Review of Salt River Project s Proposed Residential Customer Generation Price Plan. Prepared for Salt River Project

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Review of Salt River Project’s Proposed

Residential Customer Generation Price Plan

Prepared for Salt River Project

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Project Team

Amparo Nieto Vice President

About NERA Economic Consulting

In over 40 years of service to energy companies, NERA has made many important contributions to both the theory and the practice of regulatory economics. For many years, NERA has been sought as a leading authority on pricing and, through

seminars and training programs, we have taught thousands of industry professionals how to design tariffs. This experience has been applied in the US as well as in many countries in Europe and Australia. NERA, and Amparo Nieto in particular, also has extensive experience with particular aspects of pricing including marginal cost pricing as applied to electricity tariffs. NERA's method for estimating marginal costs set the industry standard in the United States when it was introduced in the late 1970s. NERA's method for estimating marginal costs has been continually updated and enhanced, incorporating more rigorous techniques for capturing time-of-use and geographic differences in costs and providing a sound basis for efficient tariffs.

NERA Economic Consulting

777 South Figueroa Street, Suite 1950 Los Angeles, CA 90017

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I. Introduction

SRP has proposed a new Customer Generation Price Plan (CGPP) intended as a mandatory rate for any residential customer who decides to install distributed generation (DG) equipment on or after January 2015.1 Net metering will be based on the per-kWh charge of the new CGP plan. The CGPP (or E-27) is aimed to ensure that the expected expansion of residential self-generators mainly through solar rooftop photovoltaics (PV) under net metering will not undermine the ability of SRP to provide electric service to all consumers, solar and non-solar, on a non-discriminatory basis.

In order to understand the implications of SRP’s existing residential rate design it is important to highlight how net metering policies work. Net metering provides customers credit, based on the retail per-kWh charge for all of their onsite solar output, regardless of whether it is used to offset the customer demand needs or delivered to the utility grid. Solar customers continue to rely on the grid for back-up capacity to make up the difference between intermittent on-site solar production and electricity needs. These intermittent loads may materialize during system peak hours and therefore need to be accounted for by SRP when planning investment and maintenance expense in generation, transmission and distribution as well as future generation contracts to maintain reliability.

When the residential rate is not properly designed, solar customers under net metering

effectively avoid paying their fair share of the costs of building, maintaining and operating the grid. Bill savings that customers realize from installing DG are greater than SRP’s avoided costs from that installation. Since SRP is entitled to recover all costs that have been prudently incurred to provide a reliable level of service, the gap between the amount of costs the utility can save with DG and the amount of costs not paid for by DG customers will likely translate into an increase in the rate for all residential users, without a corresponding increase in the costs of serving them. This problem is exacerbated as distributed generation grows, and results in non-sustainable growth of DG.

The purpose of this report is to assess the proposed CGPP in terms of the implications of its rate design for achieving the appropriate recovery of fixed costs of service, while meeting other important ratemaking goals. SRP has guided its rate proposal on the basis of marginal cost estimates from its latest Marginal Cost of Service (MCS)2, as well as cost allocation factors from its December 2014 Unbundled Revenue Analysis (URA). In order to prepare this

assessment, both of those studies were carefully reviewed, as well as SRP’s CGPP description document3 and other SRP’s residential price revisions to be in effect in 2015.

1

Existing customers with solar rooftop panels, or those who provide SRP with a signed solar contract by Dec. 8, 2014, can remain on their existing plan for 10 years if they remain in their existing residence.

2

NERA reviewed SRP’s FY2012 MCS and suggested a number of improvements that SRP took into account in its final MCS.

