Payment for Reactive Power

Commission Staff Report

AD14-7

April 22, 2014

The opinions and views expressed in this staff report do not necessarily represent those of 

the Federal Energy Regulatory Commission, its Chairman, or individual Commissioners, 

and are not binding on the Commission.
1

Payment for Reactive Power 

I. Introduction............................................................................................................. 2

II. Background............................................................................................................. 4

III. Current Methods Used to Pay for Reactive Power Capability............................... 8

A. Commission Precedent ........................................................................................... 8

B. OATT Schedule 2 ................................................................................................. 13

IV. Alternative Approaches to Payment for Reactive Power Capability ................... 16

A. Potential Improvements to the AEP Methodology............................................... 17

B. Alternative Cost-Based Approaches to Reactive Power Compensation .............. 19

C. Competitive, Market-Based Solicitation of Reactive Power................................ 22

V. Conclusion ............................................................................................................ 22

Appendix 1: Technical Characteristics of Generators........................................................ 1

Appendix 2: Cost of Reactive Power Equipment............................................................... 1

Appendix 3: Details of OATT Schedule 2 Rates for Selected Transmission Providers.... 1
2

I. Introduction

In Order No. 784, the Commission revised its regulations to foster competition and 

transparency in ancillary services markets.1

 Among other things, the Commission 

revised Part 35 of its regulations to reflect reforms to its Avista2 policy governing the sale 

of certain ancillary services at market-based rates to public utility transmission providers. 

However, the Commission found that the technical and geographic requirements 

associated with Reactive Supply and Voltage Control (Schedule 2) and Regulation and 

Frequency Response (Schedule 3) services precluded reforms to the Avista policy with 

respect to the sale of those services. Instead, the Commission stated its intention to 

gather more information regarding the technical, economic and market issues concerning 

the provision of these services. To that end, Commission staff will hold a workshop on 

April 22, 2014, to discuss these issues with interested participants.

In advance of this workshop, staff is releasing this paper to highlight some of the topics 

to be explored with respect to Schedule 2 service. Staff has examined issues surrounding 

the provision of reactive power several times over the last decade. The Commission 

established minimum requirements with respect to the provision of reactive power by 

large generators in Order Nos. 2003 and 2003-A.3

 Commission staff further considered a 

range of pricing and procurement options for reactive power in a report issued in 2005 

(2005 Staff Report).4 In Order Nos. 20065 and 661,6 the Commission revisited reactive 

 

1 Third-Party Provision of Ancillary Services; Accounting and Financial 

Reporting for New Electric Storage Technologies, Order No. 784, FERC Stats. & Regs. ¶ 

31,149 (2013), at P 61.

2 Avista Corp., 87 FERC ¶ 61,223, order on reh’g, 89 FERC ¶ 61,136 (1999) 

(Avista).

3 See Standardization of Generator Interconnection Agreements and Procedures,

Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003), at P 546, order on reh’g, Order 

No. 2003-A, FERC Stats. & Regs. ¶ 31,160, at P 416, order on reh’g, Order No. 2003-B, 

FERC Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003-C, FERC Stats. & 

Regs. ¶ 31,190 (2005), aff'd sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 

475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008). 

4 FERC, Principles for Efficient and Reliable Reactive Power Supply and 

Consumption, Docket No. AD05-1-000 (2005) (2005 Staff Report), available at

http://www.ferc.gov/EventCalendar/Files/20050310144430-02-04-05-reactive-power.pdf.
3

power issues with respect to small and wind-powered generators, generally concluding 

that small generators should be subject to the same requirements as large generators, but 

wind generators should not.7 In 2012, staff held a technical conference to evaluate 

reactive power policies as applied to wind and solar generation, leading to additional, 

informal outreach by staff with respect to reactive power compensation practices in 

various regions.

8

To date, the Commission has not required a uniform approach with respect to 

compensation for reactive power. As a result, different payment and cost recovery 

methods have been adopted in each region. Transmission providers in some regions pay 

a cost-based payment for reactive power capability, while others require reactive power 

capability as part of good utility practice, i.e., without compensation. For transmission 

providers that do pay for reactive power capability, the American Electric Power (AEP)

methodology is generally used to compute cost-based reactive power capability 

payments. Although not currently used in any region, competitive solicitations could be 

implemented to procure and price reactive power service. To facilitate that approach, 

Order No. 784 established parameters for the use of competitive solicitations by public 

utility transmission providers seeking to acquire ancillary services for purposes of 

satisfying their Open Access Transmission Tariff (OATT) obligations. Regardless of the 

procurement mechanism used, alternatives to the AEP methodology could be used to 

develop rates for reactive power, such as a multi-part payment reflecting both the 

capability and the provision of reactive power. 

