Task 4 DISTRIBUTION-LEVEL Final O & B Report PPORTUNITIES

Task 4 Final

Report

DISTRIBUTION-LEVEL

OPPORTUNITIES & BARRIERS FOR DISTRIBUTED RENEWABLES

December, 2001

Submitted to:

Nils Bolgen Massachusetts Renewable Energy Trust Fund,

Massachusetts Technology Collaborative www.mtpc.org

Paul Gromer

Solar Energy Business Association of New England

Steve Cowell Conservation Services Group (CSG)

www.csgrp.com

Prepared by:

Francis Cummings (781) 273-5700

XENERGY, Inc. www.xenergy.com

Three Burlington Woods Burlington, MA 01803-4543

An Affiliate of KEMA Consulting www.kemaconsulting.com

www.kema-kps.nl

DISTRIBUTION-LEVEL OPPORTUNITIES & BARRIERS FOR DISTRIBUTED RENEWABLES

Table of Contents

1. INTRODUCTION .................................................................................................................................................. 1

2. BENEFITS OF DISTRIBUTED RENEWABLES TO T&D SYSTEMS.................................................... 3

Types of Potential Distributed Benefits .............................................................................................................. 3

Risk Management............................................................................................................................................... 3 Distribution Facility Deferral or Avoidance.................................................................................................. 4 Line Loss Reduction.......................................................................................................................................... 4 Voltage and Stability Support .......................................................................................................................... 4 Ancillary Services .............................................................................................................................................. 5

Estimates of Potential Economic Benefits.......................................................................................................... 5

EPRI Methodology (1995)................................................................................................................................ 5 GRI Case Studies (1998)................................................................................................................................... 6 PV and Wind Case Studies by Zaininger Engineering (1999) ................................................................... 8 PV Case Studies by Pacific Energy Group (1999) ....................................................................................... 9

3. STANDBY CHARGES AND RELATED BARRIERS.................................................................................. 9

Future Issues .......................................................................................................................................................... 10

Ratemaking Principles ......................................................................................................................................... 10

National Grid ......................................................................................................................................................... 11

Current Status.................................................................................................................................................... 11 Settlement of the MECO/EUA merger......................................................................................................... 12

NSTAR – Boston Edison..................................................................................................................................... 14

Current Status.................................................................................................................................................... 14 Sources ............................................................................................................................................................... 14 History: DTE Review of Auxiliary and Reservation Charges................................................................. 14 Interconnection Policies .................................................................................................................................. 17 Information & Requirements for Electric Service (the Boston Edison "Blue Book") ......................... 18

NSTAR – Commonwealth Electric ................................................................................................................... 19

Current Status.................................................................................................................................................... 19

NSTAR – Cambridge Electric ............................................................................................................................ 19 Current Status Sources ............................................................................................................................................................... 19 Standby Tariff ................................................................................................................................................... 19 Supplementary Service Tariff G-2 Distribution Service Tariff for Comparison

NU – Western Massachusetts Electric .............................................................................................................. 19

Current Status.................................................................................................................................................... 19 Sources ............................................................................................................................................................... 20 Standby Tariff ................................................................................................................................................... 20 Outage Responsibilities ................................................................................................................................... 20


Barriers Project – December, 2001 – Page 1

1. INTRODUCTION

This Regulatory Briefing has been prepared by XENERGY as part of the project entitled “Removing Market Barriers to Distributed Renewables: Regulatory Policy” (known as the “Barriers Project”), which is managed by Conservation Services Group for the Solar Energy Association of New England (SEBANE) and funded by the Massachusetts Renewable Energy Trust Fund of the Massachusetts Technology Collaborative (MTC). Development of new distributed renewable power generating capacity not only offers benefits to the end user(s) or developers who own the generating resource, but also offers the potential to bring significant benefits to the distribution system to which it is interconnected. These benefits include deferral of costs to expand distribution capacity, line loss reduction, voltage and stability support and other benefits. While some of these benefits are very site-specific, others are of value across wider areas of the distribution grid. The nature, magnitude and allocation of these “distributed benefits” are addressed in this briefing. These benefits can be achieved even when the generators are located at customer sites, “behind the meter.” This report also reviews the “standby” or “backup” charges and other utility ratemaking arrangements that have the effect of allocating these distributed benefits, and various distribution costs, between the owner of the generators, the utility owner of the wires system and the ratepayers. Generally, higher levels of standby charges may protect the distribution utility and its ratepayers from excessive loss of revenues from self-generators, while lower standby charges may provide the on-site “host” end user the opportunity to reduce its cost of distribution service. When the potential benefits available from a distributed renewable generator are high enough, there is a basis for a “win -win” outcome in which all parties can share in the net benefits. To assess the potential for win-win solutions for distributed renewables, this project assembled a range of preliminary estimates to illustrate the relative magnitudes of standby charges and distributed benefits. The underlying utility tariffs and estimates of T&D benefits are presented in the sections of this report.



The following chart summarizes the low estimates (first bar, blue color) and the high estimates (second bar, purple color) of two indicators of cost and two measures of benefit.

