of $180 to $265 per megawatt hour, 6

a cost exceeded only by battery storage and diesel generation. Utility scale solar, in 7

contrast, is much cheaper--in the range of $72 to $86 per MWh, and combined 8

cycle gas in the $61-$87 range. Lazard’s chart is shown below:5 9

5

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1

The significant growth in solar PV DG that has occurred in many areas of the 2

country despite these uncompetitive costs may have a great deal to do with the 3

extensive system of subsidies and, perhaps even more importantly, cross subsidies 4

from non-solar to solar customers established by retail net metering tariffs. The total 5

subsidy is far from trivial--in fact, a recent study by E3 Consulting for the 6

California Public Utilities Commission projects the annual costs of net metering to 7

be $1.1 billion by 2020. 6 8

6

Energy+Environmental Economics, Inc., California Net Energy Metering

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There are several ways in which RNM for solar PV DG results in non-solar-owning 1

customers subsidizing customers with solar generation. The first has to do with how 2

non-energy utility costs (for distribution, reliability, and administration) are paid 3

for. A utility can be thought of as providing a number of different services. There is 4

the purchase and resale of energy, of course, (and associated capacity payments)— 5

but making this possible, there is also the service of distributing the energy from the 6

point of wholesale purchase or generation to individual households, the service of 7

ensuring system reliability, and the administrative services of billing and other 8

customer service work. Utilities must collect retail revenue that covers the costs of 9

all these services. SRP, like all US utilities, has long adopted a practice of including 10

only a small fixed charge on its monthly bill, and collecting most of the money 11

necessary to cover all its expenses through a per KWh rate (i.e. on a variable basis). 12

This can be seen clearly in graph 5 of SRP’s proposed pricing plan, which shows 13

that while only 27% of incurred costs vary with the amount of consumption, 88% of 14

revenues are tied to how much energy is consumed, collected through a per-kilowatt 15

hour charge. In the absence of wide use of net metering, this is a workable approach 16

that means that those who use the most energy bear more of the costs of the system, 17

and that creates incentives for energy efficiency. 18

Under RNM, however, this approach becomes a problem. When DG providers 19

export energy into the system, consumers are required to pay them full retail rates 20

for a wholesale product. Everyone agrees that solar PV DG provides an energy 21

value, although there is considerable disagreement about what that value is. Solar 22

proponents argue that it has a capacity value as well. (This report argues, below, 23

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that that value, if it exists at all, is minimal, but for the moment it will assume some 1

level of capacity value.) Both energy and capacity are wholesale products and 2

should be compensated as such. While, as is discussed below, there may well be 3

reasons to treat DG differently from wholesale generation for transmission 4

purposes, there is, absent a solar host leaving the grid, absolutely no reason to 5

discriminate between wholesale and DG producers in regard to the fixed costs of 6

the distribution system and its operations. Under RNM, however, solar PV DG 7

providers are compensated at full retail prices for what they provide. That includes 8

the not-insignificant cost of services that they, indisputably, do not provide, 9

including distribution, administrative, and back office operations. There simply can 10

be no justification whatsoever for forcing consumers to pay a provider for service 11

they not only do not provide, but, in fact, have no capability to provide. 12

Solar PV DG producers remain connected to the grid and are fully reliant upon it 13

during most hours of the day, when solar energy is not available. In fact, there is 14

virtually no time at which they are not using the grid either to import or to export 15

energy. Under RNM, that solar PV DG producer is excused from paying his/her 16

share of the costs of the distribution system when energy is being produced on 17

premises. If the costs of the distribution system were variable with energy 18

production, that would be sensible, but they are not. Distribution costs are fixed and 19

do not vary with energy production or consumption. In fact, SRP, like all other 20

distribution utilities, must construct and maintain sufficient capacity to serve each 21

and every customer in its service territory at their peak demand, regardless of 22

whether the customer chooses to avail himself/herself of that service at any given 23

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moment in time. Thus, excusing solar PV DG customers from paying for their own 1

distribution costs at the time their solar units are functioning has no justification in 2

either policy or economics. As is the case for all utilities, SRP has to either 3

reallocate these costs to non-solar customers or absorb them by cutting other 4

services, such as conservation programs or operations and maintenance. Either 5

outcome is unjustifiable and unacceptable. There simply is no reason why solar PV 6

DG customers should receive free backup service compliments of their neighbors. It 7

is an unacceptable cross-subsidy. 8

Two additional types of cross-subsidy relate to the intermittent nature of solar 9

energy. Given the intermittent nature of solar energy, no utility with an obligation to 10

serve, such as SRP, can afford to be fully reliant on the availability of solar when it 11

is needed. The first cross-subsidy that results from this fact arises when the 12

distributor relies on the availability of solar for making day-ahead purchases, and 13

the other arises when it does not do so. When it does rely on the availability of solar 14

and it turns out that solar energy is not available when called upon, the utility is 15

compelled to purchase replacement energy in the spot market at the marginal cost, 16

which is almost certainly higher than the price of the solar energy on whose 17

availability it had relied. In notable contrast to what happens in the wholesale 18

market when a supplier who is relied upon fails to deliver, those incremental costs 19

have to be borne by the utility, which passes them on to all customers, as opposed 20

to being borne by the specific solar PV DG customer whose failure to deliver 21

caused the costs to be incurred. If the distributor, in recognition of solar’s 22

intermittency, instead chooses to hedge against the risk of solar’s unavailability, the 23