3

“Proposed Adjustments to SRP’s Standard Electric Price Plans Effective with the April 2015 Billing Cycle”, SRP, December 5, 2014

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The goals of ratemaking and efficient rate structures

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II. The goals of ratemaking and efficient rate structures

Any rate design must keep in mind best practice ratemaking as well as the goals outlined by the Public Utility Regulatory Policies Act (PURPA) of 1978, which include achieving efficiency in usage, and promotion of fairness and equity. Other important ratemaking objectives include financial viability, transparency and revenue stability. The main ratemaking goals are discussed below:4

 Equity between customers in the same rate class and among customer classes can be attained by fairly recovering the costs associated with the grid from all customers, in alignment with the cost that each customer class causes. Customers connected at the same level of the network with similar usage patterns should be subject to similar network charges.

 Efficiency in consumer decisions, including usage, business location and

self-generation investment require that marginal costs5 are taken into account when setting price structures and levels. In economic terms, marginal costs represent the change in utility’s costs associated with an increase in customer usage or demand.

 Certainty of price movements, which means that in some situations rates need to be transitioned to desired levels to avoid imposing unacceptable price shocks on customers.

 Financial viability requires that that the utility is kept whole for prudent investment and operational decisions associated with meeting service requirements.

Reforming residential rates to better reflect the structure of marginal costs is necessary for better usage decisions but it is particularly critical when it comes to improving the cost

effectiveness of DG. In the context of net metering, the specific goal is to ensure that consumer decisions to install solar rooftop panels are based on economically efficient incentives and thus do not lead to uneconomic bypass of the utility system. For economically efficient investments in customer-owned generation, any usage charges paid or avoided by the DG customer should signal the full underlying marginal cost, by time-of-use period. TOU periods can lead to efficient usage and self-generation decisions as long as they align with the hours where system costs are highest (in the case of on-peak) or lower (off-peak).6

The cost of service can be divided into the following components: energy, generation capacity, transmission and high-voltage distribution costs, local distribution facilities costs –

transformers, local primary and secondary lines and customer related costs. Transmission is

4

Standard electricity ratemaking objectives are described in Dr. James Bonbright’s book Principles of Public Utility Rates. Columbia Univ. Press, New York, 1961.

5

In economic terms, marginal costs represent the change in utility’s costs associated with an increase in customer usage or demand.

6

Ideally, rating periods should be made up of hours with similar costs, although there are often constraints such as customer understanding that may limit the final definition.

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Problems with existing residential rates under Net Metering

3 sized on the basis of the growth in system peak load and distribution is sized based on area peak loads. Customer-related costs change as new customers are added. They include the cost of the meter and the service drop in addition to the costs of other customer-related services such as meter reading, collection and inspection, billing, and bad debt, etc., that vary with the number of customers. Table 1 below summarizes the optimal design of an electricity bundled tariff.

Table 1. Optimal Tariff Structure

Customer-related costs and any other costs that do not vary with time of day, including local distribution facilities costs, are appropriately recovered in a fixed customer charge. Local distribution systems include distribution transformers, secondary lines and local primary lines. These facilities are typically built using engineering design standards that take into

consideration the expected number of customers to be served and their maximum load (design demand) over the service life of the facilities. Since investment in these facilities is not subject to changes in the customer's maximum load from month to month, this component of the distribution costs should be recovered in a fixed customer charge that is consistent with the design demand of the customer. A customer who installs solar panels cannot guarantee a permanent reduction of his/her design demand due to the intermittent nature of the solar production, and the need for the utility to stand ready to provide back-up service.

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Problems with existing residential rates under Net Metering

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III. Problems with existing residential rates under Net Metering

The major SRP existing residential rates for customers include the residential Basic Price Plan (E-23), the regular TOU plan (E-26), and the TOU EZ-3 (E-21), which includes a shorter peak period. All three rates include energy usage tiers that are differentiated for three seasons, Summer, Summer Peak and Winter. Summer is defined as May, June, September and October. Summer Peak is defined as the July and August billing cycles. Winter is defined as November through April. The Basic Price Plan includes a tiered energy inverted block structure, where the kWh price increases with monthly consumption, but does not vary across the day. The two TOU rates, E-26 and E-21, include (non-blocked) energy charges that vary by peak and off-peak periods. None of the rates include demand charges. All three rates include a monthly customer charge of $17.