In this paper, staff reviews existing and alternative approaches to reactive power 

compensation in order to facilitate discussion at the April 2014 workshop with respect to 

the technical, economic and market issues associated with Schedule 2 service. The paper 

begins with background information regarding reactive power, then reviews current 

 

5 Standardization of Small Generator Interconnection Agreements and 

Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180, order on reh’g, Order No. 

2006-A, FERC Stats. & Regs. ¶ 31,196 (2005), order granting clarification, Order No. 

2006-B, FERC Stats. & Regs. ¶ 31,221 (2006).

6 Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs. ¶ 31,186, 

order on reh’g, Order No. 661-A, FERC Stats. & Regs. ¶ 31,198 (2005).

7 Order No. 2006, FERC Stats. & Regs. ¶ 31,180 at P 387; Order No. 661-A, 

FERC Stats. & Regs. ¶ 31,198 at P 41-46.

8 Notice of Technical Conference, Docket No. AD12-10-000 (Feb. 17, 2012).
4

methods used to pay for reactive power before turning to a discussion of alternative 

approaches for consideration.9

 To some degree, the compensation-related issues 

discussed herein might inform the discussion of technical, economic and market issues 

associated with Schedule 3 service. A notice of workshop and detailed agenda is being

issued concurrently with this paper. Parties are invited to discuss this report at the 

technical conference.

II. Background

Reactive power is a critical component of operating an alternating current (AC) 

electricity system, and is required to control system voltage within appropriate ranges for 

efficient and reliable operation of the transmission system. At times generators or other 

resources must either supply or consume reactive power for the transmission system to 

maintain voltage levels required to reliably supply electricity from generation to load. In 

this section, we discuss transmission system needs for reactive power, types and sources 

of reactive power from different types of generation and transmission equipment, and the 

role of energy storage and demand response in provision of reactive power.10 This 

background provides context for the discussions on payment for reactive power in later 

sections.

Ensuring that reactive power is adequate to support transmission service, whether from 

transmission system elements, generators, load, distribution system elements, energy 

storage, or an appropriate mix of these, is one of the transmission planning and operations 

responsibilities of the transmission planner and operator. Vertically integrated utilities 

meet reactive power needs by placing power factor requirements on generators and large 

loads, in addition to planning and operating their transmission and distribution systems to 

regulate voltages. In organized wholesale markets, the system operator (ISO or RTO)

and transmission owners jointly set voltage schedules for both affiliated and independent 

generators in each transmission owner area, and consider future reactive power needs as 

part of transmission system planning. 

Reactive power contributes to system voltage control: a device with a leading power 

factor tends to raise system voltage, while a device with a lagging power factor tends to 

 

9 The report has several appendices with background material on reactive power

and technical details of different types of generators: Appendix 1 – Technical 

Characteristics of Generators; Appendix 2 – Cost of Reactive Power Equipment; and, 

Appendix 3 – Details of OATT Schedule 2 Rates for Selected Transmission Providers.

10 For more detailed background on reactive power provision by different types of 

generators, please refer to Appendix 1 of this report. 
5

lower system voltage.11 In this report, the term reactive power provision refers to 

operating with leading or lagging reactive power at the instruction of the transmission 

operator. The term reactive power capability refers to the ability to operate with leading 

or lagging reactive power if the unit is online and synchronized to the power grid, just as 

capacity represents the ability to provide (real) power if the unit is online and 

synchronized to the power grid. In general, operating with leading reactive power is 

called supplying reactive power, while operating with lagging reactive power is called 

consuming reactive power.

The transmission system needs reactive power to support system voltages to allow for 

transport of real power across transmission lines. Transmission lines dissipate reactive 

power more quickly than real power, meaning that reactive power cannot be efficiently 

transferred long distances on transmission lines. This is why many people say that 

reactive power “does not travel well,” and results in geographic limitations on supply of

reactive power.

