finding a bright spot

34 IEEE power & energy magazine may/june 200934 IEEE power & energy magazine may/june 2009

Finding a Bright Spot

STEVE WILCOX (PV PANELS)© PHOTO F/X (ROBOTIC HAND)

Utility Experience, Challenges, and Opportunities in Photovoltaic Power

By Thomas Key

Digital Object Identifi er 10.1109/MPE.2009.932306

1540-7977/09/$25.00©2009 IEEE

may/june 2009 IEEE power & energy magazine 35may/june 2009 IEEE power & energy magazine 35

TTHE PHOTOVOLTAIC (PV) INDUSTRY HAS BEEN A STEADY bright spot through economic ups and downs, and the future is looking brighter than ever. PV deployment has grown rapidly—from 0.3 MW in the 1980s to an expected 3,000 MW by 2010 (Figure 1). Fueled by techni-cal, economic, environmental, and social drivers, the contribution of PV to the U.S. electricity supply mix will likely be several times that amount by 2020. PV power systems and the utility industry have had a 25-year court-ship with many different types of engagement. Utilities participated in the fi rst ground-mounted power plants and rooftop installations on residences, schools, airports, hospitals, and other public buildings. These projects in-cluded U.S. Department of Energy (DOE)-sponsored residential experiment stations in Maine, Florida, and New Mexico in the 1980s; early PV plants in California and throughout the Southwest; and grid connection, demonstra-tions, inverter and system testing, and related standards development.

In fact, utilities have been key participants in the evolution of PV power systems, particularly in the development of grid integration standards during the fi rst 25 years. One of the fi rst engagements was via the IEEE standards co-ordinating committee (SCC21) for PV systems, established in 1981, which led to IEEE 929 (a standard that sets recommended practices for utility interface of PV systems) in 1988 and the IEEE 1547 interconnection standard in 2003. This work continues as major investor-owned, municipal, and rural electric companies recognize the signifi cant potential of PV for producing electricity.

At the same time, PV system developers recognize the signifi cant value of grid connection for deploying PV systems. The electric grid enables PV generation by delivering available renewable power output to the larger en-ergy market. It simplifi es the balancing of variations in supply and demand at individual generators distributed over a wide area. This grid service in-creases the value of PV energy and reduces the diffi cult requirement for local energy balancing, storage, and control systems that must be faced in off-grid applications.

For these reasons, grid-connected PV applications are expected to ac-count for more than 90% of solar capacity additions in 2010, up from about 50% in 2000 and less than 10% a decade earlier. The number of relatively large PV projects feeding power directly to the grid will in-crease. But most systems are expected to be deployed in behind-the-meter applications, where the technology competes with the retail cost of de-livered electricity rather than the wholesale cost of energy supplied by central-station generating plants.

In addition to small rooftop installations on individual homes, distrib-uted PV is being deployed throughout “solar subdivisions,” atop parking lot structures, in multi-megawatt arrays supplying power directly to the grid or at substations, and on large and attention-getting buildings—including those owned by Google, Walmart, and Tiffany & Co. Figure 2 shows the range of possibilities for the deployment of PV power.

All of these possible engagements illustrate just how many ways PV pow-er may act to change consumer behavior, affect conventional power markets,

36 IEEE power & energy magazine may/june 2009

impose new demands on the grid, and create business op-portunities. With existing electric infrastructure, electric service providers are well positioned to embrace future PV business opportunities. For many, this may look like a fork in the road. On the one hand, they can simply respond to interconnection requests, manage grid impacts, and react as the future unfolds. On the other hand, they may decide to an-ticipate emerging applications, move into new markets, and work with regulators and other stakeholders to derive eco-nomic benefi ts, while helping to maximize the societal value of distributed PV. In any case, the expansion of end-user-sited PV systems begs the question: What will be the future role of electric utility companies in PV power deployment?

