Power Quality: Contracts and Insurance | Electrical Engineering

In this article we will discuss about power quality contracts and insurance signed by service providers to maintain the quality of electrical power supply.

Power Quality Contracts:

Once performance targets have been selected, utilities may enter into contractual agreements with end users with respect to power quality variations. While this is never an easy task, it was simpler when end users had to deal only with a single, vertically integrated utility company.

The deregulation of the electric power utilities in many areas further complicates things.

As Kennedy 12 points out regarding future trends, there now might be up to five entities involved:

i. The transmission provider (TRANSCO)

ii. The local distributor (DISTCO), or the “wires” company

iii. One or more independent power producers (IPPs) or market power producers (MPPs)

iv. Retail energy marketers (RETAILCOs) or energy service companies (ESCOs)

v. The end user.

To meet the performance requirements of the end user, there may have to be contracts between all these entities. While the bulk of the power quality variations may be the result of events on the local distributor’s system, there will also be events on the transmission system that will affect large areas.

RMS Variations Agreements:

Part of the purpose of an interconnection agreement would be to educated users on the realities of power delivery by wire and the costs associated with mitigating voltage sags and interruptions. Another part would be the establishment of some formal means by which the utility records and evaluates the fault performance of its power delivery system.

Some of the key issues that should be addressed are:

i. The number of interruptions expected each year.

ii. The number of voltage sags below a certain level each year. The level can be defined in terms of a specific number such as 70 or 80 percent. Alternatively, it can be defined in terms of a curve such as the CBEMA or ITI curve.

iii. The means by which end users can mitigate rms variations.

iv. Responsibilities of utilities in analyzing the performance of the power delivery system, following up with fault events, etc.

v. Maintenance efforts to reduce the number of faults for events within the control of the utility.

Harmonics Agreements:

Although harmonics problems are not as widespread as RMS voltage variation problems, harmonics from ASDs and other electronic loads can have a severe impact on other end-user equipment. In some cases, the equipment will fail to operate properly, while in other cases, it may suffer premature failure. Therefore, agreements regarding harmonics can be very important. Agreements on harmonics should reflect this bilateral nature.

Some of the key issues that should be addressed are:

1. Definition of the PCC.

2. Limitation of the harmonic current distortion level at the PCC to that set by IEEE Standard 519-1992 or to another value allowed by a specified exception.

3. Periodic maintenance schedules for filters and other mitigating equipment. Some equipment will require constant monitoring by permanently installed devices.

4. Responsibilities of utilities, such as:

(a) Keeping the system out of harmonic resonance

(b) Keeping records about new loads coming onto the system (this is getting tougher to do with deregulation)

(c) Performing engineering analyses when new loads come onto the system to prevent exacerbation of existing problems

(d) Educating end users about mitigation options

(e) Periodic monitoring or constant monitoring by permanently installed devices to verify proper operation of the system.

5. Definition of responsibilities for mitigation costs when limits are exceeded. Is the last end user who created the excess load responsible or is the cost shared among a class of end users and the utility?

Example Contract:

One of the most widely publicized examples of a power quality contract is the one between Detroit Edison and the “big three” automobile manufacturers.

The power quality monitoring system allows Detroit Edison to determine the frequency and severity of voltage sags that occur at the customer locations.

Some of the key details follow:

i. Interruption Targets:

The interruption targets for the DaimlerChrysler and General Motors locations are either 0 or 1. This means that only one interruption is allowed at some of these locations and none at other locations in each calendar year. The service guarantee payment amounts (SGPAs) negotiated for these two companies range between $2000 and $297,000 and are based on the type of process that is being served. Several of these locations operate with their services in parallel so that they usually do not experience a zero-voltage event.

ii. Voltage Sag Targets:

The 1998 SMC amendment states five rules that establish a subset of sags that qualify for payment:

1. The RMS voltage on any of the three phases must drop below 0.75 pu. There is no minimum duration for qualifying voltage sags; all durations are eligible. The threshold was established based on the ITI curve and discussions with the customers. Actual experience is not a factor in the sag qualification.

2. Voltage sags that are caused by the customer are excluded from the qualifying sag list.

3. Voltage sags that are measured on a non-loaded feeder are not qualifying. This is automatically determined in the PQView program from the maximum load current. Rules 2 and 3 are in place to ensure that the performance is only evaluated at the PCC.

4. Only the worst voltage sag (lowest rms voltage) in a 15-min interval at each location can qualify.

5. If a voltage interruption is measured during a 15-min interval, then any voltage sags that are also measured at the location will not qualify.

iii. Sag Score Definition:

The sag score is the average per-unit voltage lost by each of the three phase voltages for the lowest qualifying voltage sag within a 15-min interval. It is defined by-

Sag score = 1 -(V_A + V_B+ V_C)/3

For interruptions, the sag score is defined to be zero to prevent overlap with the administration of voltage interruptions. If any of the phase voltages are greater than 1 pu because of a neutral shift during a voltage sag, then each is set to 1 pu before the computation of the sag score.

