marketing and energy services manual...energy co-opportunity 2201 cooperative way herndon, virginia...

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National Rural Electric Cooperative Association

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Developing Rates for distributed GenerationDeveloping Rates for Distributed Generation

MARKETING AND ENERGY SERVICES

Developing Rates for Distributed GenerationDeveloping Rates for Distributed Generation

DG rates cover 9/9/01 8:53 AM Page 3

Prepared by

Dennis R. Eicher and Douglas R. LarsonPower System Engineering, Inc.

12301 Central Ave., N.E., Suite 250Blaine, Minnesota 55434

for

Cooperative Research Network • T&D Engineering Committee • Energy Policy DivisionNational Rural Electric

Cooperative Association4301 Wilson Boulevard

Arlington, Virginia 22203-1860

Energy Co-Opportunity2201 Cooperative Way

Herndon, Virginia 20171

National Rural Utilities Cooperative Finance Corporation

2201 Cooperative WayHerndon, Virginia 20171

P R O J E C T 0 0 - 2 8

www.crnweb.org

®

Developing Rates for Distributed GenerationDeveloping Rates for Distributed Generation


The National Rural Electric Cooperative Association (NRECA) is the national service organization of more than 900 rural electricsystems. These cooperatively owned utilities own and operate about 44% of the miles of distribution lines in the nation to provide power to less than 10% of the nation’s people, primarily in the sparsely populated, rural areas of 46 states.

NRECA was founded in 1942 to unite rural electric systems in a way that would permit them to develop the services and support they needed to properly serve rural America. NRECA is one of the largest, rural-oriented cooperative organizations inthe United States.

The NRECA Cooperative Research Network, a service of NRECA that has supported this project, was created to conduct stud-ies and carry out research of special interest to rural electric systems and their consumers.

©Developing Rates for Distributed GenerationCopyright © 2001 by National Rural Electric Cooperative Association.

Reproduction in whole or in part strictly prohibited without prior written approval of the National Rural Electric CooperativeAssociation, except that reasonable portions may be reproduced or quoted as a part of a review or other story about this publication.

Legal Notice

This manual was prepared as an account of work sponsored by the National Rural Electric Cooperative Association (NRECA).Any opinions, recommendations, and conclusions contained therein are those of the author, not of NRECA. Neither NRECA,members of NRECA, nor any person acting on their behalf (a) makes any warranty or representation, express or implied, withrespect to the accuracy, completeness, or usefulness of the information contained in this manual, (b) assumes any liability withrespect to the use of, or damages resulting from the use of, any information, apparatus, method, or process disclosed in thismanual, or (c) makes any warranty or representation that the use of any information, apparatus, method, or process disclosed inthis manual may not infringe on privately owned rights.


Contents – v

C O N T E N T S

Foreword vii

Acknowledgments viii

Section 1 Introduction 1Overview 1Section Summary 2General Observations 4

Section 2 Utility Cost Structure and Ratemaking 5Overview of Cost Studies and Rates 5Wholesale Rates 6Retail Rates 9

Section 3 Distributed Generation Issues 13Introduction 13Requirements Contracts 14Impact on System Requirements and Utility Costs 15Stranded Cost and Cost Shifting 23Interconnection Requirements 25Environmental Issues 26

Section 4 Review of Policies and Rates Applicable to Distributed Generation 27G&T Cooperatives 27Investor-Owned Utilities 31

Section 5 Development of Distributed Generation Rates 33Introduction 33Costs and Cost Savings 34Rate Design Options 36Evaluation Process 44Examples 47Rate Schedule Clauses 51

Appendix A Sample IOU Rate Schedules 57

Appendix B Examples of Electric Tariff Provisions 73

Resource Bibliography 79

Foreword – v i i

F O R E W O R D

The process by which this project came to besponsored speaks volumes about the nature andimportance of the project itself. As theCooperative Research Network was consideringthe proposal, one of our funders, Bob Reals ofNew Hampshire Electric Co-op, made us awareof a possible interest in co-funding that hadbeen expressed to him by Energy Co-Opportu-nity. At the same time, but unknown to CRN,NRECA’s Energy Policy Division was solicitingbids for essentially the same project. In one ofthose happy times when organizational commu-nications are working the way one wishes theyalways could, CRN approached Jay Morrison ofEnergy Policy to get his input regarding our project, which had now been approved by theMarketing and Energy Services Task Force andincluded ECO’s offer of co-funding. Rather thancontinue its plans to sponsor a separate project,Energy Policy agreed to co-fund—and, moreimportantly, for Jay Morrison to co-manage—thisproject. At a kickoff meeting, there seemed tobe ample reason for both CFC and NRECA’sT&D Engineering Committee to have an interestin the project, and it was suggested that theyboth be approached as possible co-sponsors aswell. Both accepted that invitation, and, for thefirst time in the history of RER or CRN, a projectwas co-funded by five interested groups!

Much information has been published anddisseminated regarding the technological aspectsof distributed generation. Increasingly, moreinformation is becoming available on the subjectof the size and nature of the market for distrib-uted generation. The time seemed right for us tobeing investigating the pricing and rate

issues. . .and, in this project, that is preciselywhat we have done!

Power System Engineering (the contractor),Jay Morrison, and I want you to take the follow-ing salient points from this manual:

• Despite the potentially confusing array of DG applications, there is a generally consis-tent process that can be followed to guide aco-op’s evaluation of costs associated witheach, and development of appropriate rateschedules.

• Cooperatives can design rates that will notonly ensure that cooperatives will recovercosts relating to DG, but that will also encour-age the installation and operation of DG in away that benefits the entire system.

• This exercise will require cooperation andcoordination between distribution coopera-tives and their G&T (if they have one) andwill likely involve co-op staff from many dis-ciplines because many varying perspectiveswill need to be considered in this new formof rate design. The reader should understandthat this is one case where one size definitelywill not fit all!

We hope that you find this manual valuablein gaining a better understanding of the rate andpricing issues associated with this pervasive newtechnology that will almost certainly have amajor impact on our industry in coming years.

Karen A. SawyerSenior Program ManagerCooperative Research Network

The Marketing and Energy Services technologyunit of the Cooperative Research Networkwould like to sincerely acknowledge the contri-butions of the following individuals to makingthis manual possible:

• I would like to express my personal gratitudeto Jay Morrison, Sr. Regulatory Counsel,NRECA, as co-manager of this project. Jay’sextensive expertise in rate issues and his tenacious oversight of this project providedthe foundation for the quality of our results.

• Co-sponsors William C. Cetti, President andCEO of Energy Co-Opportunity; the NRECAT&D Engineering System PlanningSubcommittee; the NRECA T&D EngineeringCommittee; and Bill Edwards, Director ofRegulatory Affairs at CFC, have made substan-tial contributions throughout the course of theproject. Their help in reviewing and editing

the final report is especially appreciated.• Douglas R. Larson, Vice President, Power

System Engineering, Inc., for his flexibilityand patience in working with such a diversegroup of contributors as well as the initial“melding” of the proposal they had submittedto Energy Policy with that sent to CRN.

• Finally, the Cooperative Research Committee,oversight board to the Cooperative ResearchNetwork, for its willingness to authorize anexception to CRN’s policy of restricting theresults of CRN project findings to those elec-tric cooperatives that fund CRN. A co-spon-sored project of this nature would not havebeen possible without its willingness to waivethe policy of sharing CRN project findingswith only those electric co-ops that supportthe research program.

Karen A. Sawyer

v i i i – Acknowledgments

A C K N O W L E D G M E N T S

Distributed generation is receiving increasedattention among consumers and cooperatives.Cooperatives’ perceptions as to whether distrib-uted generation should be encouraged largelyrelate to the specific distributed generationapplication at issue and the financial and opera-tional impact such distributed generation willhave on the cooperative.

Because a wide variety of distributed genera-tion applications may be pursued by consumersand cooperatives, it is important to define “dis-tributed generation.” For example, some defini-tions limit distributed generation to small-scaleenvironmentally friendly technologies such asphotovoltaics, fuel cells, micro-turbines, smallwind turbines, etc. Other definitions are moreexpansive and include any generation locatednear a load center regardless of size or energysource. As used in this manual, distributed gen-eration refers to the generation of electricity byfacilities sufficiently smaller than central generat-ing plants as to allow interconnection at nearlyany point in an electric power system.

Distributed generation can encompass manydifferent applications and technologies. Thesedistributed generation applications can be eithercustomer initiated or cooperative initiated. Inmany cases, consumers will install distributedgeneration to address specific needs. Theseneeds can be operational (including a need toprovide some level of on-site power supply dur-ing emergencies or for enhanced reliability) orfinancial. Examples of customer-initiated distrib-

uted generation include the following:

• Generation sufficient to support critical enduses during emergencies

• Generation to improve power quality or reliability

• Generation capable of meeting a portion orall of the customer’s electrical requirementsfor peaking or base load

• Generation of power for sale at wholesale

Cooperatives may also consider distributedgeneration to address system or market needs:

• Lower peak power costs• Lower market risks• Avoid or defer distribution system

expansion• Provide voltage support • Provide additional opportunities for

market sales• Encourage renewable resources• Support key accounts• Increase reliability (i.e., provide backup

power during emergencies)

Numerous issues must be addressed in settingpolicies, rates, and procedures for dealing withdistributed generation that must recognize thewide variety of distributed generation applica-tions that may be pursued by consumers andcooperatives. Despite this potentially confusingarray of distributed generation applications, a

I n t roduct ion – 1

Introduction

In This Section: Overview; section summary; general observations

Overview

1

2 – Sect ion One

generally consistent process can be followed toguide a cooperative’s evaluation of costs associ-ated with each distributed gen-eration application and develop-ment of appropriate rate sched-ules.

Cooperative staff from manydisciplines may be involved inthe development of rates,polices, and procedures dealingwith distributed generation. Thismanual is intended to facilitatesuch cooperative staff efforts by:

• Providing general backgroundinformation on rate develop-ment

• Reviewing issues related to distributed generation

• Summarizing generation and transmissioncooperative rates and policies

• Outlining a process for evalu-ating and developing appro-priate distributed generationrates

It must be emphasized, howev-er, that rate development is aprocess. A wide variety of dis-tributed generation applicationsare possible. Likewise, coopera-tive circumstances are not allalike. Cost analysis and ratedesign must recognize the dif-fering impacts that each distrib-

uted generation application will have on coop-erative costs and service to other consumers. Inthis regard, one size does not fit all cases.

1

Each distributedgenerationapplication will havediffering impacts oncooperative costsand service to otherconsumers

Section Summary

This manual is organized into four sections:

Section 2, Utility Cost Structure andRatemaking, provides a brief review of coopera-tive cost structure analysis and the developmentof traditional approaches to cooperativeratemaking. This review begins with anoverview of traditional cost-of-service (COS)studies and rate designs. Then, specific issuesrelating to generation and transmission (G&T)cooperative COS analysis and an overview ofG&T rate structures are provided. Of particularinterest are the two principal methods typicallyused in one form or another to allocate genera-tion plant costs: the cost accounting approachand the cost causation approach. Finally, distrib-ution cooperative COS issues and rate designoptions are addressed. Like G&T cost studies,distribution cost-of-service studies can employdifferent methodological approaches that cansignificantly alter the final results. Two areas ofcost allocation in particular can have a dramaticimpact on distribution cost studies:

1. The approach to allocating distribution plantcosts

2. The approach to allocating administrativeand general costs

Section 3, Distributed Generation Issues, iden-tifies and discusses a number of issues related todistributed generation:

• Requirements contracts• Impact on system requirements and

utility costs:� Generation costs� Ancillary service costs� Transmission costs� Distribution costs

• Stranded costs and cost shifting• Interconnection requirements• Environmental impact

Many of these issues are a function of thetype of generating unit, fuel source, mode ofoperation, and/or ownership of the unit. Thisdiscussion identifies where and how the charac-teristics of a specific distributed generationapplication enter into the consideration of eachissue.

Section 4, Review of Policies and RatesApplicable to Distributed Generation, providesan overview of existing G&T policy issues andwholesale rates/credits applicable to distributedgeneration. While G&T policies pertaining todistributed generation tend to be unique, a num-

I n t roduct ion – 3

ber of core policy issues are generally addressedby all G&T cooperatives:

• Ownership• Operation• Metering• Minimum size• Control frequency and duration• Allowable amount of distributed generation• Control circumstances

This section also reviews vari-ous G&T wholesale rates/creditsthat are applied to distributedgeneration used for peak reduc-tion, standby service, and pur-chases of excess capacity and/orenergy. Finally, policies andrates from investor-owned utilities are brieflyconsidered.

Section 5, Development of DistributedGeneration Rates, builds on the previous sec-tions by describing the considerations/processinvolved in evaluating and developing ratesapplicable to distributed generation. In thisregard, it must be emphasized again that ratedevelopment is a process. Cooperative circum-stances are not all alike. Cost analysis and ratedesign must recognize the specific impacts thateach distributed generation application will haveon a cooperative’s costs and on service to otherconsumers. This section begins by looking atcosts of and cost savings from service associatedwith distributed generation. While embeddedCOS results may be used as a starting point forevaluating distributed generation costs anddeveloping necessary rates, marginal costs andavoidable costs are at least as important.

Once the costs and cost savings have beenidentified for specific distributed generationapplications, it is then possible for a cooperativeto develop appropriate retail rates based on theidentified net costs/benefits of providing service.This section discusses a variety of options that acooperative has to achieve its objectives withrespect to distributed generation. Beyond areflection of costs and cost savings, rates applic-able to customers with distributed generationshould at least satisfy the following cooperativegoals:

1. At a minimum, the cooperative must ensurethat the applicable rate structure satisfies a“hold harmless” test. That is, the cooperativemust ensure that the rate or rates paid bycustomers with distributed generation recov-er sufficient revenue to cover the coopera-tive’s net incremental cost of providing ser-vice to those customers. This will ensure thatother cooperative customers are not harmedby the action of customers implementing

distributed generation, eitheron their own initiative orotherwise.

2. If the cooperative determinesthat encouraging the devel-opment of distributed gener-ation is in the long-terminterest of the coopera-

tive and its other member/consumers, theapplicable rates should be designed toencourage customers to install distributedgeneration in a manner that maximizes thebenefits. That is, rates and/or incentivesshould be used to facilitate customer installa-tion of distributed generation in desired geo-graphic areas and/or that is operated in away that lowers the cooperative’s existing orfuture cost of providing service.

Section 5 outlines an evaluation process fordistributed generation applications:

1. Identify the cooperative’s services requiredby the consumer after the distributed genera-tion is installed.

2. Determine necessary interconnectionrequirements to ensure the safety and relia-bility of the cooperative’s system.

3. Evaluate the cooperative’s costs of providingservice.

4. Determine whether there are any potentialcost savings associated with the anticipateddistributed generation.

5. Consider various rate and non-rate optionsthat will provide for the cooperative’s recov-ery of its cost of service and the accomplish-ment of other objectives.

6. Develop a specific tariff or contract thatreflects the rate and necessary conditions ofservice.

Rate development is a process

4 – Sect ion One

7. Determine whether any other supportingdocuments are necessary.

Section 5 also provides a few examples ofcooperative objectives associated with distrib-uted generation and an identification of rate andnon-rate options that may be employed toachieve these objectives. These examples areprovided for illustrative purposes only. Distribu-tion and G&T cooperatives face unique cost andservice circumstances that are impacted differ-ently when various distributed generation appli-cations are installed. Selection of appropriaterate and non-rate options must recognize theseunique cost and service circumstances.

Finally, Section 5 identifies a number of tariffprovisions to consider when establishing distrib-uted generation service rate schedules. Anyreview of electric rate schedules reveals that,while there are basic similarities in rate schedulecontent, there can also be significant content dif-ferences. The development of electric rate sched-ules is influenced by two important factors:

1. Whether a cooperative is subject to regulationby a state agency versus being self-governed

2. The cooperative’s preference for includingspecific details in a rate schedule versusincluding these details in policies or otherservice and operation documents

1

General Observations

At the outset, it is important to make some gen-eral observations regarding distributed genera-tion applications, cost analysis, and rates.

1. Cooperatives must determine the value ofdistributed generation based on a carefulanalysis of the financial costs and benefits ofa specific distributed generation applica-tion(s).

2. Cooperatives must recognize that existingwholesale and retail rates based on averageembedded costs will likely not reflect mar-ginal cost of service. Accordingly, existingwholesale and retail rates will likely haveuneconomic incentives or disincentives rela-tive to the installation of distributed genera-tion applications. Such uneconomical pricesignals can be mitigated through amendmentof existing rates or development of appropri-ately designed distributed generation rates.

3. Existing requirements contracts typically pro-hibit or limit distribution cooperatives fromowning distributed generation or purchasingthe output of distributed generation ownedby third parties. If G&Ts wish to promotedistributed generation more broadly, theremay be a need for such contract limitationsto be modified.

4. Distributed generation rates may bedesigned through standard rate schedules oroffered as customized rates for individualcustomers. In general, distributed generationrate schedules work well when several cus-

tomers are likely to participate in such ser-vice and the load and cost characteristics ofthese customers are expected to be similar.On the other hand, cooperatives may wishto pursue individualized rates if one or onlya few customers are expected to participateand anticipated cost of service and loadcharacteristics are significantly differentamong these customers.

5. It is critical that distributed generation ratesand policies be carefully coordinatedbetween G&T and distribution cooperativesto ensure that real cost and cost savings forboth organizations are properly reflected inthe retail service offered to consumers.Wholesale and retail cost analysis and ratedesign must recognize that one size doesnot necessarily fit all cooperatives. Beforeaddressing the rate issue, the G&T and itsmember distribution systems must determinethe potential impacts of distributed genera-tion on wholesale power cost and distribu-tion delivery cost. Cooperatives must deter-mine under what circumstances they want toencourage distributed generation.

6. Despite the potentially confusing array ofdistributed generation applications beingpursued by consumers and cooperatives, agenerally consistent process can be followedto guide a cooperative’s evaluation of costsassociated with each distributed generationapplication and development of an appro-priate rate schedule.

Overview of Cost Studies and Rates

To ensure financial viability, a cooperative’sretail rates must generate sufficient revenue tomeet operating expenses and margin require-ments. Margin requirements must in turn beadequate to cover interest expense and accom-plish other capital management objectives. Thesum of operating expense and margin require-ments are referred to as the “revenue require-ments” of the cooperative.

Revenue Requirements = Operating Expense + Margin Requirements

To evaluate a cooperative’s revenue require-ments and the adequacy of its present rate struc-ture to meet those requirements, it is common

practice to analyze revenue and costs for a 12-month period referred to as the Test Year.Once the cooperative’s total revenue require-ments are established, they are allocated to eachclass of service through a cost-of-service study.The results of the COS study are then used toassist the cooperative in designing specific rates.

This section provides a brief review of theapproach to cooperative cost structure analysisand the development of traditional approaches tocooperative ratemaking. This review begins withan overview of traditional COS studies and ratedesigns. Specific issues relating to G&T COSanalysis and an overview of rate structures arethen provided. Finally, distribution cooperativeCOS issues and rate design options are addressed.

Ut i l i t y Cost St ructu re and Ratemak ing – 5

Utility Cost Structure and Ratemaking

In This Section: Overview of cost studies and rates; wholesale rates; retail rates

2GENERALThe basic objective of a COS analysis is to iden-tify the cost of providing service to each rateclass as a function of load and service character-istics. The methodology most often employed byelectric cooperatives is referred to as the “fullyallocated average embedded” cost-of-serviceapproach meaning that:

1. Total costs are allocated on an average system-wide basis.

2. Embedded or accounting costs as recordedon the cooperative’s books are used in theanalysis.

COS studies are among the basic tools ofratemaking. While opinions vary on the appro-priate methodologies to be used to perform coststudies, few analysts seriously question the stan-dard that service should be provided at cost.Non-cost concepts and principles often modifythe cost-of-service standard, but COS remainsthe primary criterion for the reasonableness ofrates.1

The cost principle applies not only to the over-all level of rates, but to the rates designed forindividual services, classes of customers, and seg-ments of the utility business. Consequently, coststudies are used for the following purposes1:

1 National Association of Regulatory Utility Commissioners, Electric Utility Cost Allocation Manual, January 1992.

Wholesale Rates

6 – Sect ion Two

2• To determine the revenue requirements for

the monopoly services offered by a coopera-tive operating in both monopoly and compet-itive markets

• To attribute costs to different categories ofcustomers based on how those customerscause costs to be incurred

• To determine how costs will be recoveredfrom customers within each customer class

• To calculate costs of individual types of ser-vice based on the costs each service requiresthe cooperative to expend

Stated another way, COS studies are used toachieve two primary objectives.

1. A COS study serves as a guide for distribut-ing or allocating revenue requirements. Inthis regard, the goal is to achieve equitybetween rate classes or rate components.

2. A COS study is used as a guide for designing individual rate schedules. The goal here is to achieve equity within each rate class.

COS LIMITATIONS AND USESIt is vital to recognize some of the inherent limitations of COS studies:

1. It must be emphasized that a COS analysis,while basically an engineering evaluation, isan art, not an exact science. Many differentmethodologies, techniques, and assumptionshave been and will continue to be advocat-ed by rate analysts. Because the variousphilosophies and assumptions can signifi-cantly affect the result of the analysis, theresults should be treated as providing anindication of the general range of class costresponsibility, not as precise values.

2. A COS analysis is of necessity directed atdetermining the cost imposed by a rate classon the system rather than at determining the

cost imposed by individual customers withineach classification. The cost responsibility ofa specific, individual consumer may or maynot be entirely consistent with the cost allo-cations made to his/her assigned consumerclassification. In addition, a COS study doesnot address the problem of maintaining rela-tively smooth transitions between the vari-ous rate classes or subclasses of customerswho may be eligible to receive service undermore than one rate schedule.

3. Accurate demand characteristics and loadfactor data for individual customer classesare often unavailable. This is particularlytrue for cooperatives, most of which havenot performed the load research necessaryto obtain this data. Capacity allocationsmust, therefore, be made on the basis ofestimates or “typical” data. These assump-tions or estimates can have a significanteffect on the end results.