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cost of the hedge is likewise passed on to all customers rather than simply those 1

whose supply unpredictability caused the cost to be incurred. The fact is that one 2

way or another, a utility buying solar output must simultaneously contract for back-3

up in case of unavailability, or, in the alternative, be prepared to pay the incremental 4

cost of buying in the spot market when the solar is not available. 5

A fourth kind of cross-subsidy comes from the additional ramping demands solar 6

PV DG customers often place on the electricity system. Unlike typical residential 7

customers, in some regions solar PV DG users use little or no grid power when 8

solar production peaks, but quickly ramp up demand on peak, when, as will be 9

discussed below, PV production wanes. Utilities must be able not only to serve full 10

load on days when solar PV is not performing, but also to ramp up resources 11

quickly to address the peak created by solar PV DG users. In order to ramp up as 12

needed, utilities will purchase energy at the marginal price and then distribute those 13

costs across all users, not just solar PV DG users. Thus, users without solar PV DG 14

may be penalized for the use patterns of their solar PV DG neighbors. An 15

illustration of this may be found below, in the PacifiCorp chart showing a 16

comparison of residential electricity consumers in the western United States to 17

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residential consumers with solar PV DG: 1

2

All these forms of cross-subsidy violate a bedrock principle of regulation -- that 3

costs should be allocated to the cost causer. The function of that principle, of 4

course, is to provide price signals to improve performance, but RNM fails to 5

provide such signals and essentially holds solar PV DG providers harmless for their 6

own very low capacity factors and inefficient performance. 7

The impact of net metering is not simply the creation of a cross-subsidy from non-8

solar PV DG customers to solar PV DG customers, but, as has been pointed out in a 9

recent study by E3, a prominent economic consulting firm, it is a cross-subsidy 10

from less affluent households to more affluent ones. Indeed, the average median 11

household income of retail net metering customers in California is 68% higher than 12

that of the average household in the state, according to the study.7 Net metering is 13

7

Energy+Environmental Economics, Inc., California Net Energy Metering

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“Robin Hood” in reverse. In order to install rooftop solar panels, often individuals 1

must be homeowners with high credit ratings or sufficient capital. Leasing 2

arrangements are also widespread, but are generally available only to customers 3

who own their own premises, and they require the assignment of most of the 4

rooftop solar benefits to the lessor. Leasing arrangements also customarily transfer 5

most of the subsidy benefits from the solar host to the lessor. Thus, more affluent 6

solar PV DG customers derive disproportionately higher benefits from DG than 7

their less affluent peers. Many electricity customers, particularly less affluent ones, 8

do not own homes or lost their homes in the most recent recession. The electricity 9

customers who are unable to afford rooftop solar are forced to subsidize those who 10

are already in a more favorable financial position. Thus, it is accurate to 11

characterize RNM as a wealth transfer from less affluent ratepayers to more affluent 12

ones.8 13

8

The staff report to the Arizona Corporation Commission cites the socially regressive effect of net metering in Arizona. It is intuitively obvious that more affluent people are more likely to own their own homes and control their own rooftops, as well as more likely to have access to the capital necessary to finance solar installations and/or to qualify for leasing arrangements. (Arizona Public

Service Company – Application for Approval of Net Metering Cost Shift Solution (Docket No. E-01345A-13-0248))

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No incentives to improve efficiency and value to the grid

1

One of the more interesting aspects of net metering is that it subsidizes, and 2

therefore incentivizes, a highly inefficient use of solar PV DG. Without getting into 3

a debate over whether subsidies in general are a good or bad idea, it seems obvious 4

that if a subsidy is to be deployed to support some technology, that it ought to be 5

designed to enable resources to be more efficient and more commercially viable so 6

that the subsidy can eventually be eliminated. 7

RNM fails by this standard of encouraging development towards efficiency and 8

commercial viability, in large part because it compensates solar PV DG at flat rates 9

that fail to track the realities of supply and demand. Electricity prices can be quite 10

volatile over the course of every day, and, of course, vary seasonally as well. Rather 11

than reflecting those prices, RNM simply treats all energy the same regardless of 12

the time during which it is produced. For example, it fails to differentiate between 13

energy produced on peak and off peak. It pays off-peak solar PV DG a price that is 14

averaged with on-peak prices. Given, as will be shown below, that peak solar 15

production is not coincident with peak demand, flat payments reflecting average 16

costs retail rates have the effect of very significantly over-valuing the energy 17

produced by solar PV DG. Conversely, were solar PV DG actually produced on 18

peak, which is not generally the case, RNM would average that price with off-peak 19

prices, thus undervaluing the energy. Any form of dynamic pricing, ranging from 20

time of use (as deployed in SRP) to real time, could address this issue with more 21

precision than the flat, averaged prices produced by RNM. Interestingly, under the 22

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second, far less likely scenario, solar producers would be cross-subsidizing the 1

other ratepayers. Importantly, to the extent that solar PV DG is produced off-peak, 2

owners would have an incentive to invest in storage or other technologies to allow 3

them to sell more on-peak electricity, increasing the overall efficiency of the solar 4

resource. To the extent that RNM fails to capture the real time prices in the energy 5

market, the price signal, and the efficiency that would flow from that, is at best, 6

diluted, and in the case of flat prices, completely lost. 7

Under RNM, compensation at retail rates is not cost-reflective because net metering 8

means that solar PV DG energy exported into the distribution network is 9

compensated at the full bundled retail rate on an averaged basis rather than at a 10

price based on the unbundled cost of producing the energy at the actual time of 11

production. Thus, it does not reflect the obvious fact that the energy has greater 12

value at peak demand than it does off peak. It is a deeply flawed value proposition 13

from an economic point of view.9 The fact is that the wholesale market produces 14

hour-by-hour prices that provide generators (renewable and non-renewable alike) 15

with important price signals that reflect real-time values. Similarly, in SRP, non-16

solar PV DG consumers (non-generating consumers) are offered electricity tariffs 17

9

It is also deeply flawed from an environmental point of view, because at peak, solar PV DG is far more likely to displace less efficient generation, with higher emission levels, than it would off peak. That is because, as a general rule, absent special circumstances, these less efficient plants tend to be dispatched more on peak than at any other time.