To date, about 56 percent of SRP’s residential customers who have installed a solar rooftop panel are served under the Basic Price Plan E-23, 27 percent are on the TOU rate E-26, and about 17 percent are on the Super Peak rate, E-21. Rates E-26 and E-21, by virtue of being time-differentiated rates, provide SRP an opportunity to signal the difference in underlying costs of service by time of day and therefore they are an improvement over the Basic Price Plan. By signaling the higher cost of producing and delivering electricity at peak times, the customer is able to make more informed decisions that lead to an overall lower cost of service, by simply shifting usage to lower-priced periods. In the context of DG, time-differentiated marginal cost-based rates encourage optimizing the design and operation of DG facilities so that they maximize electricity production in the critical on-peak hours and peak seasons. While a TOU rate results in more efficient consumption decisions than traditional rate structures with no time-differentiation, it may not fully serve the goals of best practice ratemaking unless the individual charges are cost-reflective. In the case of rate E-26, the energy usage component of the per-kWh charges are reflective of time-differentiated marginal energy cost estimates as per SRP’s MCS. However, other components of the time of day usage charges in rate E-26 are not strictly related to time of use. The per-kWh charge in E-26 not only recovers variable costs but also costs that do not change with customer usage, such as the cost required to connect the customer to the local distribution system.

When the energy charges exceed the marginal cost of meeting an increment in load in a particular hour, consumption will be inefficiently low in that hour, even though the marginal cost of producing more electricity is lower than its value to the consumer. As a result, there will be a social “deadweight loss”.7 More importantly, in the presence of net metering policies, there is an artificial incentive for customers to shift to another choice of fuel or to self-generate, e.g., by installing solar equipment on their premises. This represents both an inefficient and an unequitable outcome. Since the price the customer is facing for every new kWh of

consumption is higher than the incremental cost to the utility of meeting load, the utility suffers

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Deadweight loss in economics refers to a situation where total social welfare, measured as the sum of producer surplus plus consumer surplus, is lower than total social welfare that could be achieved in a situation where prices for additional units reflected marginal costs.

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Assessment of structure of the proposed CGPP

5 losses for every kWh that the customer does not consume when self-generating. A share of the lost revenue was intended to recover fixed costs that are necessary to support the customer’s need for back-up or supplemental power. It is also inequitable because if the consumer cuts back on energy use due to his decision to self-generate, his/her bill goes down by more than the amount of the costs avoided and other customers’ bills ultimately get affected.

IV. Assessment of structure of the proposed CGPP

The CGPP or E-27 embodies a rate structure similar to the existing residential TOU rate E-26, albeit with some key differences that move the new rate towards a design more closely aligned with cost causation principles. The two main changes, which largely fix the existing structural deficiency in rate E-26, are described below.

 The fixed costs associated with local distribution facilities, including feeders

downstream of the first piece of equipment, line transformers, secondary transformers, and service laterals 8 currently recovered in the per-kWh charge of E-26 rate, have been shifted to the fixed component (the customer charge) in the CGPP. The monthly fixed charge, as proposed, will vary based on the size of the home; homes with 200 amp service or less will pay a monthly fixed charge that includes a distribution facilities component of $16.44, while homes with service greater than 200 amps will pay a distribution facilities charge of $29.64. Together with the monthly customer costs such as the cost of meters, meter reading and billing, the proposed monthly fixed charges for the CGPP are $32.44 and $45.44 for each customer size, respectively. By contrast, the proposed fixed charge for the rate E-26 in 2015 is $20 per month, with only $4.20 as the distribution facilities cost component.

 The proposed CGPP will include an “on-peak” tiered demand charge that will apply to the monthly maximum amount of energy a customer uses at any one time during system peak hours. This charge will recover the allocated fixed costs associated with high-voltage distribution (i.e., substation and trunk-line feeders), transmission, generation capacity, and other costs, such as system benefits, SRP’s environmental program adjustment factor, and certain ancillary services.9 These cost components reflect SRP’s cost allocations as per its December 2014 URA. The second tier on-peak demand charge in the CGPP rate for the summer season is $12.07 per kW, and the marginal tier demand charge reaches $22.98 per kW. For the “Summer Peak” season, the second tier on-peak demand charge is $15.05 per kW while the last tier charge is set at $28.93 per kW. Winter on-peak demand charges are much lower, with the highest set at $7.91 per kW.