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Total DistributionRate per kW Total

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Source: XENERGY Inc. These preliminary estimates show that the potential T&D benefits range widely, depending on the location of the DG installation on the distribution system and other factors. In addition, different methodologies give different estimates of benefits: the results of a very simple approach are shown in the third set of bars, and more sophisticated analyses provide a wider range of results, shown in the fourth set of bars. At the low end of the range, these benefits may not be great enough to offset the distribution or standby rates to the customer. However, when conditions are favorable, a DG project can save the utility more money by deferring T&D expansion costs than the utility would stand to lose in distribution revenues, regardless of the level of standby charges. Standby charges are shown in the second set of bars in the chart above, ranging from $15 to $40 per kW of DG capacity and recovering most or all of the distribution revenue that a customer would have paid for each kW of load, or in some cases, representing more standby revenue than the original distribution rate. Additional data could be collected and analyzed in future phases of this Barriers Project to verify these comparisons and analyze the potential implications for ratemaking and for the financial analysis of potential renewable development projects. The estimates assembled to date are incomplete and may not reflect the substantial variation in these values that exists between utilities and between different locations on the distribution system, as well as over time and across generating technologies. There is at present no prescribed regulatory process to allocate costs and benefits in such a way as to achieve a positive win-win result. For a particular DG project, the alternative to a win-win outcome may turn out to be the “no-build” option, because the economics of some DG projects may depend upon



avoiding some T&D costs in addition to avoiding the cost of generation from the grid. Therefore, additional financial analysis of the economics of renewable DG may be warranted along with the further analysis of utility rates and distributed benefits.

2. BENEFITS OF DISTRIBUTED RENEWABLES TO T&D SYSTEMS

This section reviews the potential for distribution facility deferral and other types of benefits that DP installations may provide to the distribution system. We then review a range of estimates of the magnitude of these benefits, which are often site-specific, with the potential to range up into the $1,000/kW level where the local T&D needs are greatest.

TYPES OF POTENTIAL DISTRIBUTED BENEFITS

The following benefits of DG to the T&D system and its customers are described below:

• Risk Management • Distribution Facility Deferral or Avoidance

• Line Loss Reduction

• Voltage and Stability Support

• Ancillary Services.

Risk Management

Renewable and other distributed power, including distributed generation and geographically targeted load management programs, holds the potential to reduce T&D risks by adding the equivalent of distribution capacity on an incremental basis and helping distribution companies to manage uncertain load growth and unexpected load shifts. Major T&D upgrades require long-term projections of growth and load patterns. DP allows greater flexibility in planning and deployment. A prime example is the ability to add capacity in increments, rather than through “lumpy” wires projects that involve higher risk. This can be achieved with DP installations at customer facilities or at substations or other locations on the distribution system. In the extreme, mobile DG units can also be used to mitigate shifts in demand. In California, Pacific Gas and Electric uses large mobile units in the valley during the summer to meet air conditioning peaks, then moves them to Northern California for the winter peaks in the mountainous region there. Another real-life example is the use of mobile DG units to provide generation to meet load on a system when transmission lines go down, which occurred in Chicago in 2000. These units can be trucked in and connected to the grid to meet the needs of the utility until the transmission line can be repaired. These T&D benefits represent potential offsets to standby rates, which have served to allocate the costs of the T&D system itself between customers with distributed generation on the one hand and the distribution utilities or the other electric customers on the other hand. Standby charges continue to represent a



regulatory uncertainty that potentially affects the economic evaluation of distributed generation investments in many states.

Distribution Facility Deferral or Avoidance

Installation of DG and other geographically-targeted DP or load management resources have the potential to avoid capital expenditures by utilities for distribution (and transmission) additions. There is some debate over the appropriate role of such resources in T&D planning, and over the different treatment of dispatchable and non-dispatchable resources; this debate is not addressed here.

Line Loss Reduction

Eliminating Normal Energy Losses

Another area of significant savings for utilities and transmission facilities is the reduction of line losses through the use of DG. Simply put, locating generation near the load eliminates energy losses through the line. The challenge is how to credit this back to the DG owner. PJM’s Distributed User Group recently published a draft of the emergency and economic load reduction programs for 2001, which included the recommendation that customers participating in either plan receive credit for normal line losses through the distribution system. Most utilities post a system-wide average for each customer class. This could be used as a baseline for billing purposes.

Crediting Resistive Losses

Line losses can be 4-7% system wide. However, during peak periods they can range as high as 20% because line losses increase dramatically if the thermal limit is exceeded. Therefore, every increment of generation at the top of the load curve that can be eliminated will result in substantial line loss savings. This would be most evident and quantifiable on radial distribution circuits.

Voltage and Stability Support

“Unloading” Can Improve Stability

Utilities have always had to contend with voltage stability and support. Generally, the more load on the system, voltages tend to sag, lights dim and equipment doesn’t operate as efficiently. This is most prevalent when power is transmitted long distances. DG can mitigate these problems. First, by relieving the system of load, distributed resources could reduce the effects and severity of system disturbances. Using DG as peakers or load displacement could achieve these benefits.