Examples of Recent Utility PV Engagements A growing number of utilities are trying various PV deploy-ment options while also experimenting with different incentive,

fi nancing, energy purchase, and owner-ship models. Some are looking to own customer-sited PV systems or have an-nounced investment plans to encourage end-users. Others are thinking about the expanded future role of PV power in light of current and anticipated policies and the technology’s potential relative to smart distribution systems. New busi-ness models, advanced technologies, and informed regulatory perspectives will help transform residential, com-mercial, and other distributed PV sys-tem hardware into important future grid assets. Various recent examples have been put into practice.

Long-Term Financing for Accelerated PV DeploymentIn New Jersey, the Public Service Elec-tric and Gas (PSE&G) has launched the Solar Loan Program to help proj-ect developers and consumers of all classes deploy PV systems by reduc-ing their overall installation costs. The program, with a funding level of about $105 million, seeks to add 30 MW of PV capacity within the PSE&G service territory by the end of 2010 while spur-ring economic activity in the state’s clean- energy sector. The utility assists with project fi nancing over a 10- to 15-year loan period—longer than typi-cally available for PV installations—and also helps developers and consum-ers with project implementation and figure 2. Existing and emerging feeder-level applications (EPRI 1018096).

Auxiliary PowerSupply—PV

Bulk Supply Connection

Distribution Substation

Other FeedersOther Feeders

Supply-Side PV Office Buildings—Integrated PV

Industrial and CommercialBuildings—Rooftop PV

Multifamily Housing— Rooftop PV

Single-FamilyHomes— Rooftop PV

Single-Family Homes—Off-Grid PV

Vehicle Charging Stations—Integrated PV Shade

Vehicle Charging Stations—Off-Grid PV

Grid-Connected PV

Grid-Independent PV

Subdivisions—Rooftop PV

Streetlights—Off-Grid PV

figure 1. Exponential growth in U.S. PV deployment (data: Larry Sherwood, IREC; projections: Prometheus Institute, 2008).

3,000

Cap

acity

(M

W)

200,000

180,000

160,000

140,000

120,000

100,000

80,000

Sys

tem

s (#

)

60,000

40,000

20,000

0

2,500

2,000

1,500

1,000

500

0

2003

2004

2005

2006

2007

2008

(p)

2009

(p)

2010

(p)

2011

(p)

2012

(p)

Annual Capacity (MW/yr)Cumulative Capacity (MW)Annual Systems (#/yr)Cumulative Systems (#)

may/june 2009 IEEE power & energy magazine 37

administration. Borrowers have the option to repay loans with solar renewable energy credits (RECs) instead of cash. PSE&G has worked with the Bayonne Board of Education to construct solar power systems at a number of schools, in-cluding Bayonne High School, and as of early July 2008, PSE&G had committed to fi nance more than 10 MW of dis-tributed PV in the commercial, industrial, municipal, and nonprofi t segments.

Utility Ownership of Customer-Sited PVSan Diego Gas & Electric (SDG&E) owns and operates dis-tributed PV systems on several commercial and multifamily residential buildings, and Southern California Edison (SCE) recently proposed a similar but much larger initiative to de-ploy utility-owned PV at customer sites. SDG&E’s Sustain-able Communities Program was created to promote the use of green building practices in both new construction and major renovation projects. In addition to providing design assistance and incentives, SDG&E leases rooftop space and installs, owns, and operates PV at selected sites (Figure 4). As rate-based assets, the PV systems are interconnected on the utility side of the meter, and output is fed to the grid. SDG&E is using these projects to evaluate the use of distrib-uted PV for peak shaving, investment deferral, and reliability purposes and to gain experience with incorporating small-scale, intermittent renewables into procurement plans.

