Technical Issues Related to NCUC Net Metering Docket 100

Quanta Technology Page 1 of 20 1/19/2008

Technical Issues w/ Net-Metering

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1/19/08

Consulting Project #08T001

White Paper on

Technical Issues Related to NCUC Net Metering Docket 100, Sub 83

Prepared for: North Carolina Sustainable Energy Assoc. Prepared by: Quanta Technology, LLC Authors: Donald J. Morrow, PE [email protected] 919 334 3023

H. Lee Willis, PE [email protected] 919 334 3020



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Table of Contents

1 INTRODUCTION ...................................................................................................................................... 3

1.1 NCUC NET METERING DOCKET........................................................................................................... 3 1.2 SPECIFIC QUESTIONS ............................................................................................................................ 3

2 T&D RELIABILITY CHALLENGES ..................................................................................................... 5

2.1 SAFETY ................................................................................................................................................. 6 2.2 INCREASING UNIT SIZE ......................................................................................................................... 6

2.2.1 Equipment Upgrades ....................................................................................................................... 7 2.2.2 Metering Upgrades .......................................................................................................................... 7 2.2.3 Protection and Control .................................................................................................................... 7 2.2.4 Standby Capacity ............................................................................................................................. 7 2.2.5 Power Quality .................................................................................................................................. 8

2.3 INCREASING AGGREGATE SIZE ............................................................................................................. 9 2.3.1 Adequacy & Definition of Aggregate Limit ..................................................................................... 9 2.3.2 Equipment Upgrades ..................................................................................................................... 10 2.3.3 Stand-by Capacity.......................................................................................................................... 10 2.3.4 Power Quality ................................................................................................................................ 11 2.3.5 Islanding ........................................................................................................................................ 11 2.3.6 Concentrations of Generation by Type .......................................................................................... 11

2.4 SMART GRID SYSTEMS ....................................................................................................................... 11 2.5 AGGREGATE NET EFFECT ON THE UTILITY ......................................................................................... 13

3 CONCLUSIONS ....................................................................................................................................... 15

4 ABOUT THE AUTHORS ........................................................................................................................ 17

5 BIBLIOGRAPHY..................................................................................................................................... 18

APPENDIX: CATALOG OF T&D RELIABILITY ISSUES RELATED TO DG..................................... 19



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1 Introduction

The North Carolina Sustainable Energy Association (“NCSEA”) has engaged Quanta Technology,

LLC (“QT”) to assist them with technical issues related to Net-metering Docket E-100, Sub 83 open

before the North Carolina Utilities Commission (“NCUC”).

This project draws upon the collective knowledge, experience and expertise of several QT advisors in

the areas of distributed generation, T&D engineering, T&D standards, electric system maintenance,

electric system operation, and resource planning.

1.1 NCUC Net Metering Docket

On October 20, 2005 the NCUC issued its Order Adopting Net Metering. In this Order, the NCUC

made net metering available to “a utility customer that owns and operates a solar PV, wind-powered,

or biomass-fueled renewable energy facility without battery storage.”

Among other requirements identified in this Order, NCUC allowed for generating facilities with

capacity up to 20 kW for residential customer and up to 100 kW for non-residential customers. In

addition to these individual facility limits, the NCUC adopted “an aggregate limit of 0.2% of the

utility’s North Carolina jurisdictional retail peak load for the previous year.”

Subsequent to this Order becoming effective, the NCUC in December 2007 issued an Order

Requesting Comments to address questions related to the need for specific service riders to sell excess

energy, as well as to explore the need for additional metering if the customer is not seeking credit for

sale of such excess energy. In issuing the Order Requesting Comments, the NCUC noted “the

Commission has seen tremendous growth in the number of small customer-owned electric generating

faculties and anticipates continued growth as a result of the enactment of the Renewable energy and

Energy Efficiency Portfolio standard (REPS) provisions.”

Comments are due to the NCUC in response to the December, 2007 Order Requesting Comments on

or before January 18, 2008. NCSEA intends to issue comments on this December, 2007 request.

