DISTRIBUTED GENERATIONFinding a Sustainable Path Forward

For additional information, contact:

Jay MorrisonVice President, Regulatory Issues (703) 907.5825 or jay.morrison@nreca.coop

Mary Ann RallsAssociate Director, Regulatory Counsel (703) 907.5837 or maryann.ralls@nreca.coop

What is an electric cooperative?Electric cooperatives are private, not-for-profitbusinesses governed by their consumers (knownas “member-owners”). All co-ops, includingelectric co-ops, are democratically governed andoperate at cost. Every member-owner can vote tochoose local boards that oversee the co-op, andthe co-op must, with few exceptions, return tomember-owners revenue above what is needed foroperation. Under this structure, electric co-opsprovide economic benefits to their localcommunities rather than distant stockholders.

The majority of co-ops distribute electricity toconsumers through low-voltage residential linesthat cover over 75 percent of the nation’s landmass. Many of these “distribution co-ops” havejoined to create co-ops that provide generationand transmission services (“G&T” co-ops).Distribution co-ops also buy power from investor-

owned utilities (IOUs), public power systems,federal hydropower Power MarketingAdministrations (PMAs), and the Tennessee ValleyAuthority (TVA).

The dawn of rural electrificationIn 1935, about 90 percent of the rural farms andcommunities in America had no electricity.The primary providers of electricity were IOUs,which saw little or no opportunity to profit fromserving rural customers. To bring electricity toeveryone, President Franklin D. Roosevelt created,by executive order, the Rural ElectrificationAdministration (REA). When IOUs still would notprovide service, farm communities across thecountry tapped financing from the REA andadopted the private co-op business model todeliver electricity in their communities.

ELECTRIC COOPERATIVESAmerica’s Member-Owned Utilities

What distinguishes electric co-ops from othertypes of utilities is that the co-op businessmodel keeps the focus on the member-owner and local community.

Cooperatives in perspectiveToday, 930 electric co-ops serve 42 millionconsumers in 47 states. Electric co-ops serve anaverage of 7 customers per mile, compared with35 customers per mile served by IOUs and 47customers per mile served by public powersystems. Electric co-ops bring electricity to only 12 percent of the population, but maintain 42percent of the nation’s electricity distribution lines.

The cooperative differenceWhat distinguishes electric co-ops from othertypes of utilities is that the co-op business modelkeeps the focus on the member-owner and localcommunity. Electric co-ops are involved incommunity development and revitalizationprojects, such as small business development and job creation, improvement of water and sewer systems, and assistance in health care and education services.

The future of electric cooperativesThe private, member-owned co-op business model has been a foundation for growth in manycommunities. To keep pace with this growth,electric co-ops, like all segments of the utilityindustry, must now plan for a significant amount of new generation capacity. The growing consumerbase will continue to depend upon coal, nuclear,and gas generation, with a supporting roleincreasingly played by renewable energy resourcesand efficiency measures. As such, electric co-opslead the way in developing new, cleaner coalplants along with alternatives to fossil fuels.

Renewable energy makes up almost 11% of theelectricity provided by electric co-ops, with morethan 340 megawatts from non-hydroelectricrenewable generation owned by the co-opsthemselves and more than 2,000 megawattspurchased from renewable developers. Almost 90 percent of the co-op industry offers theirconsumers power from renewable energy.

© NRECA, all rights reserved. May not be copied, reprinted, published, translated, hosted or otherwise distributed by any means without explicit permission.

America's Electric Cooperatives

COOPERATIVES AND DISTRIBUTED GENERATION

Co-ops & DG

What is distributed generation?Distributed generation (“DG”) generally refers tonon-centralized sources of electric generation,using resources such as wind, photovoltaic (PV),combined heat and power (CHP) and diesel,usually located at or near consumers’ homes orbusinesses. If developed properly, DG canpotentially provide consumers and society withmany benefits, including economic savings,improved environmental performance, and greater reliability.

Co-ops are actively investing in distributed generation As part of their continuing efforts to find ways tolower costs for rural electric consumers, co-opsacross the nation are pursuing carefullyconsidered, cost-effective DG technologies thatmeet the needs of their consumers and supporttheir systems. Currently:

2/3 of co-ops interconnect with member-ownedgeneration

75% have interconnection policies, up from 45% in 2009

45% purchase excess power from member-ownedgeneration, up from 20% in 2009

47% offer net metering, up from 28% in 2009*

A few examples of co-op DG efforts include:

SOLAR—United Power in Brighton, CO offerscommunity solar to its members. The membersreceive a monthly bill credit for the value of theirsolar panels’ production, allowing them to ownsolar without having to install the panels directlyon their homes.

WIND—Basin Electric Power Cooperative inBismarck, ND purchases excess power from a 750-kW wind turbine, installed on the RosebudSioux Indian Reservation, adjacent to the Tribe’scasino/hotel complex in South Dakota.

COMBINED HEAT AND POWER—East Kentucky PowerCooperative in Winchester, KY purchases theexcess power from a wood waste cogenerationfacility owned by Cox Interior, Inc.

NRECA offers DG-related toolsNRECA’s research arm, the Cooperative ResearchNetwork (CRN), is working with member co-opsand the FREEDM Systems Center national labora-tory at North Carolina State University to develop a“plug and play” PV system. Supported by a grantfrom the Department of Energy (DOE), the projectfocuses on streamlining permitting, inspection,and interconnection to make systems consumer-friendly and cost-effective, while still meeting relia-bility and safety requirements.