4. A COS analysis does not address itself tomany of the other legitimate objectives of ratedesign such as customer acceptance or theavoidance of excessively abrupt changes fromthe historical rate policies of the cooperative.In addition, it does not recognize the need tokeep each rate competitive, as much as possi-ble, with the corresponding rate of neighbor-ing utilities or the need to keep the rate struc-ture simple and concise so that it can beadministered and understood by customers.

With the above limitations in mind, a COSanalysis can provide a useful guideline forassigning cost responsibility (i.e., revenuerequirements) to each of the customer classifica-tions in a way that avoids unjustifiable price dis-crimination. A COS analysis also provides infor-mation useful in designing the individual rateschedules and provides support for justifyingrate differentials to retail customers.

WHOLESALE COST-OF-SERVICE ANALYSISProduction and/or purchased power costsaccount for the vast majority of typical G&Texpenses. While the allocation of fuel expense is clearly a function of the amount of energy

produced, the driving forces behind fixed costsassociated with generating plants are not asclear-cut. Two principal methods are typicallyused in one form or another by G&Ts to allocatesuch generation plant costs:


21. Cost accounting approach2. Cost causation approach

Under the cost accounting approach, some-times referred to as the fixed variable approach,the fixed costs associated with generating plantsare assigned as a capacity cost and recoveredthrough wholesale demand charges. The ratio-nale for this approach is that these costs arefixed and do not vary with the level of energyproduction. Therefore, they should be recoveredthrough demand charges.

The cost causation approach asserts that gen-eration plant costs were incurred not just tomeet capacity requirements, but instead to pro-vide an optimally priced mix of capacity andenergy. Accordingly, a portion of these genera-tion plant costs is treated as energy-relatedexpenses. For example, if capacity were theonly concern, cooperatives would only installrelatively inexpensive peaking units. The factthat cooperatives spend additional money toinstall high-efficiency, low-fuel-cost generatingunits is driven by energy considerations.Therefore, the argument goes, any additionalcosts above the cost of a peaking unit should beascribed to the need to provide low-costenergy.2

While the justification for either of these twomethods is somewhat theoretical and subject todebate, the COS results of each method canhave a dramatic impact on the resultant whole-sale rate structure for a G&T. The cost account-ing approach typically results in relatively highcapacity charges and low energy charges, whilethe cost causation approach results in moderatecapacity charges and higher energy charges. Theresultant rate structure can have a particularlydramatic impact on the recognized benefits ofdistributed generation. These impacts are dis-cussed in more detail in Section 3.

OVERVIEW OF WHOLESALE RATE STRUCTURESG&Ts have implemented a wide variety ofwholesale rate structures based on varying per-spectives on the COS analysis. These varying

wholesale rate structures include:

• Energy charges (kWh):� Flat rate� On-peak/off-peak rates� Seasonal rates� Special program rates� Fuel and/or purchased power

cost adjustments• Capacity charges (kW) based on:

� Annual peak� Seasonal peaks

� Flat rates� Differentiated rates

� Monthly peaks:� Flat rates� Differentiated rates

• Transmission charges based on:� Demand� Energy

• Ancillary service charges• Annual fixed charges• Substation charges

Energy ChargesWholesale energy rates take many forms. Mostoften, wholesale energy rates are stated as a sin-gle flat energy rate for all hours throughout theyear. However, in some instances, G&Ts haveimplemented energy rates that vary betweenspecified on-peak and off-peak hours and/orseasonally. In addition, many G&Ts have estab-lished special programs to encourage the devel-opment of specific end uses such as electricspace heating, electric water heating, and others.

Capacity ChargesEven more diverse are the approaches G&Tstake in pricing capacity to their member sys-tems. Some G&Ts have established capacitycharges based on member system contributionsto the G&T’s annual coincident peak.Depending on the geographical location of thecooperative and the predominant end usesserved by member distribution systems, thisannual peak could occur in either the summer

2 The method described is often referred to as the “equivalent peaker method.” Numerous other methods may be used to accomplish the same purpose of allocating fixed costs of production between capacity and energy components.

8 – Sect ion Two

or winter. In any event, the contribution to thesingle annual coincident peak establishes thedistribution cooperative’s capacity bill for theentire year.

Moving from the single peak approach, someG&Ts have established capacity billing based oneach member system’s contribution to seasonalpeaks. Most frequently, these seasonal peaks aredefined as the summer and winter coincidentpeaks. The resulting capacity charges may becalculated using the same rate per kW for boththe summer season and winter season or, alter-natively, a different rate may be established foreach season that reflects the difference in capac-ity value between the two seasons.

Finally, capacity charges may be based onmonthly peaks, either coincident with the G&Tor non-coincident. The resulting monthly capaci-ty rates may be a flat dollar amount applied to allmonthly billings or, alternatively, different ratesmay be established for each season. These sea-sonally differentiated monthly capacity chargesattempt to reflect the varying competitive marketcosts for capacity throughout the year.

Transmission ChargesMany G&Ts now establish separate rate chargesfor transmission service. Such transmission ratesmay be billed on an energy or a demand basis,although the Federal Energy Regulatory Com-mission (FERC) has established a standard ofusing coincident demand as the billing determi-nant. Demand billing for transmission servicecan further be based on either coincidentdemand responsibility associated with trans-mission service or non-coincident demand of the respective member systems.

Ancillary Service ChargesG&Ts are also responsible for providing ancil-lary services for their member systems asdefined by FERC:

• Scheduling system control and dispatch• Reactive supply and voltage control

from generation sources

• Regulation and frequency response• Energy imbalance3

• Operating reserve–spinning reserve service• Operating reserve–supplemental reserve non-

spinning reserves

Most G&Ts still recover the cost for providingancillary services through a bundled wholesalerate. When such costs are separately recovered,they may be recovered through either energy ordemand charges, although, like transmission,FERC has established a standard of using coinci-dent demand as the billing determinant.

Annual Fixed ChargesAnother rate form employed by some G&Ts isan annual fixed charge. Annual charges aresometimes applied as a uniform amount to allmember systems. In this form, the charges gen-erally seek to recover customer-related costsassociated with providing service to individualmember systems (e.g., customer accounting,billing, and metering).

The charges may also be used to recover thefixed costs of large base load units. For exam-ple, one G&T assigns the fixed charge based 1/3on annual peak demand, 1/3 on monthly peakdemand, and 1/3 on energy for a base period oftime. Used in this fashion, the fixed charge maybe designed to approximate the G&T’s estimatedstranded cost. This allows the G&T to price itscapacity and energy charges at prevailing com-petitive market prices.

Substation ChargesFinally, G&Ts may also own and provide substa-tion service to member distribution systems. Insuch cases, substation charges may be:

1. Determined on a system average basis andrecovered through a flat charge per substa-tion

2. Differentiated based on the capacity of thesubstation

3. Directly assigned based on the actual costs of the individual substation

2

3 FERC also recognizes energy imbalance as an ancillary service. However, since the G&T almost always provides scheduling forits member systems taking requirements service, this ancillary service has little meaning in terms of a G&T’s wholesale rate to itsmembers.


2Distribution cooperatives typically follow certainpractices in developing retail cost-of-servicestudies and rates. A retail rate study generallyinvolves the following procedures:

• Determine total revenue requirements.• Separate costs into functional categories.• Classify costs into components of the utility

service being provided.• Allocate costs to rate components or classes.

REVENUE REQUIREMENTSTo ensure financial viability, a cooperative’sretail rates must generate sufficient revenue tomeet operating expenses and margin require-ments. Margin requirements must in turn beadequate to cover interest expense and accom-plish other capital management objectives. Thetotal operating expense and margin require-ments are referred to as the “revenue require-ments” of the cooperative. Frequently, theseexpenses are adjusted for known and measur-able changes from a historical base. Whatevermethod is used, the objective is to ensure thatthe cost analysis reflects “typical” or “normal”operating conditions since the resulting ratesmust be adequate to meet these ongoing finan-cial requirements.

COST-OF-SERVICE ANALYSISFunctionalization of Revenue RequirementsOnce total revenue requirements are deter-mined, they are separated according to function.The typical functions used in an electric utilityCOS study are:

• Power supply (both production and purchased power)

• Transmission• Distribution

Generally speaking, for a distribution cooper-ative, the functionalization process is relativelystraightforward since the Uniform System ofAccounts may be relied upon to accurately statethe function that each cost category performs.For those more general accounts where thefunction may not be readily apparent (e.g.,

administrative and general expense), the func-tionalization process may be combined with theclassification process described in the next sub-section.

Classification of Revenue RequirementsThe next step is to separate the functionalizedrevenue requirements into classifications basedon the driving force behind each cost compo-nent. Such classifications include the followingcost causative categories:

• Direct. Costs that are directly attributable to one specific customer classification.Expenses associated with security lighting are an example of a direct expense.

• Consumer. Costs that are the result of thenumber and location of each customer thatdo not vary significantly with the demandimposed on the system or the amount ofenergy consumed. Metering and customeraccounting expenses perhaps best illustratethis type of expense.

• Capacity. Costs that result from providingand maintaining in readiness for operationfacilities required to meet the peak demand,whether it be the system peak, circuit peak,or individual customer service peak. Much ofthe expense of operating and maintaining adistribution three-phase backbone feederwould generally fall within this category, aswould the demand charge in a purchasedpower rate.

• Energy. Costs that are related to the amountof energy used. The major item in this cate-gory is the energy charge in a purchasedpower rate. A portion of other general costsis customarily assigned to this category aswell.

Allocation of Classified CostsAfter the cooperative’s revenue requirementshave been functionalized and classified, the nextstep is to allocate them among customer classes.To accomplish this, the customers served by thecooperative are separated into several groupsbased on the nature of service provided andload characteristics. Once the customer classes

Retail Rates

10 – Sect ion Two

to be used in the cost allocation study havebeen designated, the functionalized and classi-fied costs are allocated among the classes as follows4:

• Demand-Related Costs. Allocated among thecustomer classes on the basis of demands(kW) imposed on the system

• Energy-Related Costs. Allocated among thecustomer classes on the basis of energy(kWh) that the system must supply to servethe customers

• Customer-Related Costs. Allocated among thecustomer classes on the basis of the numberof customers or the weighted number of cus-tomers

The basic goal of the cost allocation processis to determine why the cooperative is incurringexpense in each category and then developingappropriate allocation factors to divide thesecosts among classes in a way that reflects eachclass’s responsibility for such cost causation.

Key IssuesLike G&T cost studies, distribution cost-of-ser-vice studies can employ different methodologi-cal approaches that can significantly alter thefinal results. Two areas of cost allocation in par-ticular can have dramatic impacts on distributioncost studies:

1. The approach to allocating distribution plant costs

2. The approach to allocating administrativeand general costs

Distribution Plant AllocationThree general approaches have been used toallocate distribution plant costs to various retailrate classes. The first approach assumes that theprimary function of distribution plant invest-ment, and related expenses, is to meet customercapacity requirements. This approach uses aclass demand allocation approach to spreadthese distribution plant costs and expenses torate classes.

A second approach directly assigns certaincosts (e.g., service transformers, services, meter-ing) to each customer class and separates single-phase and three-phase primary line for separateallocations. The effect is generally to reduce therevenue requirements assigned to the largepower or three-phase classes vis-à-vis theassignments that would result from a purecapacity allocation.

A third approach assumes that distributionplant investments are made not only to meetcapacity requirements, but also are necessary tosimply connect each customer to the distributionsystem. Accordingly, a portion of distributionplant costs is allocated to classes as a consumercost. Two calculation methods are commonlyused to determine this consumer cost compo-nent of distribution plant investment andexpenses5:

1. Minimum system method2. Zero-intercept method

While these approaches are technically differ-ent, each method seeks to identify the portion ofdistribution plant investment and expenses thatis made to simply connect the customer to thedistribution system. The balance of distributionplant investment and expenses is then allocatedto classes through use of a demand allocator.

The difference in results from these approach-es can be dramatic. For example, cost studies forelectric cooperatives that allocate distributionplant investment and expenses based ondemand only often result in an identification ofresidential consumer costs of about $6 to $8 permonth. This method also tends to assign morecost to the large power classes and less to theresidential classes. In contrast, cost studies forelectric cooperatives that allocate distributionplant investment and expenses using a combina-tion of consumer and demand allocators oftenresult in an identification of residential consumercost ranging from $20 to $30 per month. Thismethod also tends to assign more costs to theresidential classes and less to the large powerclasses.

2

4 National Association of Regulatory Utility Commissioners, Electric Utility Cost Allocation Manual, January 1992.5 National Association of Regulatory Utility Commissioners, Electric Utility Cost Allocation Manual, January 1992.


2Beyond the impact on consumer costs, these

methods can also result in significant differencesin identification of cost responsibility among rateclasses. Again, the results can have dramaticimpacts on resulting class rate design. For exam-ple, higher consumer costs and lower capacitycosts can lead to rate designs that provide lessincentive to distributed generation compared torate designs that have lower consumer costs andhigher demand costs.

Administrative and General Expense AllocationAnother area that must be addressed in distribu-tion cost studies is the treatment of administra-tive and general (A&G) expenses. A&G expens-es are common costs for which there exists noobvious relationship to functional categories.Thus, it is necessary to allocate these costsbased on a relationship to other expenses. Twocommon approaches are used in this regard:

1. Allocate distribution A&G expenses in proportion to all other expenses, includingpurchased power.

2. Allocate A&G expenses in proportion tolabor expense or, as a proxy, expenses only.

The first method tends to assign more costs tothe large power classes and less to the residen-tial class because purchased power makes up amuch greater part of the total cost allocated tothe large power classes. The second methodtends to assign more A&G expenses to residen-tial classes and less to the large power classesvis-à-vis the first method.

RETAIL RATE DESIGNOnce a COS study is completed, it is then possi-ble for a cooperative to develop appropriateretail rates based on the results. Many legitimateobjectives influence the design of retail rates.Some of the more important ones are as follows:

1. The proposed rates must develop the requisite total revenue.

2. The proposed rates should reflect the cost of providing service. No class or subclassshould subsidize or be subsidized by another.

3. The rate schedules should be simple andconcise to facilitate consumer acceptanceand administration.

4. Abrupt departures from historical rate prac-tices and levels should be avoided.

5. The rate structure should be acceptable tothe membership.

6. Where there is a possibility of a consumerbeing eligible to receive service under morethan one rate schedule, the transition shouldbe made as smoothly as possible.

7. The rates should promote the efficient useof energy and system capacity.

8. Whenever possible, the rate schedulesshould be competitive with those of neigh-boring utilities and alternative energysources.

It is generally not possible to fully accomplishall the above objectives in developing rate sched-ules. Compromises based on judgment reflectingthe policy of the cooperative must be made.

OVERVIEW OF RETAIL RATE STRUCTURESDistribution retail rate structures typically havethe following basic components:

• Monthly charge• Energy charge• Demand charge

Monthly ChargesThe monthly charge (often referred to as a basic,fixed, or customer charge) is typically designedto recover monthly costs associated with meter-ing, billing, and customer accounting. Thischarge may also include a portion, or all, of theconsumer component of distribution plant costsidentified through a cost-of-service study.

Energy ChargesMany forms of energy charges are in commonuse. Probably the most common form of energycharge is a flat charge per kWh that is applied toall kilowatt-hours throughout the year. Retailenergy charges can also take the form of on-peak and off-peak rates during specified hoursand days. Another variation is to differentiatethe energy charge seasonally. That is, one ener-

12 – Sect ion Two

2gy charge may be used during the summer sea-son while another rate applies during the othermonths of the year. Finally, energy charges mayhave different steps or blocked components.These charges may specify one rate for initialenergy consumption with different rates definedfor succeeding levels of consumption.

Demand ChargesDemand charges also exhibit variability at theretail level. Like energy charges, the most com-mon demand charge is a flat charge per kW for

all monthly non-coincident demand. Thesedemand charges can also vary by season, withone rate applicable in the summer and anotherduring winter months. Finally, demand chargescan also be imposed for a customer’s contribu-tion to coincident demand at the time of thepower supplier’s peak. These coincidentdemand charges, often used in combinationwith non-coincident demand charges, allow adistribution utility to differentiate rates as theyrelate to wholesale power costs versus distribu-tion capacity costs.

Introduction Numerous issues must be addressed in settingpolicies, rates, and procedures for dealing withdistributed generation. Before addressing theseissues, it is important to define what is meant by“distributed generation.” As noted in Section 1,some definitions limit distributed generation tosmall-scale, environmentally friendly technolo-gies such as photovoltaics, fuel cells, micro-tur-bines, small wind turbines, etc. Other definitionsare more expansive and would include any gen-eration located near a load center, regardless ofsize or energy source. As used in this manual,distributed generation refers to the generation ofelectricity by facilities sufficiently smaller thancentral generating plants as to allow intercon-nection at nearly any point in an electric powersystem, which is the definition adopted by theInstitute of Electrical and Electronics Engineers(IEEE).

There are many similarities between individ-ual distributed generation applications, but thereare also many differences. For example, thereare many different types of generating units andfuels used in distributed generation applications.Among the more common are:

• Combustion turbines (natural gas, diesel, oil)• Internal combustion reciprocating engines

(gasoline, diesel, propane)• Micro-turbine (natural gas, propane)

• Fuel cell (natural gas, propane)• Photovoltaic (solar)• Wind turbine (wind)

Distributed generation may be used in a number of different ways:

• Standby or backup• Peak shaving• Base load

Distributed generation may be used to supply:

• Power and energy for the owner’s own use:� Partial requirements� All requirements

• Power and energy for another retail customer’s use

• Power and energy for the wholesale market• Power quality or high reliability for a

customer or group of customers• Reactive power and other ancillary services

Ownership may also vary from:

• Utility owned• Retail customer owned• Alternative energy supplier (AES) or

independent power producer (IPP) owned• Other

Dis t r ibuted Generat ion I ssues – 13

Distributed Generation Issues

In This Section: Introduction; requirements contracts; impact on system requirements and utilitycosts; stranded cost and cost shifting; interconnection requirements; environmental issues

3

Requirements Contracts

14 – Sect ion Three

3This section identifies and discusses a number

of issues related to distributed generation:

• Requirements contracts• Impact on system requirements and

utility costs:� Generation costs� Ancillary service costs� Transmission costs� Distribution costs

• Stranded cost and cost shifting• Interconnection requirements• Environmental impact

Many of these issues are a function of thetype of generating unit, fuel source, mode ofoperation, and/or ownership of the unit. Forexample, as discussed later, the value of distrib-uted generation in reducing peak energy costsmay be dependent on the location and time ofoperation of the unit as well as the mode ofoperation. The discussion will identify whereand how the characteristics of a specific distrib-uted generation application enter into the con-sideration of each issue.

HISTORICAL RELATIONSHIP BETWEEN G&TSAND MEMBER SYSTEMSHistorically, power supply arrangementsbetween G&Ts and their member distributioncooperatives (i.e., member systems) have beengoverned by wholesale power agreements, gen-erally structured as “requirements” contracts. A“requirements” arrangement simply means thatthe G&T is responsible for supplying all thepower and energy that a distribution cooperativemember requires, and a distribution cooperativemember is required to purchase all its requiredpower and energy from the G&T. When thearrangement covers the entire load requirementsof the distribution cooperative member, the con-tracts are referred to as “all-requirements.” Onthe other hand, when the arrangements coverthe distribution cooperative’s supplementalrequirements over and above a certain baseamount, for example, the amount supplied by anallocation of power and energy from a PowerMarketing Agency (PMA) such as the WesternArea Power Administration (WAPA), the contractsare referred to as either “supplemental require-ments” or “partial requirements.”6 In either situa-tion, requirements contracts usually do not per-mit the distribution cooperative to either:

1. Purchase power and energy from anotherprovider, including the owner of distributedgeneration.

2. Install generation facilities to supply a por-tion of the distribution cooperative’s load.

Examples of typical language expressing arequirements arrangement are as follows:

• All Requirements. XYZ (G&T) shall sell anddeliver to the Member, and the Member shallpurchase and receive from XYZ, upon theterms and conditions of this Agreement, allelectric power and energy that the Membershall require for the operation of theMember’s system.

• Partial Requirements. XYZ (G&T) shall selland deliver to the Member, and the Membershall purchase and receive from XYZ, uponthe terms and conditions of this Agreement,all electric power and energy that the Membershall require for the operation of the Mem-ber’s system over and above the power andenergy supplied by the Member’s allocationfrom ABC (other source).

If such contractual obligations exist, the distri-bution cooperative may be prevented from own-ing and operating distributed generation to serveany part of its own native load.7 It may also beprohibited from purchasing the output of distrib-uted generation owned by a third party, includ-ing a retail member/consumer of the distributioncooperative. The only exceptions are for gener-

6 Occasionally, these “supplemental requirements” or “partial requirements” contracts are also referred to as “all-requirements”contracts.

7 The conclusions in this paragraph may not apply to each and every “requirements” type contract, and legal opinion based on thespecific language in the contract should be sought if this becomes an issue.


3ating units that qualify under the Public UtilitiesRegulatory Policy Act (PURPA) of 1978, referredto as qualifying facilities (QFs). In suchinstances, the distribution cooperative may beobligated to purchase whatever output a QFmakes available to it at the distribution coopera-tive’s avoided cost.8 However, with the distribu-tion cooperative’s consent, this obligation maybe transferred to the G&T.9

VARIATIONS TO HISTORICAL APPROACHWhile it is still not common, some G&Ts haverelaxed the “all-requirements” contractual obliga-tion to permit member systems to supply a por-tion of their total power and energy require-ments from other sources. For example, GreatRiver Energy (GRE) permits its members to sup-ply up to 5% of their GRE requirements (i.e.,either total requirements or supplemental

requirements) from non-GRE sources. GRE alsopermits member systems to fix their obligationto purchase power and energy from GRE at aspecified level and, thereafter, assume responsi-bility for supplying any load growth beyond thatlevel from other non-GRE sources. WabashValley Power Association, Oglethorpe PowerCorporation, and Minnkota Power Cooperativeare other examples of G&Ts that permit theirmember systems to supply a portion of theirload from other sources.

These more relaxed power supply agree-ments provide greater flexibility to the distribu-tion cooperative in terms of developing distrib-uted generation because they open up the pos-sibility that the distribution cooperative can owndistributed generation and/or purchase the out-put of such generation from a third party.