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that distinguish between peak and off-peak consumption. Solar PV DG-produced 1

energy, by contrast, is compensated on a basis that lacks a foundation in either 2

market or cost. The compensation is out of market because it is a flat price 3

regardless of when it is produced. It is hard to avoid the conclusion that on an 4

economic basis, the net meter-derived price paid for solar PV DG energy 5

completely misses the value of solar during most hours of the day. 6

In fact, as a recent New York Times article explains, this flat RNM pricing has 7

contributed to a nationwide misalignment of solar panels—they are generally 8

installed facing south, to generate the largest total quantity of solar energy over 9

the course of the day (and the greatest savings and/or revenue for homeowners 10

under RNM). If solar were paid at a time variable rate that reflected the much 11

greater value to the grid of energy provided during the late-afternoon peak 12

demand period, these panels would face west, generating less total energy, but 13

capturing the late afternoon power of the setting sun.10 It would be impossible to 14

think of a better example of why price signals are so important. RNM, with its 15

flat pricing structure, incentivizes the production of KWh even if they are of 16

marginal value when produced, while dynamic pricing of solar PV DG output, 17

would provide incentives to produce energy of far greater value. Stated 18

succinctly, RNM inevitably leads to less efficient and less valuable output. 19

10

Matthew L. Wald. “How Grid Efficiency Went South” New York Times. October 7, 2014.

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Similarly, RNM provides no financial incentive for solar PV DG owners to 1

address one of the critical shortcomings of solar from the point of view of the 2

grid, which is its intermittent availability. Indeed, that intermittency not only 3

reduces its economic value, but as discussed it also reduces the likelihood of 4

attaining the desired environmental results. With RNM, there is no financial 5

incentive provided to solar PV DG owners to do anything to mitigate 6

intermittency—so even if a cheap battery technology, for example, came along, 7

homeowners would have no incentive to invest in it. 8

Some of the consequences of the failure to properly price solar PV DG are famously 9

illustrated by the following California ISO Duck Curve: 10

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1

As is dramatically illustrated in the graph, enticed by a number of factors, not the 2

least of which is net metering, substantial investment in the growth of solar capacity 3

in the Golden State has enormously magnified the need for additional fossil plants, 4

operating on a ramping basis, to compensate for the drop off in solar production at 5

peak. In that context, the absence of any meaningful signal to make solar more 6

efficient (e.g. directing solar panels to the west, or linking solar production with 7

storage) is simply something that can no longer be tolerated. 11

While Arizona’s 8

situation is not identical to California’s, it would be pure folly for the state not to 9

learn the lesson of what has gone wrong in other jurisdictions, particularly a 10

neighboring one, and adopt a remedy before finding itself in a similar dilemma. 11

Market distortions that disadvantage other renewables

12

Large-scale bulk power renewables (e.g. large-scale wind and solar farms, hydro, 13

bio-mass, and geothermal) are put at a particular disadvantage by RNM pricing of 14

solar PV DG independent of costs or market for three basic reasons. First, large-15

11

For further discussion of the implications of the duck curve, see What the duck

curve tells us about managing a green grid, CAISO, 2013

(http://www.caiso.com/Documents/FlexibleResourcesHelpRenewables_FastFacts.p

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scale renewables are more efficient and more cost-effective than DG, yet net 1

metering provides a subsidy to the least efficient form of renewable generation. In 2

fact, solar PV DG providers are compensated for the energy they export from their 3

premises at a price that can range from two to six times the market price for energy. 4

Second, in those states with renewable portfolio standards (or, as in the case of 5

SRP, an established target for percentage of renewables in the system that guides 6

planning and energy procurement) the entry of a critical mass of non-cost-justified 7

solar PV DG units into the market could have the effect of driving more efficient, 8

large-scale renewables out of a fair share of the renewable portfolio market. Third, 9

as noted above, for renewables purchased in the wholesale market, the price paid by 10

consumers reflects all of the transmission and distribution network costs incurred in 11

delivering the energy. It is assumed for DG that there are no transmission costs. The 12

effect, in a competitive market, is to bias the market to incentivize highly inefficient 13

small-scale solar to the detriment of less costly larger-scale solar. The ultimate 14

result is higher costs than necessary to keep the system reliable and stable and 15

simultaneously reduce emissions of carbon and other pollutants. 16

Net energy metering pricing may invite federal preemption

17

The effect of net metering is to increase the prices consumers pay for energy 18

overall, without any assurance of any long-term benefit in the form of increased 19

efficiency. Solar PV DG is artificially elevated to a preferential position above 20

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more-efficient, larger scale generation, including renewables.12 The disparity in 1

treatment between solar PV DG and other forms of energy suggests that net 2

metering is not only preemption bait (as further discussed below); it is 3

fundamentally anti-competitive as well. 4

Indeed, it compels consumers to both cross-subsidize less efficient producers and to 5

pay higher prices than necessary for energy. 6

State pricing regimes for DG that are utterly inconsistent with wholesale generation 7

pricing is also risky for states who are concerned about retaining jurisdiction over 8

DG. Because of the economic distortions caused by RNM, there are some who are 9

calling for DG to be under the control of the Federal Energy Regulatory 10

Commission (“FERC”) rather than state public utilities commissions' jurisdiction 11

12

RNM assures that solar DG PV will always be the most expensive energy because all other forms of energy are purchased at wholesale prices, while RNM compensates solar PV DG generators at full retail rates. The wholesale rates, of course, are for energy-only. Transmission and distribution rates are an additional cost that are incurred but not included in the energy price. Under RNM, solar PV DG providers are compensated at prices that include not only the energy, but, as described earlier, include some or all distribution and transmission charges, so utilities purchase most energy on an unbundled energy basis, whereas they purchase solar PV DG on a fully bundled basis, as if the solar host were providing full retail service.