Ride-through of Momentary Outages

Very short outages —becoming more prevalent on most utility systems today—can and do impact users on the system. This is becoming much more pronounced today because of the use of computers and highly sophisticated equipment that requires consistent power within very tight ranges. DG units, as generating sources, have the potential to supply local loads during grid interruptions and can mitigate this problem by allowing users on portions of the grid, in some instances, to ride through momentary outages.



Ancillary Services

Distributed power may provide or facilitate the market for ancillary services, including:

• Local Voltage Control • Spinning Reserves • Load Frequency Control • Load Following/Balancing.

Electric deregulation may open significant opportunities for DG to provide ancillary services, like those listed above. The utility has provided all of these services in the past. In future, these may be provided by DG units, operating under performance contracts with the utility. There are two aspects to this issue. One is the extent to which ancillary services could be provided by the DG operator. The second is the extent to which customers can reduce their need for ancillary services from the utility by virtue of installing on-site generation. Small gas turbines can be powered up to maximum capacity in a matter of seconds. In addition, software systems now being designed for DG packages could easily be modified to follow the utility’s load and respond by increasing generation to meet the load. The new Load Response programs introduced by ISO-NE before the summer of 2001 provide revenue to end-users and their suppliers for spinning reserve benefits. The potential treatment of distributed PV as a reserve resource is expected to be addressed in a subsequent project memo.

ESTIMATES OF POTENTIAL ECONOMIC BENEFITS

Few comprehensive studies are yet available that quantify the benefits to the transmission and distribution grid of distributed generation and other DP technologies, although several such studies have been initiated under Department of Energy and other auspices. To date, much of the work in this area has centered on renewable technologies, which have generally depended on these added benefits for an important part of their economic feasibility. One study that analyzes a number of these benefits on an integrated basis is underway at Rocky Mountain Institute under the direction of Amory Lovins.1

EPRI Methodology (1995)

One simple approach to estimate the value of T&D additions that could be avoided by DG was developed for EPRI in 1995.2 This methodology is driven primarily by data on capital expenditures by utilities for distribution (and transmission) additions over time compared with the MW capacity of distribution additions over the same period (based in turn on rates of load growth). Data or assumptions are also used about the percentage of distribution expenditures that are related to load growth and the percentage of those load growth expenditures that are avoidable. XENERGY replicated this model in a worksheet and calibrated it to the EPRI report’s results for 1995, which indicated a potentially avoidable distribution cost of $686, plus an avoidable transmission cost of $240/kW, for a total of $926/kW.

1 Lovins, Amory B. with Ken Wicker, Andre Lehmann, Karl Rabago and Tom Feller, “Small is Profitable: The Hidden Benefits of Making Electrical Resources the Right Size,” Presentation to CADER Annual Conference, San Diego, CA, 9 November 2000. 2 “Strategic Market Assessment of Distributed Resources,” EPRI TR-106055, December 1995, pp. A-31-32.



We then updated this model with 1998 data for selected utilities, indicating avoidable costs in the range of $925/kW to $1,075/kW for Massachusetts utilities (Boston Edison and Massachusetts Electric). The national average cost for adding T&D infrastructure has been recently cited at the slightly higher level of $1,260 per kW in a distributed generation newsletter.3 We have also updated this model with additional years of data for these and other utilities, since additional data points over time are needed to produce and validate meaningful and reliable estimates on a utility-level basis. The following chart summarizes these results, which range between $20 and $40/kW-year.

GRI Case Studies (1998)

This section reviews several case studies which indicate a wide range of T&D benefits. Two case studies are presented in a 1998 “Distributed Generation Guidebook for Municipal Utilities:” 4

1. Iola, KS $5.2 million (1997 $) for interconnection avoided by installation and operation of a 4 MW genset every 2 to 4 years, which is equivalent in present value cost terms to 9 to 10 MW. This case indicates the following potential T&D benefits:

• $1,300/kW initially deferred, or • $500/kW avoided over a longer term.

3 “Quantifying the Value of DP,” DP Happenings, January 2001 Issue, ASCO Power Technologies. 4 “Distributed Generation Guidebook for Municipal Utilities,” Gas Research Institute (GRI), January 1998.

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BECo MECo WMECo Cambridge

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2. Large Industrial Energy User Case: $2 million substation avoided by 4 MW generation: $500 T&D cost avoided/kW.

These case study costs are consistent with a tabulation in this GRI handbook entitled “Transmission and Distribution Line Costs ($/mile)” which shows costs per mile ranging from $350,000 to $520,000/mile in urban areas, and from $250,000 to $425,000 in industrial areas, depending primarily on the types of poles used. Line termination equipment is estimated to cost an additional $140,000 for 13.8-kV lines and $340,000 for 138-kV lines. Finally, a substation is estimated to cost between $2.4 million and $2.9 million, depending on voltages.