1.2 Specific Questions

Given the recent passage of Senate Bill 3, NCSEA anticipates significant growth of sustainable

energy resources in the State. To achieve this legislative mandate, they anticipate that the

requirements related to generating facility size and aggregate system load from the Docket 100, Sub

83 may need to be increased. Indeed, NCSEA in the earlier, 2005 process had advocated for larger

net aggregate generation eligible for net metering of 1% of utility growth. As NCSEA develops their

comments on the December, 2007 Order Requesting Comments, they have requested the assistance of

QT to sort through reliability issues related to increase per facility size and the aggregate limit.

The specifically questions NCSEA asks are:

� How should the term “Aggregate Limit” discussed in the docket be defined?



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� Given the above definition and the current state of the NC electric system, what is the

maximum limit for the net system capacity for aggregated net-metering necessary to preserve

system reliability? What is the maximize size limit for individual generators eligible for net-

metering?

� Given these limits, what system upgrades may be necessary to maintain reliability?

� Please quantify this investment in terms of type of investment

During the kick-off meeting on January 10, 2008, NCSEA indicated they are contemplating

individual facility size of 1 to 2 MWs and aggregate limit of 2%



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2 T&D Reliability Challenges

Electric system reliability is a complex issue. There are several components that must be considered

as one contemplates impacts of certain changes to the electric system. These issues include:

� Continuity of service to the customer

� Quality of power delivered to the customer

� Impacts on customer equipment

� Impacts on neighboring systems (i.e., utility A’s actions impacting utility B’s reliability)

� Maintaining common interconnection standards (e.g. frequency and time standards)

� Ensuring adequacy of supply during times of peak

� System resonance conditions that transcend customer, or even utility, boundaries

Utilities utilize a variety of techniques to maintain reliability. Following are some commonly applied

methods used by utilities for maintaining the reliability of the electric system:

� Formal work practices and safety rules.

� Industry standards to ensure consistency from system to system (e.g., ANSI, NESC, IEEE,

NEC, etc.)

� Manufacturing standards to ensure consistency of device operations (e.g., ANSI, UAL, IEEE,

NEMA, etc.)

� Federal Mandated Reliability Standards implemented through the North American Electric

Reliability Corporation (“NERC”) to ensure reliable operation and capacity adequacy of the

three interconnections in the USA.

� Rates and rules set by States to ensure minimal standards are met for customer

interconnections.

� Utility design standards which reinforce, augment, and apply the above within the utility.

� Maintenance practices to ensure equipment is operating properly.

� Work practices to ensure safe operation for customers and utility workers.

� Protection schemes which monitor the performance of portions of the electric system and act

to protect equipment and restore service when incidents occur.

� Control centers which collect system data, evaluate conditions and issue controls to maintain

and ensure reliable service to the customers.

When distributed generation (“DG”) is added to the system (including sustainable facilities eligible

for net metering in North Carolina), care must be taken to ensure that reliability is maintained.

However, these methods are often adequate to maintain reliability even as the individual facility size

and the aggregate limit are increase.

In the following sections, we discuss safety as it relates to DG, the impacts to reliability based upon

increasing the size of facilities eligible for net metering, and impacts based upon increasing the

aggregate size.



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2.1 Safety

The most important issue with the electric system is safety. Working near energized electrical

equipment can be hazardous if safe equipment and design are not used, and if good work practices are

not followed. The energy present in most parts of an electric utility system is sufficient to burn, maim

or kill a human being if not properly handled. Adding generation behind the meter (i.e., at the

customer location) adds to the amount of energy present and can increase safety concerns in some

situations, particularly if there is a potential for “back-feeding” into the utility system. This occurs

when the utility’s equipment has been de-energized so that it is not feeding power to its equipment,

but customer-owned facilities are still feeding power, perhaps sufficient to cause hazardous

conditions for any field personnel caught unawares because they expect the utility equipment to be

completely de-energized.

A concern with any size and amount of customer-owned generation is that it can be difficult, and in

some cases impossible, for utility field personnel to determine if there is customer-owned generation

installed at a particular site based on only a visual inspection of the service interface. Increasing the

permitted size of customer-owned generation will increase the “reach” or extent (the portion of the

system) over such which customer-generation concerns would be an issue, and would increase also

the magnitude of any safety-related issues associated with fault current contributions such generation

would makes under back-feeding conditions1.