CRN and several partners also have signed a coop-erative agreement with DOE for a multi-state, 23MW, utility-scale solar installation research project that will explore how standardization canhelp bring down the “soft” costs—labor, procure-ment, supply chain and other costs—of PV installa-tions, while also reducing uncertainty about theeffects of these installations on a system.

*According to internal NRECA surveys

To aid member co-ops considering DG programs,NRECA also offers a wide variety of web-basedresources, such as the Distributed GenerationToolkit (which includes a business and contractguide for DG interconnection, model intercon-nection applications, short- and long-terminterconnection contracts, a DG manual andwhite paper) and papers on net metering andfeed-in tariffs. These resources can be found atwww.nreca.coop/nreca-on-the-issues/energy-operations/distributed-generation/dg-toolkit.

Benefits of distributed generationIn certain applications, DG technologies canprovide consumers, co-ops, and society significantbenefits, including reduced transmission anddistribution costs, reduced emissions, andenhanced reliability.

For instance, generation located near demand canreduce energy losses and may allow utilities to

defer upgrades tosubstations andtransmission anddistribution facilities.Meanwhile, sometechnologies,including micro-turbines and internalcombustion engines,can offer increasedefficiency by takingadvantage of waste

heat, while those powered by renewable resourcescan have emissions and land-use impactadvantages over central station generation.

Possible pitfalls of distributed generationMany of the presumed benefits of DG are highlydependent on the manner in which facilities areowned, planned, installed, and operated. Policiesthat encourage DG without taking these factorsinto account, or which do not provide the flexibilitynecessary for utilities and consumers to craftbusiness models that work for them, will beextremely costly, without capturing any of thepresumed benefits.

Risky policies are ones that:

Limit the ability of utilities to participate in DG as a part of their business, for example,prohibiting utilities from selling or leasing DGtechnologies to consumers;

Promote DG at the expense of non-DGconsumers, such as mandated net metering,feed-in tariffs or value of solar (VOS) tariffs;

Fail to recognize that high penetrations of DG can increase rather than decrease utilitysystem costs;

Fail to ensure that DG consumers pay their fair share of the costs of the utility system;

Undermine state utility territorial laws byauthorizing DG vendors to sell power at retail from consumer-sited DG; and

Fail to take into account the impact of differenttechnologies and different applications on each individual distribution system.

For these reasons, decision makers should becareful not to require utilities, consumers ortaxpayers to financially support expensive capital investments or subsidies to support DGapplications where benefits may not ultimatelyoutweigh costs.

The keys to successful DGCost-effective distributed generation technologieshave the ability to bring significant benefits to co-ops and their member-owners. These benefits,however, cannot be taken for granted. Flexibility—in selecting the right DG technologies andprojects, and in structuring arrangements thatmeet the needs of individual utilities andconsumers—is essential in realizing the potentialbenefits of distributed generation while avoidingprospective pitfalls. Non-profit cooperatives have a vested interest in finding ways to balance theneeds of their member-owners with maintainingsystem reliability.

Flexibility is essential in realizing the potentialbenefits of distributed

generation while avoidingprospective pitfalls.

Co-ops & Solar

COOPERATIVES AND SOLAR POWER

Renewables programs in the sunThe nation’s member-owned electric cooperativesare pursuing the development and utilization ofcost-effective solar distributed generationthroughout the country. According to recent NRECAdata and the Solar Electric Power Association’s“2012 SEPA Utility Solar Rankings,” co-ops locatedin 18 states have more than 4,000 solar-poweredconsumer-owned residential DG projects,representing more than 23 megawatts (MW) ofcapacity. The addition of 700-plus commercial and industrial (C&I) projects brings co-ops’ solar-powered DG capacity to almost 53 MW.Cooperatives also are investing in solar projects,using business models selected to best serve theirmember-owners through least-cost options.

Solar success storiesKAUA’I ISLAND UTILITY COOPERATIVE, LIHUE, HAWAII.KIUC, which is regulated by the Hawaii PublicUtilities Commission, has 928 residential projects,with 3.707 MW of capacity. The addition of 84 C&Iprojects with 4.345 MW of capacity brings theHawaii co-op’s total to 1,012 projects with 8.052MW of capacity.

KIUC has a long history of using solar energy—bothutility-scale and residential—to reduce itsconsumption of fossil fuels continues to evolve astechnology becomes cost effective. The co-op alsopurchases 6 MW from a 6 MW solar array andanticipates adding more solar to the system in2014. However, KIUC emphasizes the need forconsumers to understand their options andobligations before making what can be a large,long-term investment, which include HPUC-required interconnection procedures to ensure thatthe PV system can be safely and reliably tied intothe utility grid and applicable net metering rules.

SULPHUR SPRINGS VALLEY ELECTRIC COOPERATIVE,WILLCOX, ARIZONA. SSVEC has 640 residentialprojects, with 1.906 MW of capacity. The additionof 249 C&I projects with 1.861 MW of capacitybrings the Arizona co-op’s total to 889 projectswith 3.767 MW of capacity.

The SunWatts Incentive Program, which is fundedthrough an Arizona Corporation Commission-mandated surcharge on electric bills, gives SSVECmembers access to solar power generationthrough either a one-time incentive or one basedon performance. Under the one-time variant, forrooftop systems of 10 kilowatts or less, the co-opwill pay a singleincentive per watt, upto 35 percent of thesystem cost, subjectto the availability of funds and theapplicant’s place on the reservationlist. Under theperformance-basedincentive, memberscollect funds basedupon their PVsystem’s productionof kilowatt-hours (kWh). This incentive varies,depending on the length of the incentiveagreement.

