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STATEMENTS OF POLICY

Title 52—PUBLIC UTILITIES

PENNSYLVANIA PUBLIC UTILITY COMMISSION

[ 52 PA. CODE CH. 69 ]

[ M-2015-2518883 ]

Fixed Utility Distribution Rates

[48 Pa.B. 3739]
[Saturday, June 23, 2018]

 The Pennsylvania Public Utility Commission (Commission), on May 3, 2018, adopted a proposed policy statement that is intended to identify factors the Commission will consider in determining just and reasonable distribution rates that promote efficient use of electricity, natural gas or water, the use of distributed energy resources; and reduce disincentives for efficient use of resources to ensure adequate revenue to maintain the safe and reliable operation of fixed utility distribution systems.

Public Meeting held
May 3, 2018

Commissioners Present: Gladys M. Brown, Chairperson, statement follows; Andrew G. Place, Vice Chairperson; Norman J. Kennard; David W. Sweet; John F. Coleman, Jr.

Fixed Utility Distribution Rates Policy Statement; M-2015-2518883

Proposed Policy Statement Order

By the Commission:

 On March 3, 2016, the Pennsylvania Public Utility Commission (Commission) held an en banc hearing at Docket No. M-2015-2518883 to seek information from interested stakeholders on the efficacy and appropriateness of alternatives to traditional ratemaking principles for public utilities. Invited parties, including researchers, energy companies and consumer advocates testified before the Commission, giving views on whether alternative rate methodologies can encourage energy utilities to better implement energy efficiency and conservation (EE&C) programs, are just and reasonable and in the public interest, and are cost-effective.1

 On March 2, 2017, the Commission issued a Tentative Order seeking comments on and potential processes to advance, alternative rate methodologies that address issues each utility industry is facing. With this Order, the Commission continues this proceeding by issuing, for comment, a proposed policy statement that identifies factors it will consider in determining just and reasonable distribution rates that promote the efficient use of electricity, natural gas or water, the use of distributed energy resources, reduce disincentives for such efficient use and resources and ensure adequate revenue to maintain the safe and reliable operation of fixed utility distribution systems. The proposed policy statement includes the addition of a new subsection at Section 69.3303 that provides illustrations of possible distribution ratemaking and rate design options for electric distribution and natural gas distribution companies. The inclusion of this subsection does not signal, nor should it be interpreted as signaling, any predilection by the Commission to favor one proposal over another or any predetermination by the Commission that the proposal of one of these examples comes with any presumption of approval. As evidenced in this proceeding, there are a variety of rate designs that address the needs of a changing utility landscape. We believe it is important to note options that are grounded in ratemaking principles and may help customers and utilities move forward to minimize future long-term costs, allocate capital more efficiently, and achieve important policy objectives.

Background

 At the March 3, 2016 en banc hearing, the Commission sought information from interested parties on the efficacy and appropriateness of alternative rate methodologies, such as revenue decoupling. Invited participants, including researchers, energy companies and consumer advocates testified before the Commission, giving their views on three specific topics. These topics enquired (1) whether revenue decoupling or other similar rate mechanisms can encourage energy utilities to better implement energy efficiency and conservation programs; (2) whether such rate mechanisms are just and reasonable and in the public interest; and (3) whether the benefits of implementing such rate mechanisms outweigh any associated costs. The following witnesses provided testimony at the hearing: Hough Gilbert Peach, PhD, H. Gil Peach & Associates, LLC; Eric Ackerman, Director of Alternative Regulation at Edison Electric Institute; Tanya J. McCloskey, Acting Pennsylvania Consumer Advocate; Paula A. Strauss, Director of Regulatory Strategy and Support, NiSource, Inc.; Mark Newton Lowry, PhD, President of Pacific Economics Group, on behalf of Natural Resources Defense Council; Richard Sedano, Principal and US Programs Director of The Regulatory Assistance Project; Scott R. Koch, Financial Analyst, PPL Electric Utilities Corp. (PPL); Eric Miller, on behalf of the Keystone Energy Efficiency Alliance (KEEA), the Clean Air Council and Natural Resources Defense Council (NRDC); and David F. Ciarlone, PE, on behalf of the Industrial Energy Consumers of Pennsylvania.

 Following the March 3rd hearing, the Commission allowed for any interested party to submit written comments under this docket no later than March 16, 2016. The following parties submitted written comments and supplied additional input on the issue of revenue decoupling in Pennsylvania: Duquesne Light Company (Duquesne); PECO Energy Company (PECO); UGI Distribution Companies (UGI); Citizens' Electric Company of Lewisburg, PA and Wellsboro Electric Company (Citizens' and Wellsboro); Metropolitan Edison Company, Pennsylvania Electric Company, Pennsylvania Power Company, and West Penn Power Company (collectively, FirstEnergy); Citizens for Pennsylvania's Future (PennFuture); KEEA; Energy Freedom Coalition of America; Environmental Defense Fund (EDF); Sierra Club; Pennsylvania Utility Law Project (PULP); AARP Pennsylvania; Northeast Energy Efficiency Partnerships; Citizen Power, Inc.; Office of Consumer Advocate (OCA); Office of Small Business Advocate (OSBA); Energy Association of Pennsylvania (EAP); National Association of Water Companies; Industrial Energy Consumers of Pennsylvania, Duquesne Industrial Intervenors, Met-Ed Industrial Users Group, Penelec Industrial Customer Alliance, Penn Power Users Group, Philadelphia Area Industrial Energy Users Group, PP&L Industrial Customer Alliance, and West Penn Power Industrial Intervenors (Industrials); and The Pennsylvania State University (PSU).

 On March 2, 2017, the Commission issued a Tentative Order at the above-referenced Docket to continue the investigation by seeking comment on, and potential processes to advance, alternative rate methodologies that address issues each utility industry is facing. Specifically, the Commission sought comments on what alternative rate methodologies each electric distribution company (EDC), natural gas distribution company (NGDC), and water and wastewater utilities currently employ. In addition, the Commission sought comment on what alternative rate methodologies should be employed by each utility type, addressing the advantages, disadvantages, effects on low-income and income-challenged customers, efficiency programs, frequency of rate cases, interaction with existing rate mechanisms and methodology for implementation. Finally, the Commission noted that utilities had proposed alternative rate methodologies in base rate proceedings and sought comment on whether the Commission should adopt policy statements or rulemakings identifying guidelines for preferred alternative rate methodologies for each utility type and rate class.

 The following parties filed written comments to the Tentative Order: AARP; Advanced Energy Economy Institute (AEEI); Alliance for Industrial Efficiency (AIE); American Council for an Energy-efficient Economy (ACEEE); American Eagle Paper Mills, ArcelorMittal, E-Finity Distributed Generation, Cargill, Ecolab, Schneider Electric, Sheet Metal & Air Conditioning Contractors' National Assoc. of Pennsylvania, and Veola North America (collectively, CHP Advocates); Aqua Pennsylvania, Inc. (Aqua); The Bureau of Investigation and Enforcement (I&E); Valley Energy, Inc., Citizens' and Wellsboro (collectively, VCW); Columbia Gas of Pennsylvania, Inc. (Columbia); Duquesne; EAP; FirstEnergy; Industrials; KEEA; National Fuel Gas Distribution Corp. (NFG); NRDC; NRDC, Sierra Club, and Clean Air Council (collectively, Council); OCA; OSBA; PECO; Peoples Natural Gas Company LLC and Peoples TWP LLC (Collectively, Peoples); Philadelphia Gas Works (PGW); PPL; PULP; and UGI Distribution Companies (UGI).