To address these safety issues utilities have developed work practices and safety rules which make

work on utility systems with customer-owned generation safe and efficient. These safety practices

include testing for backfeed voltage, formal tagging and clearance processes, grounding practices, use

of regularly tested protective gear (e.g., rubber cloves, hot sticks), requirements for flame retardant

clothing, etc. These practices - when rigorously followed by field crews, operators and their

supervision - ensure their safety and protection.

One may argue that increasing penetration of DG installations (including those covered to the NCUC

net metering docket) will increase the probability of exposure to back feeding, and therefore

negatively impact safety. However, consistency of method and process is a hallmark of sound safety

programs. These practices need to be followed routinely whenever there is any customer-owned

generation that could be operating on the utility system, be it units limited to 20 kW in size or 2 MW,

and regardless of whether they constitute only .2% or 2% of system generation. Thus, when safety

rules and work practices are followed rigorously and accurately, individual unit size and aggregate

total limits are not really an issue for field worker safety.

2.2 Increasing Unit Size

This section discusses the specific reliability impacts due to increasing facility size.

1 A back-feed condition exists when the utility breaker is open on a feeder, but a customer generation is on and

connected to the feeder. The generator “back-feeds” the feeder and maintains voltage on the feeder.



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2.2.1 Equipment Upgrades

While unique situations are certain to exist, generally it is not anticipated that equipment upgrades

will be needed for increasing facilities eligible for net metering to 1 or 2 MWs in size.

2.2.2 Metering Upgrades

Much of the metering and customer-connection equipment in use by utilities throughout North

Carolina is unidirectional: specified, designed, and installed based on an assumption that electricity

only flows from the utility into the customer facilities. This was a very reasonable assumption to

make in the past, when no customer-owned generation was expected to be present on the system.

Bi-directional meters and other revised equipment may need to be installed for any DG installations,

whether net metered or otherwise. The “metering” and equipment under discussion is not that

required for billing purposes but that which are required for measurement of current flows so that the

utility can operate its power system safely, efficiently, and to acceptable standards of power quality

2.2.3 Protection and Control

Owners of generation facilities eligible for net metering will often desire to sell their excess energy

(energy produced by the facility and which exceeds what is required to meet their own needs) into the

utility grid. Technically, production of excess energy requires the utility to have the ability to detect

and measure flows bidirectionally (in and out of the customer site) in order to monitor power flow

and fault protection so it can control voltage and service quality for its customers. From a practical

standpoint, however, only very limited equipment, consisting of cutout fuses, may be required for

really small generators, in the range of 5 kW up to perhaps 20 kW, because such small units do not

have the capability to alter voltage or power flow on a utility circuit by a substantial amount.

Increasing the permitted generation limit to 1 or 2 MW would require monitoring and protection

equipment that is both rated at higher current levels than that required for generators in the 10 to 100

kW class facilities, and in some cases capable of more extensive measurement and control functions.

As unit size is increased, this may involve installation of additional or more precise voltage, current,

and harmonics measurement equipment, along with voltage regulators, switching or fixed capacitors,

circuit reclosers or breakers, and two-way real-time communications equipment to the utility’s

distribution control center.

2.2.4 Standby Capacity

Increasing facility size (permitted limit for customer owned generation) for net metering will likely

decrease the peak demands measured by the utility on its distribution circuits (power being feed into

distribution circuits by one customer services demand of nearby customers, reducing the amount the

utility must provide). However, the utility will still have an obligation to serve the total customer

load as imposed by the NCUC. It will have to accumulate data on gross and net installed customer-

owned generation on its system (in part by using the monitoring systems discussed in 2.2.3) and

combine that with its circuit-level peak demand readings in order to track and plan the system

capabilities needed to meet its obligations. However, such recording and planning is routinely done

by many electric utilities for other reasons (tracking large transient industrial loads), and is needed

regardless of the size and amount of generation installed.



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2.2.5 Power Quality

Many electric customers can be inconvenienced by voltage surges and dips, high voltage, voltage

flicker, or harmonics affecting their sensitive electrical equipment. As any local generation facility

increases in size, it’s potential to create noticeable power surges in the circuit area nearby increases.