Reactive power can be provided by a variety of resources. Generators can operate within 

a range of leading and lagging power factors with continuously variable reactive power 

output to meet the voltage schedule set by the transmission provider. Synchronous 

condensers are generators that have been disconnected from the mechanical turbine and 

only produce reactive power using real power from the transmission system. The 

reactive power produced by synchronous units can vary continuously over a range and 

can be used to regulate a bus voltage. By comparison, capacitors are a type of 

transmission equipment that provides a fixed amount of leading (or capacitive) reactive 

power. Inductors are another type of transmission equipment that provides a fixed 

amount of lagging (or inductive) reactive power. A combination of electronically 

controlled capacitors and inductors can be mechanically switched on and off to provide a 

stepwise reactive power source. To obtain a continuously variable reactive power source, 

transmission providers use power electronic devices, also called Flexible Alternating 

 

11 Power factor is the ratio between a generator’s real power (MW), reactive power 

(MVAr) and apparent power (MVA), where apparent power is the vector sum of real and 

reactive power. Mathematically, apparent power (MVA) = SQRT(MW2 + MVAr2

), and 

power factor = (MW / MVA). The power factor range 0.95 leading to 0.95 lagging 

represents a power factor range of 0.10, from 0.95 leading up through 1 (also known as a 

unity power factor) and from 1 through 0.95 lagging. When a generator operates at a 

power factor of 0.95 leading, its output consists of 0.3 MVAr of leading reactive power 

for every MW of real power produced; likewise, when a generator operates at a power 

factor of 0.95 lagging, its output consists of 0.3 MVAr of lagging reactive power for 

every MW of real power produced.
6

Current Transmission Systems (FACTS), which have a combination of capacitors and 

inductors to provide continuously variable leading or lagging reactive power. Static VAr 

Compensators (SVCs) and STATCOMs are specific types of FACTS devices that are 

designed to provide voltage support. Loads generally have a lagging power factor, but 

capacitors on the distribution system are often used to adjust the power factor.

Reactive power sources are generally categorized as static or dynamic based on the speed 

and continuity at which they can produce or absorb reactive power in response to changes 

in system conditions. For example, mechanically switched capacitor and reactor banks

are generally considered to be static reactive power sources, because they provide 

discrete blocks of reactive power through slow mechanical switches that cannot provide 

continuous voltage control. While a precise or consistent definition of dynamic reactive 

power is not available, in general, dynamic reactive power devices are characterized by 

faster acting and continuously variable voltage control capability, as described in the 

2005 Staff Report.

12 Supply of reactive power from a dynamic reactive power source 

generally follows a smoothly increasing relationship; that is, an additional amount of 

reactive power is produced, up to the physical limit of the resource, for every additional 

input of mechanical energy (in the case of a generator) whereas a static supply of reactive 

power can only supply fixed amounts of reactive power.

13

Static reactive power sources are usually deployed to respond to changing system 

conditions that are slow and more predictable, such as the seasonal or daily load shape 

and the resultant need for additional reactive power during peak load periods and reduced 

reactive power needs at night. Dynamic reactive power requirements are typically 

determined through a dynamic stability analysis, which considers system response 

immediately following an event or disturbance. Dynamic studies are also used to 

determine the equipment needed to meet the low voltage ride-through requirement of 

Order No. 661, which requires a wind plant to remain on-line during system voltage 

disturbances up to specified time periods and associated voltage levels.14 The time 

 

12 2005 Staff Report at 26.

13 The North American Electric Reliability Corporation (NERC) has also used this 

description of static and dynamic reactive power. See NERC, Reactive Voltage Control 

Whitepaper at 12 (2009), available at

http://www.nerc.com/pa/stand/project%20200801%20voltage%20and%20reactive%20pl

anning%20and%20c/project2008-01_white_paper_2009may18_appendix_1-

11_2009aug17.pdf (NERC Reactive Voltage Control Whitepaper).

14 Order No. 661-A, FERC Stats. & Regs. ¶ 31,198, at P 51-52.
7

interval studied generally covers a period of seconds. For example, the North American 

Electric Reliability Corporation (NERC) has specified two intervals for dynamic analysis: 

a transient interval from zero to three seconds, and a post-transient dynamic interval from 

three to 30 seconds.15 

With respect to electrical generators in particular, units are generally divided into two 

categories, synchronous and asynchronous. Synchronous generating units consist of an

electrical generator known as a synchronous machine and a mechanical turbine, and the 

generator produces electricity in sync with the transmission system at the system 

frequency (60 Hz in the U.S.). Synchronous generators have a rotating magnetic field 

which produces reactive power. Most wind generators use a different type of machine, 

known as an induction machine or asynchronous machine, to convert wind energy to 

electricity. Solar photovoltaic generators use semiconductors to convert solar energy to 

electricity. Both wind and solar photovoltaic are also called asynchronous generators 