PV and Wind Case Studies by Zaininger Engineering (1999)

Four case studies of distribution facility deferral were cited in a presentation to the October, 1999 California Energy Commission “Energy Innovations” conference by Henry W. Zaininger (Zaininger Engineering Co.5), which addressed the impacts of renewable DG on specific systems in California. We have summarized these results in the following table, comparing the T&D benefits with the generation-related benefits. The site-specific nature of T&D benefits is underscored by the range of benefits from $42/kW to $878/kW. The T&D benefits estimated for the solar PV projects were from 4% to 46% as great as the direct generation-related benefits (energy and capacity). See XENERGY’s Memo of September 10 “Analysis of Energy and Capacity Values for Massachusetts PV” for additional information on the coincidence of PV generation with the highest energy spot prices and the coincidence of PV capacity or availability with the NE system peak. For wind projects, the T&D benefits were greater relative to the avoided cost of energy and capacity, ranging from 14% to 170% of these generation benefits. The project with T&D benefits at 170% of generation benefits incorporated storage as well as wind generation.

Solar PV Projects Windpower Projects

Benefits of Particular DG Installations ($/kW)

PSC New Mexico

Commercial PV

SCE Suburban

PV

Georgia Power

Suburban PV

FPL Suburban

PV

Individual Benefit as % of T&D Benefit

Orcas P&L Wind with

Storage

Orcas P&L Wind Farm

SCE Rural Wind Farm

GMP Mountain

Wind Farm

Individual Benefit as % of T&D Benefit

T&D Benefits of DG

Distribution facility deferral 847 186 63% 858 558 69%

Transmission capacity 282 86 23% 88 200 14%

Distribution losses 15 53 62 45 11% 20 18 217 60 15%

Transmission losses 38 32 4% 44 2%

Voltage regulation (3) (4) (4) (3) -1% (4) (2) 0%

Subtotal T&D Benefits 859 555 176 42 100% 878 576 345 258 100% Ratio of T&D Benefits to Generation Benefits 46% 32% 21% 4% 170% 143% 19% 14% Generation-Related Benefits

Energy displacement 844 1,110 567 428 64% 370 369 1,580 1,513 90%

Generation capacity 1,020 624 288 733 57% 147 35 195 375 18%

Environmental externalities 339 7% 520 12%

Energy Policy Act 0% 149 149 297 312 21%

Subtotal Other Benefits 1,020 963 288 733 65% 296 184 1,012 687 51%

Total Value ($/kW) 1,879 1,518 464 775 100% 1,174 760 1,357 945 100%

5 Henry W. Zaininger, Zaininger Engineering Co., Inc., 9959 Granite Crest Ct., Granite Bay, CA 95746



PV Case Studies by Pacific Energy Group (1999)

Five other case studies of distribution facility deferral were presented at the same October, 1999 CEC conference by Pacific Energy Group, based on their QuickScreen software package for Distributed PV Evaluation, which is available on the internet.6 The following results, from this Pacific Energy Group presentation, include values of approximately $15, $50, $140, $520 and $640 per kW for five different instances of distribution facility deferral from solar PV installations, in addition to the substantial other benefits listed:

3. STANDBY CHARGES AND RELATED ISSUES

Standby and related tariffs7 enable the distribution company to retain some revenue from a DG owner to continue to cover some costs of the T&D system for which such a customer would have paid but for its own investment in its distributed power capacity. Standby charges represent a regulatory uncertainty that potentially affects the economic evaluation of distributed generation investments in most MA utility areas and in many other states. Massachusetts and most other restructured states are currently in the midst of reassessments of the ratemaking treatment of DG, which could change the level and structure of these rates dramatically.

6 Howard Wenger, Tom Hoff & Dale Furseth, Pacific Energy Group; Christy Herig, National Renewable Energy Laboratory; John Stevens, Sandia National Laboratory; QuickScreen Software for Distributed PV Evaluation, available at: http://www.pacificenergy.com/quickscn.htm. 7 In addition to standby or back-up rates per se, supplementary and maintenance rates are also established by some utilities, and the term “Auxiliary” rates is also used.



The importance of standby and related charges may depend on the type of distributed power project. In other words, when on-site generators are designed primarily to export power to the grid, their financial performance depends on the price at which their power can be sold, net of transmission rates, losses, etc. For generators designed solely to back up the grid, their financial performance depends on the value of reliability to the end user as well as the cost of grid power replaced. However, for renewable DG and distributed generating projects that are designed to provide the primary source of base load or load following power for on-site end use customers, standby and related charges are a key assumption for financial analysis. There are two different existing models of standby rates in Massachusetts: those in place for NSTAR’s Cambridge Electric (but not Commonwealth) and for Western Mass Electric (reproduced below). However, neither Boston Edison nor National Grid has a standby, backup or supplemental rate for on-site generators at present. As a result, their business customers incur a demand charge in each current month for whatever level of demand it imposes on the utility that month, with no ratchet, regardless of the extent to which such load may have been due to a DG outage or on-site power load. In other words, no demand charge applies to the capacity of the customer’s generator(s) for a month in which no DG outage is experienced. Without a ratchet, these standby charges are a function of the number of months in which unscheduled outages occur.