Particularly upon starting and stopping the unit, as size of the unit increases, the effect of surges and

“voltage flicker” becomes more noticeable for neighboring customers. Voltage regulation on the area

of the system nearby becomes more of a potential issue, too.

To address these issues, many utilities have established rules that specify times, conditions, and the

type of startup and shut-down sequences the generator must follow to provide voltage control and

manage power surges. These rules and the process to work with them are not materially different in

any way due to increasing facility or aggregate limit size. Further, the sustainable energy resources

will typically operate on a continuous basis and will not subject the system or other customers to such

conditions.

Wind turbines can create voltage flicker conditions2 due to the fact that smaller generators may use

synchronous generators which vary in their output by the variation of the wind. In these cases, the

utility may establish a rule for power factor range on small wind scale wind facilities to prevent this

type of impact on neighboring customers. Customers may be required to install certain dynamic

power factor correction equipment such as DSTATCOMs or Dynamic Var Compensator devices to

maintain voltages at acceptable levels for the utility. This case assumes that no pre-existing voltage

flicker issues exist on the feeder so that the cause of voltage flicker can be appropriately determined.

For sustainable resources that use DC-AC converters (variable speed wind turbines, solar

installations, etc.) harmonics may become an issue. Harmonics exist when energy is injected into the

grid at frequencies that are multiples of 60 hertz. Harmonic questions are often difficult to sort out as

to what causes them: often any negative affects are the cumulative result of many harmonic sources

including computer power supplies, overloaded utility or customer-owned transformers, worn or

corroded electrical equipment grounding, certain types of lighting and industrial processes, as well as

DC-AC converters.

Utilities manage these issues with regard to customer owned generation by requiring generators to

satisfy interconnection standards. The Institute for Electric and Electronic Engineers (“IEEE”), a

professional engineering organization, has addressed these concerns by developing maximum

standards for harmonic current injections by DG (distributed generation) sources through IEEE 1547.

These standards are used by manufacturers in their designs and customers are required to adhere to

their specifications. Utilities in North Carolina may enforce this standard with their service rules filed

with the NCUC. If a particular installation results in harmonic issues, these issues can be managed by

installation of harmonic filters that remove the problem before it is injected on the grid. In cases

where it is clear customer installed equipment is the cause, those customers will be required to install

harmonic filtering on their installations or make other changes or equipment installation.

2 Voltage flicker is the term used for noticeable illumination changes from lighting equipment due to voltage

fluctuations on the power system. This issue is addressed in IEEE Standard 1453.



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Once again, it should be noted that these power quality issues may be present regardless of unit size.

Nonetheless, increasing generator size could intensify the power quality impacts of customer

generation facilities that are poorly-designed, installed, or operated. However, the utility’s

requirements as based on IEEE 1547 or similar guidelines will be effective in all cases if enforced

consistently. Therefore, the harmonic issue should be effectively managed.

2.3 Increasing Aggregate Size

This section discusses the specific reliability impacts due to increasing aggregate limit size.

2.3.1 Adequacy & Definition of Aggregate Limit

Currently the aggregate limit for net metered customer-owned generation in North Carolina has been

set to 0.2% of the utilities' peak load. Assuming a 20,000 MW peak demand level for North Carolina,

this aggregate limit is equal to 40 MWs of customer-owned, net metered generation throughout the

state. NCSEA is contemplating a 2% aggregate limit, which is equal to 400 MWs of sustainable

generation.

Utilities in North Carolina, like those in the rest of the US, are required to have firm capacity reserves

based upon a certain percentage of their firm load; SERC currently has guideline requirements for

planning reserve margins of just under 15% for utilities in the SE US. Nationally, according to page 4

of the NERC Summer Assessment for 2007, "capacity margins are intended to mitigate the higher

load levels associated with extreme weather events, the unplanned loss of generation capacity, and

provide sufficient operating margins." These limits are set to maintain a loss of load probability of 1

day every 10 years.