In March 2008, SCE proposed a similar program with an ambitious goal of deploying 250 MW of utility-owned, rate-based PV at customer sites within fi ve years. This program targets commercial and industrial buildings and complexes capable of hosting 1–2-MW installations. In its regulatory fi ling, SCE attests that its program will increase the likelihood that the state’s renewable portfolio standard (RPS) targets will be achieved because the program serves a substantial PV market that is largely untapped; only projects with less than 1 MW in capacity are eligible under the state’s net-metering program. The SCE program is also aimed at reducing the capital cost of PV deployment while streamlin-ing PV interconnection and maximizing grid support value. The fi rst of these commercial warehouse installations, in Fontana, California, was completed in December 2008 (Fig-ure 5). It includes 33,730 ft2 of thin-fi lm PV that provides 2 MW of power into the local grid at about $4.20/W.

Targeted PV Deployment for Congestion Relief NStar and National Grid are participating in innovative pi-lot programs in Massachusetts that bundle distributed PV deployment with effi ciency, demand response, and other measures to reduce peak loading on constrained circuits and defer distribution system investments. The NStar project fo-cuses on two circuits in Marshfi eld, a suburb southeast of Boston, where demand growth is outpacing system capacity. Conventional distribution planning would result in upgrades beginning in 2009. To defer this investment, NStar is target-ing large commercial consumers on the overloaded feeders,

as well as a subset of residential consumers who offer the greatest potential for peak shaving. A 200-kW commercial PV installation, 15 residential PV systems, and extensive effi ciency and demand response initiatives are expected to yield more than 2 MW in load reductions.

PV Project Development for Portfolio Diversification In May 2008, PPL Renewable Energy, a subsidiary of PPL Corp., announced plans to design, fi nance, and construct the

figure 4. Rooftop PV owned by SDG&E at the Reuben H. Fleet Science Center (used with permission from Reed Kaestner).

figure 3. Solar PV at American Industrial Supply’s Ware-house with owners Ryan Higgins (left) and Sean Higgins inspecting their new system (used with permission from PSE&G).


nation’s largest rooftop PV project—a 1.7-MW system to be installed on eight buildings located on the campus of Schering-Plough Corp. in Summit, New Jersey. PPL will own and operate the project and control the RECs. Power will be sold to Schering-Plough to assist the company in

cutting its demand for high-priced peak power and achiev-ing its goal of reducing greenhouse gas emissions by 5% by 2012. The project has expanded PPL’s renewable energy portfolio to about 30 MW, including rooftop PV installa-tions sited at two Macy’s stores in New Jersey. Over the next fi ve years, PPL plans to invest at least $100 million in new renewable energy projects.

PV Power Purchasing for RPS ComplianceXcel Energy and Duke Energy have each entered into 20-year power purchase agreements (PPAs) with different large PV project developers to help achieve compliance with RPS requirements. Also, the Sacramento Municipal Utility District (SMUD) is launching an innovative program consis-tent with this objective as well as making PV power acces-sible to more consumers. Xcel Energy is buying the output and RECs from an 8.22-MW PV project in Alamosa, Colo-rado, that entered into service in December 2007 (Figure 6). Owned and operated by SunEdison, the Alamosa project is currently the nation’s largest installation supplying PV power directly to the distribution grid.

In May 2008, Duke Energy announced a similar PPA with a 16-MW PV installation in Davidson County, North Carolina, scheduled for completion by SunEdison in 2010. The company is also planning to seek approval from the North Carolina Utilities Commission for a program under which it would install, own, and operate distributed PV sys-tems on rooftops and at other customer sites.

In April 2008, SMUD awarded enXco a contract to de-velop, construct, own, and operate a 1-MW PV system in southern Sacramento County. SMUD will purchase the project’s output and RECs under a 20-year PPA, selling the energy to participants in its recently launched Solar Shares program. Complementing the utility’s other solar initiatives on public structures such as parking shade (see Figure 7) and residential neighborhood developments, this program will provide all SMUD consumers—including renters, resi-dents, and businesses occupying multiunit buildings, as well as those who might not be able to afford a PV system—with the opportunity to buy PV-generated power.