FUTURE ISSUES

NGrid could propose a new standby (Auxiliary) rate as soon as 15 MW of new on-site generation is developed, leading to a negotiation and then a DTE case. This new rate would not apply to “non-dispatchable, non-fossil fuel renewable energy facilities,” but this proceeding would apply to fuel cells using natural gas (a technology considered “renewable” for purposes of this project) and would likely establish precedents as to issues which could be important to distributed renewables (such as the payment of “distributed benefits”). NSTAR is expected to propose similar rate(s) for BECo and Commonwealth Electric at some point, and the DTE has considered initiating a generic case on these issues itself. Open points, that have already been raised to date, include:

(a) the treatment of distributed benefits (as a credit against standby charges or as a separate payment to DG owners),

(b) the appropriate principles that should govern the setting of standby rates – especially the appropriateness of NGrid’s proposed semi-automatic recovery of “lost revenue” – both through the future Auxiliary Rate and through the ambiguous provision on page 12 of the Settlement that could have the effect of automatically overriding or “short-circuiting” the results of an approved Auxiliary Rate tariff without further DTE review.8

(c) other elements of the level and structure of rates to be charged to on-site generators (renewable or otherwise).

RATEMAKING PRINCIPLES

In addition to the Cambridge and WMECo standby tariffs, there are a number of models of standby and related rates that are used in other states and additional models that were discussed by a wide range of

8 See question of interpretation in later footnote.



stakeholders during the Settlement negotiations in 1998 on a standby charge proposal by MECo.9 We can outline and compare these approaches, and illustrate their cost impacts on small DG projects, at the appropriate stage of this project. Before exploring particular mechanisms, we should discuss general principles to govern DG-related ratemaking. For example, the following principles, presented to the Restructuring Roundtable in January of 2000, could be adapted to this project:10

1.) Data on feeder power conditions should be “e-distributed” on a real-time basis to operators of distributed resources.

2.) Distribution rates and PBR mechanisms should give customers incentives to invest in distributed generation that is economically efficient compared to utility T&D investments.

3.) DG policies should be based on the full range of public policy goals, including energy efficiency and diversity, avoidance of adverse effects on the global environment and equity among all classes of ratepayers.

4.) Standby charges should avoid creating unintended incentives for users to isolate themselves from the grid.

5.) Customers should be able to select the amount of onsite capacity which they wish to back up.

6.) Physical and economic benefits to the T&D system should be reflected in standby rates or rate credits.

7.) Rates should reflect the diversity of generating resources on each feeder.

8.) Standby rates should provide incentives to minimize grid use during times of peak T&D load.

9.) Standby rates should charge capacity costs only for on-site generation outages that occur at the distribution system peak.

10.) Standby rates should credit customers for arranging load reduction within the affected portions of the T&D system which offsets generator outages.

11.) Requirements for interconnecting customer-sited generators to the distribution system should be designed to assure safety and reliability, without interfering with the power market.

NATIONAL GRID

Current Status

No Standby Rate or Tariff in effect, but some related DTE policies on standby charges for new distributed generation capacity are stated in its 3/14/2000 Order approving the MECO/EUA merger (D.T.E. 99-47), as described below.11

9 While particular positions taken by parties in that negotiation must remain confidential, many of the concepts explored were based on rate models in other states and in the public domain and can be discussed based on those precedents. 10 Source: "Paradigm Busters: Why Distributed Generation Will Rewrite the Rules of Open Access," Fran Cummings & Phil Marston, Public Utilities Fortnightly , October 15, 1999; also presented to NECPUC’s June 27, 2000 Conference in Rockport, Maine: “Distributed Power Market: Perfect Storm, or Win/Win Ratemaking Principles.” 11 D.T.E. 99-47 was the “Joint Petition of Massachusetts Electric Company and New England Power Company (subsidiaries of New England Electric System), and Eastern Edison Company (subsidiary of Eastern Utilities Associates) for approval of Eastern Edis on Company's merger into Massachusetts Electric Company.”



National Grid USA rates -- http://www.masselectric.com/library/meco/rates/mec5-00.pdf.

Settlement of the MECO/EUA merger

National Grid negotiated a vague understanding regarding its proposed “lost revenue” approach to standby charges for new distributed generation capacity in its Settlement of the MECO/EUA merger. The provisions of the settlement that address potential future Auxiliary Service rate filing(s) are attached (see Excerpts from NEES Settlement Document in MTC Barriers Project File ).12 The following is the DTE’s policy on National Grid’s proposed “lost revenue” approach to standby charges for new distributed generation capacity, as stated in its 3/14/2000 Order approving the MECO/EUA merger (D.T.E. 99-47).13

3/14/200: Excerpts from DTE Order (emphasis added)

“IV. SPECIFIC CONSIDERATIONS OF THE MERGER (B) Effect on Rates

3. Exogenous Factors

a. Introduction

“As described in Section II.F., above, the Petitioners requested that MECo be provided the opportunity to recover or refund costs associated with several exogenous factors. Below, the Department addresses the proposed exogenous factors in general and specifically addresses three issues associated with the Petitioners' proposed treatment of exogenous factors that warrant further discussion: (1) the $1 million threshold for the factors (a) tax and accounting changes and (b) regulatory or legislative changes; (2) new on-site generation exceeding 15 MW; and (3) any accumulated incentives or penalties in excess of the threshold established under the proposed service quality plan.