If sustainable resources are installed that provide high output during peak times (e.g., solar) or

facilities with stable output (e.g., gen-sets that run on methane fuel derived from farm waste), then

adequacy concerns are minimized. However, care must be taken with sustainable resources that can

radically vary their outputs when determining their capacity allocation. This is especially relevant as

parties contemplate increasing the aggregate limit.

First, if the aggregate limit is increased, it is possible that some of this anticipated supply would not

be available to the utility at the time of system peak. If that occurred, the result would be a realized

planning reserve margin reduction. Depending upon the amount of a reduction, such a reduction may

be sufficient to result in a measurable decrease in adequacy, resulting in electric customers throughout

North Carolina having a higher probability of a supply shortage. Even if a measurable reduction

were sufficient, however, it should also be noted that this measurable increased risk of a supply

shortage may still satisfy the one day in ten year NERC requirement. Only detailed analysis can

determine if that is the case.

Second, if capacity in the Docket 100, Sub 83 is taken to be the same that is used for wholesale

capacity planning, then the actual energy production potential from net metering facilities could be

higher than a limit anticipated by the NCUC. If care is not taken with the definition of capacity, then

unanticipated energy may enter the system, which may impact system operations if these amounts

significantly exceed the anticipated aggregate limit of 2%.



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Fortunately, it is relatively easy to resolve a possible mismatch in assumed capacity and use of the

appropriate amount for use in resource planning at the wholesale level by following these steps:

1. Define capacity in Docket 100, Sub 83 as the name plate rating of the facility

2. Increase firm load requirement in planning reserve calculation as follows:

Reserve = (1 - capacity contribution factor) x aggregate sustainable capacity

eligible for net metering

Using the name plate rating as the basis for capacity in Docket E100, Sub 83 will prevent the situation

where unanticipated, large amounts of sustainable energy are produced. Adjusting the firm load

calculation will align the actual anticipated output of facilities at the time of system peak with the

amount assumed during resource planning.

If these steps are taken, then increasing the aggregate limit to 2% of system peak will result in

manageable adequacy and planning issues. Operation voltage and power swings should be

manageable at these levels of sustainable energy.

2.3.2 Equipment Upgrades

Much of the equipment used at the distribution level in a utility system is based upon specific current

ratings, most often limited to no more than 400 or 600 amps. This current limit is usually standard

for the type of equipment regardless of the distribution voltage level. However, very often, and by

design, the wire or cable and other equipment used at the ends of neighborhood feeder circuits has far

less capacity than this, often only 100 amps (the nominal rating of #6 size ACSR conductor) on small

laterals at the end of feeder circuits.

As the facility size and/or aggregate limit increase, heavy concentrations of DG near the end of a

circuit, if used for the sale of excess energy (that not needed by the customer) feed back into the grid

could cause current flows to exceed the rating of this equipment. Some equipment types are not

affected, including typically instrumentation metering, lightning arresters, and breakers will not

typically be impacted by either increasing facility size or the aggregate limit.

2.3.3 Stand-by Capacity

As discussed in section 2.2.4, increasing facility size for net metering will likely decrease the load

service measured by the utility. However, the utility may still have an obligation to serve that

customer imposed by the NCUC. Care must taken in the utility design standards to take this

condition into account as new facilities are developed, especially as the aggregate limit is increased

and individual feeders become more loaded – perhaps favoring certain types of sustainable energy

due to local area resource concentrations.



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2.3.4 Power Quality

Increasing the aggregate limit for customer generation will increase the intensity of the potential

power quality problems, however rigorous application of standards and interconnection rules by the

utility should resolve these issues.

2.3.5 Islanding

As the aggregate limit is increased, the potential for “islanding” will as well. Islanding occurs when

local generation is serving all local customer energy use, and the area of the power system somehow

becomes disconnected from the electric grid (there is a blackout or other problem with the utility

power feed).

While islanding may appear advantageous to local customers (they are receiving power during a time

the utility has outage problems) islanding is nearly always problematic, because without utility

connection there is no local control of voltage, current, surges, and power flow: customer-owned DG

equipment cannot provide this function. As a result, an islanding configuration can often result in

low or high voltage, large and frequent transient voltage swings, and increased power quality

problems.