Challenges of Enabling More PV in the Grid As PV generation technologies mature, they will likely provide a signifi cant share of our nation’s electricity de-mand. However, as the market share grows, concern about the potential impacts of this growth on the stability and operation of the electricity grid might create barriers to further expansion. In general, the existing electric power system is not ready for a signifi cant deployment of PV power systems. Key questions for distribution compa-nies include how to increase penetration and maintain reliability; what the role of the smart grid will be with PV inverters and controllers as well as other distributed

figure 7. SMUD’s 540-kW, 1,000-car PV parking shade at Cal Expo in Sacramento, California (used with permission from NREL/ Kyocera Solar).

figure 6. PV Plant in Alamosa, Colorado has long-term power purchase agreement with Xcel Energy (used with permission from SunEdison).

figure 5. Recently installed thin-film solar panels on the roof of a Fontana, California, distribution warehouse (used with permission from Southern California Edison).


resources; and which applications are appropriate for future advanced metering infrastructure (AMI) with these resources. System operators must consider seasonal and time-of-day variations in PV output as well as rapid ramping of output, as shown in Figure 8.

Two evolutions are envisioned. The first is distributed PV systems that operate interactively with avail-able solar resources; varying condi-tions on the grid; and other local resources, including load control and, in the future, other generation and storage resources. The second and perhaps more challenging evo-lution is that the distribution grid will need to be rein-vented to interact with—and in some cases control—distributed generation (DG) and load demand. This will, in turn, make the electric power system more compatible with “grid-ready” distributed PV systems.

To support these evolutions, we need a strategy to move from the relatively small PV energy market of “passively interacting” systems to a PV system that is an “active part-ner” in the grid. A key component of this strategy is that the PV system will help meet system energy demand and control requirements at all grid levels, including transmis-sion and the independent system operators. Another element is recognizing the large existing capital investment in distribu-tion, which will require long-term commitment and deliberate efforts in research and development (R&D) to enable change.

Future distribution will need to be more automated and ready to interact with distributed PV and other distribution-connected energy resources. Distribution automation and a “smart” grid naturally apply to distri-bution supply and demand and will create opportunities on both sides of the meter. Therefore, it will be possible to achieve a “market-driven response” for reinventing the electric grid with PV. And it will include DG at individ-ual and groups of end-users; intelligent switches, breakers, and reclosers on feeders; intelligent load-control devic-es; local energy control systems; and, eventually, plug-in electric vehicles at end-user locations.

The specifi c requirements for this high penetration of PV will generally include the following:

Interactive ✔ voltage regu-lation and var management: Utility voltage regulator and ca-pacitor controls will be interactive

with each other and the DG sources. A central controller (Figure 9) will help manage the interactivity to ensure op-timized voltage and reactive power conditions.Bulk system coordination of DG for market and ✔

bulk system control: Control of DG from a dispatch center will be needed. This will allow DG to partici-pate and be aggregated into energy markets, as well as control the need to preserve system stability, power quality, and reliability at the bulk level.Protective relaying schemes designed for DG: ✔ The distribution system and sub-transmission will include a more extensive use of directional relaying, commu-nication-based transfer trips, pilot signal relaying, and impedance-based fault-protection schemes (like those used in transmission). These can work more effective-ly with multiple sources on the distribution system.Advanced islanding control: ✔ Ex tensively automated switchgear and DG with enhanced islanding detection

figure 9. Distributed controller results are aggregated to manage area power and system voltage profiles.

Substation

Feeder

SupplementaryRegulators

SupplementaryRegulators

DG DGDG

DG

DG

DG

DG

DG

CapacitorControl LTC Control

Voltage and VAR RegulationCoordination Algorithm

PFCapacitor

figure 8. PV system output variations over a seven-day period in upstate New York.