8

These costs are incurred when adding customers to the system, but exclude costs of meters and related costs.

9

These include ancillary services type 1 & 2 (Scheduling, system control and dispatch, and costs of reactive power and voltage control).

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Assessment of price signals under the proposed CGPP

6  The proposed energy charges in the CGPP are time-differentiated by time of day

(on-peak and off-(on-peak) and by season, following the same periods as in the current E-26 rate; the generation capacity, transmission and distribution grid costs have been moved from the peak and off-peak kWh charges to either the fixed charge or the demand charge of the CGPP, so that per-kWh charges now only recover fuel, variable

operation and maintenance expense, purchased power, operating reserves, regulation and energy imbalance service costs. The proposed on-peak per-kWh charges in the summer, summer peak and winter seasons under the CCGP will be about 75, 72 and 58 percent lower, respectively, than the corresponding kWh charges in E-26.

SRP’s proposed rate structure for CGPP is a sound method to prevent growth of inequity between customers with on-site solar generation and other residential customers. A similar rate reform is expected to be adopted elsewhere, including Spain. The net effect of shifting fixed costs to a monthly charge is that customer’s financial incentives to install solar rooftop panels will be reduced, since more of the fixed costs that SRP continues to incur to serve the solar customers will now be recovered from them. SRP has estimated that for a typical solar customer, the proposed E-27 rate will mean a $50.00 increase, on average, in his/her monthly utility bill. In absence of the rate reform, this amount would have been inefficiently shifted to non-solar customers.

The effect of setting a demand charge separate from the time-differentiated energy charge is ensuring that the cost impact of self-generators’ on-peak demands on the utility’s infrastructure does not get diluted. By using a demand charge, it is implicitly assumed that the customer’s maximum on-peak demand will generally be coincident with the time of highest system peak in the month.10 Solar customers facing the proposed demand charge under E-27 will have an incentive to shift their on-peak usage to other periods in order to limit their monthly bills.

V. Assessment of price signals under the proposed CGPP

Parallel to determining a revenue target for a particular class, it is important to conduct a marginal cost study to inform the specific rate charges that will lead to the most efficient usage and self-generation decisions. To maximize social welfare, usage charges applicable to a given hour (either energy or demand) should reflect marginal costs for that particular time of day and season. Any net difference, either positive or negative, between the revenues obtained from setting prices at marginal costs and the class revenue target, should be recovered in monthly fixed charges, i.e., the non-usage sensitive portion of the rate.11 Often, some compromises to efficiency are necessary in order to preserve revenue neutrality while limiting unacceptable customer bill impacts for low usage customers.

10

From an efficiency point of view, it is also possible to recover demand-related costs in TOU energy charges; the assumption being that customer’s maximum on-peak demand may not always coincide with the month’s highest coincident system peak. Factors such as how broadly the on-peak period is defined may influence the choice of one pricing method versus another.

11

This is aligned with “Ramsey Pricing” that calls for keeping charges as close as possible to marginal costs for the most price-elastic demands, in order to minimize distortions to overall consumption.

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Assessment of SRP’s method to determine fixed costs attributable to solar customers

7 A summary of the main findings of my analysis of SRP’s rate levels are as follows:

 The proposed energy charges by peak and off-peak periods for E-27 reflect the time-differentiated marginal energy costs by season as per SRP’s latest MCS, and thus are efficient price signals in all seasons.