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(see, for example: David B. Raskin, The Regulatory Challenge of Distributed 1

Generation, 4 Harv. Bus. L. Rev. Online 38 (2013) and David B. Raskin, Getting

2

Distributed Generation Right: A Response to “Does Disruptive Competition Mean

3

a Death Spiral for Electric Utilities?” Energy Law Journal (November 2014)).

4

Unless states begin to remedy the price distortions inherent in net metering, it 5

would be surprising if many aggrieved wholesale generators did not seek relief from 6

FERC. In a somewhat analogous situation where New Jersey and Maryland sought 7

to use state subsidies/mandates to support the construction of new power plants in 8

order to manipulate and/or bypass the PJM capacity market, the FERC, in a 9

decision (135 FERC 61,022, April 12, 2011) which was later affirmed by the Third 10

Circuit Court of Appeals (New Jersey Board of Public Utilities et al. v. FERC, 744 11

F.3d 74 (2014)), struck down the state program by preemption. State Commissions 12

that continue to prop up a net metering regime with no basis in either market-based 13

pricing or cost-of-service regulation may well discover the prospect of preemption 14

hanging over them.13 15

13

As a former state regulator myself, I am not generally well disposed toward preemption, but while still serving on the Ohio Commission, I came to recognize the likelihood of that outcome if we continued in a direction that put us on a collision course with federal regulators.

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Further foreshadowing preemption are several other examples of state net metering 1

programs running contrary to federal pricing regimes. First, the Public Utility 2

Regulatory Policies Act (“PURPA”) places an “avoided cost” ceiling on power 3

purchases; net metering evades that ceiling. Under net metering arrangements, not 4

only are purchases of excess power mandated at levels well in excess of avoided 5

costs, but they also include a cross-subsidy from non-solar customers for the 6

distribution costs of solar PV DG providers, as discussed above. Bulk power 7

renewables are subject to all of the rules of the wholesale market, which may 8

include such costs as congestion costs, ancillary services, penalties for no 9

availability, and others. Under net metering, solar PV DG providers are subject to 10

none of these disciplines. Wholesale renewable generators sometimes complain 11

angrily that the arbitrarily high prices paid under net metering have the effect of 12

attracting enough solar PV DG providers to fill up the Renewable Portfolio 13

Standard (RPS) market, so that they are being effectively squeezed out of the 14

portfolio entirely. What is particularly ironic about this is that, as noted elsewhere in 15

this analysis, distributed, small-scale solar is the least efficient form of commonly 16

used renewable energy sources in the U.S. All of these factors indicate that an 17

increasing number of parties are likely to be motivated to ask FERC to preempt net 18

metering and other state-mandated regimes that allow for unreasonably 19

discriminatory and anti-competitive pricing. 20

(27)

Net energy metering provides the wrong long-term incentives to solar PV

1

DG

2

In the short term, the cross-subsidies resulting from net metering help the solar 3

industry by transferring wealth from SRP’s non-solar customers to the solar 4

industry. In the long term, however, they are actually harmful to solar energy 5

because RNM provides absolutely no incentive to improve the performance of a 6

generating resource that, among renewables, already ranks last in efficiency and in 7

cost effectiveness for reducing carbon emissions. In effect, the solar industry is 8

putting its short-term profits ahead of the long-term value of solar energy. If they 9

prevail in seeking to maintain RNM, that victory will be short-lived, because 10

markets, both regulated and unregulated, do not prop up inefficient resources over 11

the long term. 12

SRP’s proposed revised customer generation tariff

13

This is a propitious moment to revisit solar DG PV pricing, because utilities now 14

have technology capable of measuring DG production as well as consumption on a 15

more dynamic basis. They also have pricing methodologies that are better capable 16

of providing the correct signals and incentives for greater efficiency and 17

productivity. In addition, solar PV DG, assisted by declining prices for solar panels, 18

has attained such high levels of market penetration that it can no longer be 19

dismissed as marginal, so appropriate pricing is now a non-trivial issue. These new 20

developments mean that the two reasons for the default policy of RNM, marginal 21

market presence and inability to effectively meter solar panels, are no longer 22

(28)

present. Thus, cross-subsidies for solar PV DG, can and should be replaced by a 1

carefully considered pricing policy. That is precisely what SRP has proposed to do. 2

The proposed changes to the SRP rates address the cross-subsidies in two ways. 3

First, the amount paid for energy is no longer set at a price that incorporates a large 4

share of distribution and transmission costs, but rather, consistent with sound 5

economic reasoning, is based on SRP’s actual marginal costs. The proposal 6

properly aligns supply and demand, in that it values energy higher when it is most 7

in demand, and at a lower value when demand is lower. That is precisely what is 8

accomplished by, as is being proposed, having different rates for energy produced 9

on and off peak. Solar PV DG customers will pay for energy consumed or receive 10

credit for energy provided to the grid at this time-sensitive rate. This means solar 11