b. Analysis and Findings

“The Department has defined exogenous costs as positive or negative cost changes beyond a company's control that would significantly affect the company's operations. NIPSCO-Bay State Acquisition, D.T.E. 98-31, at 17; Eastern-Essex Acquisition, D.T.E. 98-27, at 17; Boston Gas Company, D.P.U. 96-50, at 290 (1996). With the exception of the factors discussed below, the proposed exogenous factors are either consistent with the factors proposed and approved in previous merger cases (tax and accounting changes and regulatory or legislative changes), are unique to MECo but were approved in the Company's last rate case settlement, D.P.U. 93-194 (storm and hazardous waste funds), or are consistent with the electric industry's move toward restructuring (reclassification of costs).(21) Therefore, the Department accepts these proposed exogenous factors as a reasonable balance of risk between the Company and its customers.

12 ftp://spbarriers:[email protected]/MTC Barriers Project/Round 1. 200106 through 200109/Regulatory Documents/Standby Charges/991129 DG Pages from NEES-EUA Settlement Filing.pdf 13 D.T.E. 99-47 was the “Joint Petition of Massachusetts Electric Company and New England Power Company (subsidiaries of New England Electric System), and Eastern Edison Company (subsidiary of Eastern Utilities Associates) for approval of Eastern Edison Company's merger into Massachusetts Electric Company.”



“Now we turn to the exogenous factors that warrant further discussion. [First, .…] Second, regarding new on-site generation, the Settlement provides that MECo shall adjust its distribution rates to recover lost revenues resulting from the installation of any new on-site generating capacity operational on or after July 1, 1999, that in the aggregate exceeds a 15 MW threshold (Settlement at 12). In the event the 15 MW threshold is exceeded, MECo would propose Auxiliary Service provisions to seek recovery of the lost revenues for the increme nt above 15 MW.14 (22) The Settlement also provides that (1) the Auxiliary Service Rate would be sought through its Exogenous Factors Adjustment proceedings and (2) the Company will adjust its distribution rates in each rate class for any revenues lost within that rate class within the preceding calendar year to the extent that Auxiliary Service Rates approved by the Department are not sufficient to recover the lost revenues associated with new on-site generation in excess of the 15 MW (id.).15 “Although the Rate Plan does not explicitly exclude net-metering customers from the Auxiliary Service provisions (see footnote 23),16 the Company provided assurances that any proposal in the Exogenous Factors Adjustment proceedings would be consistent with the Department policy current at that time (Tr. 2, at 235-237). “Because it is outside the scope of this proceeding, the Department does not make any findings on the appropriateness of an Auxiliary Service Rate at this time . However, in addressing new on-site generation as an exogenous factor in any future Exogenous Factors Adjustment proceeding, the Department at a minimum will consider: (1) what method of analysis should be used to quantify the economic impact on the Company of new on-site generation; (2) the potential impact of assessing a special fee to certain customers installing new on-site generation on the emergence of new beneficial technologies; and (3) the extent to which revenue losses from new on-site generation should be recovered through a balance between special fees and the ratepayers within the designated rate classes (Tr. 1, at 91-93). “[Third, ….] With the specific qualifications in place associated with on-site generation and accumulated incentives and penalties, the inclusion of the Rate Plan's exogenous factors is acceptable in the context of a rate reduction for a period of time and limited rate increase for a time thereafter. Moreover, the mechanism for inclusion of specific exogenous factors is not automatic. Adjustments for exogenous factors would be subject to review, and after a public hearing, approval by the Department.17 Therefore, the Department approves the Petitioners' proposed list of exogenous factors and the mechanism for accounting for them in the future.”

14 Footnote 22: “The Settlement exempts the following technologies from the Auxiliary Service Rate: non-dispatchable cogeneration facilities; heating and cooling systems at the customer's location; and non-dispatchable, renewable energy facilities. However, the Settlement provides that these technologies will contribute to reaching or exceeding the 15 MW threshold (Settlement at 13).” 15 Key question of interpretation: Item (2) appears on page 12 of the Settlement and is rather convoluted and ambiguous. This “lost revenue” provision could have the effect of automatically increasing NGrid rates to other customers in the rate class (e.g., G-1) to cover any shortfall left by an approved Auxiliary Rate tariff. It is not clear whether this rate increase could be implemented without further DTE review. In other words, it’s not clear whether any such adjustment of “distribution rates in each rate class for any revenues lost within that rate class … to the extent that Auxiliary Service Rates … are not sufficient to recover” them would nevertheless be subject to the “adjustments for exogenous factors [that will be] subject to review, and after a public hearing, approval by the Department.” 16 Footnote 23: “According to 220 C.M.R. § 11.07(c), distribution companies shall be prohibited from imposing special fees on net metering customers.” 17 See key question of interpretation in prior footnote.



NSTAR – BOSTON EDISON

Current Status

No Standby Rate or Tariff in effect, but the company is expected to propose such a rate at some point in the future.

Sources

NSTAR rate info: start at http://www.nstaronline.com/ and choose “Your Business;” then select Boston; then under Business Rates, look for “for greater detail” and select “:Schedule of Rates.”18 See also “procedures and requirements for interconnecting on-site generation,” which may be at http://www.bedison.com/your_business/fr3.htm.