For PV systems over 10 kW or that cost more than$75,000, members can no longer collect a one-time incentive, but remain eligible for theperformance-based program. Systems above 50kW are not eligible for incentives, nor are systemsthat exceed a member’s connected load by morethan 25 percent.Limits for C&I meters are higher.

Co-ops located in 18 stateshave more than 4,000

solar-powered consumer-owned residential DGprojects, representing

more than 23 megawatts(MW) of capacity

The incentive program currently is fully subscribed,and the co-op is now collecting incentivereservation forms from members. SSVEC has alsoinstalled over 40 PV facilities at schools within itsservice territory.

SOUTHERN MARYLAND ELECTRIC COOPERATIVE,HUGHESVILLE, MARYLAND. SMECO has 224 residentialprojects, with approximately 2.5 MW of capacity.The addition of 33 C&I projects with 3.2 MW ofcapacity brings its total to 329 projects withapproximately 5.7 MW of capacity. The co-op,which is regulated by the Maryland Public ServiceCommission, provides bill credits to systemowners under the MDPSC’s net meteringregulations.

Additionally, SMECO developed a 5.5 MW solarsystem project, commissioned in late 2012, whichwill help the co-op meet its obligations underMaryland’s Renewable Portfolio Standards. SMECO currently is considering additional solaropportunities.

LA PLATA ELECTRIC ASSOCIATION, DURANGO, COLORADO.LPEA 337 residential projects, with 1.170 MW ofcapacity. The addition of 45 C&I projects with0.327 MW of capacity brings the Colorado co-op’stotal to 382 projects with 1.497 MW of capacity.

The Colorado co-op encourages distributedrenewable energy projects, and now has morethan 375 PV and wind generators interconnectedwith its electric distribution system. LPEA’s netmetering program is available to residential andcommercial members on a first-come, first-servedbasis until the rated generating capacity owned

and operated by members in LPEA’s serviceterritory reaches 1 percent of the co-op’s aggregatepeak demand. The excess generation is carriedover for a twelve-month period ending in April; atthat point, the member is credited at LPEA’saverage wholesale cost. The net metering programvalues member generation at a fair rate and helpsto ensure a safe installation.

The co-op offers an optional Renewable EnergyCredit (REC) contract and REC payment forresidential or commercial, grid-tied solar PVinstallations located within its service territory.

OKANOGAN COUNTY ELECTRIC COOPERATIVE, WINTHROP,WASHINGTON. OCEC has a cooperative-owned and a member-owned community solar project on itssystem. OCEC launched the first project, which itowns, in 2010. Totaling 20.3kV and eligible forWashington State production tax credits, it wasfully subscribed within a few weeks. Under theagreement which runs through June 2020, OCECpays the member-investors for the kWh producedat the preceding year’s average wholesale rate.

Even though many OCEC members were interested in participating in community solar, the state’s incentive program limited annualproduction payments for utility-owned projects,which capped the size of utility projects. However,the state program does not limit incentives fornon-utility projects, so a local non-profit organizeda second community solar project with Winthropas the host. The Winthrop project, which has aninstalled capacity of 22.8kW, became operationalin June 2011.

Net Metering

COOPERATIVES ON NET METERING

What is net metering? Net metering is one of many techniques availableto measure and value the output of customer-owned generation. Net metering rules generallyprovide that consumers with certain self-generationcapabilities should have a meter that rolls forwardswhen the customer consumes power from the gridand rolls backwards when the customer exportspower to the grid, thus compensating theconsumer at the retail rate for its generation. If the consumer uses more energy over the courseof a billing period than it has generated, it paysonly for the net energy imported from the system,plus any fixed monthly charges provided by the rate schedule.

Net metering varies by state 43 states have adopted net metering, but eachstate handles it very differently. When a consumergenerates more than they have used over thecourse of a billing period, certain states prohibitany payment to consumers for net exports. Otherstates require net credits to be rolled over to thenext month, generally up to one year and somestates require utilities to pay consumers “avoidedcost” (like with PURPA) for net exports at the endof a billing period or at the end of a year. Customergenerators with net excess generation may still payfixed monthly charges provided by the rateschedule for all customers in the same rate class.

The range of eligible units and number ofconsumers within state programs vary widely.Many states, like Alaska and Indiana, limit netmetering to only renewable technologies. Othersinclude qualifying facilities under PURPA. Moststates have size limits on the units that qualify for net metering.Kentucky andWyoming limitqualifying units to nolarger than 30 kWand 25 kW,respectively, whileNew Mexico’s sizelimit is 80 MW andOhio has no sizelimit. Some states have also imposed a limit onthe total number of consumers, or total capacity ofconsumer-owned generation, for which any utilityhas to provide net metering service. Louisiana andMichigan limit net metering to 0.5% and 0.75% ofthe utility’s historic peak load, respectively.

Why do so many states have net metering rules? Many states adopted net metering in the early1980s as a way of implementing PURPA Section210’s requirement that utilities buy the output ofqualifying small power production facilities. Otherstates adopted net metering because it provides asimple, easily-administered way of compensatingconsumers for their generation. Still others haveadopted net metering to subsidize the use ofenvironmentally-friendly renewable technologies.