 The following parties filed reply comments: AEEI; ACEEE; Columbia; Duquesne; EAP; FirstEnergy; KEEA; NFG; OCA; OSBA; PECO; Peoples; Pennsylvania-American Water Company (PAWC); PPL; PSU; and Strata Policy.

 The parties provided various comments on the appropriateness of alternative rate methodologies such as revenue decoupling, lost revenue adjustment, straight-fixed-variable pricing, cost trackers, choice of test years, multiyear rate plans, demand charges, standby and backup charges, and demand side management performance incentives. These alternative rate methodologies are described in more detail on pages 6—14 of the March 2, 2017 Tentative Order.

Discussion

 Based on our review of the testimony and the comments submitted to date in this proceeding, it is evident that while the parties support the effort to move toward ratemaking methodologies that support efficiency programs and distributed energy resources (DERs), and that also provide utilities with adequate revenue, there is no consensus as to which method should be used. With this Order we will discuss each methodology, the parties' positions and the Commission's views on each method. In addition, we are proposing a policy statement intended to provide guidelines utilities and stakeholders are to use in a Section 1308, 66 Pa.C.S. § 1308, rate proceeding to identify and implement appropriate rate structures for each rate class.

A. Alternative Rate Methodologies

1. Revenue Decoupling

 Decoupling mechanisms introduce a process of recovering authorized revenues between base rate cases and explicitly breaking the link between revenues and sales. Decoupling makes a utility theoretically indifferent to energy efficiency and conservation by removing the throughput incentive. Decoupling involves two separate steps. First, there is a ratemaking proceeding for determining the amount of revenues the utility is authorized to collect. Second, there is a decoupling mechanism to set an appropriate rate to ensure collection of the authorized revenue. There are three ways in which allowed revenues can be determined:

 • Revenue Cap Decoupling: With revenue cap decoupling, the authorized revenues are typically set in a base rate case and then held constant until the next base rate case.

 • Inflation and Productivity Decoupling: With inflation and productivity decoupling, the authorized revenues are adjusted between base rate cases, based on assumed known changes in inflation and company productivity. Inflation is often based on recognized government published indexes, such as the consumer price index.

 • Revenue Per Customer (RPC) Decoupling: With RPC decoupling, the average revenue per customer for each volumetric rate is computed at the end of the base rate case. In subsequent periods between base rate cases, authorized revenues are derived by multiplying the actual number of customers served by the RPC value. The underlying premise for RPC decoupling is that, between rate cases, a utility's underlying cost structure is driven primarily by changes in the number of customers served. The utility is likely to require smaller rate increases in base rate cases because RPC increases occur more frequently, base rate case increases may be simpler to implement, and through the interim recalibration of revenues on a monthly basis through RPC increases, the risk of revenue recovery related to changes in weather between rate cases can be reduced or eliminated.

 In terms of determining the revenue excess or shortfall, decoupling rate adjustment mechanisms can be divided into three different types—limited, full, and partial.

 • Limited Decoupling: Prices are adjusted periodically based on the specific measured or presumed impact on one or more, but not all, other factors, such as weather, energy efficiency, net metering, etc. that impact unit sales volumes. Limited decoupling limits the revenue recovery to a limited set of specific causes such as energy efficiency. Energy efficiency may need to be explicitly included in the calculation, using the utility, or possibly a third party, to conduct measurements or provide analyses to verify and track changes in sales due to the allowed or disallowed specific causes. Calculating the specific factors that cause the deviation in sales and to what degree is complex, requiring sophisticated measurement and calculation systems that may add costs.

 • Full Decoupling: Full decoupling simply uses billing determinants from the company's metering and billing records to periodically adjust rates. This approach captures all factors that could increase or decrease sales. Under full decoupling, rates may increase during economic downturns due to reduced usage, shielding the utility from the economic effects of the downturn, but also increasing customer expenses at a time when customer income may be reduced due to the economic downturn.

 • Partial Decoupling: A variation on limited or full decoupling that limits the rate adjustment to some portion, less than 100%, of revenues eligible for decoupling, most often expressed as a percentage of revenues.

a. Comments

 Several utilities and stakeholders that filed comments support revenue decoupling in one form or another, while most consumer advocates do not. PECO states that its preferred approach is the revenue per customer decoupling model for all but very large customers and certain street lighting customers. PECO states that this model would mitigate revenue losses from energy efficiency and DERs but notes that it could exacerbate intra-class cost shifting, particularly in the residential class due to distributed energy resources. To address this intra-class cost shifting PECO states that it would move its fixed charge to be fully cost based and establish a separate rate class for net metered residential customers.2 PPL states that in conjunction with a multi-year rate plan, its preferred method is full revenue decoupling as it is the most appropriate method to encourage DERs and EE&C measures. PPL asserts that under its method, it will have assurance that its capital investments will be recovered, while providing a limit on revenues, will reduce rate case frequency and reduce regulation related costs and maintains incentives for EE&C measures and DERs.3

 All NGDCs that filed comments also express support for revenue decoupling in one form or another. Peoples states that while it has not proposed decoupled rates, they support the Commission's authority to approve such rates.4 PGW states that the revenue per customer model may be the appropriate decoupling structure for some utilities but a single type of decoupling should not be prescribed, noting that the choice is dependent upon the specific reasons and needs of the NGDC.5 UGI states that it is not opposed to revenue decoupling to address declining use per customer, but notes that it might provide a disincentive to fuel switching from electric to gas water heating.6 NFG states that it has implemented revenue decoupling, weather normalization and lost revenue mechanisms in New York that have positively impacted different customer groups.7 Columbia states that it has previously proposed a revenue normalization adjustment charge in 2012 that was designed to promote revenue stability by establishing a baseline revenue per customer. Columbia also states that it has instituted a weather normalization adjustment for residential customers.8

 In addition to the electric and gas utilities, the water utilities that filed comments also express support for revenue decoupling. Aqua states that a decoupling mechanism would allow for greater certainty for the utility in collecting its authorized revenue and would allow for water utilities to further promote conservation, while potentially delaying base rate case filings. Aqua also notes that the utility and the customer would be protected from changes in weather. Aqua, however, acknowledges that under a decoupling mechanism, customers may not conserve water and may have difficulty in anticipating their bill amount.9 PAWC states that revenue decoupling allows water utilities to further encourage conservation without being penalized. PAWC also states that revenue decoupling effectively reduces or even eliminates the contentiousness of the ratemaking process, resulting in a more efficient and effective ratemaking process that better aligns stakeholder interests to provide more economically and environmentally efficient resource decisions.10

 The other commenters that support revenue decoupling are NRDC, AEE, KEEA and ACEEE. NRDC states that the Commission should clearly state a willingness to implement decoupling in connection with Act 129 lost revenues through a deferral mechanism, with recovery to be made in a subsequent base rate proceeding, and work with stakeholders to develop standards and criteria for decoupling mechanisms, including performance-based mechanisms. NRDC also states that the process should include a thorough review of potential rate and bill impacts and consider impacts on a wide variety of households, including low-usage customers, low-income customers, renters and customers with inelastic usage due to health needs.11 AEE states that revenue decoupling is an important way to remove financial disincentives by removing the threat of lowered revenue.12 KEEA supports decoupling and performance incentives and recommends that the Commission pursue full decoupling to remove any disincentive that may exist for utilities to pursue demand-side reductions. KEEA asserts that revenue decoupling varies little from current cost-of-service ratemaking, with the chief difference being that decoupling includes a target revenue requirement set for each year between rate cases and an adjustment mechanism that accounts for differences between target revenues and actual revenues.13 ACEEE suggests that the Commission approve full revenue decoupling for gas and electric utilities because it balances the interests of utilities and customers by ensuring cost recovery while still promoting customer investment in cost effective energy efficiency.14