since the electricity they produce is not initially synchronized with the AC grid. This is 

because either the rotor does not rotate at 60 Hz, in the case of wind generators, or the 

generator lacks a rotating machine and produces DC power, in the case of solar 

photovoltaic generators. In addition, some asynchronous generators consume reactive 

power, specifically older Type I and Type II wind turbine generators. On the other hand, 

some asynchronous generators, specifically newer Type III and Type IV wind turbine 

generators, and solar photovoltaic generators, interface to the transmission system with 

power converters that convert the electrical output of the generator to synchronized AC 

power that can be transmitted on the transmission system. These units have the 

capability to produce and control dynamic reactive power. Appendix 1 to this report has 

further details on synchronous and asynchronous generators. 

Energy storage devices can provide reactive power in limited situations. The amount of 

reactive power support depends on the ability to store (or hold) electric energy and the 

equipment used to connect and control the energy storage device to the transmission 

system. Some energy storage devices use limited inverters that are not capable of 

providing reactive power, while others use an inverter similar to those used by wind and 

solar generators that allow the energy storage device to provide reactive power support. 

Pumped hydro storage uses a synchronous generator to produce real and reactive power 

and has the capability to provide reactive power identically to other synchronous 

generators while providing nearly instantaneous response to the transmission system 

needs for reactive power and other ancillary services such as frequency response and 

reserve energy.

 

15 NERC Reactive Voltage Control Whitepaper at 14.
8

Demand resources can contribute to voltage control, mainly by regulating the power 

factor at their delivery point to reduce the amount of reactive power ancillary service they 

need to purchase from their transmission provider.16 In Order No. 890, the Commission 

determined that location and load profile could allow for the provision of reactive power 

to the transmission system by certain loads, and modified Schedule 2 of the pro forma 

OATT to allow for the provision of reactive supply and voltage control from nongeneration resources, such as demand resources, where appropriate.17 However, some 

transmission providers have suggested that unless demand is connected to a high-voltage 

transmission level interconnection node, provision of reactive power by demand response 

is of limited effectiveness in addressing transmission system voltage control. 

III. Current Methods Used to Pay for Reactive Power Capability

In this section, we survey Commission precedent regarding methods currently used to 

pay for reactive power capability from generating units, as well as reactive power charges 

to transmission customers in Schedule 2 of several transmission providers.18

A. Commission Precedent

The Commission noted in Order No. 888 that transmission customers that control 

generating units are able to reduce their reactive supply and voltage control needs by 

setting the generator to control voltage, and that transmission customers who serve load 

can reduce their reactive supply and voltage control needs by maintaining a high power 

 

16 See 2005 Staff Report, generally. Staff noted that in many cases load response 

and load-side investment could reduce the need for reactive power capability in the 

system and that increasing reactive power at certain locations (usually near a load center) 

can sometimes alleviate transmission constraints and allow cheaper real power to be 

delivered into a load pocket. See id. at 4, 108. The report also noted that distributed 

generators have the same reactive power characteristics as large generators, as both types 

of generators produce dynamic reactive power, and the amount of reactive power does 

not necessarily decrease when voltage decreases. Id. at 27.

17 See Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC 

Stats. & Regs. ¶ 31,261, P 494 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 

61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on 

clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

18 The costs of transmission equipment that provides reactive power are generally 

recovered through cost-based transmission rates, and we do not discuss those rates in 

detail in this paper.
9

factor at load delivery points.19 The Commission determined, however, that these 

transmission customer actions to reduce reactive supply and voltage control needs would 

not entirely eliminate the need for generator-supplied reactive power. The Commission 

found it necessary to require that reactive supply and voltage control service be offered as 

a discrete service and, to the extent feasible, charged for on the basis of the amount 

required.20 Pursuant to the pro forma OATT under Schedule 2, reactive supply and 

voltage control from generation or other sources service is to be provided directly by the 

transmission provider, or indirectly by the transmission provider making arrangements 

with the local control area operator that performs this service for the transmission 

provider’s system.

21 The transmission customer is required to purchase this service from 

the transmission provider or control area operator.22 

 

19 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities 

and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996), order 

on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order No. 

888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 

(1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group v. 

FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002). [Order No. 888 at 31,706-31,707]. The Commission stated that it would 

evaluate whether transmission provider proposals for delivery point power factor 

standards in service agreements with customers are just and reasonable. 