These two policies confine scores to the range 0.0833 to 1. The minimum sag score of 0.0833 corresponds to a condition where the voltage on one phase is 0.75 pu, which is the threshold for a qualifying voltage sag, and the other two phase voltages are set to 1 pu.

iv. Sag Score Targets:

A sag score target is the maximum sum of sag score values allowable for a group of locations before compensation is due. Two of the automakers have only one group score target, while the third has six. The sag scores for all qualifying sags in a group are summed and compared to the group sag score target. If the sag score total exceeds the target, compensation is computed.

v. Voltage Sag Payment:

The payment due to a location is computed by determining the sag score sum in excess of the sag score target multiplied by the SGPA subject to an annual payment cap.

Power Quality Insurance:

This article proposes a brief overview of a pricing strategy for premium power services that is founded on an insurance policy model.

i. Power Quality Insurance Concept:

Offering premium power services requires the provider, either a distribution company or an energy services provider (referred to hereafter as the utility), to price the services in such a way as to provide benefits to both customers and to the utility. Using an insurance model in which customers subscribe to their desired level of improved power quality (PQ) ensures that no customer will pay more than its own perception of the value or benefit associated with the PQ services.

Customer benefits are unique in that they reflect each individual customer’s damage function, including the customer’s risk aversion.

Utility benefits must reflect the risk associated with offering insurance and include returns commensurate with operating in a new competitive environment.

The premium PQ service program uses a business model involving premiums and claims. The utility offers PQ services under an insurance plan. Customers pay premiums for a defined level of service, and the utility pays the customer directly for events exceeding the terms of that service. Customers are motivated to pay a premium to reduce the uncertainty and/or the expected value of their damage costs. Utilities assume the financial risk associated with the claims in exchange for a return on the aggregate premiums.

The utility’s insurance service can make use of a purely financial policy or a policy that incorporates investments in PQ equipment or service.

In both cases, the critical advantage of the insurance approach over a cost-of- service approach is that it allows customers to self-select an appropriate solution from policies that are designed without use of customer damage cost data.

a. Insurance as a Financial Product:

The utility can create a purely financial insurance product in which it offers to pay customers for reliability events covered by the policy, and customers pay premiums. Utilities will use customer location to estimate an expected frequency of claims. Because the expected frequency of claims is different for various customer groupings, insurance premiums will likewise be different.

Premiums are calculated using principles of fair insurance with a margin that incorporates an appropriate level of risk mitigation and return for the utility. The utility makes no additional investments in reliability equipment or services with the purely financial product. Customers who are risk averse, or who have a higher expectation of their claims than the utility, will subscribe.

b. Incorporating PQ Investments into Insurance Products:

A utility can greatly increase the types of PQ insurance products it can offer if it considers the role that PQ investments can play. By making such investments, the utility can offer insurance products with higher payout ratios and improve customer service quality. To develop such products, the utility must investigate the types of PQ solutions that could be implemented for a group of customers with a similar event rate and location.

For example, for a given section of a feeder, there may be four different types of PQ investments a utility could make, ranging from a tree-trimming program to installation of UPS systems at customer sites. For each possible solution, the utility estimates the cost of the solution and the improvement in power quality that would result.

Based on these costs, and the expected claims after the investment is made, the utility can design insurance products that will cover their combined costs and provide the customers with an ensured level of improvement in their power quality. Power quality insurance can be provided for a number of distribution system events.

ii. Designing an Insurance Policy:

The goals of a PQ insurance scheme are to recover the cost of providing the plan, treat all customers within a group equally at cost-based premiums, improve efficient use of resources, and be comprehensible and acceptable.

iii. Estimating RMS Variations:

Voltage sags and interruptions are almost always due to short-circuit faults. Therefore, the procedure for estimating voltages due to rms variations is basically to find a fault on the feeder that produces voltages and currents that most closely match what was measured on the few existing monitors.

There are a number of potential problems with respect to rms variations:

1. The transformer connection, if not grounded wye-wye, may alter the perception of the voltages seen on the primary feeder and, therefore, by other customers. Thus, the monitor values do not represent the primary system voltage. An effective rms variation estimator would accommodate various transformer connections.

2. The phasing may not agree with the utility-side monitoring. This is a constant book keeping problem. End users frequently alter their installations, and any type of automatic estimating system for computing PQ indices must have a facility for periodically correcting the phasing.

3. The transformer impedance will alter the voltage measured for certain events.

4. The current measured at the end-user site represents only the current into that individual load. This will be of limited use in determining the state of the feeder for PQ indices.

5. There is no direct communications link to get the data back to a central site for timely processing.