PV DG customers are paid better when they produce on peak. Stated simply, the 12

proposal is deeply rooted in the elementary economic concept of supply and 13

demand. 14

Second, an increase in the fixed “monthly service charge” is being proposed for all 15

customers, including solar PV DG customers. The effect of the charge is to more 16

accurately reflect the way costs are incurred, by better reflecting the distribution 17

costs SRP must fund, regardless of how much energy its customers use This 18

proposed change is hardly radical. It simply recognizes and applies the classic 19

regulatory concept that the cost causer should pay. 20

Thirdly, a “demand charge” is introduced for solar PV DG customers that is tied to 21

the utility’s expenses for serving load on peak and providing reliability, that will 22

(29)

ensure solar DG PV hosts pay the full share of the fixed costs they cause SRP to 1

incur, including more of the distribution costs, and that will eliminate the arbitrary 2

reallocation of costs incurred by solar PV DG hosting customers to non-solar 3

customers that occurs under net metering. One interesting feature of how this 4

charge is structured is that it varies depending on how much customers use at peak 5

times—thus, potentially rewarding solar PV DG to the extent that in fact solar PV 6

DG generators reliably provide power during peak hours, so customers who can 7

truly be relied upon not to burden the system at peak pay a lower demand charge. 8

This proposal addresses the problems of net metering discussed above. First, it 9

eliminates cross subsidies. By requiring solar customers to pay their entire share of 10

customer related fixed costs, the non-solar ratepayers will no longer have those 11

costs re-allocated to them. The demand charge will end the cross-subsidy inherent 12

in socializing the costs of hedging against the unreliability of solar PV or the 13

alternative of incurring the costs associated with buying energy at the marginal cost 14

when solar panels are not producing what is required. 15

Second, by varying charges and payments with peak and non-peak usage and 16

production, the proposal corrects the market incentive problems caused by a flat 17

price reimbursement scheme. By tying pricing to peak usage, the proposed new rate 18

structure opens up the possibility of rewarding solar PV DG providers who are most 19

successful at providing on-peak, reliable energy to the grid, whether through 20

adjusting their own usage patterns or through investing in battery or other storage 21

technologies. 22

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The “Value of Solar”

1

Many in the solar industry have come to recognize that retail net metering (RNM) is, 2

in the age of smart grid and more sophisticated pricing, no longer a defensible 3

method for pricing solar PV DG. Having recognized the inevitable demise of a 4

pricing system that bestows excessive dividends on their resource, many solar 5

advocates have shifted to an argument that pricing should be based on consideration 6

of the “value of solar,” arguing that when this is properly considered, a significant 7

premium is justified for solar PV DG, which should be provided through an 8

administrative, highly subjective assessment of value, both internal and external. 9

The next section of this report will contain an analysis of the specific elements most 10

commonly proposed as the elements to be considered in assessing the value of solar. 11

To fully assess the value of solar, one would need to look at the resource in all of its 12

dimensions, not simply the costs and environmental effects derived from the energy-13

producing process itself. It is also critical to think of pricing in the context of 14

establishing incentives for technological improvements that would increase its 15

efficiency. 16

In considering using the “value of solar” approach, one needs to proceeds cautiously. 17

From an economic perspective, the optimal pricing would be by the competitive 18

market. Failing that, the next best option, and the one that is most deeply rooted in 19

American regulatory tradition, would be to derive prices from cost-based regulation. 20

Both market and cost based pricing are subjected to external discipline that should 21

lead to reasonably efficient resource decisions devoid of arbitrary or “official” 22

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preferences. Subjective consideration of the “value” of particular technologies and 1

where they may rank in the merit order of “social desirability,” as proposed by 2

certain “value of solar” advocates, effectively removes the discipline (i.e. that of the 3

market or of cost based regulatory oversight) that is more likely to produce efficient 4

results. Whereas both the marketplace and transparent cost-based regulation are 5

likely to produce coherent pricing that allows us to enjoy a degree of comfort 6

knowing that efficient performance will likely lead to productivity, administrative, 7

highly subjective consideration of soft criteria, like “value of solar,” is far less likely 8

to produce coherent and reasonable predictable price signals and incentives. 9

This does not mean that short-term efficiency is the only factor that should have a 10

role in resource selection. Economics is critical, and efficiency is of vital 11

importance. However, there are other economic values besides efficiency, 12

especially those that go beyond short-term considerations. It is also obvious that 13

many people believe that other, non-economic factors need to be considered. 14

Certainly the fairness of the impact on customers also needs to be factored into any 15

decisions. There has, for many years, been a running debate in electricity regulation 16

as to whether externalities, in the absence of a legislative grant of authority, ought 17

to be factored into regulatory decisions. This report does not join in that debate over 18

the proper scope of regulation, nor does it attempt to assess what is permissible or 19

not permissible under applicable law. The report, however, to be comprehensive 20

and thorough, needs to recognize the nature of the arguments being made and to 21

analyze them. As a result, consideration of the elements to be considered in 22

assessing the “value of solar” seems in order. 23

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To the extent that a value of solar approach is considered, efforts should be made to 1

do rigorous analysis and avoid subjectivity. Any values provided by solar PV DG 2

that are to be compensated in price should be tangible and enumerated. If 3

externalities are to be considered, then all relevant ones deserve attention, as 4

opposed to “cherry picking” the issues to best protect a particular interest. 5

Additionally, if non-economic objectives are factored into its decision, then it is 6

wise to prescribe the ways of attaining them that are the most efficient from an 7

economic point of view. 8

There are a number of criteria that advocates of a value of solar approach to pricing 9

take into consideration. They deserve careful scrutiny. One would begin by looking 10

at the energy produced, and the cost of this production (as we did in the first part of 11

this paper)., Beyond that, the criteria would include an evaluation of environmental 12

benefits, availability/capacity, reliability, impact on system operations and dispatch, 13

transmission costs and effects, distribution costs and effects, hedge value, and any 14

value associated with job creation, price reductions, and enhanced competition. 15