20 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,707 & n.359 (stating the 

possibility that separation of reactive supply and voltage control from basic transmission 

service could contribute to the development of a competitive market for such service if 

technology or industry changes resulted in improved ability to measure the reactive 

power needs of individual transmission customers or the ability to supply reactive power

from more distant sources.) At that time the Commission recognized that these 

capabilities might not yet be fully developed.

21 Order No. 888, FERC Stats. & Regs. ¶ 31,036 and Order No. 890, FERC Stats. 

& Regs. ¶ 31,241.

22 The Commission has taken a case-specific approach on self-supply of reactive 

power service. In some cases, the Commission has found that a self-supply option is 

inappropriate where the tariff provides that all generators will be compensated for their 

reactive power capability on a non-discriminatory basis, and all loads will pay their load 

ratio share of the costs of that capability. In other cases, the Commission has 

acknowledged a self-supply arrangement. Compare Midwest Independent Transmission 
10

Transmission providers can meet their Schedule 2 service obligations by using their own 

resources or those owned by third parties. With respect to the use of third-party 

resources, the Commission’s policies with respect to compensation distinguish between 

the provision of reactive power and reactive power capability. In Order No. 2003, the 

Commission required that generators be paid for reducing real power output to supply or 

consume reactive power.

23 In general, this is reactive power outside the required 0.95 

leading to 0.95 lagging power factor range.24 By comparison, the Commission did not 

require that an interconnection customer be compensated for reactive power when 

operating within its established power factor range since it is only meeting its 

obligation.25 However, the Commission clarified in Order No. 2003-A that if a 

transmission provider pays its own or its affiliated generators for reactive power within 

the established range, it must also pay the interconnection customer.26 As a result, 

payment for reactive power capability varies by region and generally falls into two 

categories: some transmission providers make no payments for reactive power capability 

within the 0.95 leading to 0.95 lagging power factor range, concluding that such 

operation is a requirement under good utility practice;27 and, some transmission providers 

 

System Operator, Inc., 113 FERC ¶ 61,046, at P 56-59 (2005), order on reh’g, 114 FERC 

¶ 61,192 (2006); American Transmission Systems, Inc., 119 FERC ¶ 61,020, at P 26 

(2007) with Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,706-31,707; Order No. 

888-A, FERC Stats. & Regs. ¶ 31,048 (1997), at 30,228-29; Georgia Power Co., 89 

FERC ¶ 61,157, at 61,443 (1999) (distinguishing between mandatory and voluntary 

provision of reactive power); Southern Company Services., Inc., 80 FERC ¶ 61,318, at 

62,089 n.62 (1997), reh'g denied, 82 FERC ¶ 61,168 (1998); see also Calpine Oneta 

Power, L.P., 124 FERC ¶ 61,193, at P 13 (2008) (rejecting proposed credit where 

transmission provider did not have operational control of the reactive power output of the 

subject plants).

23 See Order No. 2003, FERC Stats. & Regs. ¶ 31,146, at P 546. 

24 Under Order No. 2003, the required power factor range is 0.95 leading to 0.95 

lagging, unless the transmission provider establishes a different power factor range. 

25 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 546.

26 Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160 at P 416.

27 See Entergy Services, Inc., 113 FERC ¶ 61,040 (2005); Southwest Power Pool, 

Inc., 119 FERC ¶ 61,199 (2007), reh’g denied 121 FERC ¶ 61,196 (2007) (SPP); 

Bonneville Power Administration, 120 FERC ¶ 61,211 (2007) (Bonneville), reh’g denied

125 FERC ¶ 61,273 (2008); E.ON. U.S. LLC, 124 FERC ¶ 61,131 (2008).
11

make cost-based payments for reactive power capability to compensate for the costs 

incurred to provide service and align financial incentives with desired operational 

behavior.

28

In those regions where payments are made for reactive power capability, comparability of 

treatment between affiliated and non-affiliated generators has been an issue of concern. 

For example, the Commission accepted a rate of zero for reactive power within the 

required power factor range for both Bonneville and SPP, finding that the possibility that 

affiliated generators might have the opportunity to recover revenue lost from zero 

reactive power rates through retail rates does not create a comparability issue because 

there is no difference in the treatment that the transmission provider accords to affiliated 

and non-affiliated generators. In addition, the Commission noted that independent power 

producers may try to recover their lost revenue through higher power sales rates and that, 

in any event, reactive power costs within the deadband are generally small.