 In the peak hour the customer will face an “effective rate” equal to the sum of the on-peak kWh charge and the on-on-peak demand charge. Together, the combination of the two charges should approximately reflect the overall incremental costs that consumers’ demands impose on SRP’s utility system during the peak period. The on-peak demand charges in the proposed CGPP are generally reflective of marginal demand-related costs (generation capacity and network), particularly in the summer peak season. SRP has done a good job at keeping the demand charges in the most elastic season (the summer peak) as close as possible to marginal costs. The demand-related on-peak charge is slightly underestimated in the summer peak, while the E-27 customer base will face a price signal above its efficient level in all other seasons.12 To set efficient price levels in all months, SRP should consider moving the on-peak demand charges closer to the corresponding on-peak marginal cost levels, while adjusting the fixed monthly charge as necessary to meet the class revenue target.

 Time of day (peak and off-peak) period definitions in the proposed CGPP are the same as those used for the current rate E-26.13 These periods are generally consistent with the hourly probability of peak analysis undertaken by SRP as part of its MCS 14 In the case of SRP these TOU periods are appropriate for the near term. The appropriateness of the time-of-day period definitions, including how many daily periods are necessary, should be revised over time to ensure that they continue to reflect when distributed solar and storage resources would provide the most benefit to the system. This should be done based on an updated probability of peak analysis, since a large penetration of

distributed solar generation is likely to move the peak an hour or two later on peak days.

12_{The price signals that are likely to be more relevant to customers opting to install solar panels will generally be those for the}

medium and highest tiers of demand in the summer. The highest demand tier price for the Summer Peak ($28.93) is below the “efficient level” of $36.96 (monthly on-peak marginal demand-related cost for a residential customer, as per SRP’s 2014 MCS). The demand charges for the regular summer months are significantly above the on-peak summer demand MC, at $5.77. The winter on-peak last tier demand charge is also larger than the corresponding marginal cost level of $1.43.

13

On-peak hours from May 1 to October 31 are defined as hours from 1 p.m. to 8 p.m., Monday through Friday, Mountain Standard Time, excluding holidays. On-peak hours from November 1 through April 30 consist of hours from 5 a.m. to 9 a.m. and from 5 p.m. to 9 p.m., Monday through Friday, MST, excluding holidays. All other hours are off-peak.

14

As a starting point, the hours with similar responsibility for time-varying marginal costs (i.e., energy, generation capacity, transmission and high-voltage distribution) need to be grouped together, for typical weekdays and weekends in each season, in order to maximize efficiency. This preliminary definition may need to be revised to simplify periods and maximize customer understanding, or to avoid any concerns of “peak chasing”.

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Assessment of SRP’s method to determine fixed costs attributable to solar customers

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VI. Assessment of SRP’s method to determine fixed costs

attributable to solar customers

SRP allocates costs to customers following an embedded cost of service study, termed the “Unbundled Revenue Analysis” (URA). An embedded cost study is a “top-down” approach which aims to equitably allocate the full historical and forward looking cost of providing service for a particular test year to each class of customers. Embedded cost of service studies are common tools to allocate the utility overall revenue requirement by customer class in the US energy industry, albeit the exact method varies across states. Although less common, revenue requirement allocations may alternatively follow a “marginal cost-based” approach (e.g. California, Nevada). A marginal cost method is a bottom up approach that begins with marginal cost estimates. In that case, a revenue reconciliation process between the sum of marginal cost across classes and overall revenue requirement is required to hit the target. The allocation factors then depend on each customer class’ responsibility of overall marginal costs. SRP has designed the new rate to be revenue neutral with regard to the TOU rate E-26,

assuming no DG. SRP uses smart meter population data for cost allocation to each of the customer classes.Since a share of the customers who have already installed solar panels are in the E-26 class, the allocation of fixed costs to this rate has implicitly captured the impact of lower demands associated with solar customers. Going forward, as new solar customers are placed under the proposed E-27 rate, they will be treated as a separate customer class with its own net load profile and usage patterns. By placing DG customers into their own rate class, SRP will be able to fine-tune the allocation of embedded costs to these customers. To the extent that solar customers contribute less to the utility’s need for future investment than non-solar customers, the fixed cost allocation factors will be able to reflect that.