Solar proponents often phrase these issues in terms of avoided costs. In addition to 16

those dimensions, for any plan to provide “value of solar” price advantages, there 17

are also all of the considerations discussed above in the specific context of net 18

metering: degree of subsidization and cross-subsidization, efficiency 19

considerations, impact on alternative technologies, market price impact, reliability, 20

and social effects, including environmental and customer class impacts. 21

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In what follows, this report will examine some of the claims about avoided costs 1

and argue that many of the costs identified are not actually avoided. In other cases 2

(in particular, the environmental case), there are true avoided costs—however, 3

singling out solar PV DG for disproportionately high payments (either through 4

RNM or through some other subsidy) causes market distortions that far outweigh 5

the benefits offered. 6

Environmental value

7

Clearly, one of the most compelling public policy arguments for solar PV DG is 8

that it reduces carbon emissions and other pollutants. Expectations of environmental 9

externality benefits may be the biggest motivator for supporting and subsidizing 10

solar PV DG. Proponents of solar PV DG note that solar has zero carbon or other 11

harmful emissions related to the process of producing energy.14 Additionally, solar 12

proponents contend, to the extent that wide deployment of solar PV DG avoids the 13

14

This paper will not enter into the question of whether there are environmental externalities associated with the production of solar panels themselves, as there is no source of energy that, over its full cycle of production, deployment and use, and system impacts, does not have such secondary effects. Solar PV DG panels go through an energy intensive process to be manufactured, much of that occurring in the world’s most carbon intensive energy economy, China, so like every other energy source, solar has a carbon footprint that extends well beyond the carbon-free way in which the panels themselves produce energy.

(34)

need to invest in technologies that do have carbon and other undesirable emissions, 1

there is an environmental benefit that comes from avoiding the social costs 2

associated with pollution. In the absence of legal limits on relevant emissions, such 3

costs, solar advocates correctly point out, are not captured in the internalized costs 4

of the competing technologies. Therefore, solar advocates suggest that regulators 5

and policy makers should take these external social costs into consideration in 6

setting prices for various forms of energy. 7

Before delving into this claim any further, it is important to address two issues. 8

First, as referenced above, the idea that regulators or others who set electricity 9

process should use external social costs, as opposed to solely the internalized 10

economics of various forms of energy, as a factor in pricing, is a controversial 11

subject. Many oppose the use of externalities as a factor in pricing because it 12

necessitates social judgments those empowered to set utility rates may not be 13

empowered to make. There is also not always agreement about what should be 14

considered an externality that should be reflected in prices. In the views of such 15

opponents, the only non-internal factors that ought to be incorporated into pricing 16

are those that are internalized by legal mandate. Proponents of incorporating 17

externalities into rates through regulatory action, on the other hand, contend that 18

doing so is the only way to accurately reflect all costs. They also contend that 19

factoring in environmental externalities is a form of insurance against future 20

regulatory requirements. This report does not attempt to take on that large, 21

theoretical/ideological debate about the inclusion of non-mandated externalities in 22

pricing, but rather simply acknowledges that the debate exists and attempts to 23

(35)

address the positions advanced by those who favor inclusion of externalities. 1

Without making any judgment about the merits of incorporating externalities into 2

ratemaking, the report will assume, solely for purposes of doing complete analysis, 3

that at least price setters and policymakers might want to consider externalities for 4

purposes of measuring the value of solar PV DG, or, even if they ultimately 5

choose not to do so, they will almost certainly have to confront issues raised by 6

advocates urging them to do so. The report will, therefore, address how 7

externalities ought to be considered and, striving to avoid cherry picking, suggest 8

what externalities might merit consideration in order to make sure that the analysis 9

of the value of solar is both thorough and balanced. Second, it is important to note 10

that the U.S. E.P.A., whose jurisdiction over carbon emissions has been affirmed by 11

the U.S. Supreme Court (Massachusetts v. Environmental Protection Agency, 549 12

US 497 (2007)), has proposed new rules under Section 111(d) of the Environmental 13

Protection Act that would, if promulgated, internalize the costs of carbon into 14

electricity ratemaking. If this were to occur, the issue of whether or not to consider 15

the costs of carbon would no longer be debatable. Thus, in the short term, there is a 16

great deal of uncertainty, which effectively strengthens the hand of those who 17

contend that consideration of carbon emissions would be a form of insurance 18

against future regulation. In the longer run, however, if carbon limitations are 19

imposed, then the cost of carbon will be fully internalized in all energy resources, 20

so special, favorable, arrangements (e.g. pricing) for renewable resources, including 21

solar PV DG, would be of little value in reducing carbon, and perhaps even counter-22

productive to market prices that would already reflect the cost of carbon That, of 23

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course, is because in a carbon regulated marketplace, carbon-free resources such as 1

solar PV DG would, ipso facto have higher value on this dimension than carbon 2

emitting resources would have. Should carbon controls be imposed, the market 3

itself should produce the price signals that will inherently reflect the costs of 4

carbon. At that point, special programs such as RPS and RNM could actually serve 5

to impede the most efficient ways of reducing carbon, by diluting price signals that 6

are formed with carbon control fully internalized. 7

Regardless, while acknowledging that, all things being equal, solar PV DG does 8

indeed offer value associated with the absence of carbon emissions and other 9

pollutants, the question the remainder of this section focuses on is whether 10

providing a disproportionate subsidy to solar PV DG (one not available to other 11

renewable or non-emitting sources), is, in fact, helpful in addressing the 12

environmental externality of carbon and other pollutants associated with electricity 13

production, especially (as is the case with SRP), when a renewable preference 14

policy (similar to an RPS) has already been adopted, mandating that 20% of retail 15

energy requirements be met with “sustainable resources” by 2020.15 In fact, as is 16

explained below, disproportionately subsidizing a technology that is not cost 17

effective in reducing carbon emissions, as is true of solar PV DG is, to understate 18