History: DTE Review of Auxiliary and Reservation Charges

From late 1992 through 1997, Boston Edison had in effect a “Reservation Charge for Sporadic Loads. While it went out of effect during the restructuring process, its approval in DPU 92-92 may establish some precedent or identify some issues.

D.P.U. 85-271-A: BECo Auxiliary Service Charge Denied

In the previous rate case in 1985, Boston Edison had proposed, and the Department had denied , an “Auxiliary Service Charge” with four different rates for segregated service, partial requirements service, back-up service and maintenance service (D.P.U. 85-271-A). BECo’s proposal was rejected at that time because “to treat customers who have similar loads differently is discriminatory” (D.P.U. 85-271-A, page 275). The problem appeared to be essentially that BECo had singled out customers “having another source of electrical power” for treatment different than that afforded to other “customers at the voltage level and with similar load characteristics as its proposed auxiliary service customers” (D.P.U. 85-271-A, page 275). When BECo fixed this problem in 92-92 by applying its Reservation Charge to any customer that meets a specific set of “trigger” conditions (see below), the DPU approved the new charge.3

DPU 92-92: Reservation Charge for Sporadic Loads

In the 1992 Boston Edison rate case (D.P.U. 92-92), Boston Edison proposed and the DPU approved a “Reservation Charge for Sporadic Loads” as a new Miscellaneous Charge. This new charge was designed to collect the reserve portion of the Company’s marginal distribution costs. A sporadic distribution load (which might be abbreviated “SDL”) was defined by the following conditions from the D.P.U. 92-92 Order (page 58) and from the tariff sheet (reproduced below):

1. “There is a difference of 500 kw or more between the customer’s maximum billing demand in a calendar year and the average of the billing demands in the other 11 months; and”

2. “The maximum billing demands in the summer and winter seasons exceed by 100% or more the average billing demands of the other months in that season.”

18 This takes you to http://www.nstaronline.com/your_business/03_rates_bus.htm (formerly http://www.bedison.com/your_business/fr3.htm). 3 However, the current Cambridge Electric rates for Standby and Supplemental Service, which evolved for the MIT cogeneration stranded cost case, apply only to customers with such onsite generation.



Essentially, the D.P.U. precedent from this case appears to include the policy that “if the Company must stand ready to serve a particular customer, then the customer should pay some portion of the distribution plant that is reserved for the customer’s use…. Absent a reservation charge, the customer would be subsidized by the Company’s other customers.” (D.P.U. 92-92, page 61, emphasis added) However, the DPU seemed to accept BECo’s characterization of these loads as based on “the reserve margin of the distribution system” (page 59), as opposed to some other measures of the costs incurred to back up an on-site generator’s capacity. The key portion of the tariff sheet is reproduced below, and the relevant portion of the DPU Order is attached:

In its Order approving this Reservation Charge, the Department stated:



“The proposed charges are $1.15 per KW at the high level tension level and $1.85 at the secondary level and are based on BECo’s marginal distribution costs. These charges are designed to collect the reserve portion of the company’s marginal distribution costs (Exh. BE-RDS-10, p. 23). The application of these charges will unburden the Company’s full requirements customers from subsidizing the cost of dedicated facilities which are used intermittently. The Energy Consortium does not challenge the cost-based nature of the charges, nor does it dispute the purpose of these charges, i.e., if the Company must stand ready to serve a particular customer, then the customer should pay some portion of the distribution plant that is reserved for the customer’s use. Absent a reservation charge, the customer would be subsidized by the Company’s other customers. We agree with this reasoning and find that a charge for sporadic loads is appropriate. In particular, the Department approves the threshold condition by the Company that would trigger the imposition of the sporadic load charge.”

The Department’s other findings in the 92-92 Order suggest a policy under which the charges for customers with sporadic loads should be based on the costs allocated to the class into which the customer falls for its other rates, rather than “designing a separate rate for the sporadic load customers,” because of the small number of these customers and the volatility of their loads.4 5

1997: Reservation Charge Dropped

This charge was dropped form the BECo tariff in 1997, but without any explicit discussion with the Department or other parties that would have provided a basis for such a change. What happened was that in 1997 the Company did not include this Reservation Charge on the tariff sheets that it submitted in response to the DPU’s requirement for rate unbundling, nor on the sheets that it filed in July, 1997 as part of its Restructuring Settlement with the Attorney General and other parties. As a result, the Reservation Charge is no longer in effect or available as a tariff rate, 19 although it may present a precedent that may berelevant in the future.

4 Consistent with this direction, the recent MECo proposal for “Auxiliary Service” for customers with their own generation states that “customers receiving service under these provisions will pay for [service] under the provisions of the filed rate on which they take service,” such that what changes is primarily the determination of demand and energy levels. 5 The DPU’s reasoning primarily addressed generation and transmission charges. 19 It appears that this rate was rarely if ever used.