 Several commenters, however, do not support revenue decoupling. OCA states that low to moderate income households that are unable to participate in energy efficiency programs for various reasons would bear the brunt of the increases caused by revenue decoupling. OCA also argues that revenue decoupling could reduce a utility's incentive for timely storm repair. Furthermore, OCA asserts that through Act 129 the General Assembly rejected decoupling as an EDC ratemaking mechanism. OCA also asserts that revenue decoupling, if implemented, should include specific consumer protections, such as, legislative authorization, adjustment caps, reduced return on equity, exclusion of automatic adjustment revenues and consumer education, to name a few. Regarding NGDC rates, OCA asserts that weather is the largest factor that impacts customer gas usage and that any rate adjustment due to over- or under-collection in combination with the weather-related changes in usage could cause improper and confusing price signals that stifle consumers' decisions to engage in conservation efforts.15

 In addition to OCA, the Industrials assert that revenue decoupling cannot be implemented for several reasons. Industrials assert that decoupling is illegal under the current statutory framework, it constitutes single-issue ratemaking, prevents the Commission from ensuring that rates are just and reasonable, it cannot be reconciled with cost of service principles, it is poor policy making and it undercuts reliability.16

b. Commission View

 We agree that revenue decoupling may result in just and reasonable rates for fixed utilities in certain forms and in certain circumstances, so long as the revenue decoupling plan includes appropriate consumer safeguards. Among the consumer protections that could be considered are (1) a revenue adjustment cap (to limit the consumer's rate adjustment exposure) and (2) a reduced return on equity (to reflect possible reduced business risk for the utility). We recognize that revenue decoupling, if done in an appropriate manner removes the throughput incentive in such a way that may promote adoption of cost-effective efficiency and conservation measures.

 At the same time, we note that revenue decoupling may not be appropriate, may not result in just and reasonable rates, or may not be authorized by the Public Utility Code for certain fixed utilities in certain circumstances. We recognize that if done inappropriately, revenue decoupling may adversely impact customers who, due to personal circumstances, are unable to take advantage of efficiency or conservation measures to reduce their consumption. Also, customers who are the recipients of after-the-fact billing increases for past shortfalls, for whatever reason, may be unhappy in being required to make up the difference once the actual mechanics of revenue decoupling become clear. Accordingly, with this proposed policy statement, in lieu of establishing a specific rate methodology to be applied to all fixed utilities, we are proposing to establish factors the fixed utilities, complainants, intervenors, and the Commission will consider in any future fixed utility Section 1308 rate proceeding.

 For the natural gas industry, we propose illustrative examples of revenue decoupling mechanisms, such as a weather normalization adjustment and/or revenue per customer adjustments. Our proposed Section 69.3303 states that any future decoupling proposal should address important consumer protection issues including, but not limited to, revenue adjustment dead-bands, seasonal adjustment limitations, adjustment timelines, and any just and reasonable cost of capital adjustments, and describe which rate classes are subject to the ratemaking proposal.

2. Lost Revenue Adjustment Mechanism (LRA)

 Lost revenue adjustments are similar to limited decoupling, as they are based on recovery of lost revenues from specific causes. Compensation for lost margins is usually effected through a rate rider that can operate in years between base rate cases. LRA mechanisms are similar to limited decoupling in that they identify specific issues that reduce revenue and seek to restore them as accurately as possible. Giving a utility lost revenue from its energy efficiency programs removes the utility's disincentive to support those programs, but still allows the utility to benefit from increased sales.

a. Comments

 Duquesne supports exploring a form of LRA that would adjust base distribution revenues every six or twelve months when the actual revenues are different from an allowed revenue requirement.17 NFG states that it has implemented LRA in New York that has had a positive impact on many different customer groups and could help alleviate some revenue pressure on the utility.18 AEE states that while it prefers revenue decoupling, it notes that LRA methods, while more targeted to lost revenue for certain programs, also removes the utility's throughput incentive.19

 FirstEnergy states that LRA would likely require legislative changes to be implemented for electric utilities.20 PPL states that LRAs are not as desirable as full revenue decoupling as they are limited to recovery of lost revenue due to specific causes and do not address the challenges caused by DERs and other emerging technologies faced by EDCs.21 OCA submits that LRA incentivizes utilities to discourage energy efficiency as customers that aggressively adopt conservation measures would see little to no rewards because of surcharges imposed due to the utility's under-recovery of revenues.22 OSBA asserts that Act 129 specifically prohibits an LRA in the case of lost revenues resulting from the EDCs' EE&C programs.23 ACEEE states that LRAs should be rejected because they do not remove the throughput incentive and allow utilities an opportunity to over-earn revenue requirements.24

b. Commission View

 As with revenue decoupling, the Commission recognizes that LRAs may be appropriate in certain circumstances. The Commission, however, agrees with the parties that point out that LRAs are limited in scope and thus may not provide an adequately comprehensive approach to promote efficiency and DER. The Commission also recognizes that, depending on how an LRA is employed by an EDC, the mechanism may not be in full compliance with Act 129.25 And, again, as with decoupling, customers who are the recipients of after-the-fact billing increases for LRA shortfalls may be unhappy at being required to make up the differences for past events. Accordingly, while not rejecting LRAs, any utility proposing an LRA will need to demonstrate that the proposed rate does not discourage efficiency measures, does not conflict with the Public Utility Code and will enjoy consumer acceptance.

3. Straight Fixed / Variable (SFV) Pricing

 As a matter of rate design theory, SFV is based on the fact that most, if not all, of the utility's distribution system costs may be fixed in the short run and therefore customers should pay for those costs through fixed charges on their bills that reflect the amount of fixed costs of the distribution system for each customer class. The main advantage of utilizing SFV pricing is the revenue certainty for the utility. The utility is assured recovery of its allowed revenues through higher fixed charges and lower volume-based charges. Customers will have lower variations in their monthly electric bill because more charges are fixed, and bills will vary less due to variations in usage.

 While SFV has the effect of decoupling the utility's earnings from consumption, it also has the effect of decoupling the customer's usage from the bill as to the fixed costs of the utility's distribution system. SFV may diminish the value of customer usage reduction methods, such as energy efficiency and distributed generation, as some of the charges are fixed. High fixed charges may also challenge low-income customers. However, even with SFV, the consumer's bill for supply, which represents a variable cost, would continue to be based on the consumer's actual consumption of electricity, natural gas or water.

a. Comments

 Duquesne states that while it supports continuing use of cost trackers as well as the distribution system improvement charge (DSIC) and is considering new methodologies, including select performance incentives, revenue normalization adjustment clauses and formulaic approaches, in the interim, it supports a move toward more SFV pricing.26 FirstEnergy states that SFV removes the utility's throughput incentive and can be easily implemented as part of a base rate proceeding without negatively impacting the use of fully projected future test year (FPFTY), DSIC or other cost trackers in a way that aligns charges to match the fixed and variable nature of the utility's costs.27 Citizens states that expanding the definition of ''customer charge'' to include additional demand-related costs that can be included in the fixed charge can present the benefits of stable revenues for utilities and charges for customers.28 PPL notes that it supports and currently uses a form of SFV pricing for its commercial and industrial (C&I) customers and has recently increased its customer charges for residential rates to reflect customer cost of service and enhanced revenue protection. PPL states that SFV is compatible with a multi-year rate plan with full revenue decoupling.29 Columbia also states that, ideally, residential customers would be charged a flat monthly rate for distribution service as it most accurately reflects the manner in which the utility incurs costs to serve these customers, and that it will lessen the subsidies between customer classes.30 Aqua states that designing utility rates that emphasize a greater weight on the fixed charge would help ensure that the utility is collecting its authorized revenue requirement, reduce the risk of regulatory lag, and provide more predictable rate requests in the future.31