Impact on System Requirements and Utility Costs

OVERVIEWDistributed generation has the potential ofreducing the cooperative’s overall cost of operation by:

• Displacing the production of energy• Delaying or eliminating the need for new

generating capacity• Reducing or eliminating the need for

purchased power and energy• Supplying some ancillary services that would

otherwise have to be supplied from the cooperative’s own resources or purchased

• Delaying, modifying, or even, in someinstances, eliminating the need for transmission and distribution improvements

The extent to which a G&T and/or distribu-tion cooperative can utilize the output of distrib-uted generation to accomplish these objectivesis often case specific, dependent upon the char-acteristics of the G&T and distribution coopera-tive as well as the characteristics of the distrib-uted generation.

Distributed generation also has the potentialof increasing a cooperative’s overall cost ofoperation by:

• Hurting the cooperative’s system load profile• Increasing load volatility• Requiring upgrades to the distribution system

or even to other customers’ electrical equip-ment (e.g., changing fault currents mayrequire upgrade in breakers of other customers)

• Requiring system studies for interconnectionsafety inspections, maintenance, etc.

In identifying the impact of distributed gener-ation on the cooperative’s cost, the concept of“avoided cost” is useful, keeping in mind thatsuch costs can be positive or negative. Avoidedcost is defined by FERC in Order 69 implement-ing PURPA as follows:

“ ‘Avoided costs’ means the incrementalcost to an electric utility of electric energyor capacity or both which, but for the pur-

8 Some G&Ts have successfully argued that the distribution cooperative’s avoided cost should be considered the same as theG&T’s avoided cost since any revenue shortfall experienced by the G&T will inevitably flow back through the base wholesale rate.

9 While there is some case law in this regard, there is still some disagreement within the industry and, perhaps, within the coop-erative family as to how PURPA requirements should be interpreted.


chase from the qualifying facility or quali-fying facilities, such utility would generateitself or purchase from another source.”

18 C.F.R. § 292.101(b)(6)

Since this definition is focused on facilitiesthat qualify under PURPA and also on the pro-duction side of the business, a slightly modifiedversion of the definition is more useful whenaddressing the avoided costs associated with dis-tributed generation:

“‘Avoided costs’ means theincremental cost to the elec-tric utility of electric energyor capacity in generation,transmission, or distributionfacilities and/or serviceswhich, but for the distrib-uted generation, such utilitywould generate or installitself or purchase fromanother source.”

In other words, the avoidedcost associated with distributedgeneration represents the cost that a utilitywould incur but for the existence of the distrib-uted generation. While the general concept ofavoided cost is relatively simple, applying thedefinition to specific circumstances is not.Considerable debate may take place in deter-mining the avoided costs in a specific applica-tion. Nevertheless, the focus of the debate isclear and should be on the “incremental” impact of the distributed generation for better or for worse on a cooperative’s system andcosts.

This, of course, differs from the way tradition-al wholesale and retail rates for cooperatives aretypically designed. Generally speaking, whole-sale and retail rates, particularly for coopera-tives, are designed around average embeddedcosts, not incremental or avoided costs. Even inthose instances where marginal costing princi-ples are applied, the application is usually limit-ed to one or two components of the rate struc-ture since applying marginal costing principlesto the entire rate structure will inevitably resultin a mismatch between the cooperative’s rev-

enue and revenue requirements. For example, ifthe energy charge is priced incrementally, thedemand charge will need to be modified tocompensate so that the total revenue producedby application of the rates to billing determi-nants will equal the revenue requirements of thecooperative. Some G&Ts have resorted to afixed cost rate component in an attempt to dealwith this problem. In such cases, the demandand energy components are designed to approx-imate the G&T’s marginal costs and/or market

prices, with the fixed chargecomponent used to cover anyshortfall in revenue.

The point is that, withoutadjustment, the standardwholesale and/or retail ratesare not likely to accuratelyreflect a cooperative’s avoidedcost resulting from the instal-lation of distributed genera-tion. Special rates and/orcredits are necessary to pro-vide accurate price signals.

At the same time, it isimportant to emphasize that,

except in instances where required by law orregulatory rules (e.g., QFs under PURPA), thecooperative is not obligated to provide credits orpayments to the owners of distributed genera-tion equal to the cooperative’s full avoided cost.Credits, payments, and/or rates may be estab-lished system-wide or negotiated with individualowners, depending on the circumstances, andthe prices may consider factors other thanavoided costs so that the cooperative and othercustomers on the distribution system may gainsome value from the distributed generation.Nevertheless, it is important to identify as accu-rately as possible the cost that is avoided as aresult of the distributed generation since thisshould generally represent the ceiling of anycredit or payment made to the owner of suchgeneration.

IMPACT ON GENERATION COSTSThe avoided generation cost has two compo-nents: energy and capacity. The avoided energycost component is the easier of the two to estab-lish. By definition, the avoided energy cost is the

3

Without adjustment,standard wholesaleand/or retail rates arenot likely to accuratelyreflect a cooperative’scost resulting fromdistributed generation


3cost of energy that the cooperative would havebeen required to produce or procure but for theenergy output of the distributed generation.Thus, the most straightforward valuation of theenergy produced by a distributed generationunit would start with the cooperative’s incre-mental cost of production, calculated on anhourly basis and adjusted for losses.10 As analternative, the avoided energy cost value couldreflect the market value of energy since theenergy produced by these units may be consid-ered to either:

1. Reduce the amount of energy that must bepurchased by the cooperative

2. Increase the amount of energy that thecooperative has available for sale

Again, the determination should be made hourby hour, with an adjustment for losses. Depend-ing on the circumstances, it may be possible tosimplify matters with minimal loss of accuracyby establishing an average avoided energy costvalue in lieu of an hour-by-hour value. How-ever, the current market tendency toward wildlyfluctuating energy prices makes it very difficultin most instances to establish a single averageprice that accurately represents the value of theenergy output of a distributed generation unit.In some instances, seasonal and/or time-of-dayrates may represent a reasonable compromisebetween accuracy and simplicity.

Determining the avoided capacity cost valueassociated with distributed generation is morecomplex. The avoided capacity cost value alsohas two components: the amount of capacity adistributed generating unit reliably provides interms of kilowatts (kW) and the per unit valueof that capacity in terms of $/kW/month or$/kW/year. The amount of capacity that a givendistributed generating unit allows a cooperative

to avoid depends on the reliability and availabil-ity of the generating unit when the cooperativeneeds it, as well as on the nameplate capacity ofthe unit. If it is possible to accredit a distributedgenerating unit in the same manner that the util-ity’s own generating units are accredited in apower pooling or similar arrangement, then theavoided capacity value of the unit is equal to theaccredited capacity.11

The avoided capacity value of distributedgeneration that cannot be accredited is more dif-ficult to determine. It is a function of the modeof operation (e.g., base load, peaking), the avail-ability of the output at the time of the coopera-tive’s need for the capacity (e.g., “dispatchabili-ty”), and the type of generating unit (e.g., com-bustion turbine, diesel, wind, solar). If the dis-tributed generating unit is operated as a baseload unit (i.e., generally available and on line atall times except when down for maintenance12

and during an emergency), the capacity value isequal to the maximum dependable capacity ofthe unit. (This may or may not be equal to thenameplate value of the unit.) The same mayhold true for a distributed generating unit oper-ating in a peaking mode, provided that the unitis dispatchable in some manner so that it isavailable when needed by the cooperative.Generating units that are not dispatchable havelimited capacity value, although there may besome value if there is a sufficiently large numberof the generating units and the characteristics ofsuch units are such that there is a reasonabledegree of assurance that some predictableamount of capacity will be available when need-ed by the cooperative. For example, it is con-ceivable that a group of wind generators or pho-tovoltaic generators could provide some capaci-ty value to the cooperative even though thecapacity value would need to be severely dis-counted from the nameplate ratings to reflect

10 Because distributed generation is, as a general rule, located closer to the load than the cooperative’s central station generationfacilities, a credit adjustment for reduced losses is appropriate.

11 While there may be a theoretical basis for arguing for an adjustment for losses to the capacity value of distributed generation,most pools would not recognize this adjustment in determining the accredited capacity value of a generating unit.

12 Of course, this presumes that maintenance is not scheduled during the time of the cooperative’s peak demand, however that isdetermined by the cooperative’s wholesale supply contract. That can best be ensured by providing under contract that thecooperative can schedule or actually perform required maintenance.


the low availability that would most likely beassociated with such units.

Once the capacity value of a distributed generation unit is determined,the per unit value in terms of$/kW/month or $/kW/yearmust be established. Therewould appear to be severalrational ways of establishingthe per unit value. For distribu-tion cooperatives, simplestwould be to look at the capaci-ty charge the cooperative isresponsible for under itswholesale power contract. Most distributioncooperatives’ all-requirements contracts willhave a stated capacity charge. If the distributedgeneration is operating at the time the capacitycharge is set, its output at that time determinesits value to the distribution cooperative. A dis-tributed generation unit installed shortly afterthe coincident peak may have zero capacityvalue to the cooperative for a full year, until thenext peak is hit. Also, some all-requirementscontracts will have a demand ratchet: the capaci-ty charge under these contracts may not reflectthe full amount of the reduced peak demand fora stated period of time. Again, the capacityvalue of a distributed generation unit will bereduced by a provision.

For a G&T, if it obtains all its supply underwholesale contracts, the calculation may be thesame. More likely, it will be necessary to useanother approach. First, one could look to themarketplace.13 In such instances, the value ofdistributed generation capacity to a utility maybe considered to be either:

1. The cost that the utility would avoid byvirtue of not having to purchase capacity inthe market, or

2. The additional revenue that the utility wouldrealize by having additional capacity to sellin the market

An alternative approach to pricing capacity isto reflect the annual/monthly cost of installingpeaking generation. The argument for this

approach is that it representsan alternative to purchasingcapacity from distributed gen-eration.

While it is customary toapproach this on an averageinstalled cost basis, it can alsobe viewed on an incrementalcost basis (e.g., the differencein the installed cost of a 100 MW versus a 75 MW

combustion turbine, divided by 25 MW).As indicated by the discussion above, the

determination of the avoided generation costattributable to distributed generation is not easi-ly reduced to “one size fits all.” Each G&Tand/or distribution cooperative must determinethe avoided generation cost value for itself, rec-ognizing the mode of operation and availabilityand reliability characteristics of different types ofgeneration units, as well as the cooperative’sown cost characteristics and philosophy.

IMPACT ON ANCILLARY SERVICE COSTDistributed generation may also allow a cooper-ative to avoid certain ancillary service costs.FERC defines ancillary services as the following:

1. Scheduling, System Control, and DispatchService

2. Reactive Supply and Voltage Control fromGeneration Sources Service

3. Regulation and Frequency Response Service4. Energy Imbalance Service5. Operating Reserve–Spinning Reserve Service6. Operating Reserve–Supplemental Reserve

Service

Of these six ancillary services, distributedgeneration may potentially be used to supplythe following:

3

13 In some regions, separate markets have been established for capacity and energy, while in other markets capacity and energyare treated as a combined entity. When the capacity and energy markets are combined, it is important that the capacity com-ponent in the credit and/or payment provided to owners of distributed generation not be doubled up (i.e., included once in thepayment for energy and also in a separate capacity payment).

Capacity value is equal to the maximumdependable capacityof the unit


3• Reactive Supply and Voltage Control from

Generation Sources Service• Operating Reserve–Spinning Reserve Service• Operating Reserve–Supplemental Reserve

Service

To supply reactive power (VARs) and voltagecontrol from generation sources, the distributedgenerating unit must be on line and capable ofsupplying VARs to the system most of the time.As a general rule, this means that the distributedgenerating unit must be operated in a base loadmode. Likewise, when a distributed generatingunit is considered to be supplying spinningoperating reserves, the unit must be on linemost of the time with the ability to increase out-put when called upon in accordance with thecontrol area rules. This ancillary service alsorequires a unit that generally operates in a baseload mode. Operating reserves–supplemental,on the other hand, may be supplied by a distrib-uted generating unit that operates in a peakingmode, provided it meets the requirements of thelocal control area operator and/or regional pool-ing authority. Typically, the requirements willinclude the need for dispatchability and the abil-ity to come on line and up to full load withinsome specified period (e.g., 10 minutes).

When the distributed generating units qualifyto provide reactive power support on the distri-bution system, the avoided cost value to thecooperative depends on the cost of the availablealternative approaches to providing the requiredsystem support. For example, the benchmarkcost for reactive power support may be estab-lished at the cooperative’s cost of installingcapacitor banks. When the distributed generat-ing units qualify to provide reserves or to pro-vide reactive power on the transmission system,the avoided cost value to the cooperative maybe considered to be equal to the appropriateancillary service rates as stated in the coopera-tive’s Open Access Transmission Tariff (OATT).However, it is important that this not be doubledup with the capacity value already determined.For example, if a capacity credit has alreadybeen given for the full capacity of the distrib-uted generating unit, a credit should not also begiven for the operating reserves value of theunit.

IMPACT ON TRANSMISSION COSTSA utility’s avoided transmission costs associatedwith distributed generation may be determinedin two ways. First, one can consider the value ofspecific avoided transmission facilities. Such adetermination is obviously case specific andmust recognize the characteristics of the existingtransmission system, as well as the location,capacity, and characteristics of the distributedgeneration. The analysis may be complicated bythe fact that the times that the distributed gener-ation is needed to operate in order to supportthe transmission system may not coincide withthe times it is needed for generation. This is nota major problem for base load distributed gener-ation or dispatchable distributed generation withunlimited availability, but it could be a problemfor other, less flexible forms of distributed gen-eration. Another complication is the fact thattransmission additions and upgrades are bynature installed in discrete increments.Furthermore, a single distributed generating unit is seldom sufficient in and of itself to deferor possibly eliminate the need for a transmissionimprovement, and it may be necessary to installa number of units in or about a specific locationto accomplish the intended purpose. Finally,establishing the avoided transmission cost onthe basis of deferred or avoided facilitiesrequires a case-by-case determination. Thismakes it very difficult to establish any credit orpayment schedule that would apply across theboard.

A second approach is to base the avoidedtransmission cost on the average cost of the sys-tem or network as expressed in the utility’s aver-age transmission rate. In times past, the accuracyof this approach would have been subject toquestion since each utility’s costs were basedlargely on its own system. However, the adventof joint transmission systems, multi-utility net-works, independent system operators (ISOs),and regional transmission organizations (RTOs)may make the average system cost approach themost accurate for the future. As transmissioncosts are blended across a region, the utility’savoided cost due to distributed generation willbe, in many instances, determined on the basisof the regional transmission charges that the util-ity can avoid. Since these transmission charges


3will be a function of the utility’s contribution tothe monthly coincident demand of the regionalnetwork, the output of the distributed genera-tion unit at the time of the monthly coincidentpeak of the regional network will be the majordeterminant.14

In this regard, it is important to understandFERC’s views on the treatment of distributedgeneration vis-à-vis network transmission andancillary service charges. While few G&Tspresently fall under FERC’s jurisdiction relativeto setting rates and policies for their membersystems,15 many G&Ts do participate in networktransmission systems either through pooling,purchased power, or other arrangements, andthese network systems generally are subject toFERC jurisdiction. If nothing else, a G&T inter-connected to a FERC jurisdictional transmissionutility’s system and wishing to obtain transmis-sion services from that utility is usually subjectto certain reciprocity provisions in that utility’sOATT that require service under terms and con-ditions similar to the OATT.

“6 ReciprocityA Transmission Customer receiving trans-mission service under this Tariff agrees toprovide comparable transmission servicethat it is capable of providing to theTransmission Provider on similar termsand conditions over facilities used for thetransmission of electric energy owned,controlled or operated by the Transmis-sion Customer and over facilities used forthe transmission of electric energy owned,controlled or operated by the Transmis-sion Customer’s corporate affiliates.”

18 C.F.R. §§ 35 and 385, FERC Pro Forma OATT

In such instances, the G&T’s transmissioncosts are directly or indirectly impacted byFERC’s policies on pricing transmission andancillary services.

Furthermore, in accordance with the authoritygranted FERC in the 1992 Energy Policy Act (19ct), there is risk that a G&T might be subject tocompliance with Section 211 procedures shouldit attempt to offer special treatment and dis-counts to member systems that are not availableto other users. Finally, some of the restructuringlegislation being proposed on the federal levelseeks to bring all transmission facilities, includ-ing facilities owned by cooperatives, underFERC’s jurisdiction. For all the above reasons,G&T transmission and ancillary service ratesapplicable to member systems should reflectFERC’s policies to whatever extent practicable,and when a G&T chooses to deviate from FERCpolicies it should do so only after careful consid-eration of justifications for doing so.

The specific FERC policies that relate to trans-mission services associated with distributed gen-eration are generally referred to as FERC’s“behind-the-meter” and “inside-the-fence” gener-ation policies. Under FERC’s Pro Forma OATT,which all jurisdictional utilities must adhere to, awholesale transmission customer must decidewhether it wishes to take point-to-point or net-work transmission service.16

FERC describes point-to-point and networktransmission service as follows:

“Point-to-Point Transmission Service:“The reservation and transmission ofcapacity and energy on either a firm ornon-firm basis from the Point(s) of Receiptto the Point(s) of Delivery under Part II ofthe Tariff.”

14 Technically, the FERC standard approach to establishing each customer’s transmission charges is to multiply the monthly rev-enue requirements of the transmission system by a rolling load ratio that is based on the current monthly coincident demandplus the previous 11 monthly coincident demands of the customer divided by the current monthly coincident demand plus theprevious 11 months of coincident demand of the transmission system.

15 Wolverine Power Supply Cooperative and Deseret Generation and Transmission Cooperative, Inc. are two examples of G&Tcooperatives that do come under FERC jurisdiction.

16 While a customer may take point-to-point transmission service at one delivery point and network transmission service at anoth-er delivery point, it may not split the type of service taken at any single delivery point (i.e., into a portion served under point-to-point transmission service and a portion served under network transmission service).


“Network Transmission Service:“Transmission Provider will provide firmtransmission service over its TransmissionSystem to the Network Customer for thedelivery of capacity and energy from itsdesignated Network Resources to serviceits Network Loads on a basis that is com-parable to the Transmission Provider’s useof the Transmission System to reliablyserve its Native Load Customers.”

18 C.F.R. § 35, FERC Pro Forma OATT

Under point-to-point transmission service, theamount of capacity used to determine the trans-mission and ancillary service charges is basedon a specified contract amount, independent ofwhat actually flows over the transmission systemto the delivery point. Under network transmis-sion service, each network transmission cus-tomer is allocated a share of the transmissionowner’s monthly revenue requirements, usingan allocation factor based on a rolling 12-monthload ratio. The load ratio is defined as the cus-tomer’s demand at the time of the monthly coin-cident peak on the transmission system dividedby the monthly coincident transmission systempeak. In this calculation, the wholesale cus-tomer’s total load connected to the network isincluded, even though some of that load may beserved by “behind-the-meter” generation. Inother words, generation located on the load sideof the delivery point meter is added back intothe delivery point meter reading to obtain thetotal coincident demand of the customer used todetermine the customer’s load ratio. FERC’srationale for taking this approach is that thetransmission provider must provide sufficient

capacity to cover an outage of the “behind-the-meter” generation, and, thus, the customershould pay for transmission services on the basisof its total load, not just the net load that flowsthrough the meter.17 Even though this policysometimes leads to absurd results,18 FERC hasmade it clear that the “behind-the-meter” policyis here to stay.

It is important to note that FERC’s “behind-the-meter” generation policy does not, at thepresent time, extend to generation owned byretail customers. Load served by retail customer-owned generation, often referred to as “inside-the-fence” generation, is not added back to theload metered at the delivery point to determinethe wholesale customer’s load ratio share forpurposes of allocating network transmission andancillary services revenue requirements.

Hypothetical CasesThe following hypothetical cases summarized inthe table on page 22 illustrate these principles.

Case A represents the simple, normal casewithout any additional generation on the loadside of the distribution delivery point. In thiscase, the wholesale supplier supplies the totalwholesale customer load of 10,000 kW. Undertraditional ratemaking philosophy, the wholesalesupplier would bill the wholesale customer for10,000 kW of transmission and ancillary servicecharges.19

Case B represents the situation where thewholesale customer owns generation located onthe load side of the meter that reduces the coin-cident load metered at the delivery point. In theexample, the distributed generation serves toreduce the monthly peak by 2,000 kW so thatthe wholesale supplier supplies 8,000 kW of the

3

17 Reference Order 888.18 For example, if a municipal has a total load of 100 MW, of which 90 MW is supplied from its own internal generation and

10 MW from outside sources using network transmission (e.g., a system power purchase), it will be assessed transmissioncharges equal to 100 MW, even though one might argue that the municipal needs only 10 MW of transmission capacity. In thissimple example, the municipal might be able to avoid this excessive transmission charge by purchasing out of a specific gener-ating unit rather than out of its supplier’s generating system. However, if the municipal does purchase system power, it mustpurchase network transmission and ancillary service, not point-to-point. Because most distribution cooperative member sys-tems purchase their power and energy requirements out of the G&T’s system rather than out of specific designated generatingunits, the transmission service provided by the G&T is clearly network, not point-to-point. Point-to-point service over the G&T’ssystem is simply not an option for the member systems under FERC’s current policies.

19 This is true whether the wholesale supplier’s rate is bundled or unbundled.


10,000 kW.20 Under FERC’s “behind-the-meter”generation policy, the wholesale customer’s loadfor purposes of the load ratio calculation isbased on the delivery point meter reading plusthe output of the generating unit at the time ofthe transmission system peak (i.e., 10,000 kW).Again, FERC’s rationale for this policy is that thetransmission system may be called upon at sometime to supply the full 10,000 kW when the gen-erator is down.

Case C is identical to Case B, except for theownership of the generation. In this case, sincea retail customer owns the generation, FERCdoes not require the 2,000 kW to be added backinto the delivery point meter reading. Thus, thewholesale customer is assessed transmission andancillary service charges based on 8,000 kW ofload. This, of course, assumes that the generatoris actually operating at a level of 2,000 kW at thetime of the network transmission system peak.