Source: Environmental Protection Agency

Net meters allowcustomers to under-pay

the fixed costs they imposeon the system.

Why are utilities concerned about net metering? Net metering policies require utilities to payconsumers the retail price for wholesale power.The retail rate utilities charge includes not only themarginal cost of power, but also recovers costsincurred by utilities for transmission, distribution,generating capacity, and other utility services notprovided by the customer-generator.

The policies require utilities to pay high costs forwhat is often intermittent, low-value power thatcannot be scheduled or dispatched reliably tomeet system requirements. Customer generationthat could technically be dispatched to meetrequirements are not required to enter intooperating agreements with utilities in order toobtain net metering.

Net meters allow customers to under-pay the fixedcosts they impose on the system. A utility has toinstall sufficient facilities to meet the peakrequirement of the consumer and recover thecosts of those facilities through a kWh charge.When the net meter rolls backwards, it understatesthe total energy used by the consumer, and thusunderstates the consumer’s impact on the fixedcosts of the system. It also understates theconsumer’s total share of other fixed chargesborne by all consumers such as taxes, strandedcosts, transition costs, and public benefitscharges.

Net meters can also be deliberately orinadvertently gamed. Consumers can take powerfrom the system at peak times when it costs theutility the most to provide it, and then roll theirmeters backwards by generating power at non-peak times when the utility has little need for it.That is a particular risk, for example, with gas anddiesel fueled units that can be operated ondemand.

Different kinds of net metering

AGGREGATED NET METERING (ANM) allows onecustomer who owns a generating asset andreceives service via multiple meters or accounts onthe same or contiguous property to aggregate orcombine loads so that the generator can offsetutility purchases for the aggregated load.

COMMUNITY NET METERING (CNM) allows multiplecustomers of the same utility to share the outputof a generating asset that does not have to be ontheir properties, and to offset utility powerpurchases with each customer’s pro rata share ofthe generator’s output.

VIRTUAL NET METERING (VNM) allows customers tocombine loads from multiple meters that they own,located at different facilities on differentproperties.

Like single customer/one meter net metering,AMN,CNM and VNM programs can result in unfaircost shifting among customers. Also, becauseANM, CNM and VNM programs involve moremeters and, oftentimes, larger generation units,economic and reliability issues noted below canbe compounded. Allocating excess kWh creditscan be complicated, and can impose additional ITand billing system costs on the utility. Creditallocation may also be subject to gaming if theaccounts have different rates.

How can we gain the benefits of net metering without unfair cost shifting?

ADOPT POLICIES THAT SUPPORT RENEWABLE TECHNOLOGIES WITHOUT SHIFTING COSTSBETWEEN CONSUMERS:

• Provide tax credits for consumers that install renewable generation;

• Appropriate funds for research, development, and demonstration projects aimed at lowering the costs of DG;

• Implement net billing programs. Such programs typically:

– Permit interconnection of customer generation to the grid;

– Permit consumers to use their generation to reduce their consumption of utility power;

– Ensure appropriate compensation to consumers for their net excess generation at reasonable rates;

– Ensure consumer generators pay an appropriate share of system costs,protecting other consumers from cross-subsidies.

IF NET METERING POLICIES ARE ADOPTED, IMPOSE APPROPRIATE LIMITS:

• They should apply only to small residential generators (<10 kW) that useintermittent renewable energy such as wind, solar, and hydro;

• They should only be permitted up to a small percentage (i.e., 0.1%) of the utility’s historic peak load;

• They should not be available to:

– larger, more sophisticated consumers who do not need the leg up;

– larger units or large numbers of units, which can exacerbate the cost shifting problem; or,

– gas or diesel powered units that can more easily be used to game net metering rules.

• They should be available only to consumers on marginal cost time-of-use rates that ensure that excess generation is credited at the appropriate value.

• They should be reviewed regularly to ensure that they are still necessary to meet the goals for which they were adopted and are not forcing otherconsumers to subsidize net-metered consumer costs.

FEDERAL RULES, IF ANY, SHOULD NOT PREEMPT STATE NET METERING RULES, INCLUDING THOSE THAT PUT LIMITATIONS ON THE AVAILABILITY OF NET METERING.

Feed-in Tariffs

COOPERATIVES ON FEED-IN TARIFFS

What are feed-in tariffs?Feed-in tariffs, also called “renewable energypayments,” are a policy tool used to promoterenewable resources. They generally requireutilities to sign long-term wholesale contracts withrenewable energy generators agreeing to purchasepower at rates established by state regulators, andat levels required to ensure generators a rate ofreturn sufficient to attract investment.

The rates can be described as incorporating thesocietal benefits of renewable resources inaddition to the energy and capacity value of thepower. As an example, one program would paywind projects between $.12 and $.18/kWh, andphotovoltaic projects between $.15 and$1.08/kWh, depending on the underlying project.

Some feed-in tariff proposals provide for somegenerator or tax-payer funding for the costsutilities incur in complying with the feed-in tariffobligations. Feed-in tariffs may also beaccompanied by other policies that grantrenewable resources priority access totransmission capacity and grant renewableresources priority rights to be dispatched.

Why are advocates promoting feed-in tariffs?Advocates claim feed-in tariffs will:

Facilitate investment in renewable generation bygiving renewable energy generators a guaranteed,long-term wholesale purchaser at a favorable rate.