All of these issues can be addressed using standard utility grid sensing methods and equipment with

provisions to open the customer breaker (disconnect their generator) when the grid is not connected.

Sensing methods are improved greatly when advanced metering infrastructure (“AMI”) or Smart Grid

technology is used and may be required in certain instances.

2.3.6 Concentrations of Generation by Type

It is possible that while the overall diversity of sustainable resources by type may be significant, local

pockets within the North Carolina power grid may contain concentrations of only one type. For

example, it is likely that bio-mass processes will be concentrated on feeders that serve multiple hog

farms, solar will be concentrated in areas with high insolation, and wind will be concentrated in areas

with relatively, consistently steady wind resources.

As a result, the utility may experience an intensification of the issues identified in this report in a

given area of the system or even specific feeders. The technical resolution of the reliability issues are

the same. Utilities current methods discussed in other sections of this white paper should be

sufficient to manage these issues. However, it is conceivable that certain configurations may require

more advanced monitoring and control. In these cases, Smart Grid technologies may be warranted.

2.4 Smart Grid Systems

New technologies, products and control schemes permitting improved monitoring and control of local

distribution system performance and status are being brought into the electric power system

equipment market on an almost daily basis. These many new devices and systems are often referred

to jointly as “Smart Grid” technology. Smart Grid consists of combined use of technical

developments in several new technology areas (Figure 1).



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Figure 1: Smart Grid Technology Overview

Smart Grid systems use a diverse range of local measurement sensors installed at many key points

throughout a utility distribution system to measure voltage, current, and perhaps equipment status and

condition on a moment to moment basis. “Smart” local equipment (voltage regulators, switches, etc.)

reacts automatically to control voltage, restore power flow if there are equipment outages, and

maintain good service to customers based on local readings and “knowledge” stored in their

computers about how they should react to various situations. Low cost data communications is used

to transmit key data on distribution system status and the actions of this automatic equipment back to

the utility control center.

Industry experience with these systems is evolving rapidly, driven by a number of trends and forces

(Figure 2) that have combined to both drive the industry to use this technology and to encourage

R&D to create new devices and systems to fill in “gaps” in needed capabilities of Smart Grid

systems. Overall, potential improvements in safety, efficiency, lower cost and improved reliability

and service quality are the benefits being sought.



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Figure 2: Smart Grid Landscape

Smart Grid technology would enable an electric utility to monitor and adjust its distribution system

locally on an as-needed basis to best accommodate the output of sustainable customer owned

sustainable generation into its distribution grid on a moment-to-moment and location-to-location

basis, improving reliability, service quality, and potentially improving its ability to synergistically

combine cost-effective use of its existing distribution system with that of customer owned sustainable

generation, to improve reliability and to defer the need to add other resources on its system. The

degree to which utilities can install and utilitize such a system and gain these benefits will depend in

good measure on the support they get for use of such technologies from regulators and their rate

structure.

2.5 Aggregate Net Effect on the Utility

Sections 2.2.1 through 2.2.5, and 2.3.2 through 2.4 outlined various technical issues which a utility

might confront if limits are increased. These sections also identify equipment upgrades and/or other

additions utilities may need to make to address these technical issues.

The net effect of these changes in aggregate, along with increased size and totals for customer-owned

sustainable generation on the utility system’s performance and reliability, would depend greatly on



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how well those issues were addressed in the engineering designs and standards followed by the utility

and the performance of the facilities being installed. Assuming that utilities are permitted to justify,

add, and pay for that needed additional equipment, including newer technologies (Section 2.4) in the

manner similar to how they have invested in their past systems, there is every reason to expect the net

impact would even be positive. First, the equipment and additions discussed here can potentially

alleviate all negative issues with respect to safety, reliability of service, power quality, equipment

utilization and operation, and overall utility performance. Second, availability of such local

generation has the potential to reduce electrical loses many hours of the year, actually boost voltage

and power factor (if combined with the correct added equipment, an assumption here) and to reduce

or defer future capital investment required for T&D expansion as consumer demand for power

continues to grow.