It is important to emphasize that it is FERC’spolicy to assess transmission and ancillary ser-vice charges based on the actual meter reading,not the meter reading adjusted for an artificialcredit based on the capacity of the generatingunit. A retail customer-owned generator pro-vides tangible transmission and ancillary servicesbenefits to the transmission service provideronly to the extent that it operates to reducemetered load during the transmission systempeak. Thus, a policy to provide credits to themember system based on a retail consumer’sgenerating capacity rating, rather than on thecoincident output, deviates from FERC policyand would not accurately reflect the impact ofthe generator on the cooperative’s costs.

Case D represents the situation where the

load served by the generating unit (whetherowned by the wholesale customer or by a retailcustomer) is separated physically from the restof the system. In this situation, because theentire load of the wholesale customer is sup-plied over the transmission system, the whole-sale customer is inherently billed for the fullload as metered at the delivery point in theexample, 10,000 kW.

In summary, the following FERC policiesshould be carefully considered by a G&T as itestablishes its policy regarding transmissioncharges relative to distributed generation:

• Distributed generation owned by a membersystem on the load side of the delivery pointmeter may not be used to reduce the demandused to bill for transmission and ancillary ser-vices. Any load supplied by such generationduring the period used to establish the deliverypoint billing demand must be added back tothe actual metered load so that the billingdemand reflects the demand that would havebeen recorded had the generator not operated.

• Distributed generation owned by a retail cus-tomer of the member system on the load sideof the delivery point meter may be used toreduce the transmission and ancillary servicesbilling demand to the extent that it servesload at the time the billing demand is estab-lished. Thus, the load actually metered at thedelivery point that the transmission billingdemand is established becomes the billingdemand of the delivery point. Credits basedon the capacity of the generating unit and noton its actual output at the time of the peakare not permitted.

3Case Ownership of

DistributedGeneration

Total WholesaleCustomer

Load

Supplied byDistributedGeneration

Supplied byWholesaleSupplier

TransmissionCharges Based on

(kW) (kW) (kW) (kW)

A None 10,000 -0- 10,000 10,000

B Wholesale Customer 10,000 2,000 8,000 10,000

C Retail Customer 10,000 2,000 8,000 8,000

D Off System 10,000 2,000 8,000 10,000

20 It is important to note that the determinant here is the output of the generator at the time of the system peak, not the genera-tor’s nameplate or tested capacity.


• Billing demand for transmission services isbased on a rolling 12 coincident peak loadratio, with the coincident peak demand beingdefined as the load coincident with the peakdemand of the transmission system.

While a non-FERC jurisdictional G&T maywish to deviate from strict adherence to FERCpolicies, it should do so fully aware of possibleconsequences.21 At the least, the G&T may beforced to offer the same treatment to non-mem-ber system users of its transmission system.

IMPACT ON DISTRIBUTION COSTSThe avoided distribution cost associated withdistributed generation is even more case specif-ic. Here the location of the generating unit, thecapacity of the unit, and the capacity require-ments of the distribution circuit where the gen-eration unit is located are of critical importance.In many instances, distributed generation willnot enable the cooperative to avoid distributioncosts, and, in some instances (e.g., when thedistributed generation capacity is large withrespect to the capacity of the load in the areaand/or the capacity of the distribution system),installation of a distributed generating unit mayactually increase the cooperative’s cost. For dis-tributed generation to allow the cooperative toavoid distribution system cost, the followingmust occur:

1. There must be an imminent need forupgrading the distribution system.

2. Load must not be growing too fast or theplanned capacity of the distributed genera-tion could be overwhelmed.

3. The distributed generation must be locatedsuch that it can be used to serve load in amanner that will reduce or eliminate theneed for distribution system improvements.

4. The distributed generation must be on lineat all times or, at the very least, dispatchableby the distribution cooperative so that it canbe used to reduce the load on the distribu-tion facilities at the time of the distributionsystem peak.

Accomplishing these four objectives requiresclose coordination between the owner of thedistributed generation and the distribution coop-erative. However, it is most readily accom-plished if the distribution cooperative is in aposition to take a proactive lead in the planning,installation, and operation of the distributedgeneration.

Some proponents of distributed generationhave argued that the generation should be cred-ited with the average distribution cost asexpressed in the distribution utility’s retail rate.While this is certainly a simple and easily admin-istered approach to establishing a distributioncredit, except in very rare instances, this willeither over- or understate the value of distrib-uted generation. Furthermore, unless the creditis based on the actual value of distributed gener-ation in reduced distribution system require-ments, there will be no incentive to locate andsize such generation in a way that will lead to areduction in distribution system cost. This maychange, of course, with the advent of multiplesmall distributed generating units installed on amore widespread basis, but the industry is by nomeans there yet.

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21 For example, most G&Ts are likely to find the rolling 12 coincident peak load ratio approach to billing for transmission and ancil-lary services to be cumbersome in dealing with their member systems, and translating FERC traditional methodology into retailrates is likely to be even more difficult.

Stranded Cost and Cost Shifting

One of the major issues involved in the restruc-turing debate is the issue of stranded cost.Stranded cost is most often thought of as occur-ring when an alternative energy supplier beginsto serve load that was formerly served by thelocal utility, and it leaves the utility in a positionof having to sell the released capacity and ener-gy in the marketplace at a price that is lowerthan it was receiving. However, stranded cost

can also occur with respect to distributed gener-ation. If a G&T loses load to distributed genera-tion and is unable to market the released capac-ity and energy at a price equal to what it wasreceiving, the G&T will suffer a net loss of rev-enue that may be referred to as “stranded cost.”For example, if distributed generation is locatedon a member distribution system and operatedso that it reduces the billing demand and energy


recorded at the delivery point meter, and theG&T’s wholesale rate is greater than its avoidedcost, the reduction in revenue will exceed thereduction in operating expense and there willbe a net loss of revenue. Likewise, if the G&Testablishes credits that exceed its avoided cost, itwill experience a net loss of revenue or strand-ed cost.

FERC recognized the possibility of this occur-ring with respect to QFs supplanting sales previ-ously made by wholesale suppliers to theirwholesale customers served under requirements-type agreements. In the preamble to Order 69,FERC states the following:

“This would not appear to be the case ifthe qualifying facility offers to supplycapacity and energy in a situation inwhich the supplying utility is in an excesscapacity situation. Since the supplying util-ity has excess capacity, its avoided costswould include only energy costs. On theother hand, if the avoided cost werebased on the wholesale rate to the all-requirements utility, theavoided cost would includethe demand charge includ-ed in the wholesale rate,which would usually reflectan allocation of a portion ofthe fixed charges associatedwith excess capacity.

“Use of the unadjustedwholesale rate fails to takeinto account the effect ofreduced revenue to the supplying utility, asa result of the substitute of the qualifyingfacility’s output for energy previously sup-plied by the supplying utility. As the level ofpurchase by the all-requirements utilitydecreases, the supplying utility’s fixed costswill have to be allocated over a smallernumber of units of output. In effect, theloss in revenue to the supplying utility willcause the demand charges to the supply-ing utility’s customers (including the all-

requirements customers interconnectedwith the qualifying facility) to increase.Under the definition of ‘avoided costs’ inthis section, the purchasing utility must bein the same financial position it wouldhave been had it not purchased the quali-fying facility’s output. As a result, ratherthan allocating its loss in revenue amongall of its customers, in this situation thesupplying utility should assign all of theselosses to the all-requirements utility. Thatutility should, in turn, deduct these lossesfrom its previously calculated avoidedcosts, and pay the qualifying facilityaccordingly.”

18 C.F.R. § 292, Preamble (emphasis added)

As noted by FERC, if the credit provided tothe owner of distributed generation exceeds theG&T’s avoided cost and no other adjustment ismade, the G&T will be forced to increase itsbase wholesale rate to all its members. Theeffect is to transfer cost responsibility from

members having the most dis-tributed generation to mem-bers having the least. Thus,distributed generation raisesthe possibility of cost shiftingbetween the members of theG&T.

There would appear to betwo ways for a G&T to dealwith this potential problem.First, as suggested by FERC,the G&T could establish a

mechanism to surcharge the member system forthe stranded cost attributable to distributed gen-eration on its system. However, this may not bepermitted in all states, particularly in stateswhere retail customers are permitted to choosetheir own power supplier.22

It should be noted that it is very rare that theG&T’s base wholesale rate accurately reflects itsincremental cost, let alone the avoided costassociated with distributed generation.Consequently, whenever distributed generation

3

Distributed generationraises the possibility ofcost shifting betweenthe members of theG&T

22 Some states (e.g., Maine) do not permit stranded cost to be assigned to retail customers who install generation to serve theirown load.


is used in a way that reduces the power andenergy purchased by a member system from theG&T, there will inevitably be a mismatchbetween the reduction in revenue realized bythe G&T and the reduction in the G&T’s costs.While it is conceivable that this difference couldresult in a net benefit to the G&T (i.e., when theavoided cost exceeds the loss of revenue so thatthe G&T realizes a net gain), in many instancesthe G&T will suffer a net loss in revenue.

It is also important to note that the strandedcost issue only arises in situa-tions where the owners of dis-tributed generation choose tosupply their own load. In stateswhere retail customers canchoose their energy supplier,the G&T’s stranded cost thatoccurs when distributed gener-ation is used to supply the loadof other retail customers willbe covered under the generalstranded cost provisions of therestructuring legislation rules.In instances where the distributed generation issold to the G&T, the distribution cooperative, orto other market participants, the output is notdisplacing capacity and energy formerly sup-plied by the G&T; thus, there is no strandedcost, provided the payments to the owner donot exceed the value to the G&T and/or the dis-tribution cooperative.

Another way of dealing with the situation isto require all distributed generation to be servedunder a special rate tariff where the rates aredesigned around the G&T and member systems’avoided costs. However, in many states it maynot be possible to use this mechanism to addresssituations where a retail customer installs distrib-uted generation to serve its own load. Retail cus-tomers are usually permitted to do this withoutincurring stranded cost obligations.

Distributed generation can also have animpact on distribution cooper-ative stranded costs. Forexample, in some stateswhere restructuring has beenimplemented, utilities areallowed to charge retail cus-tomers a fixed charge forcompetition-related costs.Customers installing distrib-uted generation to meet alltheir requirements couldbypass such fixed charges,increasing costs to other cus-

tomers. Fixed costs of the distribution systemcould also be bypassed if standby or other dis-tributed generation rates are not set properly toadequately recover such system costs (or if regu-lators do not allow them to be set properly).Finally, stranded distribution costs occur if a cus-tomer installs distributed generation and discon-nects from the distribution system altogether.

3

The stranded costissue only ariseswhere the owners ofdistributed generationchoose to supply theirown load

Interconnection Requirements

Many owners and/or promoters of distributedgeneration have complained about unnecessarilyrestrictive and costly interconnection require-ments imposed by utilities. A special IEEE sub-committee has been working on developingUniform Interconnection RequirementsStandards. Draft standards are out for reviewwith the final standards expected to be issued in2002. Once the final interconnection standardsare published, the focus will shift from individualutility requirements to national interconnection.Thus, one way for a cooperative to avoid contro-versy is simply to adopt the IEEE standards.23

Beyond the technical requirements covered bythe IEEE standard, concern has been raised overother interconnection issues including the proce-dures for accomplishing interconnection (cus-tomer and cooperative contacts, time allowed forthe various steps for interconnection such as sys-tem studies) and contractual requirements (whois liable for what, the parties’ rights and obliga-tions, insurance requirements of customers withdistributed generation). All of these involve costsand fees: costs of technical interconnection equip-ment, cost of interconnection studies, cost of buy-ing insurance, cost of needed system upgrades.

23 NRECA is issuing an Application Guide to help cooperative engineers implement the IEEE interconnection standard, P 1547.


One issue related to interconnectionsbetween distributed generation and the utility’sdistribution or transmission system that has beendebated is the responsibility for paying for theinterconnection. It seems reasonable that theowner of a distributed generation unit should beresponsible for covering the incremental costincurred in interconnecting the distributed gen-eration to the utility’s system. FERC hasendorsed this concept in its Order 69 imple-menting PURPA:

“§ 292.306 Interconnection costs.(a) Obligation to pay. Each qualifying

facility shall be obligated to pay anyinterconnection costs which theState regulatory authority (withrespect to any electric utility overwhich it has ratemaking authority)or non-regulated electric utility mayassess against the qualifying facilityon a nondiscriminatory basis withrespect to other customers withsimilar load characteristics.”

18 C.F.R. § 292

This has been interpreted by FERC to refer tothe incremental cost of the interconnection, notnecessarily the total cost of the interconnection.

For example, it would cost the utility $8,000 tointerconnect a customer with distributed genera-tion but only $5,000 without the generation; theutility would be permitted to charge the cus-tomer $3,000 for the interconnection of the dis-tributed generation. The remaining $5,000would presumably be recovered through theutility’s base rates unless the utility has a policyof directly assigning all or a portion of the costsfor new connections. To the extent the utilitycan minimize these costs, for example, throughthe use of standardized equipment, the better.Of course, to the extent feasible, the utilityshould try to establish charges for interconnec-tion that reflect the actual costs of interconnec-tion associated with varying cooperative effortand costs. That is, the standard application feefor a small solar generator should not be thesame as the fee for a large industrial generatorunless the system study and administrative costsof processing the two applications truly arecomparable.

There may, of course, be instances where it ismore convenient for the cooperative to actuallypay the incremental out-of-pocket cost to makethe interconnection, but, if this done, it shouldbe recognized in developing the credits, pay-ments, or charges so that the cooperative and itsother consumer ratepayers remain whole.

3

EnvironmentalIssues

While many distributed generation technologiesare environmentally friendly (e.g., photovoltaics,fuel cells, wind turbines), most of these tech-nologies are either uneconomical for generalapplication or still under development. Thetechnologies predominantly in service today fordistributed generation technology are driven bydiesel engines and/or internal combustionengines. These technologies often have difficultymeeting emission standards unless operatedonly during emergencies. However, some newturbine technologies have no difficulty meetingemission standards or are established technolo-gy that burns cleaner fuels (e.g., reciprocatingengines that burn natural gas). Before promot-

ing specific distributed generation applications,cooperatives would be well advised to reviewthe emission characteristics of the generatingunits being considered in light of the environ-mental standards in the state. This is particularlytrue if the units are being used for anythingmore than emergency backup.

Finally, some states have a requirement thatutilities acquire a certain percentage of generationfrom renewable sources, or a utility may be ableto charge some consumers more for a “green”product generated with some renewable sources.In such cases, it may be advantageous for the util-ity to encourage consumers to install wind orsolar generators and to pay for the output.

Many G&Ts presently have policies and ratesapplicable to distributed generation. With com-petition emerging in the electric utility industry,some cooperatives are guarded about releasingspecific policies and rates. Accordingly, this sec-tion will discuss policies and rate structureswithout referencing specific G&Ts.

Policies and rates of investor-owned utilities(IOUs) will also be considered through inclusion

of a few specific IOU rates applicable to distrib-uted generation. Since IOUs are rate regulated,access to IOU rate schedules is easily accom-plished through public utility commissionsand/or IOU Web sites. Appendix A includes asample of distributed generation rates used byIOUs for interruptible service, standby service,and buyback of excess customer capacity.

Rev iew o f Po l i c ies and Rates App l i cab le to D is t r ibuted Generat ion – 27

Review of Policies and RatesApplicable to DistributedGeneration

In This Section: C&T cooperatives; investor-owned utilities

4G&T Cooperatives Many G&Ts have adopted policies and rates for

distributed generation applications.

APPLICABILITYG&Ts have adopted policies and rates that rec-ognize or encourage the following associatedwith distributed generation:

• Peak reduction• Standby service• Qualifying facilities• Emerging technologies• Purchase of excess customer capacity• Supplemental power for distribution

cooperatives

Probably the most common distributed gener-ation application recognized in G&T policiesand rates is for the use of distributed generationto reduce G&T peak demands. In such cases,the operation of customer-owned, or in somecases distribution cooperative-owned, distrib-

uted generation is coordinated by the G&T in aneffort to reduce seasonal or monthly peakdemands.

With the advent of PURPA, all electric utilitiesare required to purchase capacity and energyfrom qualifying facilities at either avoided costor net metered rates. Accordingly, G&Ts haveestablished policies and rates applicable to suchqualifying facilities. These policies and rates areconsistent with federal and state requirementsadopted to implement PURPA.

Some G&Ts have developed policies andrates applicable to supplemental, maintenance,and backup service required by retail customersthat have installed distributed generation facili-ties capable of meeting all or a portion of thecustomer’s electric requirements. In general,such policies and rates have been developed inresponse to customer requests for such serviceor the expectation that such service will berequested.

The increasingly volatile wholesale market

28 – Sect ion Four

4has caused some G&Ts to implement policiesand rates that allow for the purchase of excessdistributed generation capacity and energy dur-ing times of high market prices. These policiesand rates allow the G&T to secure capacity andenergy at prices lower than market. At the sametime, such efforts provide additional economicreturn to customers that own distributed genera-tion facilities that have capacity in excess of thecustomer’s load requirements.

Some G&Ts have adopted policies that allowdistribution cooperatives to own distributed gen-eration to provide a portion of the distributioncooperative’s requirements. In such cases, thedistributed generation can be owned by the dis-tribution cooperative or such supplementalpower can be purchased from a third party thatowns distributed resources.

Finally, a few G&Ts have established policiesthat facilitate the installation of emerging distrib-uted generation technologies. At least one G&T,for example, has adopted a policy that allowsdistribution cooperatives to own and/or leasefuel cells for the benefit of distribution coopera-tive retail customers. The distribution coopera-tive is able to purchase capacity and energyfrom such fuel cells without violating the termsof the all-requirements contract between theG&T and distribution systems.

POLICY ISSUESWhile G&T policies pertaining to distributedgeneration tend to be unique, a number of corepolicy issues are generally addressed by all G&Tcooperatives:

• Ownership• Operation• Metering• Minimum size• Control frequency and duration• Allowable amount of distributed generation• Control circumstances

OwnershipRetail customers can install and operate distrib-uted generation independently of the utility gridto achieve a variety of objectives. When distrib-uted generation is used to participate in a G&T

program, ownership requirements are oftendefined. In most cases, in fact, distributed gener-ation can only be owned by the retail customer.(Ownership by the distribution cooperativesgenerally violates all-requirements contract pro-visions. Such provisions have been adopted toprovide financial assurance for loans associatedwith cooperative generation.) In some cases,however, G&Ts have established policies thatpermit distribution cooperatives to own distrib-uted generation. In those cases, it may be neces-sary for the distribution system to “associate”such distributed generation with individual cus-tomers. That is, a distributed generation facilitymay be installed at a specific customer site. Ifthat customer no longer receives electric servicefrom the distribution cooperative, then the dis-tributed generation facilities must be moved toanother customer site. In other cases where dis-tribution cooperatives are allowed to own dis-tributed generation facilities, such distributedgenerators may be located at distribution substa-tions. These distributed generators may then beoperated either in participation with a peakreduction/load management program or betreated as a supplemental power source for thedistribution cooperative.

OperationPolicies also exist to ensure that a distributedgenerator will be operated to provide capacityand/or energy benefits for the G&T when thedistributed generation is being used to partici-pate in a G&T program. This usually means thatthe G&T specifies that the distributed generationfacility must be dispatchable by the G&T. Whilethe G&T dispatches the distributed generator,policies still allow for direct operation by eitherthe customer or distribution cooperative inresponse to the dispatch call from the G&T.

MeteringMetering requirements are integrally related tothe rates/credits offered by G&Ts. Since thecapacity value of the output of distributed gen-eration is generally time sensitive, intervalrecording meters are often required to accurate-ly determine rates and/or credits that corre-spond to peak reduction periods.


4Minimum SizeG&T policies may also specify minimum qualify-ing sizes of distributed generators for participa-tion in a G&T program. Such minimum qualify-ing size requirements ensure that distributedgenerators are sufficiently large to provide sys-tem benefits that exceed the cost of intercon-necting the units and administering applicableprograms/rates. Such minimum qualifying sizescan range anywhere from 50 kW to 1,000 kW.

Control Frequency and DurationThe number and frequency of G&T programcontrol events for distributed generation isanother issue addressed in distributed genera-tion policies. Distributed generators must beavailable to G&Ts to provide recognized pro-gram benefits. However, the frequency andduration of required operation of distributedgenerators can be a concern to retail customers.Accordingly, some G&T policies may place lim-its on either the frequency or duration ofrequired distributed generator operation. In onecase, a G&T has specified that distributed gener-ators will be required to operate a maximum of12 times per year with no more than one opera-tion per day. In other cases, the G&T may notlimit the number of control events but will spec-ify a maximum number of hours that distributedgeneration will be required to operate in a sin-gle day. In most cases, however, G&T policiesdo not place any limit on the frequency or dura-tion of required operation of distributed genera-tors participating in a program.

Allowable Amount of Distributed GenerationWhile distributed generation can provide systembenefits, excessive levels of distributed genera-tion installations participating in a program canresult in cost shifting between distribution coop-eratives or more installed capacity than is eco-nomically justified. To avoid such consequences,some G&Ts have adopted policies that establishan upper threshold for allowed distributed gen-eration that may participate in a program. Insome instances, this threshold is stated in termsof kW, while in other cases the G&T threshold isbased on a percentage of the G&T’s annual sys-tem peak demand. Of course, a customer may

install any amount of distributed generation for itsown use that is not part of a cooperative program.

Control CircumstancesFinally, some G&T policies address the circum-stances under which distributed generators willbe required to operate when participating in aspecific program. As was mentioned earlier, themost common use of distributed generators is toachieve peak demand reductions during times ofG&T system peak. Beyond this peak demandapplication, distributed generators may also becalled upon to help alleviate transmissionand/or distribution system loading constraints.Other G&Ts have established policies that allowdistributed generators to be operated to facilitatemarket sales by the G&T. In such cases, theG&T will likely provide some form of additionalcompensation to the retail customer.

WHOLESALE RATES/CREDITSG&Ts have adopted a variety of wholesale ratesand/or credits that are applicable to distributedgeneration.