Promote less economic forms of renewableresources, such as community-sized wind projects,that advocates argue will provide greater societalbenefits than the utility-scale projects.

Result in a whole range of potential benefits thatcan come from renewable energy development,including domestic “green jobs” and reductions in CO2 and other power-plant emissions.

Why are utilities concerned about feed-in tariffs?

Utilities are concerned that feed-in tariffs will:

Raise the cost of power for retail consumers byrequiring utilities to pay far more for certainfavored resources than their “avoided cost” — the cost the utilities would incur to purchase thepower elsewhere. For example, a feed-in tariffcould require a utility to purchase wind from aback-yard wind generator at 23 cents/kWh at an hour when the utility could otherwise haveacquired power from an existing coal or hydroresource for 2 cents/kWh.

Require utilities to purchase each category ofrenewable resource at a price that makes thatcategory viable, instead of allowing the utility to acquire the lowest cost renewable available. For example, a feed-in tariff could require a utility to purchase solar energy at $1.08/kWh whenthe utility could instead have acquired powerfrom a utility-scale wind farm with equivalentenvironmental attributes for 12 cents/kWh.

Discourage developers from consideringtransmission capacity or utility resourceplanning when they site renewable generationdue to lack of incentive, which is not cost-effective for consumers and may not provideadequate system reliability.

Source: U.S. Energy Information Administration (EIA), 2013

Require utilities to purchase far more generationthan they need and possibly incur costs for:

• Upgrading the local distribution ortransmission system to integrate thegeneration reliably or wheel the power toother wholesale purchasers;

• Selling the power into a market alreadysaturated with renewables;

• Congestion charges associated with wheelingthe power across an under-built transmissionsystem; and

• Acquiring the reserves, ramping resources,reactive power resources, and otherdispatchable generation required to integratehigh levels of variable generation reliably.

A cooperative exampleBig Flat Electric Cooperative serves about 1,069consumers spread across more than 8,600 squaremiles of windy territory in north-central Montana.Even one community wind farm would far outstripboth the co-op’s 5 MW peak demand and thecapacity of the regional transmission system.

If there were a feed-in tariff, the co-op would haveto replace its low-cost hydro power with high-costwind energy and pay for:

Upgrades for transmission to integrate the windinto its own system;

Upgrades to the regional transmission system tomove the power across three or more states to thenearest large population center;

Ancillary services required to support thattransmission service.

The co-op would then lose money on every kWh ofhigh-priced power it had to resell into the market.The economic impact on the co-op’s 1,069 ruralconsumers would be devastating.

Policies associated with feed-in tariffs that giverenewable resources priority access totransmission facilities would further increase coststo consumers by displacing the low-cost energythose facilities had been carrying to consumersand forcing consumers either to acquire highercost resources over those transmission paths thatare still available or pay to build new transmissioncapacity to replace that taken by the priorityrenewable resources.

Policies intended to reduce the cost of feed-intariffs for utility consumers, such as a tax-basedreimbursement fund, are unlikely to cover the fulldirect financial cost of the feed-in tariff and will notaddress the indirect operational, reliability, andcost challenges caused by feed-in tariffs.

How do feed-in tariffs differ from PURPA § 210,net metering?Both feed-in tariffs and PURPA § 210 require utilitiesto interconnect with and to enter into long-termwholesale contracts for the output of renewableresources. PURPA, however, included severalconsumer protections not available under feed-intariff policies. Both feed-in tariffs and net meteringare designed to require utilities to interconnect withand purchase the output from certain generators ata rate that exceeds most utilities’ avoided cost. Netmetering laws, however, generally may includesome limits not imposed by feed-in tariffs.

Price to utility is capped at avoidedcost and drops to 0 when utility hasmet its load needs

Size is capped at 80 MW

Utilities may request waiver from “mustpurchase” if a competitive wholesalemarket for the power exists

Utilities can charge QF for providinginterconnection and other services

Compensate net metering (NM)generation at retail rate which resultsin unfair cross-subsidization of NMconsumers’ costs by others

Most states have limits on generatorsize or overall capacity w/in a program,which can limit other non-NMconsumers’ exposure to higher costs.

Price includes incentive to support theunderlying eligible generation resource,regardless of utility need for power,which is almost always higher thanretail rate

May not include a size limit

No utility waiver opportunity

May prohibit utility from charging forinterconnection

PURPA NET METERING FIT

Are feed-in tariffs consistent with federal law?Since feed-in tariffs require utilities to purchasepower at wholesale, the rates, terms, andconditions of wholesale sales of electricity aresubject to one of two federal laws:

If the generator is a Qualifying Facility (QF) therates at which it may sell at wholesale are subjectto PURPA and are capped at the utility’s avoidedcost.

• In October 2010, the Federal Energy RegulatoryCommission (FERC) clarified that states withrenewable portfolio standards (RPS) mayrequire utilities which must comply with the RPSto apply a multi-tier avoided cost calculation.Under such a calculation, utilities could onlybase avoided costs paid under a feed-in tariffon generation sources that would be eligible tomeet the RPS in the same way as the generatorseeking to sell under the feed-in tariff. However,this calculation would only apply if the state hasa RPS and the purchasing utility needs theoutput from the generator seeking to sell underthe feed-in-tariff to meet its RPS requirements.

If the generator is not a QF, its sale of wholesalepower in interstate commerce makes it a publicutility subject to regulation by FERC pursuant tothe Federal Power Act (FPA).