 PAWC states that decoupling is preferable to SFV and asserts that SFV shifts more of the cost of service to lower water use customers, does not provide customers with appropriate price signals that incent conservation and negatively impacts low-income customers.32 OCA asserts that SFV with high fixed charges often involves an expanded definition of fixed costs to the point where it severs the relationship between usage and the embedded costs of the utility system, becomes contrary to effective EE&C efforts and is contrary to prior Commission decisions.33 OSBA asserts that since most distribution costs are considered fixed in the short run, SFV effectively decouples a utility's revenue stream from usage levels resulting in charges that are not avoidable by reducing usage and would likely violate the Commonwealth Court's decision in Lloyd v. Pa. PUC, 904 A.2d 1010, 1020 (Pa. Cmwlth. 2006).34 AEE states that they are particularly concerned about the risk of decoupling bills from consumption as a disincentive to efficient use of electricity.35 KEEA asserts that SFV should not be pursued because it weakens the price signal to customers, improperly allocates costs within rate classes, adversely impacts low-usage customers and harms low-income customers.36 ACEEE asserts that SFV is not cost based and sends very poor price signals to customers to conserve electricity that would drive higher utility costs due to increased infrastructure investments to meet the higher demand.37

b. Commission View

 The Commission recognizes that SFV will reduce the price signals to customers in regard to the actual consumption of supply, particularly in those situations where a utility's fixed costs make up a significant portion of a customer's entire bill. Alternatively, in situations where the fixed costs comprise a relatively small part of a customer's total bill, SFV will have little impact on a customer's incentive to employ efficiency measures and more appropriately aligns the utility's costs with the long-term causes of those costs. However, to the extent that fixed costs are used to amplify the price signals for consumption of supply, this is, in economic terms, an artificially high price signal because the costs of the distribution system, in the short run, are fixed and do not vary by day or by month. More significantly, while the supply costs of energy, natural gas and water vary as their consumption varies, distribution service costs do not vary, in the short run between rate cases, in proportion to a consumer's daily or monthly levels of consumption.

 Furthermore, we agree with the parties that note that SFV provides utilities with greater revenue stability and reduces the disincentives for utilities to promote efficiency and conservation measures. Regarding impacts on high usage customers and low-income customers, the Commission again recognizes that in certain circumstances, these customers may be negatively impacted, but also recognize that these impacts may vary by utility and may be appropriately mitigated by other programs, such as the Low-Income Usage Reduction Program (LIURP), the Low-Income Heating Assistance Program (LIHEAP) and utility consumer assistance programs (CAPs). Accordingly, as with the other rate methodologies discussed in this proceeding, while not rejecting SFV, any utility proposing SFV will need to demonstrate that the proposed rate does not discourage efficiency measures, appropriately aligns costs in accordance with cost causation principles, and does not inappropriately impact low-income customers or appropriately mitigates such impacts, among other things.

4. Multiyear Rate Plans

 A multiyear rate plan implements a moratorium on base rate case filings and either automatically adjusts rates based on an index such as inflation or sets rates to increase in steps for the duration of the plan. Some multiyear rate plans are set based upon a target return on equity with both the surplus and deficit earnings shared between the utility and ratepayers. As a means to counteract any tendency towards inefficacy or lack of cost control, multiyear rate plans typically include a performance-based incentive to limit any adverse effect the plan may have. Multiyear rate plans can adjust rates automatically for changing economic conditions and thereby provide a utility with greater assurance of earning its authorized revenue requirement. Automatic adjustments in multiyear rate plans also reduce regulatory lag and can reduce the frequency of base rate filings by removing the need for a rate case filing if the plan is tied to the proper index. Under a multiyear rate plan, it may be difficult to accurately project rate base investment and other costs for the duration of the usual three- to five-year plan.

a. Comments

 PPL believes that a multi-year rate plan with full revenue decoupling is the most appropriate rate methodology to address its need and the needs of its customers.38 PECO states that multi-year rate plans can provide a more predictable revenue stream, particularly when a utility is anticipating substantial capital investment, and can include performance-based incentives to encourage utilities to control costs. PECO, however, believes that legislation authorizing multi-year rate plans might be required.39 AEE asserts that along with performance-based rates, multi-year rate plans provide stability for utilities, cuts down on the cost of administrative oversight and can play an important part in providing utilities with the right incentives to meet state policy objectives.40

 OCA asserts that Pennsylvania law and accepted ratemaking principles do not permit multi-year rate plans, citing FPFTY in Section 315 of the Public Utility Code, 66 Pa.C.S. § 315(e).41 OSBA states that while multi-year rate plans would reduce the frequency of rate cases, DSIC in combination with FPFTY effectively eliminate the need for annual rate filings.42

b. Commission View

 Initially, the Commission notes that, as the parties point out, multi-year rate plans may be more effective and appropriate when combined with other rate methodologies as opposed to a standalone rate mechanism. Again, as with the other rate methodologies discussed in this proceeding, the utilities' unique circumstances may warrant the use of a multi-year rate plan. Regarding OCA's assertion that Pennsylvania law does not permit multi-year rate plans or PECO's suggestion that legislation specifically permitting multi-year rate plans be promulgated prior to their adoption, the Commission, at this time, takes no position on their legality and would expect any proposal, including multi-year rate plans, to include legal justification.

 With that said, we are not adopting, nor precluding, any particular rate methodology in this proceeding. Under the proposed policy statement, any utility proposing a multi-year rate plan will need to demonstrate, in addition to the Commission's authority to approve it, that the proposed rate plan does not discourage efficiency measures, appropriately aligns costs in accordance with cost causation principles, and does not inappropriately impact low-income customers or appropriately mitigates such impacts, among other things.

5. Demand Charges

 This method establishes distribution system rates based on the distribution system capacity used by the customer (kilowatts for electric, hundred cubic feet for natural gas, and per-100-gallons for water). Historically, demand charges have been used to recover generation, transmission, or distribution system capacity costs from primarily large-volume C&I customers. Demand charges can vary in design. The objective behind the use of demand charges is to send desired price signals to influence customer behavior by encouraging customers to direct their usage to off-peak demand periods, as opposed to on-peak periods. Shifting demand to off-peak periods may increase the load factor of the utility system and therefore potentially defer investments in additional system capacity. Pricing usage on such a cost-of-service basis, with peak usage being priced higher than off-peak, can allow utilities the opportunity to obtain cost recovery that more closely approximates cost incurrence.43

a. Comments

 OSBA states that the vast majority of small business customers are currently served on rate schedules that include a demand charge and that OSBA supports the use of demand charges for small business customers, provided the charges are cost based. OSBA could also support cost-based demand charges for small business customers in the gas and water industries, with an appropriate phase-in period and adequate education.44 UGI states that for its electric division, implementing demand charges for residential customers would involve an investment in smart meters and appropriate back office systems and that there are other means to address DER.45 OCA does not support mandatory demand charges for residential customers as there has not been acceptance of such charges given their complexities and potential for unreasonable and burdensome results.46