15

According to its website, “SRP has established a goal that by FY20, SRP will meet a target of 20% of its expected retail energy requirements with sustainable resources.” http://www.srpnet.com/environment/renewable.aspx

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the point, not a helpful approach to reducing overall carbon emissions from the 1

electricity sector. 2

An environmental analysis of solar PV DG as an emissions reduction technology 3

should include an examination of the least-cost, most efficient ways to get to the 4

desired emission reduction results. As discussed in the first section of this paper, 5

solar PV DG is expensive. Therefore investment in solar PV DG is an expensive 6

way to reduce carbon emissions, based on the levelized cost of energy alone. 7

However, in addition to this, there are other factors that need to be considered in 8

assessing the cost-effectiveness of solar PV DG as an emissions reduction tool, and 9

which raise further questions about the value it offers in this area. 10

There are some characteristics specific to solar PV DG (some of which may apply 11

to utility-scale solar as well) which suggest that a system reliant on this resource 12

may suffer some unintended consequences in terms of increased pollution 13

emissions in other parts of the system. The first such problem may come from the 14

fact (discussed in detail in the next section) that solar PV DG production peaks 15

before the overall system peak, dropping steeply by the time the system peak occurs 16

several hours later. 17

This not only means that solar PV DG has less value as energy, but it is also 18

powerful evidence that it also has less environmental value. This is because, as a 19

general rule, the least efficient and “higher emitting” plants are dispatched at times 20

of peak demand. Thus, when solar PV DG is producing energy, it is not displacing 21

(38)

the most carbon emitting plants. Instead, it is displacing more efficient, less 1

polluting generating units. 2

Second, solar PV DG is an intermittent and unpredictable resource. As such, its 3

availability is uncertain and in order to supplement it, fossil plants are often called 4

upon to operate on a less efficient, more carbon-emitting "ramping" basis than if 5

they were running as pure baseload. 6

The intermittent nature of solar PV DG16 has still another effect that may serve to 7

dampen environmental expectations. Because the capacity required to supplement 8

the renewable is ramping rather than baseload (and thus able to sell electricity for 9

many fewer hours), the signals to investors to build new, more efficient generators 10

is diluted, and is therefore less attractive from a financial point of view. (This is a 11

particularly interesting issue in the context of the California duck chart.) If the new 12

investments are not made, then older and likely “higher emitting” plants will have 13

to have their lives extended and/or be operated on a ramping basis for which they 14

were not designed. The result will be less efficiency and, therefore, likely increased 15

emissions. 16

16

Intermittency is also an issue for wind and large scale solar, but those two resources have the advantage of being less expensive, especially so when NEM is the basis for pricing solar PV DC, so their cost effectiveness in reducing carbon is much better than solar PV DG.

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Thus, to be truly meaningful and intellectually honest, any analysis of 1

environmental impact must take into account the change in dispatch and operations 2

Among analyses that take these kinds of factors into consideration, there is 3

agreement that it is the least efficient of all renewable energy resources (including 4

demand side/energy efficiency measures) in common use in this country. An 5

interesting dialogue occurred recently between Charles Frank, an economist at 6

Brookings, and Amory Lovins of the Rocky Mountain Institute, based on an effort 7

by Frank to develop an analysis of the cost-effectiveness of solar PV as a carbon 8

reduction tool, taking into account not only the levelized cost of energy, but some of 9

the considerations about peak production and effects on the functioning of the 10

overall energy system discussed above.17 Their dialogue, while contentious on many 11

points, includes, on both sides, numbers that would suggest agreement on the fact 12

that solar PV is the least cost effective of all carbon-benign resources in reducing 13

emissions. Frank analyzed five generation resources by their cost effectiveness in 14

reducing carbon and concluded that nuclear and natural gas, followed by hydro, 15

17

See Charles R. Frank, Jr., “The Net Benefits of Low and No-Carbon Electricity Technologies.” Global Economy and Development at Brookings Working Paper 73, May 2014; and Amory Lovins, “An initial critique of Dr. Charles R. Frank, Jr.’s working paper ‘The Net Benefits of Low and No-Carbon Electricity Technologies,’ summarized in The Economist as ‘Free exchange: Sun, wind and drain’.” Rocky Mountain Institute, 2014. (http://www.rmi.org/Knowledge-Center/Library/2014-21_Frank-Rebuttal)

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wind, and solar were, in that order, the most cost-effective types of generators for 1

reducing carbon. 2

Lovins took issue with Frank for using outdated data and for not looking at energy 3

efficiency. After a colleague re-ran Frank’s calculations using Lovins’ suggested 4

data, Lovins reported the following: 5

Instead of gas combined-cycle and nuclear plants’ offering the greatest net benefit

6

from displacing coal plants, followed by hydro, wind, and last of all solar, the ranks

7

reversed. The new, correct, story: first hydro (on his purely economic assumptions)

8

and gas (only if we omit its price volatility), then wind, solar, and last of all

9

nuclear—still omitting efficiency, which beats them all.18

10

Here, he shows nuclear ranked last in cost effectiveness, and it should be noted that 11

he expresses some reservations about the ranking of natural gas, because of its price 12

volatility, which is not considered in the rankings. What is significant, however, is 13

that among renewable resources, as noted above, solar continues to rank as the 14

least cost-effective renewable resource for reducing carbon, even in Lovins’ 15

analysis. 19

Lovins himself does suggest that this may not be his final word on the 16

18

Lovins, Amory B. “Sowing Confusion about Renewable Energy.” Forbes August 5, 2014.