Finally, much of the equipment added because of customer-owned generation will have ancillary or

additional benefits to the utility. For example, harmonics monitoring and control devices, and

additional voltage regulation and power factor controllers that might be needed to accommodate

customer-owned sustainable generation could improve power quality all hours of the year, regardless

of whether that customer generation is operating. Utilization of Smart Grid technology has the

possibility of further enhancing a utility’s ability to monitor and control its own and customer

equipment and improves the operation and reliability of its system.



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3 Conclusions

QT investigated the technical issues related to the T&D system resulting from increasing individual

sustainable resource size of customer-owned generation operated on a net-metered basis to the 1 to 2

MW range and increasing the aggregate limit to 2% of total system peak load. To summarize:

1. How should the term “Aggregate Limit” discussed in the docket be defined?

Answer: Based upon our review, safety, reliability and operating issues are manageable as long as

the definition of aggregate capacity in Docket 100, Sub 83 is taken as name plate capacity and

utilities adjust their firm load calculation for capacity planning as discussed in section 2.3.1.

2. Given the above definition and the current state of the NC electric system, what is the

maximum limit for the net system capacity for aggregated net-metering necessary to preserve

system reliability? What is the maximize size limit for individual generators eligible for net-

metering?

Answer: Assuming that utilities are permitted to justify, add, and pay for needed additional

equipment, including newer technologies, in a manner compatible with their traditional levels

of comprehensive engineering and equipment coordination, there is reason to expect the net

impact of customer-owned sustainable generation in the 1 to 2 MW class and aggregate total

of 2% of system peak on the North Carolina electric grid is manageable. The potential exists

that net impact could even be positive with regard to reliability, power quality, and system

efficiency.

3. Given these limits, what system upgrades may be necessary to maintain reliability?

Answer: The following are anticipated adjustments to utility systems as result of these contemplated

increases to facility size and aggregate limit:

� Investment in cable, wire and certain related equipment upgrades may be required on some

portions of distribution feeders.

� Additional or upgraded distribution equipment may need to be upgraded or new feeders

added in rare cases.

� Additional monitoring and protection equipment for bi-directional measurement, response,

and control of the distribution system in selected places of the system in which there are large

and/or heavy local concentrations of customer-owned generation.

� Bi-directional control metering and protection equipment may need to be installed.

� Operating procedures and standards may need to be revised, particularly in any local areas

with high concentrations of DG.



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� Utility design standards and planning methods may need to be modified to take into account

the obligation to serve requirements for net metering facilities.

� Advanced metering infrastructure, Smart Grid methodologies and local area communications

may be required to manage coordination of increased concentrations of net metered facilities

on individual feeders.

4. Please quantify this investment in terms of type of investment

Answer: See question 3 summary.



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4 About the Authors

H. Lee Willis, PE, Senior Vice President, is internationally recognized innovator and

practitioner of electric T&D systems planning and engineering. During his 35 years of professional

experience he has been transmission planning manager at a major investor-owned utility, an executive

with a major equipment supplier, and a senior consultant who has directly performed or supervised

more than 400 system planning and asset management projects for utilities around the world. . Lee is

an IEEE Fellow, and served on the National Research Council, which advises the US Congress on the

nation’s civilian technology needs through input to the National Labs system. He has published more

than 230 technical papers including 57 in peer-reviewed engineering journals, as well as seven books

on power systems engineering, which include Power Distribution Planning Reference Book (now it

its Second Edition) and Distributed Power Generation, both by CRC Press.

Donald J. Morrow, P.E., VP Transmission. Mr. Morrow has held a variety of engineering and

management responsibilities including: transmission planning, transmission operations, control area

operations, generation operations, energy market operations, distribution operations, and natural gas

distribution dispatch. Don and his team at Quanta technology have led a variety of projects to study

the transmission designs necessary to reliably deliver renewable energy to the interconnected grid.

Previous to joining Quanta Technology, Don was responsible for the start up and management of

system operations at American Transmission Company. He has been actively involved in many

industry organizations including NERC, MRO, RFC, MAPP, MISO, and Power Systems Engineering

Research Consortium. Mr. Morrow is a registered professional engineer in the States of Wisconsin

and Arkansas.