–20,000

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

9/11 9/12 9/13 9/14 9/15 9/16 9/17 9/18 9/19 9/20P

ower

Out

put (

W)

Partly Cloudy Conditions Clear Conditions


will improve the capability for detecting unintentional islands. Also, these systems should be able to recon-fi gure the grid/DG into reliability-enhancing “inten-tional islands.”Interactive service restoration: ✔ Sectionalizing schemes for service restoration allow distributed PV and oth-er DG to help pick up load during the restoration

process (Figure 10). When these DG come back on the feeder they can help to deal with overloads from cold-load pickup and to provide the current in-rush required to recharge the system.Improved grounding compatibility: ✔ New de-vices and architectures in both DG and distribution address grounding incompatibilities among power

system sensing, protection, and har-monic flows. Techniques include:

controlling or limiting ground-fault • overvoltage via relaying techniques or ancillary devices instead of effec-tively grounded DG requirementshardening the power system and • loads so they are less susceptible to ground-fault overvoltage (increase voltage withstand ratings)changing protective relaying for • ground faults so a high penetration of grounding sources does not affect the ground-fault relayingchanging the feeder-grounding scheme • or load-serving scheme back to a grounded three-wire system.

Charging the Car Grid-connected charging stations for plug-in hybrid

vehicles and all-electric vehicles represent a particu-

larly promising PV-dc application for the future. The

illus tration shows a charging station that incorporates

PV- powered sunshades (see Figure S1) to keep vehicles

cool while supplying power directly to vehicle batteries

without the ac-to-dc conversion losses when charging

from the grid. If solar output exceeds the charging load,

then the excess can be fed to the grid through a bidi-

rectional inverter. With appropriate station and vehicle

controls, battery energy can even be dispatched when

needed for grid-support purposes. As a supplement to

grid power, PV-dc battery charging provides a potentially

cost-effective way to employ renewable energy for trans-

portation applications because the charging station and so-

lar generation functions require common balance-of- system

components. In addition, vehicle owners with parking/

charging options might prefer PV power—and might pay a

premium for it. Similarly, consumers may be interested in

PV-powered home charging stations.

Utility Gridac dc

Inverter(Bidirectional) PV Array

VehicleCharging

Interface Unit

figure s1. PV-assisted sun-shading carport and vehicle charging station.

Utilities have been key participants in the evolution of PV power systems, particularly in the development of grid integration standards during the first 25 years.

figure 10. Illustration of cascaded restoration of distributed generation.

Feeder

Circuit Breaker(First to Close)

LoadArea 1

Substation

RotatingMachineSource

LoadArea 2 Load

Area 3

Switch B(Third to Close)

Switch A(Second to Close)

PVInverterSource

RotatingMachineSource

LoadArea 4

Switch C(Last to Close)

PVInverterSource


Distributed energy storage: ✔

Energy storage of various forms will apply to correct temporary load/genera tion mismatches, reg-ulate frequency, mitigate fl icker, and assist advanced islanding functions and service restora-tion. One important future op-tion for energy storage to sup-port the grid is the electric car (see “Charging the Car”).

Advanced inverters/ controllers and energy management will be re-quired to interface with emerging smart-grid technology and must be capable of supporting communica-tion protocols used by current energy management and utility distribution-level communication systems. These systems must meet the performance and reliability targets set forth by the AIIC/EMS program based on using the cost of energy (COE) as a metric. The shift from today’s central control system to a future intelligent control system is illustrated in Figure 11.

Microgrids might also have a role in the future distri-bution grid, and they could come in a broad range of sizes and confi gurations. Figure 12 shows examples of possible microgrid “subsets” that could be derived on a typical ra-dial distribution system. These microgrid subsets include a single customer, a group of customers, an entire feeder, or a complete substation with multiple feeders. A very large substation could have up to 100 MW of capacity and eight or more feeders and serve more than 10,000 customers. A mas-ter controller is the key to providing very sophisticated microgrid op-eration that maximizes efficiency, quality, and reliability. Some of the capabilities identified for an intel-ligent microgrid master controller are currently being researched; other capabilities, however, do not yet exist.