Interconnection Policies

BECo Network DG Interconnection Policy

The following policy was distributed by BECo in and around the early 1999 timeframe:

“The network area … is defined as the area in Boston bounded by the Charles River, Boston Harbor, Fort Point Channel, Southeast Expressway, Melnea Cass Boulevard through Northeastern University to Huntington Avenue, Museum Road, the Fenway, Park Drive and St. Mary's St. (the Brookline line), and all of Charlestown.” -- from “Information & Requirements for Electric Service” (the Boston Edison "Blue Book"



Notification Requirements for On-Site Generation

The following 6-month notification period20 is specified in the Tariff for General Service Rate G-3, under “Term Of Service:”

“Customers served under this rate must provide the Company with six (6) months prior written notice before installing or allowing to be installed for its use a non-emergency generator with a nameplate capacity greater than that in place on the Customer’s location as of October 1, 1993.”

Information & Requirements for Electric Service (the Boston Edison "Blue Book")

Effective May 1st 1998 [note: may have been superceded] . . . 306 Customer Generation The following general requirements apply to customer generating facilities designed to operate directly connected to the Company's electrical system (parallel operation) and those which are designed to operate isolated from the Company's system (non-parallel operation). Requirements and specifications for various types and sizes of customer facilities shall be obtained from the Customer Service Engineer in the Electric Delivery Organization for the applicable city or town prior to installation.

A - Standby Generation (Non-Parallel Operation)

The customer may install a standby generator to supply all or part of the load in the event of a service interruption. The customer's wiring shall be arranged so as to prohibit the interconnection of the Company's service and the customer's alternate source of supply. This will require the installation of a double-throw switch or its equivalent as approved by the Company. Sketch #1 schematically illustrates some typical installations of standby generating equipment. Note: Precautions must be taken where alternate means of generation are employed, whether emergency or otherwise, to eliminate the possibility of electrical connection between the Company's service and the customer's alternate source of supply (e.g., marinas with dockside service, truck docks, etc.). The customer must notify the Customer Service Engineer in the Electric Delivery Organization for the applicable city or town and provide electrical details of generator installation and isolation from the Company's system.

B - Auxiliary Generation (Parallel Operation)

Prior to the installation of any auxiliary generator facilities (e.g., wind turbine, solar panel, etc.), the customer must notify the Customer Service Engineer in the Electric Delivery Organization for the applicable city or town to provide interconnection details and to obtain approval for the facility's protective and synchronizing equipment arrangement. Customers wishing to sell electricity to the Company shall consult with the Power Contracts Department at (617) 424-3139 for the Company's Power Purchase Policy.

20 This 6-month notification concept was first introduced in the 1966 NEES Restructuring Settlement.



C - Cogeneration (Parallel Operation)

Cogenerators are defined as facilities that produce electrical energy and utilize the heat energy by-product for other purposes (e.g., heating or cooling). As in Parts A and B above, the customer must notify the Customer Service Engineer in the Electric Delivery Organization for the applicable city or town prior to the installation of this equipment in order to provide design information and obtain approval for connection of the equipment to the Company's facilities.

NSTAR – COMMONWEALTH ELECTRIC

Current Status

No Standby Rate or Tariff in effect at the time of this writing.

NSTAR – CAMBRIDGE ELECTRIC

Sources

NSTAR rate info: from http://www.nstaronline.com/ , choose “Your Business” and then select Cambridge; then under Business Rates, look for “for greater detail” and select “:Schedule of Rates.”

Standby Tariff

The following tariffs are current for 2001. The first is the Standby rate, which is followed by the associated Supplementary rate. The definitions of these categories of service are specified in the Tariff sheets. After these are presented, we also include for comparison the G-2 rate for regular distribution service, which would apply to a large retail store as an example of a facility that could host a small renewable generating system.

[Available on request. Omitted from this version to reduce the size of the file.]

NU – WESTERN MASSACHUSETTS ELECTRIC

Current Status

WMECO Standby Schedule PR (DTE 97-120-2) is reproduced below. It does not have the same structure or rates as the Cambridge Electric standby tariff, but it nevertheless represents one precedent to which the DTE could refer to some degree in acting on any new rate proposals from NGrid or NSTAR. See the definitions of the terms “backup,” “supplementary” and “maintenance.” WMECO’s standby rates have a “rachet” over a long 24-month period (see Supplementary Rates below), as well as other features which impose significant backup and other costs on self-generators.



Sources

WMECO rate information: http://www.wmeco.com/programs/rates/rateslist.asp and/or http://www.wmeco.com/customer/rates/index.html.

Standby Tariff

[Available on request. Omitted from this version to reduce the size of the file.]

Outage Responsibilities

The following language concerning the determination of responsibility for outages appeared in an earlier version of WMECO Standby Schedule PR tariff (MDTE No. 1013C), per DTE 97-120-2, July 2, 1998 (we haven’t checked the latest version above to see if it’s changed):

“a condition on the Company’s side of the point of delivery is determined to be responsible….” The general concept is that no customer should be responsible for paying a demand charge (or penalty) in connection with any demand that is caused not by its own generator outage, but by a condition on the distribution lines. This is a matter of serious concern to many existing self-generators, especially in areas prone to outages.