• The FPA requires FERC to ensure that the rates,terms, and conditions of wholesale sales arejust and reasonable and not undulydiscriminatory or preferential.

• The FPA preempts any state effort to regulaterates for wholesale sales by public utilities.

How can we gain the benefits of renewable resources without the disadvantages of feed-in tariffs?

Adopt policies that support renewabletechnologies without shifting costs betweenconsumers:

• Provide tax credits and other governmentfunding for consumers that install renewablegeneration;

• Support expansionof the transmissiongrid to moverenewableresources from the remote areaswhere they aremost plentiful topopulationcenters;

• Appropriate funds for research, development,and demonstration projects aimed at loweringthe costs of DG; and,

• Remove federal regulatory burdens onconsumers who generate their own power.

Implement net billing programs for smallrenewable generators. Such programs typically:

• Permit interconnection of customer generationto the grid;

• Permit consumers to use their generation toreduce their consumption of utility power;

• Ensure appropriate compensation to consumersfor their net excess generation at reasonablerates;

• Ensure consumer generators pay an appropriateshare of system costs, protecting otherconsumers from cross-subsidies.

Adopt policies that supportrenewable technologieswithout shifting costsbetween consumers

VOS Tariffs

COOPERATIVES ON VALUE OF SOLAR (VOS) TARIFFS

Value of solar tariffsValue of solar (VOS) is a proposed technique tomeasure and value the output of customer-ownedsolar distributed generation (“distributed PV”) to autility. It’s been implemented by a few states andmunicipalities as an alternative to net metering.Whereas net metering requires utilities to compen-sate consumers at the retail rate for wholesalepower that they generate, under a VOS tariff, all of the electricity consumed by the distributed PVcustomer is billed at the standard retail rate. Aseparate meter measures the energy produced bythe distributed PV. The “full value” of that energy iscalculated under the VOS tariff which the utilitythen credits to the customer’s monthly bill.

The proposed VOS technique calculates the fullvalue based on “Value Buckets.” According to pro-ponents, these would include, among other things:

ENERGY – The time-specific energy cost the utilityavoids buying from the solar unit instead of themarginal unit from which it would otherwise obtainenergy at that time.

GENERATION CAPACITY – Solar production correlates,in part, with utility system peaks. This may result insome level of generation capacity deferral(depending upon the capacity VOS and the utility’sforecast need for new generation).

TRANSMISSION & DISTRIBUTION (T&D) – Distributed PVmay have the potential to defer some T&Dexpenses, due to the proximity of the distributedPV to load.

SYSTEM LOSSES – Distributed PV is sited at the load;therefore, losses associated with transmitting theenergy across the T&D system may be avoided.

ENVIRONMENTAL BENEFITS – Distributed PV mayreduce the environmental emission compliancecosts utilities may face (e.g., SOx and NOx). Insome jurisdictions, increased levels of distributedPV may lower the otherwise applicable renewableportfolio standard (RPS) requirements, potentiallysaving utilities compliance costs.

SYSTEM INTEGRATION – There are costs allocated tointermittent resources for additional operatingreserves that are required to maintain systemreliability.

Value Buckets are not limited to capturing actualcost savings to the utility and its consumers. Theyare designed to give the distributed PV customeradditional compensation for future benefits thatmay not occur or may be inflated in value.

Why are advocates promoting VOS tariffs?Under VOS tariffs, utilities would be required topay distributed PV consumers or retail solarinstallers under long-term agreements at rates thatreflect all of the potential benefits that distributedPV may possibly offer in the future to the utility, theelectric grid, community and the environment as awhole, creating a strong market for investments indistributed PV.

Moreover, advocates assert, VOS tariffs promoteconsumer distributed PV that provides greatersocietal benefits than the utility-scale solarprojects that are more cost-effective and have the same environmental attributes.

Advocates also argue that only VOS tariffsrecognize the true value that a consumer offers the utility system and are thus necessary to ensure rate fairness.

Why are utilities concerned about the VOS tariffs?Similar to feed-in tariffs, VOS tariffs can raise thecost of power for other retail consumers byrequiring utilities to pay far more for resourcesthan their avoided cost — the cost utilities wouldincur to purchase the power elsewhere. A VOStariff could require a utility to purchase distributedPV at premium rates when the utility couldotherwise have acquired power from an existinghydro resource or from a utility scale wind farmwith equivalent environmental attributes at asignificantly lower price.

VOS tariffs are supposed to reflect the value PVoffers to the grid, communities, and theenvironment; however, depending on how thecalculation is done, these benefits can be easilyinflated and the costs imposed on the system bythe technology ignored. For example, proponentsof VOS tariffs presume that distributed PV will helputilities defer or avoid investments in distribution,transmission, or new generation capacity. In fact, ifVOS tariffs encourage significant investment in PV,the utility could actually bear higher costs for:

• Upgrading the local distribution or transmissionsystem to integrate the generation reliably. Forexample, at higher levels of PV, utilities will needto upgrade transformers, replace isolationdevices to permit two-way flows on thedistribution system, invest in distribution SCADAto permit the system to respond to greateruncertainty and variability in distribution loadsand power flows, and install newcommunications networks in order to track andcontrol smart inverters on the PV systems.

• Acquiring the reserves, ramping resources,reactive power resources, and otherdispatchable generation required to integratehigh levels of variable generation reliably. Athigher levels of PV, the system can experiencedramatic upramps during evening peak periodsas solar generation tapers off at the same timethat customers come home, turn on the airconditioning, turn on stoves, and begin to usehot water. Existing generation resources insome regions may not be able to meet thoseramps and would have to be replaced.