 PULP asserts that low-income and income-challenged consumers would be disproportionately harmed by demand charges as residential consumers cannot appropriately respond to demand charge price signals, even with extensive education.47 ACEEE asserts that the cost bases for residential demand charges are highly questionable as the distribution system is not sized to meet the utility system-wide peak or a customer's individual peak, it is sized to meet a diverse set of individual customer loads that may or may not align with the system peak.48 KEEA and NRDC oppose demand charges for residential customers and suggest that time-of-use rates and other time-varying rates such as critical peak pricing and peak time rebates are more proven alternatives.49

b. Commission View

 As stated previously, we are not adopting, nor precluding, any particular rate methodology in this proceeding. Under the proposed policy statement, any utility proposing a rate plan will need to demonstrate, in addition to the Commission's authority to approve it, that the proposed rate plan does not discourage efficiency measures, appropriately aligns costs in accordance with cost causation principles, and does not inappropriately impact low-income customers or appropriately mitigates such impacts, among other things. However, to the extent that demand charges are cost-based and reflective of the distribution service costs for particular customers, categories of customers or geographic areas, such charges may be appropriate for further development in utility rate structures to better align rates with costs.

 For the electric utility industry, Section 69.3303 provides an illustrative example of critical peak pricing or similar demand-based programs that use average usage over critical peak periods as demand-based billing determinants. A critical peak pricing proposal could be (1) a fixed customer charge component reflecting metering, final line transformer and service drop cost recovery, (2) a critical peak volumetric price or average demand component, which reflects usage over the local or nodal substations, feeders, and other related distribution system components during localized peak usage periods, and (3) a volumetric on-peak, off-peak, or other rate for recovery of other distribution costs. An electric utility proposal under this rate design could be applicable to certain customer rate classes or services or designed for specific geographic locations within a service territory where such focus better serves the goals of eliminating the need for future capital investments, maximizing system utilization, or providing incentives for other Commission policies.

6. Standby and Backup Charges

 Standby charges are typically assessed on customers that fully or partially self-supply and have utility service as a backup in case of loss of self-supply, either planned or unplanned. Standby service ensures that the utility maintains adequate reserves to supply service to the self-supply customer upon demand. These charges typically involve a demand charge and an energy charge that together recover the cost of the energy used by the customer as well as the cost of the capacity to meet the customer's peak demand needs. Backup service is similar to standby service except it is usually not available instantaneously and is used to cover planned outages with long lead-time notice.50

a. Comments

 FirstEnergy states that it already offers two types of standby rates, backup and maintenance service, and reserves capacity up to the level agreed so the cost of service for allocated distribution service assets are designed to be recovered through standby rates.51 The CHP Advocates state that excessive standby rates harm competitiveness and discourage companies from developing combined heat and power (CHP) and waste heat projects. In particular, they state that tariffs that are based on the unlikely assumption that utilities must maintain excess capacity equivalent to a CHP facility's generation capacity do not consider the diversity of customer load and the actual cost of service imposed by partial use customers that generate their own power 95% of the time.52 ACEEE asserts that confusing and often excessive charges for supplemental, standby and back-up electricity can create a disincentive to invest in CHP.53

 AIE and KEEA state that the Commission should work with utilities to adopt fair and transparent standby tariffs that allow utilities to recover costs and encourage reductions in peak load, such as the Model Standby Service Template developed by the Midwest Cogeneration Association.54 AEE suggests that to mitigate disincentives standby rates may have on DER such rates should include a rebate that is equal to contracted demand less the customer's actual maximum demand in two consecutive summer periods during peak hours.55

b. Commission View

 As stated previously, we are not adopting, nor precluding, any particular rate methodology in this proceeding. Under the proposed policy statement, any utility proposing a rate plan will need to demonstrate, in addition to the Commission's authority to approve it, that the proposed rate plan does not discourage efficiency measures, appropriately aligns costs in accordance with cost causation principles, and does not inappropriately impact DER, among other things.

7. DSM Performance Incentive Mechanism

 As part of the en banc hearing, several witnesses and commentators suggested that in order to remove barriers for utilities to promote EE&C programs, both revenue decoupling and performance incentive mechanisms should be implemented together. In particular, Mr. Miller testified that ''while revenue decoupling removes utilities financial disincentives to pursue advanced technologies that reduce energy consumption, it does not provide a positive incentive to utilities to pursue these technologies per se.''56 He went on to testify that ''in order to better incentivize utilities to aggressively pursue actions that will reduce energy consumption, the Commission should adopt targeted performance incentive mechanisms (PIMs) alongside revenue decoupling.''57

a. Comments

 FirstEnergy states that establishing true performance incentive mechanisms for exceeding goals would better align the Commission's public policy goals relative to EE&C performance with an EDC's operating performance, as well as the utility's revenue. FirstEnergy advocates for a shared savings approach to incentivize utilities to exceed their statutorily-mandated EE&C reduction goals.58 PPL asserts that PIM deployment should not be limited to EE&C programs and could begin in Pennsylvania with state-wide metrics, such as customer satisfaction and reliability, that are applied to utilities of the same type through best-in-class benchmarks that are already defined by the industry and the Commission.59 Duquesne also states that performance incentives could be tied to a number of different areas, EE&C targets, reliability metrics, safety performance, among others.60 UGI generally supports the concept of offering performance incentives establishing authorized rates of return in base rate proceedings and believes the Commission already has the requisite legal authority to do so under 66 Pa.C.S. § 523.61

 NRDC asserts that a well-designed PIM would not only provide more incentive for EDCs to spend up to their Act 129 budgets and achieve more cost-effective energy savings; it would also provide additional efficiency measures and other assistance to low-income consumers, alleviating the significant energy burdens that they face.62 AEE supports implementing broad PIMs that tie designated financial rewards and penalties to specific performance metrics. AEE states that PIMs shift the focus of the utility from static cost minimization to enhancement of value as utilities are incented to improve performance. AEE argues that this leads to an increased return on investment and enhanced transparency and accountability and also addresses prudency and value of capital investment.63 KEEA also supports PIMs as one of the most useful tools to incent utilities to meet and exceed public policy goals, such as increasing the deployment of energy efficiency measures.64 ACEEE also supports the adoption of PIMs to drive greater performance in EE&C programs.65

 PECO notes that PIMs may not be permitted by Act 129, and that PIMs alone would not address existing cost-shifting concerns, including those generated by net metering.66 The OCA submits that the EDCs have achieved robust energy efficiency and demand response under Act 129 without PIMs and further notes that demand response programs are also provided by competitive suppliers, making EDC performance metrics particularly inappropriate in a competitive environment.67 OSBA also asserts that PIMs are unnecessary with respect to EDCs required to comply with Act 129, but may be appropriately considered in the natural gas and water/wastewater arenas, provided they are coupled with an approved, utility-specific EE&C program to facilitate an after-the-fact evaluation.68

b. Commission View

 As stated previously, we are not adopting, nor precluding, any particular rate methodology or performance incentive in this proceeding. Under the proposed policy statement, any utility proposing a rate plan that includes performance incentives will need to demonstrate, in addition to the Commission's authority to approve it, that the proposed rate plan including performance incentives does not discourage efficiency measures, appropriately aligns costs in accordance with cost causation principles, and does not inappropriately impact low-income customers or appropriately mitigates such impacts, among other things.