Peak Reduction Rates/CreditsG&Ts have adopted both rates and creditsapplicable to distributed generators used forpeak reduction purposes. These rates and cred-its offer a specified payment for distributed gen-eration used for peak reduction purposes orreduction in wholesale charges applicable tosuch customers. The rates/credits offered byG&Ts include:

• A specified dollar credit per kW on a monthlyor annual basis

• A reduction in the applicable seasonal ormonthly kW charges for wholesale service

• A reduction in the applicable billing demandfor the distributed generation customer thatresults in a full reduction in applicable seasonal or monthly kW charges

• A formula credit based on hours of operationand required length of advance notice ofoperation

• Negotiated rates• A specified dollar credit per kW in addition

to reductions in seasonal demand charges

30 – Sect ion Four

While there is substantial variety in rates andcredits offered for distributed generators usedfor peak reduction, the observed bottom linebenefit seems to reflect current market costs forpeaking capacity. That is, a G&T may offer ratereductions or credits to applicable wholesalecharges that are designed to reflect marketprices. This means that when G&Ts have whole-sale capacity charges that closely reflect marketconditions, they will simply reduce the whole-sale billing units in an amount corresponding tothe output of the distributed generator. On theother hand, when G&Ts have wholesale capaci-ty charges that are higher than market capacitycosts, they tend to offer market-based creditsthat are applied toward the G&T’s wholesalecapacity charges.

Standby RatesCustomers that install distributed generation tomeet a portion or all of their electric require-ments often require utility supplemental service(that is, where the output of the distributed gen-eration is less than the consumer’s totaldemand), electric service during maintenanceperiods, and backup service in case their distrib-uted generation is unavailable. Such supplemen-tal, maintenance, and backup service may bepriced in a number of ways:

• Charge a fixed dollar amount per kW permonth for reserving capacity to support thecustomer’s generation.

• Charge applicable wholesale rates when theretail customer requires utility service.

• Pass through procurement costs that the G&Tincurs when required to provide service to astandby customer.

Each of these alternatives can be designed toallow a G&T to cover its fixed and variable costsassociated with service to standby customers.

Purchase of Excess CapacitySome G&Ts have recognized that excess capaci-ty in customer-owned distributed generation canbe acquired by the G&T for the mutual benefitof the G&T and the retail customer. When aG&T is required to make market purchases of

capacity or energy, such purchases can be madeinstead from customers with distributed genera-tion resources. These purchases may be made atprices below prevailing wholesale market prices.This provides a net savings to the G&T whileproviding additional revenue to the retail customer. Options for purchasing excess distri-buted generation capacity and/or energy are asfollows:

• Establish an energy purchase price based ona fuel index formula plus a fixed adder perkWh for operation and maintenance.

• Purchase capacity at a fixed dollar amountper kW month.

• Submit purchase offers to retail customersbased on some percentage of prevailing mar-ket prices.

• Receive sales offers from retail customers.

Penalty ProvisionsThe rates and credits offered by G&Ts relative todistributed generation programs recognize thepotential system benefit of operating such facili-ties. However, if customers are unable to oper-ate distributed generators when called upon, theG&T could experience significant costs to pur-chase or generate such energy. Penalty provi-sions are often incorporated in wholesale ratesapplicable to distributed generation to be surethat customers make best efforts to ensure theavailability of distributed generators and to placerevenue responsibility on individual customers ifthe distributed generation is unavailable whenneeded. G&Ts have adopted a variety of penaltyprovisions:

• Charge individual customers for market pur-chases that are made because of the unavail-ability of the customer’s distributed genera-tion.

• Apply a formula reduction to the credit thatthe customer would otherwise receive.

• Charge a fixed dollar amount per kW permonth for distributed generation capacity thatis unavailable.

• Remove the customer from the applicablewholesale tariff for 12 months from the timethe distributed generation is unavailable.

4


4Each of these penalty mechanisms is designed

to provide an incentive for the customer toensure that the distributed generation facilitiesare properly maintained and available for usewhen needed by the G&T. In addition, these

penalty provisions seek to recover sufficient rev-enue from the individual distributed generationcustomer so that remaining customers are notharmed.

Investor-Owned Utilities

IOUs generally operate through a vertically inte-grated structure. That is, an IOU provides gener-ation, transmission, and distribution services tothe retail customers it serves. Accordingly, IOUsdo not need to establish policies and ratesbetween a wholesale entity and a retail entity.Despite these organizational differences, IOUservice to customers with distributed generationexhibits many of the same policy considerationsdiscussed previously for G&Ts. These policies,which are reflected in electric service rate sched-ules, include operation, metering, minimum size,control frequency and duration, and control cir-cumstances. Noticeably absent from this list ofpolicy issues is ownership of distributed genera-tion. IOUs take advantage of distributed genera-

tion as circumstances warrant without considera-tion of all-requirements contracts that defineG&T and distribution cooperative relationships.

Since IOUs are rate regulated, access to IOUrate schedules is easily accomplished throughpublic utility commissions and/or IOU Web sites.Depending on the competitive circumstancesfaced by individual cooperatives, a review ofneighboring IOU distributed generation rateschedules may be advisable prior to establishingsuch cooperative rate schedules. Appendix Aincludes a sample of distributed generation rateschedules used by IOUs for interruptible service,standby service, and buyback of excess customercapacity. These rate schedules are provided forillustrative purposes only.

Introduction Developing distributed generation rates requirescareful consideration of many issues. Section 2,Utility Cost Structure and Ratemaking, providedan overview of methodologies, techniques, andassumptions that have been and will continue toimpact wholesale and retail cost-of-service stud-ies. The various philosophies and assumptionsused in cost studies can significantly affect theresults of COS analysis and, in turn, the respec-tive wholesale and retail rates developed torecover these costs. Section 3, DistributedGeneration Issues, identified and discussed anumber of issues, many of which deal withpotential costs and benefits ofdistributed generation, thatdirectly impact the develop-ment of rates applicable to dis-tributed generation. Section 4,Review of Policies and RatesApplicable to DistributedGeneration, provided a broadoverview of policies and ratesthat G&Ts (and, in some instances, IOUs) haveestablished for addressing distributed genera-tion.

This section describes the considerations/process involved in evaluating and developingrates applicable to distributed generation. Itmust be emphasized that rate development is aprocess. Cooperative circumstances are not allalike. Cost analysis and rate design must recog-nize the specific impacts that each distributedgeneration application will have on a coopera-

tive’s costs and service to other consumers. Inthis regard, one size does not fit all cases. Thenext subsection, Costs and Cost Savings, pages34-35, summarizes previous discussions regard-ing costs, and potential cost savings, of serviceassociated with distributed generation. The sub-section on Rate Design Options, pages 36-44,reviews rate and non-rate options to recovercosts. Evaluation Process, pages 44-47, outlinesthe process for evaluating costs and cost savingsfor a variety of customer-initiated and coopera-tive-initiated scenarios regarding distributed gen-eration. A few examples of cooperative objec-

tives associated with distrib-uted generation with an iden-tification of how rate and non-rate options can be employedto achieve these objectives areprovided on pages 47-51.Finally, Rate Schedule Clauses,pages 51-55, identifies a num-ber of tariff provisions to con-

sider when establishing a specific distributedgeneration rate schedule.

GENERAL OBSERVATIONSBefore proceeding, it is important to make somegeneral observations regarding distributed gen-eration applications, cost analysis, and rates:

1. It must be emphasized that it is not a fore-gone conclusion that distributed generationis either good or bad for a cooperative

Deve lopment o f D is t r ibuted Generat ion Rates – 33

Development of DistributedGeneration Rates

In This Section: Introduction; costs and cost savings; rate design options; evaluation process; examples; rate schedule classes

5Rate development is a process

Costs and Cost Savings

34 – Sect ion F i ve

5and/or its consumers. Cooperatives mustdetermine the value based on a carefulanalysis of cost and cost savings of specificdistributed generation applications.

2. Cooperatives must recognize that existingwholesale and retail rates based on averageembedded costs will likely not reflect mar-ginal cost of service. Accordingly, existingwholesale and retail rates will likely provideuneconomic incentives or disincentives rela-tive to the installation of distributed genera-tion applications. Such uneconomic pricesignals can be mitigated through appropriatedesign of distributed generation rates.

3. Existing requirements contracts typically pro-hibit distribution cooperatives from owningdistributed generation or purchasing the out-put of distributed generation owned by thirdparties. If G&Ts wish to promote distributedgeneration more broadly, there is a need forsuch contract limitations to be modified.

4. Distributed generation rates may be designedthrough standard rate schedules or offered ascustomized rates for individual customers. Ingeneral, distributed generation rate scheduleswork well when several customers are expect-ed to participate in such service and the loadand cost characteristics of these customers areexpected to be similar. On the other hand,cooperatives may wish to pursue individual-ized rates if one or only a few customers areexpected to participate and anticipated costsof service and load characteristics are signifi-cantly different among these customers.

5. It is critical that distributed generation ratesand policies be carefully coordinatedbetween a G&T and its distribution coopera-tives to ensure that real costs and cost sav-ings for both organizations are properlyreflected in the retail service offered to con-sumers and to prevent cost shifting betweenmembers of a G&T.

24. National Association of Regulatory Utility Commissioners, Electric Utility Cost Allocation Manual, January 1992.

COST ANALYSISCost-of-service studies are among the basic toolsof ratemaking. While opinions vary on theappropriate methodologies to be used to per-form cost studies, few analysts seriously ques-tion the standard that service should be provid-ed at cost. Non-cost concepts and principlesoften modify the cost-of-service standard, butCOS remains the primary criterion for the rea-sonableness of rates.24

The cost principle applies not only to theoverall level of rates, but to the rates designedfor individual services, classes of customers, andsegments of the utility business. Stated anotherway, COS studies are used to achieve two pri-mary objectives.

1. A COS study serves as a guide for distribut-ing or allocating revenue requirements. Inthis regard, the goal is to achieve equitybetween rate classes.

2. A COS study is used as a guide for designingindividual rate schedules. The goal here is toachieve equity within each rate class.

As discussed on pages 5-6, the COS method-ology most often employed by electric coopera-tives for use in designing rates in general isreferred to as the “fully allocated averageembedded” cost of service approach, meaningthat:

1. Total costs are allocated on an average sys-tem-wide basis.

2. Embedded or accounting costs as recordedon the cooperative’s books are used in theanalysis.

While embedded COS results may also be usedas a starting point for evaluating distributed gen-eration costs and developing necessary rates,marginal costs and “avoidable costs” as dis-cussed on pages 15-16 are at least as important.Avoidable costs associated with distributed gen-eration represent the costs that a utility wouldincur but for the existence of the distributedgeneration. While the general concept is rela-tively simple, applying the definition to specificdistributed generation applications is not and is


5often controversial. Nevertheless, the focus ofthe debate is clear and should be on the incre-mental impact of the distributed generation on acooperative’s system and costs, which will gen-erally include:

• Incremental costs• Avoidable costs (or savings)

COST IDENTIFICATIONCooperatives will incur both direct and indirectcosts associated with service to customers withdistributed generation.

Direct CostsDirect costs are those costs directly attributableto one specific customer or a class of customers.Such costs are incremental in the sense that theygenerally would not have been incurred but forservice to the customer or class of customers. Inproviding service to customers with distributedgeneration, certain incremental costs are likelyto be incurred:

• Interconnection of customer distributed gen-eration facilities to the cooperative’s distribu-tion system

• Special metering equipment• Control equipment that allows the generation

to be started remotely under the terms of anapplicable service schedule

• Cooperative testing and monitoring of customer-owned facilities to ensure compli-ance with applicable safety and operational standards

To the extent that these direct costs are antici-pated to be uniform among all customers partic-ipating in a distributed generation rate, suchcosts may be recovered through a fixed chargeor facilities charge in the applicable rate sched-ule. However, if such costs are expected to varymaterially from customer to customer, thenrecovery of these costs would more appro-priately be accomplished through a facilitycharge unique to each customer.

Indirect CostsLike other rates offered by a cooperative, ratesapplicable to distributed generation shouldmake an equitable contribution toward the fol-lowing cooperative expenses:

• Distribution operation and maintenance• Consumer accounts• Customer service and information• Administrative and general• Depreciation• Interest• Taxes

Since these indirect costs cannot be directlyassigned to individual customers or customerclasses, they must be allocated through thecooperative’s COS study. The challenge forcooperatives is ensuring that rates charged forall types of service reflect a “just and reason-able” contribution toward all direct and indirectcosts associated with such service.

COST SAVINGSDistributed generation has the potential ofreducing the cooperative’s overall cost of opera-tion by:

• Displacing the production of energy• Delaying or eliminating the need for new

generating capacity• Reducing or eliminating the need for pur-

chased power and energy• Supplying some of the ancillary services that

would otherwise have to be supplied fromthe cooperative’s own resources or purchased

• Delaying, modifying, or even, in someinstances, eliminating the need for transmis-sion and distribution improvements

The extent to which a G&T and/or distribu-tion cooperative can utilize the output of distrib-uted generation to accomplish these objectivesis often case specific, dependent upon the char-acteristics of the G&T and the distribution coop-erative as well as the characteristics of the dis-tributed generation. In any event, it is imperativethat cost savings reflect real benefits of distrib-uted generation, not overly optimistic assumedbenefits.


Once the direct and indirect costs and cost sav-ings have been identified for specific distributedgeneration applications, it is then possible for acooperative to develop appropriate retail ratesbased on the identified net costs/benefits of pro-viding service. Many objectives influence thedesign of such retail rates. Widely acceptedobjectives are listed on page 11. It is importantto emphasize again that it is seldom, if ever,possible to fully accomplish all these objectivesin developing rate schedules. Compromisesbased on judgment reflecting the policy of thecooperative must be made.

The cooperative also has a variety of optionsto achieve its objectives with respect to distrib-uted generation. The cooperative can choose toamend the various rate and non-rate compo-nents of its existing rate schedules and bills. Itcan adopt a variety of new rate schedules ornon-rate approaches that apply only to thoseconsumers that install distributed generation forcertain applications. Or it can use some combi-nation of the above. The following sections dis-cuss the effect that adjustments to the differentrate and non-rate components will have on thecooperative’s different objectives.

RATE COMPONENTSOverviewThe rate structures and policies implemented byG&Ts relative to distributed generation havebeen based on varying approaches to COSanalysis and a determination of whether distrib-uted generation benefits the cooperative and itsconsumers. Pages 34-35 identified some of thecosts and cost savings that are associated withservice to distributed generation. Distributedgeneration rates should recognize the uniquecost characteristics of the service being offered.Beyond a reflection of costs and cost savings,rates applicable to customers with distributedgeneration should at least satisfy the followingcooperative goals:

1. At a minimum, the cooperative must ensurethat the applicable rate structure satisfies a“hold harmless” test. That is, the cooperativemust ensure that the rate or rates paid bycustomers with distributed generation recov-er sufficient revenue to cover the coopera-

tive’s net incremental cost of providing ser-vice to those customers. This will ensure thatother cooperative customers are not harmedby the action of customers implementingdistributed generation, either on their owninitiative or otherwise.

2. If the cooperative determines that encourag-ing the development of distributed genera-tion is in the long-term interest of the coop-erative and its other member consumers, theapplicable rates should be designed toencourage customers to install distributedgeneration in a way that maximizes the ben-efits. That is, rates and/or incentives shouldbe used to facilitate customer installation ofdistributed generation in desired geographi-cal areas that is operated in a way that low-ers the cooperative’s existing or future costof providing service.

Both rate structure and rate level are impor-tant in accomplishing these objectives. Rate levelis, of course, a function of each cooperative’scosts. Rate structure, on the other hand, can beaddressed on a more generic basis. Electriccooperative rate structures typically include oneor more of the following basic components:

• Monthly fixed charge• Energy charge• Demand charge

The next few subsections discuss each ofthese components as they apply to customersconsidering the installation of distributed gener-ation and customers already owning and operat-ing distributed generation.

Monthly ChargeIn a traditional, non-distributed generation rate,the monthly charge (often referred to as a basiccharge, fixed charge, or customer charge) is typ-ically designed to recover monthly costs associ-ated with metering, billing, and customeraccounting. This charge may also recover a por-tion, or all, of the identified consumer compo-nent of distribution plant costs, although mostcooperatives recover only a small portion of dis-tribution plant fixed costs required to serve con-sumers through the monthly charge, with the

5Rate DesignOptions


5remainder recovered through an energy charge.

This common approach to rate design has sig-nificant implications vis-à-vis distributed genera-tion. Consumers with distributed generation arelikely to use far less energy than other con-sumers in the same rate class. As a result, whena significant percentage of fixed costs are recov-ered through the energy charge, distributed gen-eration customers make a far smaller contribu-tion to the fixed costs of the system than othersuch consumers, and the cooperative undercol-lects its appropriate revenue requirement. Thisundercollection relates primarily to smaller con-sumers where the “consumer” cost componentmakes up a larger portion of the classes’ totalcost of service. For larger customers, this poten-tial undercollection is minor incomparison since consumercosts for large customers aretypically just a fraction of thetotal cost of service.

This issue, of course, goesbeyond distributed generationand affects how the coopera-tive recovers its revenuerequirements from all cus-tomers. Consequently, thecooperative could address thisproblem by setting the monthly charge for allconsumers at a level that recovers all the coop-erative’s fixed costs. That would ensure that anycustomer that reduced its energy usage byinstalling distributed generation would still payits share of fixed costs. Unfortunately, in manycases, that approach would not be politicallyfeasible since it would be a significant departurefrom historical rate practices. Alternatively, thecooperative could design a separate rate sched-ule for consumers with distributed generationthat would have a larger monthly charge thanthat paid by other consumers. This approach, ofcourse, would not be popular with proponentsof distributed generation or with consumersinterested in distributed generation, but it wouldhelp to ensure that the cooperative recovered itsfixed costs.

When fixed costs of the system are recoveredthrough the energy charge, the consumer seesan artificial price signal that encourages invest-ment in distributed generation. That is, a rela-

tively low monthly charge means that remainingfixed distribution costs are generally recoveredfrom small consumers through a volumetricenergy charge. This means that smaller con-sumers can install distributed generation andachieve savings on their electric bills that reflectboth variable (avoidable) and fixed (unavoid-able) distribution costs.

For customers with distributed generation,direct costs (e.g., special interconnection costs)may be recovered through a monthly facilitiescharge. If direct costs are reasonably uniformamong all customers participating in a distrib-uted generation rate, a facilities charge commonto all customers may be established. Thisensures consistent treatment among similarly sit-

uated customers. If directcosts are expected to vary sig-nificantly from customer tocustomer, these costs must berecovered through a cus-tomer-specific facilities charge.

A monthly charge may alsobe applied to minimum orpredictable load circum-stances. For example, serviceto remote locations for enduses such as stock tanks, elec-

tric fences, pumps, or security lighting may bepowered with cooperative-owned windmills orphotovoltaic arrays instead of through costly ser-vice extensions. In these circumstances, a flatmonthly charge could be applied to allow for fullrecovery of cooperative costs associated withproviding this remote service. In such cases, theamount of energy used is less important than thefact that fixed capital investments were requiredto provide the service in question.

Energy ChargesMany forms of energy charges are in commonuse. Probably the most common form of energycharge is a flat charge per kWh that is applied toall kilowatt-hours throughout the year. Retailenergy charges can also take the form of on-peak and off-peak rates during specified hoursand days, or rates that vary by season. Energycharges may also have different steps or blockedcomponents. These charges may specify onerate for initial energy consumption with different

A facilities chargeensures consistenttreatment amongsimilarly situatedcustomers


rates defined for succeeding levels of consump-tion. Energy charges may reflect real-time(hourly) changes in market prices. To makeenergy rates acceptable to consumers andensure they properly reflect the cooperative’scosts, it is important that they bear a relationshipto the cost of the energy to the cooperative andits G&T. For example, it is far easier for the dis-tribution cooperative politically to justify peakhour or seasonal rate differen-tials if the rate the distributioncooperative pays its G&Tincludes an equivalent differ-ential.

Establishing wholesale ener-gy charges either above orbelow the cooperative’s mar-ginal cost of service can unin-tentionally encourage or dis-courage the installation of dis-tributed generation beyondwhat is cost justified. For example, G&T energyrates set higher than marginal cost will generallyhave a negative impact on high load factor cus-tomers. If energy prices are too high, such cus-tomers may find it economical to install distrib-uted generation capable of supplying a largeportion or all of their electric requirements thanmight otherwise be the case if energy werepriced near the cooperative’s marginal cost.Conversely, energy rates set too far below mar-ginal cost are likely to discourage customersfrom installing generation that could not onlybenefit individual customers but also benefit thecooperative by avoiding the purchase or genera-tion of high-priced on-peak energy.

The energy charge can be used to provideincentives for different behavior. If the coopera-tive wants to encourage the use of distributedgeneration and/or conservation during the coop-erative’s peak hours, it could establish higherenergy charges during those peak hours.Providing rate incentives for distributed genera-tors to operate during peak hours can benefitconsumers and reduce the G&T’s exposure inthe market. Similarly, if the cooperative wants toencourage the use of distributed generationand/or conservation during certain seasons, itcould increase the energy charges during thoseseasons. Such seasonal rate differentials should

recognize cost-of-service differences determinedfor G&Ts and/or distribution systems. As withfixed charges, modifications to energy chargescan be made for all consumers or just for thoseconsumers with distributed generation. Rates thatapply just to consumers that install distributedgeneration may be more acceptable to con-sumers that do not install distributed genera-tion because they see no change in their rate

schedule. Adjustments to the energy

charges for consumers withdistributed generation could in some cases be a win–winsolution. For example, a con-sumer that installs a solarpanel could see significantsavings if put on a plan thatraises the cost of power dur-ing summer afternoons—when the generator is working

well—and lowers the cost of energy at night orin the winter when energy is supplied from thegrid. A cooperative could offer consumers achoice among several rate structures. Consumerswith solar generation could opt for one with atime-sensitive energy charge. (This, of course,assumes that such seasonal rates reflect thewholesale power supplier costs and/or marketprices.)