Electric industry leaders call-ing for these research efforts an-ticipate the integration of signifi-cant quantities of distributed solar electricity into the electricity grid. As the penetration of distributed resources increases, the challenge for grid operators and the grid’s dependence on the DGs capac-ity and energy will also increase. Simply put, the rules for operat-ing the electric grid will have to

change as renewable penetration grows. This fact has become clear with the growth of wind generation and its aggregation into large wind farms connected at trans-mission and subtransmission levels (see IEEE Power & Energy Magazine, November/December 2007). Just as the transmission grid codes for wind integration have evolved to better support the grid, so will the rules for distribution integration of PV.

The transition to active distributed PV systems and a distribution system that is ready for integration of these systems will not be achieved abruptly. Such a sudden shift would disrupt existing power delivery and require

figure 12. Concept of distribution microgrids of various sizes and levels allowing reliability islands and grid-tie operation.

DistributionSubstation

Bulk Supply Connection(Subtransmission)

SingleUserMicrogrid

OthersFeeders

Feeder

Full SubstationMicrogrid

Full FeederMicrogrid

Partial FeederMicrogrid

GenGen

Gen

Gen

figure 11. Distributed controllers integrated with distribution control systems to maximize system value.

Cap

acity

Today

Status Quo Future

Intelligent Control

DER

DER

DERDistributionNetworks

DistributionNetworks

TransmissionNetworks

TransmissionNetworks

DistributionNetworks

TransmissionNetworksCentral

GenerationCentral

GenerationCentral

GenerationCen

tral

ized

Con

trol

Dis

trib

uted

Con

trol

Cen

tral

ized

Con

trol

Pass

ive

Ope

ratio

n

Pas

sive

O

pera

tion


too much new capital investment. DG is now operating in compliance with utility voltage limits, and high pen-etrations can be achieved by using adaptive, autonomous, local control systems that operate under utility supervi-sion and the use of rapid, inverter-based fault-current limiting. However, it will take time to adapt the grid and fully integrate these distributed systems with automated distribution management systems, which involves invest-ments by both utilities and PV system manufacturers.

To illustrate the notion that the grid, PV systems, and rules all need to evolve, Table 1 compares differ-ent penetration levels relative to impacts, expectations for

grid support, interconnection rules, and electric distri-bution system operating concerns. Required changes in grid operation depend on both relative penetration levels and the strength of the grid supply. The main point is that different scenarios will, by practical necessity, lead to dif-ferent roles and operating requirements.

Future research, integration device requirements and needs, and standards development will all depend on rela-tive penetration. Anticipating these changes, the Electric Power Research Institute (EPRI) has initiated a research program for enabling large-scale penetration of PV. These efforts build on prior work on the integration of microtur-bines, fuel cells, PV, and other distribution-connected dis-tributed resources. The research is aimed at assisting the distribution engineer in planning, designing, and screen-ing DG to enable high penetration levels. Specifi c objec-tives include screening tools, guidelines and deployment criteria, technical updates, workshops on utility practic-es, and reports on future grid functionality requirements. Also related to PV integration and metering are surveys on new products and applications, guides for integrating AMI and other PV interface devices, laboratory test pro-tocols, evaluation reports, and fi eld monitoring.

Future Role for Power CompaniesThe dynamic nature of distributed PV markets implies an uncertain future as they expand. One possible scenario

figure 13. One scenario of utility engagement with PV.

02468

101214161820

GW

2000 2004 2008 2012 2016 2020Years

Net MeteredThird PartyUtility Owned/Purchased

In the future, many providers will face the decision of whether to modify traditional business models for active engagement or maintain a reactive stance relative to PV and grid integration.

table 1. Grid penetration scenarios, PV impact/role, objectives, rules, and concerns.