VOS tariffs could also drive up electricity costs forconsumers by charging utilities — and thus theircustomers — for many values not presentlyincorporated in electricity rates. Utilities chargeconsumers for the cost of providing safe, reliable,and affordable power. They do not chargeconsumers for all of the benefits that consumersand the economy get from that power. Nor doutilities charge consumers the value that theirother generation resources offer consumers,communities, and the environment. Utilities, forexample, do not charge consumers more thantheir cost for nuclear power because it has no airemissions. Utilities do not charge consumers morethan their cost for utility-scale solar power becauseit produces no pollutants. Utilities do not chargemore than their cost for coal-power to reflect thenumber of good jobs the coal mine and the coalplant provide the community. The VOS tariffrequires the utility to tax some of its consumerswith such costs in order to subsidize others.

How do VOS transactions differ from feed-intariffs and net metering?Both feed-in tariffs and net metering are designedto require utilities to interconnect with andpurchase the output from certain generators at arate that exceeds most utilities’ avoided cost. Netmetering laws, however, generally include severallimits not necessarily imposed by feed-in tariffs orVOS tariffs.

Net metering rules require utilities to giveconsumers credit against their energy usage forenergy their generators export to the system overthe course of a billing period or longer period. Thiseffectively compensates consumers at the retailrate for their generation up to the point where thegeneration completely offsets usage during thecredit period. Some states credit any net excessgeneration to the utility or require payment atavoided cost. Feed-in tariffs require payment for all generation at the level required to provide theinvestor a rate of return designed to encourage the underlying generation resource. While feed-intariffs are almost always going to be higher thanthe payment under net metering, VOS tariffs likelywill require even higher payments than either netmetering or feed-in tariffs as the price to be paid isnot limited by either the utility’s retail rate or thegenerator’s revenue requirement. Depending onwhat is included in the “value buckets” and howthose are calculated, the VOS tariff could provideinvestors a significant premium over their revenuerequirement.

Most states limit the number of generators oramount of generation capacity entitled to netmetering. The limits reduce non-solar consumers’maximum exposure to higher power costs neededto subsidize the solar consumer. Feed-in tariffsand VOS tariffs may not impose such limits,requiring other consumers to subsidize even largenumbers of projects producing significantamounts of energy, even if that exceeds the totaldemands of the purchasing utility.

How can we gain the benefits of renewable resources without the disadvantages of VOS tariffs?

Adopt policies that support renewabletechnologies without shifting costs betweenconsumers:

• Provide tax credits and other governmentfunding for consumers that install renewablegeneration;

• Appropriate funds for research, development,and demonstration projects aimed at loweringthe costs of DG.

Implement net billing programs for smallrenewable generators. Such programs typically:

• Permit interconnection of customer generationto the grid;

• Permit consumers to use their generation toreduce their consumption of utility power;

• Ensure appropriate compensation to consumersfor their net excess generation at reasonablerates; and

• Ensure consumer generators pay an appropriateshare of system costs, protecting otherconsumers from cross-subsidies.

Depending on what isincluded in the “value

buckets” and how thoseare calculated, the VOS

tariff could provideinvestors a significant

premium over theirrevenue requirement.

Retail Rates

DISTRIBUTED GENERATION: EXPLORING RETAIL RATES

Designing retail rates to accommodate distributed generationElectric cooperatives are member-owned,member-governed, not-for-profit electric utilities.They exist to provide safe, reliable, and affordableelectric service to the electric consumers that ownthem at rates that reflect the cost of providing thatservice. Like other utilities, cooperatives havetraditionally designed their retail rates to recovertheir costs, to minimize cost shifting between orwithin rate classes, and to be simple andunderstandable.

As distributed generation is becoming morecommon, however, some co-ops are finding thattheir traditional rate designs may no longer meettheir needs. Changes are needed to ensure thoseco-ops can recover their costs of service, minimizecost shifting between members, and providemembers with accurate price signals forinvestments in distributed generation.

Traditional electric rates may not permit cooperatives to recover fixed costs as DG increases

Electric rates, particularly for residentialcustomers, are typically comprised of a fixedcharge, often referred to as the customer charge,and a variable energy charge, which is imposed oneach kilowatt-hour (kWh) consumed.

For most utilities, including cooperatives, thecustomer charge is often considerably less thanthe actual fixed costs incurred to serve customerson the system. A large proportion of these fixedcosts, which cooperatives incur in order to buildthe generation, transmission, distribution,communications, and other infrastructure requiredto ensure reliable electric service, are oftenrecovered through the variable kWh energy charge.

The kWh charge is typically set at a level that iscalculated to recover all of the cooperatives’ fixedand variable costs each year based on itsprojected sales.

If members generate their own energy such thatsales decrease below the levels anticipated whenrates were set, the cooperative will not recover itsfull cost of providing service until it is able toinstitute a rate increase.

Traditional electric rates may shift costs fromcustomers with DG to all other customers

Just as the cooperative’s kWh charges are typicallyset to recover its full revenue requirement, they arealso set at a levelanticipated to recovera fair share of thecooperative’s fixedcosts from eachmember, based onaverage usage withineach rate class.

If a subset ofmembers installgeneration, and thususe significantly lessthan average, thatgroup of members will not contribute their fairshare of the cooperatives’ fixed costs, shiftingthose costs to other members who are not self-generating.