In some situations, cooperatives may find itnecessary to purchase energy during high-pricedon-peak hours or supply energy from generatingunits with high variable operating costs. If thecooperative wants to encourage distributed gen-eration to avoid such purchases or generation ofenergy, real-time pricing provides an opportuni-ty to encourage customer installations for thispurpose. In such circumstances, the cooperativecan offer a real-time price signal that reflectsmarket purchase prices or incremental generat-ing costs. Customers could then operate distrib-uted generation facilities when energy pricesexceed their individual economic threshold. Thisallows the customer to avoid high prices andachieve an overall lower delivered cost of ener-gy while benefiting the cooperative since it isable to avoid these higher costs.

In some areas, customers, legislatures, or reg-ulatory agencies are very interested in encourag-

5

The energy charge canbe used to provideincentives for differentbehavior


5ing the use of energy from renewable resources.While PURPA qualifying facility requirementsspecify the rates that utilities must apply to pur-chases of renewables, utilities have the option ofpurchasing renewable energy at higher rates.While such purchases are not justified on anavoided cost basis, these purchases may beappropriate if the energy can be resold to cus-tomers for purchase on a voluntary basis. Inthese circumstances, a cooperative could pur-chase energy from small-scale renewable cus-tomer facilities at a price higher than avoidedcost and then resell this energy to specific cus-tomers desiring such service. This approach canaddress a niche market for specific customersand/or respond to legislative mandates requiringdevelopment of market-based renewable energy.

Demand ChargesDemand charges also exhibit variability. Likeenergy charges, the most common demandcharge is a flat charge per kW. These demandcharges can also vary by sea-son, with one rate applicablein the summer and anotherduring the winter. Finally,demand charges can also beimposed for a customer’s con-tribution to coincident demandat the time of the power sup-plier’s peak. These coincidentdemand charges, often used incombination with non-coinci-dent demand charges, allow adistribution cooperative to dif-ferentiate rates as they relateto wholesale power costs versus distributioncapacity costs. For the most part, distributioncooperatives impose demand charges when customers exceed a specified threshold suchas 25 kW to 50 kW.

Beyond cost-of-service considerations, ratestructure can also influence implementation ofdistributed generation. For example, some G&Tswill phase in the wholesale billing impact ofdemand reductions from distributed generationover a specified number of years. In such cases,distribution cooperatives will not achieve the fullreduction in wholesale power bills for sometime after a distributed generation unit is opera-

tional. This lag in achieving full financial benefitfrom distributed generation installations presentsan economic hurdle that hinders developmentof distributed generation. Similarly, ratchet pro-visions in wholesale rates can negate the benefitof distributed generation offered for peak reduc-tion purposes.

Demand charges that do not reflect cost ofservice can provide uneconomic signals whenapplying existing rates to distributed generationor designing new distributed generation rates.For example, a demand charge that is estab-lished below cost-of-service levels may not rec-ognize the full value of potential savings inwholesale capacity charges or distribution sys-tem benefits associated with distributed genera-tion. If a cooperative wishes to encourage peakdemand reduction (in coordination with theG&T wholesale power supplier) but the existingretail demand charge is below the wholesalepower cost, then the cooperative is unable toreflect the full value of such wholesale capacity

savings through a reductionin the demand charge.Instead, some of thesewholesale capacity savingswould be reflected through areduction in the energycharge. This tends to encour-age peak demand reductionamong high load factor cus-tomers compared to low loadfactor customers. Such ratedesign makes it difficult toachieve demand reductionfrom low load factor cus-

tomers that could lower the overall class cost ofservice, thus lowering rates for other consumers.

As with energy charges, demand charges canbe adjusted to provide incentives for installationand operation of distributed generation in a waythat provides benefits to the system. If the distri-bution cooperative wants to defer expansion orupgrade of a distribution feeder, it can design ademand charge specific to that feeder thatencourages use of distributed generation thatreduces load on the feeder at that feeder’s peakhours. Such demand charges can be based on asingle non-coincident demand or differentiatedby on-peak and off-peak periods. If the distribu-

Demand charges canbe adjusted to provideincentives for instal-lation and operation ofdistributed generationto benefit the system


5tion cooperative pays a coincident demandcharge to its G&T, it can design a demandcharge at the retail level that encourages use ofdistributed generation at those hours necessaryto reduce wholesale coincident demand charges.Such efforts require careful coordination amongthe G&T, distribution cooperative, and con-sumers.

Both G&T and distribution system costs arestrongly influenced by seasonal peak consumerdemand. Wholesale power suppliers must haveadequate generating capacity to meet expectedsummer and winter peaks. Likewise, distributionsystems must be designed to meet the highestanticipated consumer demand. If a cooperativewants to encourage the use of distributed gener-ation to reduce short-term costs during thesehigh-demand periods, seasonal demand chargesare a means of encouraging distributed genera-tion operation during such times. In other cases,a G&T may forecast a long-term need for morepeaking capacity at costs wellabove existing peaking costs.In this case the G&T couldpromote the installation ofmore distributed generation toreduce or avoid the need forsuch new plant construction.Demand charges in this casecould be set above short-termlevels but below expectedlong-term capacity costs. Time-of-use demand charges presenta further refinement to season-al demand charges. When coordinated withwholesale power supplier and/or distributionsystem requirements, such time-of-use rates can encourage distributed generation duringspecific hours each day or during identifiedpeak periods.

NON-RATE COMPONENTSBilling components included in rate schedules,in general, reflect the overall average systemcost of providing service to customers within aclass. In the case of distributed generation, thereare circumstances where a cooperative wouldbenefit from distributed generation located incertain geographical areas, or operation of dis-tributed generation under certain circumstances.

In such cases, non-rate components are a wayof targeting desirable distributed generationinstallations or ensuring that undesirable distrib-uted generation installations do not harm thecooperative or other customers. Examples ofnon-rate components include rebates, deaver-aged distribution credits, equipment rates, con-tributions in aid of construction, purchaseoptions, and contracts.

RebatesRebates provide a targeted financial incentivethat can be applied in well-defined circum-stances. Cooperatives have the option of estab-lishing targeted rebates to encourage the instal-lation of beneficial distributed generation.Accordingly, rebates can be used as an enhance-ment to rate schedule price signals. However,caution must be used when providing lump-sumrebates. If cost or operational savings do notmaterialize as expected, then the rebate simply

provides a windfall to therecipient, with no net benefitto other customers.

One use of targeted rebatesis to encourage distributedgeneration at specific geo-graphical locations whereoperation of such generationwill reduce loading on the dis-tribution system, therebydelaying the need to invest inadditional distribution facilities.A location- and technology-

sensitive rebate program could also encouragethe installation of distributed generation that canprovide VAR support on the distribution system.

Another use of rebates is to encourage certaincustomers on standard rate schedules to partici-pate in a distributed generation rate schedule.An example of such a circumstance is a cus-tomer with undesirable load characteristicsbeing served under a standard rate schedule.(That is, a customer may have a very low loadfactor compared to the class average, whichmeans that the customer is likely imposing sig-nificant purchased power costs on the coopera-tive that are not fully recovered through averageclass rates charged to this customer.) In thiscase, the customer could be encouraged to

A targeted rebate mayprovide the necessaryadded financialincentive to move todistributed generation


install distributed generation facilities and partic-ipate in a rate schedule that could significantlylower the cooperative’s cost of wholesale powerassociated with serving this individual customer.If the customer’s annual rate savings are not suf-ficient to warrant moving from standard serviceto a distributed generation rate schedule, then atargeted rebate may provide the necessaryadded financial incentive.

Deaveraged Distribution Credits 25

The basic premise of deaveraged distributioncredits is that incremental/decremental costs ofcooperative plant investment in specific areas ona distribution system should be reflected in cred-its to specific customers installing distributedgeneration. In other words, the credits would bebased on site-specific avoided cost. As appliedto the installation of distributed generation,cooperatives faced with potentially large capitalinvestments to serve customers in certain geo-graphical areas could offer specific creditsencouraging those customers to install genera-tion sufficient to avoid such cooperative invest-ments. The deaveraged distribution credit bene-fits all consumers by allowing the cooperative toavoid costly plant expenditures.

Using a credit mechanism, as opposed to arate, allows the cooperative to charge the cus-tomer a rate based on average system costswhile recognizing that the actual available distri-bution system costs that may be realizedthrough distributed generation are highly depen-dent on local circumstances. While deaverageddistribution credits can be applied to specificfeeders or customer sites, the concept of distrib-uted resource development zones would applysuch credits within a defined geographical area.

While deaveraged distribution credits canallow cooperatives to encourage the location ofdistributed generation to avoid costly newinvestments in distribution plants, such site-spe-cific credits pose potential problems. Becausesuch deaveraged distribution credits rely on anunderstanding of specific distribution systemcosts, the application of specific credits will notbe easily understood or verified by customers.

Customers will likely question why credits areavailable in one area and not in another.Similarly, concerns could be raised by politicalsubdivisions. Competition for new businessesamong political subdivisions can often becomeintense. If a cooperative is offering deaverageddistribution credits for one political subdivisionbut not in another, this will likely result in com-plaints in areas not receiving deaveraged distrib-ution credits. Since cooperatives often workclosely with, and rely on good working relation-ships with political subdivisions, deaveraged dis-tribution credits could negatively impact suchrelationships.

Equipment RatesBeyond traditional rates and incentives toenhance traditional rate structures, opportunitiesmay also exist for cooperatives to own distrib-uted generation equipment and charge cus-tomers for services related to such ownership.(Such ownership rates may also be referred toas marketing or sales-based rates.) These oppor-tunities occur when an investment in generationor distribution facilities can be minimized oravoided with distributed generation and neitherthe G&T or distribution cooperative is harmedby such distributed generation investment.Examples of the application of ownership ratesmay include the following situations:

1. The cooperative owns distributed generationequipment and the customer provides allfuels.

2. The cooperative and customer jointly owndistributed generation equipment and sharein revenues earned from wholesale transac-tions or avoidance of peak wholesale powercharges.

3. The cooperative retains a customer byinstalling distributed generation to serve crit-ical power quality loads.

A cooperative may decide to own distributedgeneration at a customer’s site and establishrates to the customer that reflect capital andoperating costs of such equipment plus margin.

5

25 See David Moskovitz, “Profits and Progress Through Distributed Resources,” The Regulatory Assistance Project, February 2000.


The customer could be responsible for provid-ing all fuels. A cooperative may decide to pur-sue such an arrangement for several differentreasons. For example, the customer may alreadybe considering distributed generation equipmentto meet a portion or all of its electric require-ments. In such instances, cooperative revenuebased on ownership of distributed generationequipment could help defray stranded costsassociated with a customer’s meeting its ownelectric requirements.

The cooperative may also consider joint own-ership of distributed generation equipment witha customer. In such circumstances, the coopera-tive and customer could share in revenuesearned from wholesale transactions or avoid-ance of peak wholesale power charges.

A cooperative may consider installing distrib-uted generation at a customer’s site as part of acustomer retention effort. Such distributed gen-eration could enhance reliability for criticalpower quality loads of the customer. If distrib-uted generation is installed to achieve reliabilityor provide backup capabilities for the customer,the cooperative could charge a standby rate forsuch service. (This standby rate would be inaddition to rates charged for firm service fromthe cooperative.) In other instances, the cooper-ative could install distributed generation at acustomer’s site at no charge to the customer. Insuch instances, the distributed generation couldbe accredited by the cooperative in order tomeet overall system requirements. The distrib-uted generation would simply be located in anarea that allows for the provision of backup ser-vice for a certain customer or customers.

While distributed generation ownership ratesoffer opportunities for both cooperatives andcustomers, it is critical that such opportunitiesbe carefully evaluated. Ownership rates mustrecognize and accommodate two critical princi-ples:

1. Cooperative ownership of distributed gener-ation equipment must comply with provi-sions of all-requirements contracts betweenthe G&T and distribution cooperatives.

2. A cooperative’s decision to own distributedgeneration equipment and offer rates to cus-tomers based on such ownership must

ensure that the cooperative and its otherconsumers are not harmed by such offerings.

Contributions in Aid of ConstructionContributions in aid of construction are oftenassessed to customers when the cooperative’sinvestment in facilities to serve the customerexceeds a determined “normal” amount. A coop-erative may use its contributions in aid of con-struction policy as either an incentive or disin-centive for distributed generation.

For customer-initiated distributed generation,contributions in aid of construction are a meansof ensuring that the customer is paying for thefull cost of service provided by the cooperative.Contributions in aid of construction provide ameans of charging customers up front for exces-sive costs associated with service desired by thecustomer.

Alternatively, if a cooperative is trying toencourage the siting of distributed generation atspecific locations to achieve net system savings,the cooperative can recognize anticipated distri-bution system benefits as a reduction in the con-tributions in aid of construction charge thatwould otherwise be imposed on the customer.While the concept is similar to that of a rebate,there is the opportunity to calculate a credit thatis more site specific than may be possible undera general rebate.

Purchase OptionsThe recent volatility in wholesale markets hascaused some utilities to establish programs thatallow for the purchase of excess capacity fromcustomer-owned distributed generation. In suchcases, a cooperative will prequalify the availabil-ity of customer-owned distributed generationresources for future use. Customer-owned gen-eration can be used in at least two ways bycooperatives:

1. If a cooperative is reaching a situation wheremarket purchases will be necessary to satisfysystem requirements, the cooperative canfirst offer to purchase energy from customerswith excess distributed generation capacity.These purchases allow customers to obtainadditional revenue from their distributedgeneration facilities while at the same time

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allowing the cooperative to purchase energybelow prices it would otherwise pay in acompetitive wholesale market.

2. Purchase options can also be exercised sole-ly for market gain. That is, the cooperativemay have sufficient resources to meet therequirements of its native load customers.However, market prices may be escalatingwell above the cooperative’s productioncosts. In this case, the cooperative couldoffer to purchase energy from customer-owned generation that would be resold inthe wholesale market. Again, the customerreceives additional revenue, and the cooper-ative obtains additional non-member rev-enue for the benefit of all other consumers.

While the above discussion of purchaseoptions focuses on cooperative offers to pur-chase energy from customers, this same conceptcan be pursued in the form of competitive bid-ding. That is, rather than having a cooperativeoffer to purchase energy at a specified price, thecooperative could request competitive bids fromcustomers with distributed generation. A com-petitive bidding process allows customers todefine a discrete economic threshold that meetstheir internal financial requirements. Thisapproach may also allow a cooperative tosecure such energy at a price below what wouldbe offered by the cooperative.

ContractsContracts are another means of ensuring that acooperative will be fully compensated for thedirect costs of providing service to customers.When a cooperative is required to install addi-tional facilities to meet the needs of a customerinstalling distributed generation, contract provi-sions can be used to ensure future revenuestreams are sufficient to cover such cooperativeexpenditures.

Individualized contracts also provide coopera-tives with a case-specific ability to recover costsimposed by a distributed generation unit orcompensate consumers for providing services tothe cooperative. Some activities, costs, and ben-efits can best be addressed through a generalrate schedule, while other activities, costs, andbenefits should be addressed case by case

through a contract. Contracts can be standard-ized to apply, for example, to all consumersoffering peak-shaving service with their distrib-uted generation unit. Or contracts can be indi-vidualized to apply to a specific application. Theneed for contract standardization will likelyincrease as the number of consumers interestedin installing distributed generation increases.Standardization is also important for smaller dis-tributed generation installations, particularlythose in residential applications. Negotiatingindividual contracts is costly for both the con-sumer and the cooperative.

SHARING THE VALUE OF DISTRIBUTEDGENERATIONThe development of distributed generation ratesshould strive to share the value of such distrib-uted generation among all parties. That is,wholesale rates applicable to distributed genera-tion should cover the full cost of providing suchwholesale service, including margin levels com-mensurate with the cooperative’s standardwholesale rates. Similarly, distribution coopera-tive rates applicable to distributed generationshould fully recover the cooperative’s cost ofproviding such service, while recognizing allappropriate cost savings. Like wholesale rates,retail distribution cooperative rates must providesufficient contribution to the cooperative’s over-all operating costs, including margin. Finally, theremaining savings associated with distributedgeneration will accrue to the benefit of the par-ticipating customer. From an economic perspec-tive, the net savings associated with distributedgeneration, compared to service under standardrate schedules, provides the financial incentivefor customers to pursue distributed generation.

EVALUATING REVENUE IMPACTSWhen a cooperative implements a new standardrate, or distributed generation rate, it is impor-tant to evaluate potential net revenue impacts.Customers will readily respond to rate and non-rate incentives. The development of standardrates and distributed generation rates is basedon an analysis of customer classes. While theresulting rates are appropriate for the averagecustomer within each class, such average cus-tomers are the exception. That is, customers will

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likely exhibit load characteristics different fromthe class average. When a specific customermoves from a standard rate schedule to a dis-tributed generation rate schedule, it is very likelythat the cooperative will experience a gain orloss in net revenue. This occurs because thecooperative’s cost of providing service to anindividual customer will not track the cost ofserving the average customer within a class. It isimportant that a cooperative attempt to antici-pate likely customer movement from one rateschedule to another. Such rate migration willlikely result in either a net gain or loss of rev-enue to the cooperative, which will requireother rate changes to ensure that the coopera-tive achieves the overall level of revenue neces-sary to support its operations.

NET METERINGThe “White Paper on Distributed Generation”released by the National Rural ElectricCooperative Association described net meteringas follows.26

“While not clearly or uniformly defined, netmetering rules generally provide that con-sumers with certain self-generation capabil-ities should have a meter that rolls forwardwhen the customer consumes power fromthe grid and rolls backward when the cus-tomer exports power to the grid.”

Under net metering, a customer receives pay-ment for self-generation that reflects the cooper-ative’s full retail rate with no consideration ofthe cooperative’s avoided cost of providing ser-vice to the customer. Accordingly, the customerreceives a payment for self-generation thatexceeds the avoided cost of power supply anddistribution service from the cooperative. Thissubsidy has been used to encourage generationfrom qualifying facilities, but comes at theexpense of all other ratepayers.

While net metering ignores consideration of acooperative’s avoided cost, there may be cir-cumstances where net metering is more eco-nomical than the installation of sophisticatedmetering equipment. For example, installation ofphotovoltaic systems will likely avoid high-costsummer energy and capacity costs. However,under net metering, the customer receives pay-ment based on average annual system costs.While such costs include distribution systemcosts, the avoided wholesale purchases duringthe summer peak hours could exceed the cus-tomer’s payment under net metering.

At least 30 states today have net meteringrequirements, although some do not apply tocooperatives. It is important before a coopera-tive begins to develop its rate schedules for dis-tributed generation that it investigates local andstate regulations. If the cooperative is subject toa net metering obligation, that will need to betaken into account.

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26 National Rural Electric Cooperative Association, “White Paper on Distributed Generation,” January 2000. Available atwww.nreca.org.

Evaluation Process

Distributed generation can encompass many dif-ferent applications and technologies. These dis-tributed generation applications can be eithercustomer-initiated or cooperative-initiated. Inmany cases, customers will install distributedgeneration to address specific needs, eitheroperational (including a need to provide somelevel of on-site power supply during emergen-cies or for enhanced reliability) or financial. Dis-tributed generation may also be considered bycooperatives to address system or market needs.

Despite the potentially confusing array of dis-

tributed generation applications being pursuedby customers and cooperatives, a generally con-sistent process can be followed to guide a coop-erative’s evaluation of costs associated with eachapplication and development of an appropriaterate schedule.

CUSTOMER-INITIATED SCENARIOSCustomer interest in distributed generation isincreasing for both operational and financial rea-sons. Examples of reasons for customer-initiateddistributed generation include the following:


• Generation sufficient to support critical enduses during emergencies

• Generation capable of meeting a portion orall of the customer’s electric requirements

• Generating power for wholesale transactions• Requirements for power quality

Evaluating customer-initiated distributed gen-eration can follow a similar process for a varietyof distributed generation applications:

1. Identify the cooperative services requiredby the customer after the distributed gen-eration is installed. The type of servicesrequired by a customer will vary accordingto the distributed generation application. Forexample, customers installing distributedgeneration only for emergency purposes willcontinue to require the same level of serviceas in the past. The primary issue in the caseof emergency distributed generation relatesto any applicable interconnection require-ments and costs. On the other hand, cus-tomers installing distributed generation tomeet all or a portion of their electric require-ments may want a variety of different coop-erative services. For example, customerswith distributed generation capable of pro-viding their entire electric requirements maywish to obtain coordinated outage servicefrom the cooperative. Coordinated outageservice allows the customer to purchasepower from the cooperative while the dis-tributed generator is receiving periodicscheduled maintenance. In other cases, acustomer may install distributed generationcapable of providing only a portion of itstotal electric requirements. The balance ofthe customer’s electric requirements will beprovided by the cooperative. Finally, cus-tomers with distributed generation may wishto secure either full or partial backup servicein the event that the distributed generation isunexpectedly out of service.

Regardless of the distributed generationapplication, it is critical that all necessarycooperative services be identified so thatresulting costs and potential cost savings canbe determined.

Different rates may be appropriate for

each type of service. While the distributioncooperative’s fixed distribution costs maynot differ much, it can cost the G&T consid-erably more to provide full backup servicethan to provide coordinated outage service.By offering different rates for the differentservices, the cooperative can ensure that dis-tribution and G&T costs are recovered whilesatisfying regulators and distributed genera-tion proponents that it is not improperly dis-couraging distributed generation.

2. Determine necessary interconnectionrequirements to ensure the safety and reli-ability of the cooperative system. Suchinterconnection requirements will likely dif-fer depending on the intended operation ofthe distributed generation. For example,interconnection requirements to ensure safe-ty will be different for generation that isoperated in isolation from the cooperativegrid as compared to generation that operatesin parallel with the grid. Beyond determiningthe technical interconnection requirements, itis necessary to identify cost responsibility forsuch requirements. In such cases, the distinc-tion between customer responsibility andcooperative responsibility for interconnectioncosts should be determined by asking a basicquestion: “Would these costs have been in-curred by the cooperative in the absence ofthe customer-installed distributed generation?”

3. Evaluate the cooperative’s costs of provid-ing service. As discussed previously, thesecosts will include both wholesale powersupply costs (which could include wholesalecapacity, energy, transmission, and ancillaryservices) as well as distribution system costs.The distribution system costs will be com-posed of both direct costs and indirect allo-cated costs as discussed on pages 34-35. It isimportant to note that individual cooperativecircumstances will impact cost analysis. Insome cases, cooperatives have a long-stand-ing tradition of developing all rates based onfully allocated cost of service. In other cases,cooperatives have implemented certain ratesbased on incremental net costs/benefits.Either method may be used in the establish-ment of rates applicable to distributed gener-ation.