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5 Bibliography

1. H. Lee Willis, Power Distribution Planning Reference Book, 2nd

edition, CRC Press, New

York, 2004.

2. Lorrin Philipson and H. Lee Willis, Understanding Electric Utilities and De-Regulation, 2nd

edition, CRC Press, New York, 2005.

3. H. Lee Willis & Walter G. Scott, Distributed Power Generation – Planning and Evaluation,

CRC Press, New York, 2001.

4. Jim Burke, Power Distribution engineering – Fundamentals and Applications, CRC Press,

New York, 1994.

5. Standardization of Small Generator Interconnection Agreements and Procedures, Order no.

2006, 18 CFR Part 35, Federal Energy Regulatory Commission, May 12, 2005.

6. Order Adopting Net Metering, Docket No. E-100, Sub 83, North Carolina Utilities

Commission, Oct. 20, 2005.

7. http://www.ncuc.commerce.state.nc.us/ncrules/Chapter08.pdf

8. IEEE Standard 1547 on Distributed Generation Interconnection Standards

9. IEEE Standard 1453 on Voltage Flicker.

10. NERC 2007 Summer Assessment.



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Appendix: Catalog of T&D Reliability Issues related to DG

The following table is a catalogue of reliability issues related to DG. The table identifies current

industry practices and techniques for resolution. Thee issues are not necessarily related to unit or

aggregated size and, therefore, they are included as an appendix to the report.

T&D Reliability Issues

Related to DG

Discussion Typical Resolution

Safety Concern over back-feeding of customer generation

during circuit outages.

Work Practices (tagging & clear-

ance protocols), AMI & Smart

Grid coordination.

Equipment Overloads Certain equipment rated for specific current carrying

capability (e.g., elbows typically rated at 600 amps)

Upgrade equipment, add addi-

tional circuits or current pathways

Protection Coordina-

tion

Interaction of generators on radial feeders appear like

a network configuration, necessitating new standards

& revised protection design. Possible increased fault

currents due to additional sources.

System studies, reverse power

relays, protection schemes ori-

ented to network-like operation

Islanding Unintended operation of feeder when disconnected

from utility grid. Concern is safety and customer

power quality (e.g., low or high voltage, flicker, etc.).

Protection coordination, utility

grid sensing, AMI & Smart Grid

coordination

Harmonics & Tran-

sients

DG installation of sustainable energy often have

power converters that could introduce harmonics

(continuous electrical energy at multiples of 60 hz) or

transients (short duration, high power surges)

Planning studies using currently

available SW, manufacturer’s

standards, AMI & Smart Grid

monitoring & control

Voltage Flicker Periodic variation of voltage which results in lighting

variation often disturbing nearby customers.

Dynamic VAR Compensation,

manufacturer’s standards, system

studies

Resonance Heavy concentrations of uncoordinated generation on

a feeder may have control systems that interact in a

way that they fight each other in a continuous manner

AMI & Smart Grid, coordinated

protection schemes

Substation and

Feeder Design Stan-

dards

Heavier concentrations of generation will change the

commonly accepted design principles used by utilities

– e.g., bi-directionality, fault current levels, loading

profiles.

Revision to standards

Voltage Profile Radial distribution designs presume decreasing volt-

age as one moves away from the utility substation.

DG reduces this profile and, if heavy supply to the

grid is occurring, may reverse this profile.

Protection coordination, AMI &

Smart Grid coordination, revised

design standards, revised field

power factor-compensation

schemes.

Meter Directionality Instrumentation metering (voltage, current, power) has

been sometimes been assumed to be unidirectional.

DG creates the potential for bi-directionality.

New Meters



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Adequacy: Resource

Planning

If there is a high degree of DG penetration, concern

exists about resource adequacy if wholesale resources

are acquired with presumption of DG utilization – this

is a particular concern if DG is concentrated as wind

or solar which has high variability.

Defined Rules at Regional Level,

Increased Planning Reserve Mar-

gins; change planning guidelines

Adequacy: Obliga-

tion to Serve

If a utility is obligated to serve if DG is down, un-

anticipated loading may occur on distribution level

equipment

Distribution planning criteria

Documents

Technical Issues Related to NCUC Net Metering Docket 100