% of Generation # 2% # 10% # 30% 100%

Grid penetration scenarios

Low-numbers and level of PV with relatively stiff grid connection

Moderate-level of PV with relatively soft grid connection

High-level of PV with capacity of grid less than the load demand

PV operates part time as an island or microgrid

PV impact and its role in the grid

Very low, not significant to grid operation

Noncritical, can affect distribution voltage near PV

Critical to power delivery and meeting demand

Primary power source for stand alone operation

Interconnection and integration objectives

Noninterference, good citizen, and compatible

Manage any local distribution impacts

Engage PV for system operations and control

Rely on PV for stability and regulation

Rules/standard operating procedures

IEEE 1547-2003 current practice radial feeders

Modified 1547, add network and penetration limits

New rules include operation and grid support requirement

Standalone rules that are system dependent

Main concerns with respect to system dynamic grid impacts

— Voltage and current trip limits

— Response to faults— Synchronization

— Interfere with regulation

— Recovery times— Islanding— Coordination

— Availability— Regulation provided— Remping response— Interactions of

machine controls

— Availability— Load following— Voltage control— Normal and reserve

capacity


through 2020 is shown in Figure 13. In this scenario, third-party providers become well established and cap-ture a major share of this emerging energy market. In an-other scenario, utilities may be the largest player, either owning the majority of added capacity or purchasing its output via PPAs.

The argument for third-party engagement is that smaller, faster-moving companies can be more effective at introducing new technology. The argument for utility engagement is based on taking more responsibility for benefi cial PV integration, improving the potential for grid support and faster expansion of PV deployment. Different

ownership structures for consumer-sited, grid-connected PV systems determine the degree to which utilities can infl uence project siting and sizing, grid impacts, and other key issues (Figure 14).

PV as a Consumer Asset or Third-Party AssetPV systems can be deployed, owned, and operated by con-sumers, as is the traditional approach, or by third parties, per an emerging business model. Solar generation may serve on-site loads and be net metered, host consumers may buy energy through PPAs, or owners may manage output within

figure 14. Advantages and disadvantages of different utility engagement levels in customer-sited PV.

PV PV PVInverter

andPV Meter

PV PV PVInverter

andPV Meter

Inverterand

PV Meter

Loads

Consumer Asset

Shared Asset

Utility Asset

Ser

vice

Pan

el

Meter

Loads

Ser

vice

Pan

el

Meter

Loads

Ser

vice

Pan

el

Meter

• No Control Over Location and Sizing

• Obligation to Evaluate and Service Interconnection

• Negative Effect on kWh Revenues

• No REC Ownership

• No Control Over PV System Operation

• Limited Control Over Location and Sizing

• Incentive for Interconnection; Some Control Possible

• Negative, Neutral, or Positive Effect on kWh Revenues

• Potential REC Ownership

• Some Control Over PV System Operation

• Potential for Rate-Based Cost Recovery

• Full Control Over Location and Sizing

• Incentive for and Control Over Interconnection

• Neutral or Positive Effect on kWh Revenues

• Rec Ownership

• Maximum Control Over PV System Operation

• Potential for Rate-Based Cost Recovery

PV PV PV

Customer-Sited PV: Alternative Ownership Structures

Owned by Consumer Owned by Utility


a larger portfolio of generating assets. Consumers or third-party providers own the RECs. The utility role is limited to ownership of the revenue meter and perhaps to provid-ing incentives, and PV systems serve as negative loads and daytime generators that are more likely to have adverse im-pacts on power quality and grid reliability and less likely to provide grid-support functions. The potential for rate-based cost recovery is limited.