19

Charles Frank blog post, “ Alternative Energies Debate—The Net Benefits of Low and No-Carbon Electricity Technologies: Better Numbers, Same Conclusions” September 4, 2014. http://www.brookings.edu/blogs/planetpolicy/posts/2014/09/04-low-carbon-tech-lovins-response-frank

As Frank puts it, even after addressing Lovins' criticisms, "Wind continues to rank number four and solar ranks number five by a large margin."

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subject—he notes that the analysis would have more value if “other hidden costs, 1

risks, and benefits” were counted. But it remains significant that according to the 2

analyses of both men -- who hold quite divergent views on how best to reduce 3

carbon emissions -- not only is solar PV expensive, it is the least cost-effective 4

renewable resource for reducing carbon emissions. Solar PV DG itself was not 5

considered in these calculations—however, based on the Lazard pricing analysis 6

shown at the beginning of this paper, it is safe to assume that the economics of 7

distributed solar as a carbon reduction mechanism are even worse than the numbers 8

for utility-scale solar PV. 9

The lack of direct correlation between increasing the amount of solar PV DG in an 10

electric system and reducing carbon emissions has been dramatically demonstrated 11

by developments in Germany. In Germany, where there has been a very dramatic 12

increase in reliance on intermittent energy resources, prices have risen since 2005. 13

That was not surprising, but what was not expected was the spike in carbon 14

emissions that resulted (See Eddy, Melissa, “German Energy Push Runs Into 15

Problems.” The New York Times, March 19, 2014). While there are very significant 16

differences between the SRP territory and Germany, (perhaps most notably that 17

Germany has been phasing out its nuclear fleet), the experience in that country is 18

very telling. It clearly demonstrates that an increased dependence on renewable 19

energy resources, and particularly intermittent resources, does not, as many solar 20

proponents claim, ipso facto mean fewer carbon emissions, and may, in fact, cause 21

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the opposite to occur. It also demonstrates that prices can escalate dramatically 1

when subsidy mechanisms (in the German case, feed-in tariffs) are far in excess of 2

market prices. The Germans, incidentally, have recognized their miscalculations 3

and are in the process of recalibrating their strategy. 4

Problematically for the environmental “value of solar” argument, attempts to reflect 5

the “value of solar” in preferential pricing of DG PV, as opposed to non-DG forms 6

of renewables, may lead to distortions that favor DG PV over larger-scale, usually 7

more efficient and less costly forms of non-emitting generation that will achieve 8

more environmental benefits at lower cost. Results such as that cannot be justified 9

on the basis of externalities, which are no different between DG PV and larger-scale 10

renewables. Indeed, it could well be argued that overpayment for DG PV would 11

have the effect of squeezing more efficient forms of renewable energy out of RPS 12

markets by using preferential pricing to grab a disproportionate share of the RPS 13

market for a less efficient resource. In the long run, of course, the inherent 14

favoritism in pricing PV DG over other renewable energy sources does not bode 15

well for the future of renewables. Discrimination in favor of inefficient resources on 16

a long-term basis is almost never sustainable. The inevitable backlash in the 17

marketplace has the potential to sweep away public support for renewable energy in 18

general, an outcome no one concerned about the environment would want. 19

Capacity value

20

Capacity is another value that solar advocates typically contend is provided by solar 21

PV DG and should be compensated. This claim deserves close examination. The 22

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capacity value of a generating asset is derived from its availability to produce 1

energy when called upon to do so. If a generator is not available when needed, it 2

has little or no capacity value. By its very nature, solar PV DG on its own, without 3

its own backup capacity (e.g. storage), can only produce energy intermittently. It is 4

completely dependent on sunshine in good atmospheric conditions. Unless sunshine 5

is guaranteed at all times at which solar PV DG is called upon to produce, it cannot 6

be relied upon to be available when needed. Moreover, even if all days were 7

reliably sunny, the energy derived from the sun is only accessible at certain times of 8

the day. In many jurisdictions, as discussed above, the presence and potency of 9

sunshine is not coincident with peak demand. Frequently, solar PV DG capacity is 10

greatest in the early afternoon, while peak demand occurs later in the afternoon or 11

in early evening. 12

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The chart below, from EPRI, illustrates the divergence between solar PV DG and 1

utility peak on a national level: 2

3

The following two charts show the relationship in New England. They are derived 4

from a 2013 report, “Update on Solar PV and Other DSG in New England,” 5

prepared by ISO New England, and illustrate that facile assumptions made that 6

solar benefits include near-term reductions in peak generation are precisely that.20 7

20

Black, John. “Update on Solar PV and Other DG in New England.” ISO New England (June 2013).

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1

These two charts dramatically demonstrate that on the days chosen as representative 2

of summer and winter in New England, solar PV peak and peak demand are not the 3

same. Solar PV is completely absent during the winter peak, reaches its peak 4

production as peak demand is rising in the summertime, and drops off dramatically 5

during almost the entire plateau period when demand is at peak. It should also be 6

noted that on the days chosen, the sun was shining. The graph, of course, would 7

look very different on cloudy days when solar production is virtually nil. 8

In the western United States, a similar problem is nicely illustrated by the California 9

duck graph (discussed above), with its steepening ramp to peak as it projects the 10

demand trajectory of a solar intensive system. 11

In SRP itself, where the utility’s summer peak rate applies from 1pm to 8pm, and 12

the winter peak rate is applied from 5am-9am and from 5pm-9pm, a similar 13

disjunction between solar peak and demand peak can be seen in the chart below, 14

which illustrates the four-hour summer gap between the solar peak and the system 15

Matching Prices and Value for. Proposal