B. Proposed Policy Statement

 A consistent theme expressed in the comments is that the Commission should not take a one-size-fits-all approach, with some parties suggesting that we establish guidelines.69 We agree with these parties that the type and extent of alternative ratemaking methodologies employed by each fixed utility should be developed in a transparent manner in accordance with each utility's unique circumstances. We also agree that establishment of the guidelines each utility and stakeholder should consider in a Section 1308 rate proceeding would be helpful in determining if, the type(s) of and to what extent, alternative ratemaking methodologies should be employed.

 With this Order, we are proposing the following Policy Statement as set forth in Annex A to this Order. Initially, we propose a paragraph setting forth the purpose and scope of the proposed policy statement. This paragraph is intended to establish what the Commission views as important policy initiatives that must be considered in designing and establishing rates for all classes of fixed utility customers. It is not intended to convey all policy initiatives that are to be considered, or that these policy initiatives are to be considered above all other ratemaking principles, but to identify these policy initiatives as important to the Commission. Specifically, we propose the following:

§ 69.3301. Purpose and Scope

 Due to Federal and State policy initiatives to promote the efficient use of electricity, natural gas and water, as well as policy initiatives to promote distributed energy, the fixed utilities within this Commonwealth have seen minimal, flat or even declining load growth. The purpose of this policy statement is to invite the proposal, within a utility's base rate proceeding, of fixed utility distribution rate designs that further promote these Federal and State policy objectives, reduce fixed utility disincentives for promoting these objectives, provide incentives to improve system economic efficiency, avoid future capital investments, and ensure that fixed utilities receive adequate revenue to maintain the safe and reliable operation of their distribution systems. At the same time, an alternative rate design methodology should reflect the sound application of cost of service principles, establish a rate structure that is just and reasonable, and consider customer impacts.

 Next, we propose the following guidelines for specific issues that the Commission will consider in reviewing the rates and proposed rate structures filed by fixed utilities:

§ 69.3302. Distribution rate considerations.

 (a) In determining just and reasonable distribution rates that promote the efficient use of electricity, natural gas or water, as well as the use of distributed energy resources, the Commission will consider, among other relevant factors:

 (1) How the rates align revenues with cost causation principles as to both fixed and variable costs.

 (2) How the rates impact the fixed utility's capacity utilization.

 (3) Whether the rates reflect the level of demand associated with the customer's anticipated consumption levels.

 (4) How the rates limit or eliminate inter-class and intra-class cost shifting.

 (5) How the rates limit or eliminate disincentives for the promotion of efficiency programs.

 (6) How the rates impact customer incentives to employ efficiency measures and distributed energy resources.

 (7) How the rates impact low-income customers and support consumer assistance programs.

 (8) How the rates impact customer rate stability principles.

 (9) How weather impacts utility revenue under these rates.

 (10) How the rates impact the frequency of rate case filings and affect regulatory lag.

 (11) If or how the rates interact with other revenue sources, such as Section 1307 automatic adjustment surcharges, 66 Pa.C.S. § 1307 (relating to sliding scale of rates; adjustments), riders such as 66 Pa.C.S. § 2804(9) (relating to universal service and energy conservation policies) or system improvement charges, 66 Pa.C.S. § 1353 (relating to distribution system improvement charge).

 (12) Whether the alternative rate mechanism includes appropriate consumer protections.

 (13) Whether the alternative rate mechanism is understandable and acceptable to consumers and comports with Pennsylvania law.

 (b) In any distribution rate filing by a fixed utility under 66 Pa.C.S. § 1308 (relating to voluntary changes in rates), the fixed utility shall explain how these factors impact the distribution rates for each customer class.

 The utility landscape is evolving rapidly, none more rapidly than the electric industry. Increased penetration of distributed energy resources and electric vehicles present both a challenge and an opportunity for regulators and utilities. From a challenge perspective, the increased adoption of these technologies will likely work to decrease utilities' capacity utilization—or the ratio of peak demand to average demand. This places significant headwinds on distribution rates. However, the electricity industry has an opportunity to utilize the portfolio of new technologies such as advanced metering, advanced grid monitoring, energy efficiency, demand response, and smart thermostats to better accommodate the evolving demand profiles created by this new energy landscape.

 Accordingly, we wish to highlight that this proposed policy statement includes a general provision related to the impact of capacity utilization. As a measure, capacity utilization can be used to judge the efficiency of an electric distribution system. We are interested in consideration of rates by our electric utilities which can work to increase distribution system capacity utilization to foster system efficiency, and, insulate customers from rate increases. We encourage parties to comment on rate designs that can foster distributed energy adoption while also working to increase capacity utilization in an effort to potentially guide the Commission to more specific policy statement provisions.

 Finally, we propose possible ratemaking and rate design options for electric and natural gas distribution companies. As previously noted, Section 69.3303 recognizes that the changing energy landscape, in particular, necessitates rate designs that address a few first-order principles:

 1. Policies must support the continued efficient use of all energy resources.

 2. The evolution of a distributed energy environment requires substantial and well-targeted investment in distribution infrastructure.

 3. Policies must encourage least-cost solutions, with cost recovery based on long-term cost causation.

 4. Rate design should embrace, where feasible, the additional capabilities enabled by smart meter deployment.

 5. Finally, as noted by the OCA, ''costs are variable in the long run.''70 Therefore, it may be appropriate for energy utilities to design rates in a manner that minimizes the long-term costs of serving existing and new loads. Given the substantial and ongoing Long-Term Infrastructure Improvement Plan spending by the electric and natural gas utilities, a long-term approach to rate design may be appropriate.

 Given these principles, the Commission notes that a number of new approaches in the electric industry could be advanced. These include, but are not limited to, performance-based incentive rate designs, performance incentive mechanisms, various levels of decoupling, and variations of demand-based and time-of-use pricing options, such as critical peak pricing.

 Given current advanced metering constraints in the natural gas industry, models such as a weather normalization adjustment71 or a revenue per customer adjustment,72 if proposed and implemented with care, could balance utility and consumer needs by just and reasonable means that better ensure utility revenue recovery and system use. On the electric utility side, critical peak pricing and demand-based programs that use average usage over critical peak periods as demand-based billing determinants may offer a proper balance of these interests.

 For these reasons, the Commission proposes the addition of the new subsection 69.3303, for illustrative purposes, these principles for consideration. The inclusion of this subsection does not signal, nor should it be interpreted as signaling, any predilection by the Commission to favor one proposal over another or any predetermination by the Commission that the proposal of one of these examples comes with any presumption of approval. As evidenced in this proceeding, there are a variety of rate designs that address the needs of a changing utility landscape. We believe it is important to note options that are grounded in ratemaking principles and may help customers and utilities move forward to minimize future long-term costs, allocate capital more efficiently, and achieve important policy objectives.

§ 69.3303. Illustration of possible distribution ratemaking and rate design options for the energy industry.

 (a) In a base rate proceeding, energy utilities may propose, among others, alternative rate designs and methodologies identified in this subsection that will be subject to Commission approval or modification. Identification of these proposals is for illustration only. It does not propose the adoption, nor preclude the consideration, of any particular design or methodology, and it does not signal, nor should it be interpreted as signaling, any predilection by the Commission for one proposal over another or any predetermination of approval by the Commission of one proposal over another.

 (b) A natural gas distribution company may propose a weather normalization adjustment and/or revenue per customer ratemaking proposal. Any proposal under this subsection:

 (1) Must address consumer protection issues including, but not limited to, revenue adjustment dead-bands, seasonal adjustment limitations, adjustment timelines, and any just and reasonable cost of capital adjustments.