PV as a Shared Asset PV systems can be deployed, owned, and operated through consumer-utility partnerships or producer-utility part-nerships, both of which represent emerging approaches. Figure 14 shows a system in which the utility owns the inverter and the consumer owns the PV array, but many other arrangements are possible. Regardless, PV systems operate as distributed yet intermittent resources that may serve as negative loads, are less likely to have adverse impacts on grid operations, and are more likely to pro-vide premium power and grid support services. On-site usage, net metering, PPAs, and REC ownership agree-ments are negotiated. Additional potential exists for rate-based cost recovery.

PV as a Utility AssetPV systems can be deployed, owned, and operated by utilities. The systems serve as distributed yet daytime resources that may provide premium power and grid-support services. Solar generation may be separately metered to serve on-site loads via PPAs and/or managed within a larger portfolio of generating assets. RECs are owned by the utility, and rate-based cost re-covery is very likely.

ConclusionElectric service providers are well positioned to expand their engagement in deploying PV systems. Many have found themselves in a bright spot relative to solar business oppor-tunities. However, most providers are still facing the decision of whether to modify traditional business models for active engagement or maintain a reactive stance relative to PV and grid integrations. In either case, R&D that will lead to a more fl exible and interactive electric distribution system is needed. A near-term priority for individual utilities is to defi ne the grid-interactive and grid-independent applications and mar-kets that offer the greatest potential risks and rewards and to develop plans for addressing them. This is particularly impor-tant in areas with excellent solar resources, strong incentives,

or both. And this may hold true across the country under cur-rent policy and market conditions.

AcknowledgmentsThis article is based on an EPRI public white paper pre-pared by Phil Barker of Nova Energy Specialists, Chris Po-wicki of Water Energy & Ecology Information Services, and Elizabeth Hooper of Hooper Design. It is available by EPRI 1018096 or http://my.epri.com/portal/server.pt?Abstract_id=000000000001018096.

For Further ReadingEPRI, “Solar photovoltaics: Expanding electric generation options,” Palo Alto, CA, EPRI 1016279, Dec. 2007.

EPRI, “Distributed photovoltaics: Utility integration issues & opportunities,” Palo Alto, CA, EPRI 1018096, Aug. 2008.

T. Key, “Evaluation of grid-connected inverter power systems: The utility interface,” IEEE Trans. Ind. Applicat., vol. IA-20, no. 4, pp 735–741, July/Aug. 1984.

EPRI, “Engineering guide for integration of distributed generation and storage into power distribution systems,” Palo Alto, CA, EPRI 1000419, 2002.

T. Key, B. Johnson, R. Langley, L. Morgan, and T. Rizy, “Dynamic interactions: The next hurdle for integration of dis-tributed energy resources,” presented at the Power Systems 2004 Conf., Madren Center, Clemson Univ., Mar. 2–4, 2003.

R. Dugan, T. Key, and G. Ball, “Distributed resource standards,” IEEE Ind. Applicat. Mag., vol. 12, no. 1, pp. 27–34, Jan./Feb. 2006.

EPRI, “Creating incentives for electricity providers to in-tegrate distributed energy resources. A report of the EPRI distributed energy resources public/private partnership,” Palo Alto, CA, EPRI 1014899, CEC-500-02-014, 2007.

Solar Electric Power Association. Utility Solar Business Models: Emerging Utility Strategies & Innovation, Solar Electric Power Association #03-08, 2008.

P. Barker, M. McGranaghan, T. Ortmeyer, D. Crudele, J. Smith, and T. Key, Advanced Grid Planning and Opera-tions, SAND2008-0994 P, Feb. 2008 [Online]. Available: www1.eere.energy.gov/solar/solar_america/rsi.html

EPRI. (2006, Nov.). Master controller requirements spec-ifi cations for perfect power systems. Revision 2-1. EPRI, Palo Alto, CA. [Online]. Available: www.galvinpower.org

BiographyThomas Key is the technical lead for renewables at EPRI. p&e

PV systems can be deployed, owned, and operated through consumer-utility partnerships or producer-utility partnerships, both of which represent emerging approaches.

finding a bright spot

Documents