SRP’s URA methods conform to utility best practice among embedded cost of service studies. SRP’s URA is superior to other embedded cost of service studies in that it recognizes that not all fixed Operation and Maintenance (O&M) and capital costs of generation are demand-related. Production committed capital is allocated to the customer classes based on the

“Average and Excess” (A&E) methodology, which assumes that part of production expense is used to provide energy (average) and part is needed for capacity (excess). The excess is allocated to customer classes based on their loads during the four summer highest coincident peaks (4CP) for the months of June through September. Transmission revenue requirement is also allocated based on summer 4 CPs. This method is aligned with cost causation since SRP mostly looks at transmission summer peaks when designing the system. Distribution revenue requirement is allocated based on a number of combined factors.

At the present time, it is unclear the extent to which DG resources can play a meaningful role in deferring transmission or high voltage distribution investment, if any. Utility resource planning tends to follow a conservative approach with regards to modeling distributed generation since planners need to be confident that reliability standards will be met. When solar DG can begin to be reliably modeled in long-term resource planning, it will be possible for SRP to better analyze whether DG may actually defer utility investment in generation capacity or transmission. At that point SRP’s cost allocation methods may need to be revisited

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Conclusion

9 to look at contributions to summer hours with highest net peak load and not just the four

coincident peaks, to determine a class revenue target to customers on net metering.

SRP’s allocation of revenue requirement to the CGPP class should eventually include any extra costs that solar customers many impose on the system, namely integration costs. The

integration challenges such as voltage support, frequency control and ramping needs needed to accommodate motor starting and other large load fluctuations, might require a reinforcement of the distribution transformers or need for higher operating reserves.15 These impacts will be more obvious with high penetration levels.

VII. Conclusion

Upon a review of SRP’s latest marginal and embedded cost of service studies and the proposed CGPP structure and price levels, my view is that the CGPP is a necessary step and is well grounded. The main implication of the current rate design of all residential price plans is that customers who elect to install solar panels are able to avoid paying for fixed costs of service that SRP does not avoid with the presence of self-generation. DG customers are also likely to impose incremental costs that have not yet been quantified. To prevent expansion of cross subsidies against non-solar customers, SRP has proposed a new mandatory rate, largely based on marginal cost principles, applicable to new solar customers. The reform is timely given the expected growth of solar customers on net metering in the very near term.

An important merit of the CGPP is that its design is largely aligned with a marginal cost

structure. An efficient rate mimics the structure of marginal costs of services, by which charges that more directly affect marginal consumption (energy and demand charges) reflect as close as possible the underlying time-differentiated marginal costs of energy, generation capacity, transmission and high-voltage distribution marginal costs. Costs that are not directly a

function of changes in near term load, such as the cost of local distribution facilities, belong in fixed charges to avoid distorting consumption decisions. The energy and on-peak demand charges under the proposed CGPP, particularly during the summer peak, are close to the marginal cost within the relevant season as estimated in SRP’s MCS. As a result, the credit provided through net metering to solar customers under the proposed rate will be more aligned with the value of their excess energy to the system. The proposal will help SRP keep the overall cost of service low while maintaining reliability, and will provide solar customers with an opportunity to save on electricity bills by managing their peak load.

Finally, the class revenue target assigned to residential customers is based on SRP’s embedded cost-of-service study, which implicitly uses the available information on solar loads. As more customers are added to the rate, SRP should continue to monitor the amount of costs that are attributable to this new class of customers, by observing the impact of their net loads on the distribution and transmission infrastructure, as well as the net effect of their intermittent usage on the generation capacity requirements.

15 Simulating the impact in terms of operating reserves is generally challenging due to the many variables that need to be considered.

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NERA Economic Consulting

777 South Figueroa Street, Suite 1950 Los Angeles, CA 90017-5837 Tel: +1 213 346 3000 Fax: +1 213 346 3030

Review of Salt River Project s Proposed Residential Customer Generation Price Plan. Prepared for Salt River Project