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4. Determine whether there are any potentialcost savings associated with the anticipateddistributed generation. Depending on theanalysis approach, the wholesale power costsavings may already be incorporated in theidentification of net wholesale power supplycosts described in Step 3. Beyond wholesalepower, determine whether any other coop-erative cost savings exist. As with costsincurred, analyze potential savings separate-ly for different classes of distributed genera-tion applications that meet specific criteria.For example, the cooperative can plan onreduced wholesale demand charges onlyfrom those distributed generation facilitiesthat are operated pursuant to a contract fordemand reduction. Or the cooperative canplan on reduced wholesale demand chargesfrom distributed generation based on a pre-dicted response to a retail rate with a demandadder. The cost savings will depend on thetype of distributed generation, the applicationfor which it is installed, and the program es-tablished by the cooperative to encouragedesired operation of the distributed generation.

5. Consider various rate and non-rate optionsthat will provide for the cooperative’srecovery of its cost of service and theaccomplishment of other objectives. In thisregard, it is important to note that, while dif-ferent rate designs may yield the sameaggregate cooperative revenue, the impacton individual customers can differ. Thesedifferences in turn can provide either incen-tives or disincentives for distributed genera-tion. Anticipating the likely customerresponse to a distributed generation rate isaccomplished by comparing various distrib-uted generation rate options with the stan-dard rates now available to customers. Thatis, a cooperative can calculate an individualcustomer’s annual bill under its present stan-dard rate schedule and compare this to theestimated bill under a proposed distributedgeneration rate. The resulting savings willprovide the necessary financial incentive toa customer considering distributed genera-tion. This level of savings for individual cus-tomers can vary depending on the relativecharge included in each respective rate com-

ponent (i.e., monthly charge, energy charge,demand charge). Rates should be designedto recover costs and provide incentives foreconomically justified customer action.

Beyond rate considerations, also considernon-rate components to provide targetedincentives for distributed generation in spe-cific geographical locations or to encourageparticipation from customers with certainload characteristics.

6. Develop a specific tariff or contract thatreflects the rate and necessary conditionsof service. It is frequently observed that ratedesign is an art, not a science. Accordingly,many approaches may be taken to develop-ing rates applicable to distributed genera-tion. In some cases, a cooperative maychoose to develop customized contracts foreach distributed generation application. Thiscontract approach allows for customizationbased on each individual customer’s circum-stance. This ensures that resulting rates andcost of service properly reflect identifiedcosts and cost savings in each circumstance.For some cooperatives, this approach maywork well when very few distributed gener-ation installations are expected. In caseswhere many customers are expected toinstall distributed generation, however, thecontract approach can be time-consumingand costly for both the cooperative and cus-tomer. Rather than establish contracts, othercooperatives establish standard rate sched-ules for distributed generation within certainsize thresholds. This approach works wellwhen it is expected that there is general sim-ilarity among customers within a rate class.Further, standard rate schedules provide rateand conditions of service certainty for devel-opers and customers, while potentially low-ering administrative costs for the coopera-tive. A description of rate schedule clauses isprovided on pages 51-54.

7. Determine whether any other supportingdocuments are necessary. Examples ofsuch supporting documents could include:

• Interconnection requirements• Operating policies• Contract documents

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The general steps described above allow acooperative to systematically evaluate the ser-vices and costs associated with any distributedgeneration application that may be initiated bycustomers. While the specific circumstances of acooperative system and distributed generationapplication may vary, this process allows for asystematic review of relevant issues and devel-opment of appropriate rate and/or non-rateoptions.

COOPERATIVE-INITIATED SCENARIOSA number of circumstances exist where a distri-bution cooperative and/or G&T may want toencourage distributed generation:

• Lower peak power costs.• Lower market risks.• Avoid or defer distribution system expansion.• Provide voltage support.• Provide additional opportunities for market

sales.• Encourage renewable resources.

Like customer-initiated scenarios, cooperative-initiated scenarios can encompass a wide variety

of different distributed generation technologiesand applications. Despite this variety, however,a consistent process can be followed to assist inthe evaluation of a specific application anddevelopment of appropriate rates. This processis very similar to that outlined for customer-initi-ated distributed generation. The basic differenceis in the identification of serving and cost issues:

1. The cooperative must identify what specif-ic service or cost issue it wishes to addresswith distributed generation. For example, adistribution cooperative may be seekingways to lower peak power cost, or a G&Tmay be seeking alternatives to lower marketrisks associated with wholesale purchases.Depending on the issue being addressedand the anticipated distributed generationapplication desired, the cooperative mustthen develop a list of services that customerswill require when installing and operatingthe necessary distributed generation facili-ties.

2. The remaining steps are similar to thosedescribed for customer-initiated distrib-uted generation.

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Examples The following are examples of cooperativeobjectives associated with distributed generationthat identify rate and non-rate options that canbe employed to achieve these objectives. Theseexamples are provided for illustrative purposesonly. Distribution cooperatives and G&Ts faceunique cost and service circumstances that areimpacted differently when various distributedgeneration applications are installed. Cost analy-sis and rate design must recognize that one sizedoes not necessarily fit all cooperatives. Beforeaddressing the rate issue, the G&T and its mem-ber distribution systems must determine thepotential impact of distributed generation onwholesale power cost and distribution deliverycost. Cooperatives must determine whether dis-tributed generation is something that the coop-eratives want to encourage or discourage undervarying circumstances. Will distributed genera-tion be helpful or harmful to the cooperativeand its consumers?

The following examples are intended to illus-

trate how rates can be approached once thesebasic premises are identified. The followingexamples will be considered:

1. Ensure full cost recovery for customer-initiat-ed distributed generation.

2. Avoid or defer distribution system investments.

3. Promote renewable energy.4. Reduce wholesale peak demand costs.

EXAMPLE #1: FULL COST RECOVERYExample 1 assumes that customer interest in dis-tributed generation is increasing as a result ofboth operational and financial considerations.While the cooperative in the example may bene-fit from such customer-initiated installations, it isimportant that the cooperative establish rates toprovide full cost recovery for such customer-ini-tiated distributed generation. This full costrecovery can be accomplished through a num-ber of rate and non-rate provisions:


1. Cost-based rates for standard service. In anumber of circumstances, rates for standardservice can deviate, sometimes significantly,from cost-of-service principles. That is,monthly charges, energy charges, anddemand charges may be above or below thelevel necessary to recover costs allocated tothese components. Such imbalances in ratecomponents can hinder full cost recoverywhen customers install distributed genera-tion. Cost-based rates promote full costrecovery and provide appropriate price sig-nals for distributed generation.

2. Monthly charges that fully recover directcosts. If direct costs are reasonably uniformamong all customers participating in a dis-tributed generation rate, then such costs maybe recovered through the monthly charge.This ensures consistent treatment among allsimilarly situated customers and providesrevenue certainty for cooperatives. However,if direct costs are expected to vary signifi-cantly from customer to customer, thesecosts should be recovered through a uniquefacility charge applicable to each individualcustomer. The decision to impose a commonor unique monthly charge must balanceadministrative efficiency against equity andfairness to individual customers.

3. Peak hour energy charges. A cooperativemay implement on-peak and off-peak ener-gy charges that encourage the use of distrib-uted generation on its system during thecooperative’s peak hours. This peak energypricing encourages customers to reducedemand on the distribution system duringhigh use periods. Peak hour energy chargesare particularly appropriate if the customerrequires electric service predominantly dur-ing periods of high-cost production or sys-tem loading.

4. Seasonal energy charges. Seasonal energycharges can be applied to customers withdistributed generation. Such charges allowthe cooperative to reflect variations in pur-chased energy costs throughout the year.Depending on the magnitude of suchcharges, customers may select to operatedistributed generation during seasons whencosts are higher. Or, if distributed generation

is mostly available during low-cost periods(e.g., wind generation in spring and fallmonths), then the benefit to the customerscorresponds to this lower value.

5. Real-time pricing. Real-time pricing pro-vides an opportunity to encourage cus-tomers to use distributed generation facilitieswhen energy prices become extreme. Thisallows customers to avoid purchasing energyduring the highest priced hours and achievean overall lower delivered cost of energy,while at the same time allowing the cooper-ative to avoid high-cost purchases or opera-tion of generating plants with high variablecosts. Since real-time pricing requires signifi-cant cooperative administrative efforts andexpensive metering, this option is only prac-tical for very large customers.

6. Coincident demand charges. Coincidentdemand charges allow a distribution cooper-ative to differentiate rates as they relate towholesale power costs. That is, coincidentdemand charges can reflect wholesale ratespaid by distribution cooperatives. A pass-through of these price signals will encouragecustomers to use distributed generation attimes when wholesale coincident demandcharges are highest. Coincident demandcharges can provide a close link betweencustomer load characteristics and wholesalepower supply costs.

7. Contributions in aid of construction.Contributions in aid of construction are oftenassessed to customers when the coopera-tive’s investment in facilities to serve the cus-tomer exceeds a determined “normal”amount. Contributions in aid of constructionare particularly useful for ensuring that acooperative is held harmless when a cus-tomer decides to install distributed genera-tion.

8. Contracts. Contracts are another means ofensuring that a cooperative will be fullycompensated for the direct cost of providingservice to customers with distributed genera-tion. Contract provisions can be used toensure future revenue streams are sufficientto cover cooperative expenditures made on behalf of individual customers. Con-tracts are a useful approach when expected

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customer distributed generation installationsare limited.

9. Ownership rates. Ownership rates offer thecooperative an opportunity to partner withcustomers that are interested in installingdistributed generation for either operationalor financial considerations. The cooperativemay, under certain circumstances, own thedistributed generation equipment capable ofmeeting a customer’s full or partial require-ments. The cooperative may also considerinstalling distributed generation for reliabilitypurposes at the customer site. It is criticalthat such opportunities be carefully evaluat-ed.

EXAMPLE #2: AVOID OR DEFER DISTRIBUTIONSYSTEM INVESTMENTSExample 2 assumes that the cooperative hasdetermined that certain distributed generationcan be used to avoid unnecessarily high cooper-ative investments in new distribution plant. Rateand non-rate components can be employed toencourage distributed generation to achieve dis-tribution benefits as follows:

1. Coincident demand charges. Coincidentdemand charges allow a distribution cooper-ative to differentiate rates as they relate toperiods or hours of high distribution systemloading. A coincident demand chargeimposed during high use periods of the dis-tribution system can encourage customers touse distributed generation at such times toreduce demand and avoid or defer the needto increase distribution feeder capacity.

2. Feeder-specific demand charge. If the distri-bution cooperative wants to defer expansionor upgrade of a specific distribution feeder,it can design a demand charge specific tothat feeder that encourages use of distrib-uted generation and reduces load on thefeeder at peak hours. While such approach-es may be cost-justified, they may be per-ceived as unfair by customers or politicalsubdivisions eager to promote growth.

3. Seasonal peak demand charge. If a cooper-ative wants to encourage the use of distrib-uted generation during high distribution sys-tem demand periods, seasonal demand

charges are a means of encouraging distrib-uted generation operation. This option rec-ognizes that distribution demand is highestin a particular season, but is likely too broadsince it treats all hours in the season thesame while demand is highest only during afew specified hours of the day or season.

4. Rebates. Rebates provide a targeted financialincentive that can be applied in well-definedcircumstances. Accordingly, rebates can betargeted to avoid or defer distribution systeminvestments by encouraging distributed gen-eration installations in certain geographicalareas or operation under certain circum-stances.

5. Deaveraged distribution credits. Deaver-aged distribution credits provide an opportu-nity to more specifically target incentives toavoid or defer distribution system invest-ments in potentially high-cost situations.However, such credits may be difficult forcustomers to understand and could be per-ceived as unreasonable.

6. Contracts. Individualized contracts can bedesigned to ensure that distributed genera-tion is installed in a geographical area bene-ficial for the cooperative and operated whenneeded to achieve cost savings/system benefits.

7. Ownership rates. A cooperative may con-sider ownership rates as a means of avoid-ing unnecessarily high cooperative invest-ments in new distribution plant. Such own-ership could belong with a customer or besolely by the cooperative. Cooperative own-ership of distributed generation in these cir-cumstances ensures that the equipment willbe operated to meet distribution systemneeds. It is critical that such opportunities becarefully evaluated.

EXAMPLE #3: PROMOTE RENEWABLE ENERGYIn some areas, customers, legislatures, or regula-tory agencies are very interested in promotingenergy use from renewable resources. Example 3assumes that a cooperative seeks to promoterenewable energy in response to a mandate orto provide renewable energy to customers inter-ested in purchasing renewables at a premium.The following rates and non-rate components

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can be used to promote the installation ofrenewable resource distributed generation:

1. Low monthly charge. A relatively lowmonthly charge means that remaining fixeddistribution costs are generally recoveredfrom small consumers through a volumetricenergy charge. This means that smaller con-sumers can install renewable distributedgeneration and achieve billed energy savingsthat reflect both variable (avoided) and fixed(unavoidable) distribution costs. This tendsto encourage small customers to install smallrenewable facilities like photovoltaics orwind generation. However, a low monthlycharge will have an insignificant impact onencouraging larger distributed generationprograms.

2. Seasonal energy charges. A consumer whoinstalls a solar panel could see significantsavings in his/her bill if he/she is put on aplan that raises the cost of power duringsummer afternoons, when the generator isworking well, and lowers the cost of energyat night or in the winter when he/she takespower from the grid. While this option canencourage certain distributed generation, itcould hurt some customers on standard rateschedules. If the desire is to encouragerenewables, it should be targeted at distrib-uted generation.

3. Incentive energy rates. Cooperatives havethe option of purchasing renewable energyat rates higher than avoided cost. While suchpurchases are not justified on a cost basis,these purchases may be appropriate if theenergy can be resold to customers on a vol-untary basis with a renewable premium.

4. Rebates. Rebates provide a targeted financialincentive that can be applied in well-definedcircumstances. Accordingly, rebates can beused to specifically encourage the installa-tion of renewable resource distributed gen-eration.

5. Contracts. Contracts are another means ofencouraging renewable resource distributedgeneration. Cooperatives can arrange bycontract with distributed generation ownersto purchase renewable energy for sale toother customers at a renewable premium.

EXAMPLE #4: REDUCE WHOLESALE PEAKDEMAND COSTSWholesale power supply costs are strongly influ-enced by peak customer demand. Distributioncooperatives and G&Ts can work together topromote distributed generation as a means ofreducing customer demand during peak times.Example 4 assumes that a G&T and its distribu-tion cooperatives have identified beneficial dis-tributed generation applications that can reducecosts for participating customers while benefit-ing, or holding harmless, all remaining con-sumers. Rate and non-rate components can beemployed to achieve this objective as follows:

1. Peak hour energy charges. A cooperativemay implement on-peak and off-peak ener-gy charges that encourage the use of distrib-uted generation on its system during thecooperative’s peak hours. This peak energypricing encourages customers to reducedemand and energy use during predictablyhigher cost periods.

2. Seasonal energy charges. Seasonal energycharges can be applied to customers withdistributed generation. Such charges allowthe cooperative to reflect variations in pur-chased energy costs throughout the year.Depending on the magnitude of suchcharges, customers may select to operatedistributed generation during seasons whencosts are higher.

3. Real-time pricing. Real-time pricing pro-vides an opportunity to encourage cus-tomers to use distributed generation facilitieswhen energy prices become extreme. Thisallows customers to avoid purchasing energyduring the highest priced hours and achievean overall lower delivered cost of energywhile at the same time allowing the cooper-ative to avoid high-cost purchases or opera-tion of generating plants with high variablecosts. Since real-time pricing requires signifi-cant administrative efforts and expensivemetering, this option is only practical forvery large customers.

4. Coincident demand charges. Coincidentdemand charges allow a cooperative to dif-ferentiate rates as they relate to wholesalepower costs. That is, coincident demand

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charges can reflect wholesale rates paid bydistribution cooperatives. A pass-through ofthese price signals will encourage customersto use distributed generation at times whenwholesale coincident demand charges arehighest. Alternatively, participation in a ratecould require that distributed generation bedispatchable by the cooperative. Coincidentdemand charges can provide a close linkbetween customer load characteristics andwholesale power supply costs.

5. Seasonal peak demand charge. If a cooper-ative wants to encourage the use of distrib-uted generation during high G&T demandperiods, seasonal demand charges are ameans of encouraging distributed generationoperation. This seasonal variation can becombined with coincident demand charges,where justified on a cost basis, to amplifythe price signal to customers.

6. Rebates. Rebates provide a targeted financialincentive that can be applied in well-defined

circumstances. Accordingly, rebates can betargeted to encourage distributed generationinstallation and operation by customers withdefined load characteristics, resulting inreduced wholesale production or purchasecosts.

7. Contracts. Contracts are another means ofensuring that distributed generation isinstalled and operated to achieve reducedwholesale power costs. Contracts can bedesigned to compensate consumers to prop-erly locate and operate distributed genera-tion in a way that benefits the cooperative.

8. Ownership rates. The cooperative couldpursue joint ownership of distributed gener-ation as a means of reducing demand duringpeak times. In this circumstance, the cooper-ative and customer could share in the sav-ings of reduced peak wholesale powercharges. It is critical that such opportunitiesbe carefully evaluated.

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Rate Schedule Clauses

OVERVIEWAny review of electric cooperative rate sched-ules reveals that, while there are basic similari-ties in rate schedule content, there can also besignificant content differences. The developmentof electric cooperative rate schedules is influ-enced by two important factors:

1. Whether a cooperative is subject to regula-tion by a state agency versus being self-governed

2. The cooperative’s preference for includingspecific details in a rate schedule versusincluding these details in policies or otherservice and operating condition documents

State regulatory agencies not only approverates for the utilities they regulate but also influ-ence the content of rate schedules. Accordingly,regulated utilities will often include similarclauses in rate schedules approved by a com-mission. Electric cooperatives that are self-gov-erned do not experience these same regulatoryinfluences in the development of rate schedules.However, cooperatives generally have individualpreferences regarding the level of detail to

include in rate schedules. These individualcooperative preferences influence the content ofdistributed generation rate schedules.

Developing a distributed generation rateschedule will be influenced by the above factorsas well as consideration of the specific servicebeing offered. Each of the many different ser-vices will require unique tariff language toaddress specific issues relating to rate, service,and operating requirements.

A number of tariff provisions need to be con-sidered when establishing distributed generationservice rate schedules. These rate schedule pro-visions have been categorized as either “stan-dard” or “other.” Standard Tariff Provisionsbelow reviews tariff language commonly used ina wide variety of electric service rate schedules.The subsection on Other Tariff Provisions liststariff language that is more directly related todistributed generation as well as other tariff pro-visions that are used less frequently than thoseidentified as “standard.” Finally, page 55describes points to consider as a cooperativedevelops a specific distributed generation rateschedule.

Examples of tariff provisions are presented in


Appendix B. This information is provided as anexample only. Specific tariff language is oftenunique to each cooperative.

The Internet provides another useful resourcefor examining electric utility rate schedules.Many utilities, especially IOUs, include the fulltext of all rate schedules somewhere within theirWeb site. A useful Internet service called “TheUtility Connection” provides a listing and linksto a wide variety of utility Web sites. This sitepresently includes 155 IOUs.

STANDARD TARIFF PROVISIONSA review of rate schedules offered by electriccooperatives reveals a number of tariff provi-sions that are included in a wide variety of rateschedules. These tariff provisions are “standard”and include language covering the followingmatters:

• Availability• Applicability• Character of service• Monthly rate• Minimum charge• Definitions• Billing/payments• Power factor• Taxes• Late charges• Power cost adjustments

While the language for these standard provi-sions will vary among cooperatives, examplesare provided in Appendix B. This information isprovided for illustrative purposes only and is notmeant to endorse specific language.

AvailabilityAvailability clauses specify the type of customer(residential, non-residential, interruptible, stand-by, etc.) that qualifies for the specific rate sched-ule. These clauses may also describe geographi-cal locations where the rate is available. In addi-tion, minimum qualifying load thresholds interms of kW or kVA can be specified.

ApplicabilityApplicability clauses are often used in conjunc-tion with availability clauses. In such cases, the

availability language will deal with type of cus-tomer, geographic area, and location of ade-quate facilities to provide service. The applica-bility clause will then cover issues such as cus-tomer load characteristics, delivery points, anduse of service.

Character of ServiceCharacter of service, sometimes referred to astype of service, simply specifies whether thecooperative is providing single-phase or three-phase service, the voltage level, and whetherthis service is intended for delivery at secondary,primary, or substation levels.

Monthly RateThe monthly rate clause describes the variousapplicable electric cooperative charges.

Minimum ChargeAs the name implies, minimum charge clausesspecify the applicable monthly minimum chargethe cooperative will bill a customer. Minimummonthly charges for non-residential customersusually include any applicable facilities chargeand/or monthly service charge, along with ademand charge related to a specified percentageof the customer’s highest applicable demandduring the previous 12 months. Minimumcharges help ensure that the cooperativereceives a specified amount of revenue permonth to help cover fixed capital costs associat-ed with extending service to individual cus-tomers.

DefinitionsIt is often useful to include definitions of specif-ic terms used within the rate schedule. Thesedefinitions are useful for both customers andcooperative staff responsible for administeringthe rate schedule. Items commonly definedinclude determination of coincident demand,measurement of non-coincident demand, identi-fication of seasonal peak periods, identificationof on-peak and off-peak hours, and other defini-tions relating to specific distributed generationservices.

Billing/PaymentsBilling and payment clauses specify when bills

5


will be rendered each month along with thetime within which such bills must be paid by thecustomer.

Power FactorPower factor clauses specify the minimumacceptable threshold for lagging reactive kilo-volt-ampere-hours during the month. Customerswith power factors below this threshold willreceive corresponding adjustments in billingdemand.

TaxesA tax clause indicates that changes in taxesapplicable to electric service will be passedthrough to customers accordingly. While suchclauses formerly dealt exclusively with sales tax,these clauses are increasingly being expanded toinclude any new taxes that may be imposed ondistribution or transmission service.