The cost shifts will become more pronounced ifcooperatives are forced to raise their kWh rates inorder to recover their full revenue requirements. As DG penetration levels increase, this could leadto power becoming unaffordable for lower-incomeconsumers.

The financial riskassociated with declining

kWh sales can be mitigatedunder a rate design that

recovers costs in the sameways they are incurred

by the utility.

While there are many rate options, rate designs that recover all of a cooperative’sfixed costs with fixed charges can provide stability and rate equity

The financial risk associated with declining kWhsales can be mitigated under a rate design thatrecovers costs in the same ways they are incurredby the utility. Under this approach, fixed costs arerecovered through fixed charges and variable coststhrough variable charges. This rate design,sometimes referred to as straight fixed variablerates, can be established by first conducting acost-of-service study that identifies the utility’scost structure. Based on the study’s results, theutility’s retail rates are then rebalanced, throughincreases in the customer charge and decreases inthe kWh charge.

Rebalancing rates in this manner serves to protectthe financial stability of the utility that facesdeclines in kWh sales due to distributedgeneration. All cooperative members, includingmembers who have installed distributedgeneration, pay a monthly customer charge thatreflects the utility’s fixed investment made on theirbehalf.

Rebalancing rates in this manner also eliminatesthe cross subsidies caused by the interactionbetween traditional rate designs and DG. Everymember, regardless of whether they install DG,pays the cost of investments the cooperativemakes in infrastructure required to serve thatmember. Other members without DG, therefore,are not required to pick up an inequitable share ofthe cooperative’s costs.

Rebalancing rates to recover costs in the way they are incurred provides members moreaccurate price signals

Basic principles of rate design suggest that ratesshould send accurate price signals to consumersin order to encourage consumers to make goodeconomic decisions.

Traditional rate designs, which incorporate someunavoidable fixed costs of service in the kWh rate,give members an inaccurate price signal,encouraging them to overinvest in DG so long as the cost to them is less than the fully loadedretail rate.

Rate designs that recover costs in the way they are incurred, on the other hand, provide a moreaccurate price signal. While any member could stillinvest in DG, they only have an economic incentiveto do so if the variable cost of their own generationis less than the variable cost of the power thecooperative would have otherwise provided.

Some energy efficiency (EE) and DG proponentsare concerned that rate designs with higher fixedcosts and lower per kWh charges provide areduced incentive to consumers to invest in EE andDG. It is true that a lower kWh charge does providea lower incentive, but if the kWh charge properlyreflects the variable cost of service, it is a moreaccurate incentive and is more consistent withprinciples of rate design.

Forcing utilities to include unspecified levels offixed costs in the variable charge in order tosubsidize investments in EE and DG denies bothconsumers and regulators the transparencyrequired to make good investment and policydecisions.

Subsidizing EE and DG through poor rate design isalso unsustainable. As DG penetration levels rise,utilities could be forced to recover the fixed costsof the system in fewer and fewer total kWh, forcingthat charge up, increasing the hidden subsidy,creating greater political opposition to DG fromthose forced to pay the subsidy, and imposinggreater financial risk on the utilities.

Recovering fixed cost with fixed charges can benefit low-income consumers

Some policy makers are concerned that revisedrate designs that recover all of a utility’s fixed coststhrough a fixed monthly charge may harm lowerincome consumers. However, lower incomeconsumers are not necessarily low-usageconsumers.

In cooperative territories, lower income consumersoften live in the oldest and least energy efficienthousing stock. They are least likely to have theresources to invest in weatherization, efficientHVAC systems and appliances, energy efficienthousing and other conservation measures.

Lower income customers are often also the leastlikely to invest in distributed generation, becausethey lack the upfront cash, because they live inrental housing, or because they have otherpriorities. They are, therefore, the most likely to bear the cost of subsidizing DG investmentsthrough rate designs that fail to recover fixed costs of service from members with DG. Accordingto a recent California Public Utilities Commissionreport, 78% of California consumers that have netmetering have household incomes above the statemedian level*.

Straight-fixed variable rates are only one option for cooperatives whose traditional rate designs do not meet their needs as dg levels increase

Cooperatives’ goal is to provide their members with safe, reliable, affordable power at fair ratesthat recover the cooperatives’ cost of providingservice. There are many ways to accomplish thatgoal and the appropriate approach will be differentfor each cooperative depending on their localcircumstances, members, board, and management.

In addition to the straight-fixed variable approachdiscussed above, for example:

Some cooperatives have adopted 3-part rates forresidential customers, like those often charged tocommercial and industrial customers. Those ratesdivide charges between customer charges for suchfixed costs as metering and billing demand,charges for fixed costs relating to the member’smaximum demand on the system (such asgeneration capacity, distribution and transmissioninfrastructure), and variable charges that reflectthe cost of providing members the energy theyactually consume.

Other cooperatives have retained the traditionalrate design, but layered on top stand-by charges orother member-specific charges for those membersthat install DG to recover from those customers thefixed costs of providing service.

*California Net Energy Metering (NEM) Draft Cost-Effectiveness Evaluation: NEM Study Evaluation,” California Public Utilities Commission Energy Division, September 26, 2013

The National Rural Electric Cooperative Association (NRECA) is the national service organization representing the interests of cooperative electric utilities and their consumers. In addition to advocating consensus views on legislative and regulatoryissues, NRECA provides health care, pension and many other programs for its members.

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