 (2) Must describe which rate classes are subject to the ratemaking proposal.

 (c) An electric distribution company may propose critical peak pricing or similar demand-based programs that use average usage over critical peak periods as demand-based billing determinants. A critical peak pricing proposal should be composed of:

 (1) A fixed customer charge component reflecting metering, final line transformer and service drop cost recovery.

 (2) A critical peak volumetric price or average demand component, which reflects usage over the local or nodal substations, feeders, and other related distribution system components during localized peak usage periods.

 (3) A volumetric on-peak, off-peak, or other rate for recovery of other distribution costs.

 (d) Optional rate designs under this subsection may be applicable to certain customer rate classes or services or designed for specific geographic locations within a service territory where such focus better serves the goals of eliminating the need for future capital investments, maximizing system utilization, or providing incentives for other Commission policies.

 Again, these guidelines are not meant to be the only issues the Commission will consider in any rate case, or that they are to be considered above all other ratemaking principles, but to identify these policy issues as important to the Commission. These guidelines are intended to ensure that these issues are considered and addressed to ensure that we have the most appropriate rates for the changing utility environment.

Conclusion

 With this Order, the Commission is proposing guidance for fixed utilities and interested stakeholders on what is to be considered when investigating alternative ratemaking methodologies in a Section 1308 rate proceeding. The Commission welcomes comments on all aspects of this proposed policy statement; Therefore,

It Is Ordered That:

 1. The proposed policy statement set forth in Annex A is issued for comment.

 2. The Law Bureau shall submit this Order and Annex A to the Governor's Budget Office for review of fiscal impact.

 3. The Law Bureau shall deposit this Order and Annex A with the Legislative Reference Bureau for publication in the Pennsylvania Bulletin.

 4. Interested parties shall have 60 days from the date of publication of this proposed policy statement in the Pennsylvania Bulletin to file written comments referencing Docket No. M-2015-2518883 to the Pennsylvania Public Utility Commission, Attn: Secretary Rosemary Chiavetta, Pennsylvania Public Utility Commission, Commonwealth Keystone Building, Second Floor, 400 North Street, Harrisburg, Pennsylvania 17120. Comments may also be filed electronically through the Commission's e-File System.

 5. Written replies to comments referencing Docket No. M-2015-2518883 be submitted within 90 days of the date of publication of this proposed policy statement in the Pennsylvania Bulletin to the Pennsylvania Public Utility Commission, Attn: Secretary Rosemary Chiavetta, Pennsylvania Public Utility Commission, Commonwealth Keystone Building, Second Floor, 400 North Street, Harrisburg, Pennsylvania 17120. Comments may also be filed electronically through the Commission's e-File System.

 6. A copy of this order be served on all jurisdictional electric distribution companies, all jurisdictional natural gas distribution companies, all jurisdictional water and wastewater utilities, the Office of Consumer Advocate, the Office of Small Business Advocate, the Commission's Bureau of Investigation and Enforcement, and all parties that filed comments at Docket No. M-2015-2518883.

 7. The contact persons for this matter are Kriss Brown in the Law Bureau (717) 787-4518, kribrown@pa.gov, Marissa Boyle, (717) 787-7237, maboyle@pa.gov and Andrew Herster, (717) 783-5392, aherster@pa.gov in the Bureau of Technical Utility Services.

ROSEMARY CHIAVETTA, 
Secretary

Fiscal Note: 57-322. No fiscal impact; (8) recommends adoption.

Statement of Chairperson Gladys M. Brown

 Before the Commission are the comments regarding alternative rate-making policies for fixed utilities. I thank each entity which has informed the record with proposals and considerations. Today the Commission takes its next step in deliberating the future of utility rates.

 The utility landscape is evolving rapidly, none more rapidly than the electricity industry. Increased penetration of distributed energy resources and electric vehicles present both a challenge and an opportunity for regulators and utilities. From a challenge perspective, the increased adoption of these technologies will likely work to decrease utilities' capacity utilization—or the ratio of peak demand to average demand. This places significant headwinds on distribution rates. However, the electricity industry has an opportunity to utilize the portfolio of new technologies such as advanced metering, advanced grid monitoring, energy efficiency, demand response, and smart thermostats to better accommodate the evolving demand profiles created by this new energy landscape.

 Accordingly, I wish to highlight that this proposed policy statement includes a general provision related to the impact of capacity utilization. As a measure, capacity utilization can be used to judge the efficiency of an electric distribution system. I am interested in consideration of rates by our electric utilities which can work to increase distribution system capacity utilization in effort to foster system efficiency, and, insulate customers from rate increases. I encourage parties to comment on rate designs that can foster distributed energy adoption while also working to increase capacity utilization in effort to potentially guide the Commission to more specific policy statement annex provisions.

GLADYS M. BROWN, 
Chairperson

Annex A

TITLE 52. PUBLIC UTILITIES

PART I. PUBLIC UTILITY COMMISSION

Subpart C. FIXED SERVICE UTILITIES

CHAPTER 69. GENERAL ORDERS, POLICY STATEMENTS AND GUIDELINES ON FIXED UTILITIES

DISTRIBUTION RATES—STATEMENT OF POLICY

§ 69.3301. Purpose and scope.

 Due to Federal and State policy initiatives to promote the efficient use of electricity, natural gas and water, as well as policy initiatives to promote distributed energy, the fixed utilities in this Commonwealth have seen minimal, flat or even declining load growth. The purpose of this statement of policy is to invite the proposal, within a utility's base rate proceeding, of fixed utility distribution rate designs that further promote these Federal and State policy objectives, reduce fixed utility disincentives for promoting these objectives, provide incentives to improve system economic efficiency, avoid future capital investments, and ensure that fixed utilities receive adequate revenue to maintain the safe and reliable operation of their distribution systems. At the same time, an alternative rate design methodology should reflect the sound application of cost of service principles, establish a rate structure that is just and reasonable, and consider customer impacts.

§ 69.3302. Distribution rate considerations.

 (a) In determining just and reasonable distribution rates that promote the efficient use of electricity, natural gas or water, as well as the use of distributed energy resources, the Commission will consider, among other relevant factors, the following:

 (1) How the rates align revenues with cost causation principles as to both fixed and variable costs.

 (2) How the rates impact the fixed utility's capacity utilization.

 (3) Whether the rates reflect the level of demand associated with the customer's anticipated consumption levels.

 (4) How the rates limit or eliminate interclass and intraclass cost shifting.

 (5) How the rates limit or eliminate disincentives for the promotion of efficiency programs.

 (6) How the rates impact customer incentives to employ efficiency measures and distributed energy resources.

 (7) How the rates impact low-income customers and support consumer assistance programs.

 (8) How the rates impact customer rate stability principles.

 (9) How weather impacts utility revenue under these rates.

 (10) How the rates impact the frequency of rate case filings and affect regulatory lag.

 (11) If or how the rates interact with other revenue sources, such as Section 1307 automatic adjustment surcharges, 66 Pa.C.S. § 1307 (relating to sliding scale of rates; adjustments), riders such as 66 Pa.C.S. § 2804(9) (relating to standards for restructuring of electric industry) or system improvement charges, 66 Pa.C.S. § 1353 (relating to distribution system improvement charge).

 (12) Whether the alternative rate mechanism includes appropriate consumer protections.

 (13) Whether the alternative rate mechanism is understandable and acceptable to consumers and comports with Commonwealth law.