Late ChargesClauses for late payment charges specify theapplicable interest rate, or minimum dollarcharge, that will be applied to outstanding bal-ances not paid by a specified due date.

Power Cost AdjustmentPower cost adjustment clauses allow distributioncooperatives to adjust their retail bills forincreases or decreases in wholesale power costsapplicable to such retail service. These clausesallow distribution entities to recover changes inwholesale power costs on a current basis with-out the need to adjust base retail rates.

OTHER TARIFF PROVISIONSBeyond the standard tariff provisions identifiedabove, distributed generation rate schedulesinclude other tariff provisions that directly relateto the specific distributed generation serviceoffered by the cooperative. In addition, othermiscellaneous tariff provisions are used less fre-quently than those identified as “standard.”These “other” tariff provisions can include thefollowing matters:

• Conditions of service• Rules• Special conditions

• Metering• Maintenance periods• Dispute resolution• Interconnection• Hours of interruption• Notice of interruption• Penalties• Contributions in aid of construction• Term• Parallel operation

As with standard tariff provisions, the lan-guage for these other tariff provisions will varyamong cooperatives. Examples of these othertariff provisions are also provided in Appen-dix B. This information is provided for illustra-tive purposes only and is not meant to endorsespecific language.

Conditions of ServiceConditions of service clauses are intended todescribe the cooperative’s provision of serviceand customers’ responsibilities for ensuring thattheir load requirements conform with the serviceoffered by the cooperative.

RulesCooperatives will often reference the existenceof general rules and regulations contained inother tariff sheets, policies, or service documentsas well as applicable rules of state regulatoryauthorities.

Special ConditionsLanguage dealing with special conditions can becomparable to conditions of service clauses. Ingeneral, however, special condition languagetends to be focused on customer responsibilitiesrather than describing cooperative service condi-tions.

MeteringMetering clauses describe the enhanced level ofmetering that is necessary for the specific serviceoffered. These clauses also describe cooperativeand customer responsibility for such meteringcosts.

Maintenance PeriodsFor customers receiving service under supple-

5


mental, maintenance, backup, or standby servicerates, cooperatives will often define allowablemaintenance periods during a calendar year.Such language requires customers to schedulemaintenance periods during months whenwholesale power costs are low and there is suf-ficient generating capacity to provide service tothese customers.

Dispute ResolutionIn some situations, cooperatives specify disputeresolution procedures for resolving differencesregarding application of a rate schedule. Suchprovisions may be more common for utilitiesthat are regulated. In any event, such languageestablishes a process for resolving differences.

InterconnectionWhenever a customer installs distributed genera-tion, it is important to ensure that such installa-tions are coordinated with the distribution coop-erative. Such coordination ensures that installa-tions do not compromise the reliability or safetyof the distribution system. Cooperatives general-ly adopt interconnection requirements toaddress these issues. While such documents areseparate from rate schedules, the existence ofthese interconnection requirements is sometimesreferenced within a distributed generation rateschedule.

Hours of InterruptionCustomers participating in interruptible rates areoften informed of the circumstances underwhich a cooperative will implement interrup-tions. These hours of interruption clauses cancover circumstances such as capacity needs ofthe cooperative, transmission constraints, or cir-cumstances encountered at the local distributionlevel.

Notice of InterruptionNotice of interruption clauses specify theadvance notice that the cooperative will provideto a customer prior to the interruption of ser-vice. While cooperatives strive to provideadvance notice of interruptions, these clausesalso indicate that interruption may be imple-mented without notice. These clauses will alsoindicate that the customer should provide the

cooperative with names and contact informationregarding such interruptions.

PenaltiesDistributed generation rates reflect some level ofsavings to the customer compared to standardfirm service rates. In the event that a customer isnot able to operate its distributed generationequipment in a manner consistent with the dis-tributed generation rate schedule, penalties maybe imposed. Penalty clauses will specify theconditions under which penalties may beassessed to a customer and the amount of suchpenalties.

Contributions in Aid of ConstructionCooperative rates generally include some baselevel of investment to serve customers underrespective rate schedules. In some circum-stances, a cooperative may be required to installfacilities in excess of capital costs recovered inrates. In such circumstances, contributions in aidof construction clauses define the level of invest-ment and a threshold beyond which customerswill be required to pay for plant investment ontheir behalf. Beyond plant investment, suchclauses may specify that customers bear costsfor communication equipment associated withautomated metering.

TermIn an effort to keep customers from movingfrom one rate schedule to another to takeadvantage of short-term opportunities, it is com-mon to specify a minimum term of service. Oneyear is a common minimum term for such provi-sions. These clauses can also reference arequirement for customers who must enter intoa contract for distributed generation service.

Parallel OperationWhen customers operate distributed generationin parallel with the distribution system, coopera-tives will reference requirements for such opera-tion under parallel operation clauses. Theseclauses may reference interconnection require-ments and ensure that any such parallel opera-tion can only take place upon written approvalfrom the cooperative.

5


PREPARING A SPECIFIC RATE SCHEDULEAs was stated at the beginning of this section,any review of electric rate schedules revealsthat, while there are basic similarities in rateschedule content, there can also be significantcontent differences. These differences reflect thefollowing factors:

• Requirements and rates from wholesalepower suppliers

• Conditions of service unique to the distrib-uted generation service being offered

• Applicable regulatory considerations• Local preferences regarding rate schedule

detail versus reference to other supportingmaterial

When preparing a distributed generation rateschedule, it is important to consider all aspectsof the service being offered. The range of dis-tributed generation applications will eachimpose different requirements on the wholesalepower supplier and the distribution cooperative.A distribution cooperative must coordinate suchdistributed generation rates with any applicablewholesale supplier requirements and rate provi-sions. It is also important to consider any uniqueconditions imposed by the anticipated service.

For those cooperatives subject to regulatoryauthority, it is important to be aware of regulato-ry agency practices regarding rate scheduledesign applicable to distributed generation.

Beyond regulatory agency practices, a distribu-tion cooperative must also be aware of anyapplicable state rules regarding the anticipatedservice. Knowledge of applicable state agencypractices and state rules can provide for asmoother development of new rate schedules.

Finally, it is important for a cooperative toconsider its history and preference regardingrate schedules. This includes application of stan-dard provisions found in other rate schedulesoffered by the cooperative. Beyond these stan-dard provisions, other tariff provisions must beincluded to address the unique service condi-tions identified for the specific distributed gener-ation application being considered. Finally, thedistribution cooperative needs to ensure that theschedule recognizes, and is consistent with,other internal policies, interconnection require-ments, and contract documents applicable todistributed generation.

A rate schedule is simply one componentamong many other potential supporting docu-ments applicable to distributed generation. Ingeneral, the level of detail provided in a distrib-uted generation rate schedule should be suffi-cient to cover necessary requirements whileconsidering other existing supporting docu-ments, without being excessive. Striking this bal-ance will ensure that the rate schedule is rela-tively easy for customers to understand andcomply with as well as ensuring smooth admin-istration by cooperative staff.

5

Sample IOU Rate Schedu les – 57

Sample IOU Rate SchedulesA


A

60 – Append ix A

A


A

62 – Append ix A

A


A

64 – Append ix A

A


A

66 – Append ix A

A


A

68 – Append ix A

A


A

70 – Append ix A

A


A

72 – Append ix A

A

APPLICABILITYTo electric service up to 50,000 kVA for industri-al purposes and for other electric service forwhich no specific rate schedule is provided, ofwhich at least half of load must be able to standinterruption. All service is supplied through onemetering installation at one point of delivery.Service hereunder is subject to any of theCompany’s rider schedules that may be applica-ble. Service under this schedule shall not beresold, sub-metered, used for standby, or sharedwith others. Interruptible Power may be sup-plied when, as and if Company, in its judgment,has such power available for the sale but onlyto customers having adequate generating equipment.

Source: Entergy New Orleans, Inc.

AVAILABILITYAvailable to any non-residential customer forgeneral service who agrees to control demandto a predetermined level whenever required byCompany. Availability is restricted to customerswith a minimum controllable demand of 50 kW.

Source: Northern States Power Company

CHARACTER OF SERVICEAlternating current, 60 cycles, at the voltage andphase of the Company’s established secondarydistribution system immediately adjacent to theservice location.

Source: Kansas City Power & Light Company

LATE PAYMENT CHARGEA one percent (1%) per month late paymentcharge will be applied to outstanding chargesunpaid 20 days after the date of billing.

Source: Northern States Power CompanyWisconsin

MINIMUM CHARGEThe monthly minimum charge is the applicablefacilities charge.

Source: Wisconsin Electric Power Company

PAYMENTThe Net Monthly Bill is due and payable eachmonth. The Gross Monthly Bill, which is the NetMonthly Bill plus 2%, becomes due after theGross Due Date shown on the bill, which shallnot be less than twenty (20) days from the dateof billing.

Source: Entergy New Orleans, Inc.

POWER COST ADJUSTMENTThe Power Cost Adjustment (PCA) willincrease/decrease by 1/100¢ per kilowatt-hourfor every corresponding 1/100¢ increase/decrease in the cooperative’s total projectedpower cost per kilowatt-hour. The referencepoint for measuring such changes is a basepower cost of 4.19¢ per kilowatt-hour sold.Total projected power costs for this service willinclude all costs for power supply excludingload management programs. This adjustmentwill be calculated and applied monthly on customer bills.

Source: East Central Energy

Examples o f E lect r i c Ta r i f f Prov is ions – 73

Examples of Electric Tariff Provisions

Standard Tariff Provisions

B

Other Tariff Provisions

74 – Append ix B

BPOWER FACTORThe customer shall at all times take and usepower in such manner that the average powerfactor shall be as near 100% as possible, butwhen the average power factor is less than 90%,then the billing demand shall be determined bymultiplying the greatest 15-minute load duringthe month for which bill is rendered by 90% anddividing the product thus obtained by the aver-age power factor expressed in percent.

The average power factor is defined to be thequotient obtained by dividing the kilowatt-hoursused during the month by the square root of thesum of the squares of the kilowatt-hours usedand the lagging reactive kilovolt-ampere-hourssupplied during the same period. Any leadingkilovolt-ampere-hours supplied during the peri-od will not be considered in determining theaverage power factor.

Source: Northern States Power CompanyWisconsin

TAXESThe rates set forth are based on taxes as ofJanuary 1, 1991. The amount of any increase inexisting or new taxes on the transmission, distri-bution, or sales of electricity allocable to saleshereunder, excluding real and personal propertytaxes already recovered through the RTA, shallbe added to the above rate as appropriate.

Source: Dakota Electric Association

DISTRIBUTION FACILITIESAny investment in additions or changes to theCompany’s distribution facilities required to pro-vide auxiliary service (in excess of such invest-ments normally made by the Company to pro-vide equivalent service to the customer) will bepaid by the customer before the interconnectionof Company and customer facilities. In addition,when necessary, the cost of communicationsequipment, such as telemetering or telephone,will be paid by the customer.

Source: PECO Energy Company

Conditions of ServiceThe Company reserves the right to curtail ser-vice to the customer at any time and for suchperiod of time that in the Company’s sole judg-ment the operation of its system requires curtail-ment of customer’s service. Company will not,however, request customer to curtail load underthe terms of this paragraph to less than 25 per-cent of customer’s contract capacity.

The Company shall make available full con-tract capacity requirement of the customer for atleast 145 hours during each calendar week andfor at least 630 hours during each billing month.

This limit shall not apply during a period ofextended emergency experienced by theCompany.

The Company will endeavor to provide to thecustomer as much advance notice as possible ofthe interruptions or curtailments of service here-under. However, the customer shall interrupt orcurtail service within ten minutes if so requested.

Customers may, at their option, provide auxil-iary switching in their plant for the purpose ofsubdividing the interruptible load so that if theCompany requests a reduction in load ratherthan a complete interruption, such reductionmay be accomplished by the customer whenthe Company so requests. In the event the cus-tomer requires power service which is not sub-ject to interruptions as provided for under thistariff, such service either (a) shall be separatelysupplied and metered under the provisions of atariff applicable to the type of service which thecustomer requires or (b) shall be billed underthe provisions of Tariff I.P.

The customer shall own, operate, and main-tain all necessary substation and appurtenancesthereto for receiving and purchasing all electricenergy at the delivery voltage. All telemetering


Band communications equipment within the cus-tomer’s premises required for interruptible ser-vice shall be paid for by the customer and shallbe owned and maintained by the Company.

If the customer fails to interrupt or curtailload as requested by the Company, theCompany shall bill the entire billing demand at arate equal to three times the applicable firm ser-vice demand charge for that billing month. TheCompany further reserves the right to discontin-ue service under this tariff for a 12-month periodafter two failures by the customer to interrupt orcurtail on a timely basis in any 12 consecutivemonths and will thereafter bill the customerunder the applicable firm service tariff.

No responsibility of any kind shall attach tothe Company for, or on account of, any loss ordamage caused by or resulting from any inter-ruption or curtailment of this service.

Source: Indiana Michigan Power Company

DISPUTE RESOLUTION PROCEDUREAny customer who disputes a determination orinterpretation made by the Company under thisrider may deliver a written notice of such dis-pute to the customer’s service representative atthe Company. The Company will respond to thenotice in writing within 20 working days.

Disputes between the Company and the cus-tomer may be presented to the Michigan PublicService Commission for informal resolution.

Any customer who disputes a determinationmade by the Company under this rider may atany time file a formal complaint with the Officeof the Secretary of the Michigan Public ServiceCommission.

Source: The Detroit Edison Company

HOURS OF INTERRUPTIONAll electric power delivered hereunder shall besubject to curtailment on order of the Company.Customers may be ordered to interrupt onlywhen the Company finds it necessary to do soeither to maintain system integrity or when theexistence of such loads shall lead to a capacitydeficiency by the utility. A System IntegrityInterruption Order may be given by the Com-pany when the failure to interrupt will con-tribute to the implementation of the rules for

emergency electrical procedures under Rule B-3.7. A Capacity Deficiency InterruptionOrder may be given by the Company whenavailable system generation is insufficient tomeet anticipated system load.


INTERCONNECTIONPrior to interconnection, the customer-generatormust execute and comply with the requirementsof PG&E’s “Interconnection Agreement for NetEnergy Metering for Residential or SmallCommercial Solar or Wind Electric GeneratingFacilities of 10 kW or Less,” (Form 79-854). Thecustomer-generator must meet all applicablesafety and performance standards established bythe National Electrical Code, the Institute ofElectrical and Electronics Engineers, and accred-ited testing laboratories such as UnderwritersLaboratories and, where applicable rules of theCalifornia Public Utilities Commission regardingsafety and reliability.

Source: Pacific Gas and Electric Company

MAINTENANCE PERIODSA customer may specify, subject to conditionsbelow set by the Company, up to 20 on-peakdays during a year as maintenance days. Inaddition, the day after Thanksgiving and on-peak days occurring during the period fromDecember 24 through January 1 plus contiguousrecognized legal holidays may be scheduled asmaintenance days subject to conditions belowexcluding (d). A maintenance day is a calendar24-hour day.

Conditions:

(a) The customer must request maintenancedays in writing.

(b) The Company must receive the request atleast 45 days before the first requested main-tenance day.

(c) Requests will be honored according to thedate received.

(d) Requests may be refused by the Company ifthey conflict with the Company’s ownschedule of maintenance and expecteddemands. The Company will offer alterna-

76 – Append ix B

Btive maintenance days.

(e) After the Company and the customer haveagreed upon maintenance days, if there is asubstantial change in circumstances whichmake the agreed-upon schedule impracticalfor either party, the other party upon requestshall make reasonable efforts to adjust theschedule in a manner that is mutually agreeable.


METERINGMetering shall be provided by the Company inaccordance with the provisions of customer’sFull Requirements Rate, except as modificationsto such metering may be required by the provi-sions of this rate. The Company may install anymetering equipment necessary to accomplish thepurposes of this rate, including the measurementof output from the customer’s generating facili-ties. Customer shall provide suitable meter loca-tions for the Company’s metering facilities.

All costs of metering equipment in excess ofcosts normally incurred by the Company to pro-vide service under customer’s Full RequirementsRate shall be borne by the customer.

Source: Public Service Companyof New Hampshire

NOTIFICATION OF INTERRUPTIONThe customer shall provide to the Company thenames and telephone numbers of persons tonotify to request reduction of load duringHourly Interruptible Periods. The Company shall provide the customer with up to onehour’s notice of any Hourly Interruptible Period,to request that the customer reduce load. TheCompany will strive to provide more advancenotification, if possible. The Company will alsonotify the customer prior to the end of the interruption.

Source: Public Service Company of New Hampshire

PARALLEL OPERATIONThe customer must meet the interconnectionrequirements of Detroit Edison specified in“Protective Relaying Operating and TelemeteringGuidelines for Independently-OwnedGeneration,” published by the Company, asapproved by the Michigan Public ServiceCommission, before parallel operation will bepermitted. The Company must approve in writ-ing any subsequent changes in the interconnec-tion configuration before such changes areallowed. Operating in parallel with theCompany’s system without written approval bythe Company of the interconnection and anysubsequent changes to the interconnection willmake the customer subject to disconnection.


PENALTIESFailure of the Customer to effect load reductionto its Firm Power Level in response to anyCompany request for curtailment shall result inthe following charges:

A charge of $10.00 per kW, for each kWabove the Firm Power Level, on each day theCustomer exceeds the Firm Power Level.

The Customer shall be liable to the Companyfor any capacity deficiency payments theCompany is obligated to pay to any power pool(or similar arrangement) due to the Customer’sfailure to comply with a duly issued curtailmentrequest. The capacity deficiency payment oblig-ation is limited to no more than the amountassociated with the Customer’s excess load overthe Firm Power Level, such excess load beingincreased by the percentage reserve marginrequired by the power pool.

The Company reserves the right to waivenoncompliance penalties during the Customer’sfirst four months of Curtailment Season service.Any Customer who fails to reduce load to itsFirm Power Level on three or more occasionswithin any calendar year may be ineligible forthis Rider for a period of two years from the dateof the third failure.

Source: Kansas City Power & Light Company

RULES AND REGULATIONSService under this Schedule is subject to theGeneral Rules and Regulations contained in thetariff of which this Schedule is a part and tothose prescribed by regulatory authorities.

Source: Pacific Power & Light Company

Special ConditionsCustomer must install and maintain, atCustomer’s expense, such devices as may benecessary to protect Customer’s and Company’sequipment and service.

Electric Service is available under this RateSchedule only when the provision of such ser-vice does not impair the electric utility’s abilityto provide adequate service to its customers, or does not place an undue burden on theCompany.

Customer shall notify Company in writing atleast 7 days in advance prior to commencing ascheduled outage. The Company shall approvesuch request if, in Company’s sole judgment, theprovision of such maintenance service does notimpair the electric utility’s ability to provide ade-quate service to its customers, or does not placean undue burden on the Company.

Customers requiring supplemental service inaddition to backup and maintenance service will

be allowed to receive such service under thisrate at one metering point if the annual load fac-tor (calculated using annual kW) at the point ofdelivery does not exceed 10%. In all other cases,supplemental service shall be separatelymetered and billed under the applicable GeneralService rate.

Customer shall report to Company informa-tion concerning outages of the customer’s ownself-generation.

Source: Texas Utilities Electric Company

TERMThe term of service under this rate shall be oneyear, and shall continue thereafter until canceledby one month’s notice to the Company by thecustomer. The customer will not be permitted tochange from this rate to any other rate until thecustomer has taken service under this rate for atleast twelve months. However, upon paymentby the customer of a suitable terminationcharge, the Company may, at its option, waivethis provision where a substantial hardship tothe customer would otherwise result.

Source: Public Service Company of New Hampshire


B

R E S O U R C E B I B L I O G R A P H Y

Arthur D. Little, Inc. “Distributed Generation: Policy Framework for Regulators.” A White Paper.Cambridge, Mass., 1999.

Arthur D. Little, Inc. “Distributed Generation: System Interfaces.” A White Paper. Cambridge, Mass.,1999.

Arthur D. Little, Inc. “Distributed Generation: Understanding the Economics.” A White Paper.Cambridge, Mass., 1999.

Daly, Peter A., and Jay Morrison. “Understanding the Potential Benefits of Distributed Generation onPower Delivery Systems.” IEEE Rural Power Conference, Little Rock, 2001.

Energy Co-Opportunity. “Report of the Ad Hoc Committee on Distribution Generation.” Herndon, Va.,April 28, 2000.

Lindenberg, Steven P. “Distributed Generation: An Action Plan for Co-ops.” CRN Brief. Arlington, Va.,Cooperative Research Network, November 1999.

Moskovitz, David, et al. (The Regulatory Assistance Project). “Profits and Progress Through DistributedResources.” Gardiner, Maine, February 2000.

National Rural Electric Cooperative Association. “White Paper on Distributed Generation,” January2000. Available at www.nreca.org.

New York Department of Public Service, New York State Public Service Commission. “ProposedAmendments to Standardized Interconnection Requirements.” June 23, 2000.

Starrs, Thomas J., “Net Metering: New Opportunities for Home Power.” Renewable Energy PolicyProject. Issue Brief No. 2. September 1996. Available at www.repp.org.

Starrs, Thomas J., and Howard J. Wenger, “Policies to Support a Distributed Energy System.”Renewable Energy Policy Project. December 1998. Available at www.repp.org.

State of Texas. State Rules, Chapter 25. December 1999.

United States Department of Energy, 18 Code of Federal Regulations §§ 35, 292, and 385.

United States Department of Energy, Power Outage Study Team on Electric Reliability Events of theSummer of 1999. “Report of the U.S. Department of Energy’s Power Outage Study Team.” Washington,DOE, March 2000.

United States Department of Energy, Office of Energy Efficiency and Renewable Energy, Office ofFossil Energy. “Strategic Plan for Distributed Energy Resources.” Washington, DOE, September 2000.

Weston, Frederick, et al. (The Regulatory Assistance Project). “Charging for Distribution UtilityServices: Issues in Rate Design.” Montpelier, Vt., December 2000.

Wisconsin Public Service Commission. “Draft Report to the Legislature on the Development ofDistributed Electric Generation in the State of Wisconsin.” 05-EI-122. November 2000.

Resource B ib l iog raphy – 79

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