 (b) In any distribution rate filing by a fixed utility under 66 Pa.C.S. § 1308 (relating to voluntary changes in rates), the fixed utility shall explain how these factors impact the distribution rates for each customer class.

§ 69.3303. Illustration of possible distribution ratemaking and rate design options for the energy industry.

 (a) In a base rate proceeding, energy utilities may propose, among others, alternative rate designs and methodologies identified in this subsection that will be subject to Commission approval or modification. Identification of these proposals is for illustration only. It does not propose the adoption, nor preclude the consideration, of any particular design or methodology, and it does not signal, nor should it be interpreted as signaling, any predilection by the Commission for one proposal over another or any predetermination of approval by the Commission of one proposal over another.

 (b) A natural gas distribution company may propose a weather normalization adjustment or revenue per customer ratemaking proposal, or both. Any proposal under this subsection must:

 (1) Address consumer protection issues including revenue adjustment dead-bands, seasonal adjustment limitations, adjustment timelines, and any just and reasonable cost of capital adjustments.

 (2) Describe which rate classes are subject to the ratemaking proposal.

 (c) An electric distribution company may propose critical peak pricing or similar demand-based programs that use average usage over critical peak periods as demand-based billing determinants. A critical peak pricing proposal should be composed of all of the following:

 (1) A fixed customer charge component reflecting metering, final line transformer and service drop cost recovery.

 (2) A critical peak volumetric price or average demand component, which reflects usage over the local or nodal substations, feeders and other related distribution system components during localized peak usage periods.

 (3) A volumetric on-peak, off-peak or other rate for recovery of other distribution costs.

 (d) Optional rate designs under this subsection may be applicable to certain customer rate classes or services or designed for specific geographic locations within a service territory where this focus better serves the goals of eliminating the need for future capital investments, maximizing system utilization or providing incentives for other Commission policies.

[Pa.B. Doc. No. 18-963. Filed for public inspection June 22, 2018, 9:00 a.m.]

_______

1  In the context of this proceeding, examples of alternative rate methodologies to be considered in order to encourage better implementation of energy efficiency and conservation programs include (1) revenue decoupling and other rate designs that separate some or all of a utility's authorized revenue recovery from volumetric sales following the determination of an overall revenue requirement; and/or (2) a utility's performance with respect to energy efficiency and conservation as a part of the determination of the overall authorized revenue requirement.

2  PECO Comments at 13—15.

3  PPL Comments at 9, 11, 18, and 20—22, and Reply Comments at 11—13.

4  Peoples Comments at 3-4.

5  PGW Comments at 7.

6  UGI Comments at 17—19.

7  NFG Comments at 2, 4 and 6.

8  Columbia Comments at 9-10 and Reply Comments at 3-4.

9  Aqua Comments at 4-5.

10  PAWC Reply Comments at 2-3.

11  NRDC Comments at 12-13.

12 AEE Comments at 8.

13  KEEA Comments at 8-9.

14  ACEEE Comments at 3 and Reply Comments at 2.

15  OCA Comments at 14, 15, 19, 20, 30, 31, 37, 51—55, 59 and 60 and Reply Comments at 9, 10, 24, 35 and 36.

16  Industrials Comments at 2, 5—8 and Reply Comments at 3—7.

17  Duquesne Comments at 14—16.

18  NFG Comments at 2.

19  AEE Comments at 8-9.

20  FirstEnergy Comments at 14.

21  PPL Comments at 11-12.

22  OCA Comments at 15, 54 and Reply Comments at 10, 11, 24—26.

23  OSBA Comments at 6-7.

24  ACEEE Comments at 3 and Reply Comments at 1-2.

25  Specifically, 66 Pa.C.S. § 2806.1(k)(2).

26  Duquesne Comments at 8, 10—13.

27  FirstEnergy Comments at 9, 10, 12—14, 18, 19 and Reply Comments at 8, 9, 12.

28  Citizens Comments at 5, 4 and Reply Comments at 1, 2.

29  PPL Comments at 12.

30  Columbia Comments at 7—9, 14, 15.

31  Aqua Comments at 5, 6.

32  PAWC Reply Comments at fn. 4.

33  OCA Comments at 15—17 and Reply Comments at 12—15, 26—29, 36.

34  OSBA Comments at 9.

35  AEE Comments at 9.

36  KEEA Reply Comments at 4, 8—11.

37  ACEEE Reply Comments at 2, 3.

38  PPL Comments at 11.

39  PECO Comments at 11, 12.

40  AEE Comments at 6, 10.

41  OCA Reply Comments at 17, 18.

42  OSBA Reply Comments at 5.

43  See Distributed Energy Resources Rate Design and Compensation: A Manual Prepared by the NARUC Staff Subcommittee on Rate Design at 98-99, available at http://pubs.naruc.org/pub/19FDF48B-AA57-5160-DBA1-BE2E9C2F7EA0.

44  OSBA Comments at 10.

45  UGI Comments at 16.

46  OCA Comments at 39—50 and Reply Comments at 18—20, 38, 39.

47  PULP Comments at 3—7.

48  ACEEE Comments at 4, 5.

49  KEEA Comments at 20, NRDC Comments at 14—17.

50  See Distributed Energy Resources Rate Design and Compensation: A Manual Prepared by the NARUC Staff Subcommittee on Rate Design at 120—123, available at http://pubs.naruc.org/pub/19FDF48B-AA57-5160-DBA1-BE2E9C2F7EA0.

51  FirstEnergy Reply Comments at 14, 15.

52  CHP Advocates Comments at 1—4.

53  ACEEE Comments at 6.

54  AIE Comments at 3, 4; KEEA Comments at 19, 20.

55  AEE Comments at 11, 12.

56  Testimony of Eric Miller at 6.

57  Id. See also Testimony of Eric Ackerman at 3.

58  FirstEnergy Reply Comments at 6, 7.

59  PPL Comments at 15, 16.

60  Duquesne Comments at 13.

61  UGI Comments at 17.

62  NRDC Comments at 8—12.

63  AEE Comments at 3, 9.

64  KEEA Comments at 10—13 and Reply Comments at 6, 7.

65  ACEEE Comments at 7.

66   PECO Comments at 12, 13 and Reply Comments at 10, 11.

67  OCA Reply Comments at 20.

68  OSBA Comments at 8.

69  See Columbia Reply Comments at 2; Council Comments at 6-7; Duquesne Comments at 5 and Reply Comments at 8-9; EAP Comments at 3 and Reply Comments at 2-3; FirstEnergy Comments at 20; I&E Comments at 2, 8, 9; NFG Reply Comments at 2, 6; Industrials Reply Comments at 9; KEEA Reply Comments at 3-4; OSBA Comments at 11; Peoples Comments at 3-4 and Reply Comments at 3; PAWC Reply Comments at 1-2; PECO Comments at 3 and Reply Comments at 1, 3—6; PGW Comments at 1-2, 10; PPL Comments at 2 and Reply Comments at 2; PSU Reply Comments at 3-4, 10-11; UGI Comments at 4-5; and VCW Comments at 3 and Reply Comments at 1.

70  See OCA Reply Comments at 12.

71  Weather normalization adjustments were implemented by both Columbia Gas of Pennsylvania, Inc. since 2012 and Philadelphia Gas Works since 2002. See Columbia Reply Comments at 3-4 and PGW Comments at 4.

72  Revenue per customer adjustments have already been implemented in other states such as Ohio, Maryland, Massachusetts and Virginia, therefore, there is a history of experience from which to draw if proposing effective revenue per customer adjustments to benefit both customers and utilities. See Columbia Comments at 6.



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