29 

However, the D.C. Circuit criticized this reasoning in a later case involving MISO rate 

schedules for reactive power. The court vacated Commission orders approving a separate 

rate schedule for MISO that would have allowed some transmission providers in MISO 

not to compensate generators in their transmission provider zones for reactive power 

capability within the required power factor range.30 The Court found this policy of 

allowing a rate of zero in some zones but not others to be discriminatory, since generators 

in MISO compete across transmission provider zones. Reflecting on the Commission’s 

position in the SPP and Bonneville cases, the court stated, “This appears to be a complete 

non-answer (or is based on a misconception of rudimentary economics).... Generators 

that follow the Commission’s advice to raise their power sales rates would suffer an 

increased risk of being undersold by generators from zones where reactive power costs 

are compensated.”31

 

28 In addition to the general payment policies adopted by a particular transmission 

provider, additional payments are sometimes made to specific resources under reliability 

must run contract or through uplift payments to provide voltage support. This report does 

not cover the details of these arrangements.

29 Bonneville, 120 FERC ¶ 61,211, at P 11, 21; SPP, 119 FERC ¶ 61,199, at P 17.

30 Dynegy Midwest Generation, Inc. v. FERC, No. 09-1306 (D.C. Cir. Feb. 11, 

2011).

31 Dynegy Midwest Generation, Inc. v. FERC, No. 09-1306 (D.C. Cir. Feb. 11, 

2011) at pp. 8-9.
12

For those third party generators receiving payment for reactive power capability, the 

Commission has required that such payments be based on the cost of providing reactive 

power. In Opinion No. 440, the Commission approved a methodology presented by AEP 

for its affiliated generators to recover costs for reactive power.32 AEP identified three 

components of a generation plant related to the production of reactive power: (1) the 

generator and its exciter; (2) accessory electric equipment that supports the operation of 

the generator-exciter; and (3) the remaining total production investment required to 

provide real power and operate the exciter. Because these plant items produce both real 

and reactive power, AEP developed an allocation factor to sort the annual revenue 

requirements of these components between real and reactive power production (the AEP 

methodology).

33 Subsequently, the Commission indicated that all generators that have 

actual cost data should use this AEP methodology in seeking reactive power cost 

recovery.34 The AEP methodology can be thought of as an option payment for the right 

to call on a generator for reactive power within the required power factor range.

In addition, the Commission has found that the compensation should not be based on the 

total quantity of reactive power a generator produces (MVArs/year, for example) or the 

number of hours it is online and thus available to provide reactive power.35 The 

Commission has also found that if a needs test is applied to determine which generators 

to pay for reactive power, it must be applied in a non-discriminatory manner to all 

 

32 American Electric Power Service Corp., Opinion No. 440, 88 FERC ¶ 61,141 

(1999) (AEP).

33 The factor for allocating to reactive power, developed by AEP, is 

MVAr

2

/MVA2, where MVAr is megavolt amperes reactive capability and MVA is 

megavolt amperes capability at a power factor of 1.

34 WPS Westwood Generation, LLC, 101 FERC ¶ 61,290, at 62,167 (2002) (WPS 

Westwood). The inputs to the AEP methodology are disputed in some cases, and these 

are generally settled before a Commission administrative law judge. Generators that file 

FERC Form 1 use that data for some of the inputs to the AEP methodology. However, 

the Commission has granted waiver requests to most independent power producers of the 

requirement to file FERC Form 1, so they must provide other evidence to support the 

inputs to the AEP methodology.

35 See, e.g., Bluegrass Generation Company, L.L.C, 121 FERC ¶ 61,018, at P 13 

(2007) (Bluegrass); Calpine Oneta Power, L.P., 119 FERC ¶ 61,177, at P 11 (2007)

(Calpine).
13

generation sources of reactive power supply, including resources owned by the 

transmission provider and its affiliates.36

To date, there have been relatively few instances of market-based sales of reactive power 

to transmission providers. This has been due, in part, to the Commission’s Avista 

restrictions on the sale of ancillary services to public utility transmission providers for 

purposes of meeting their OATT obligations.37 In Order No. 784, the Commission 

revisited the Avista restrictions and determined that there was insufficient information to 

support elimination of those restrictions with respect to Schedule 2 service. Instead, the 

Commission concluded that sellers who have not been shown to lack market power with 

respect to reactive power could make market-based sales of Schedule 2 service to public 

utility transmission providers under two circumstances. First, they may do so at rates not 

to exceed the buying public utility transmission provider’s OATT rate for the same 

service. The Commission found that because the buying public utility transmission 

provider’s OATT ancillary service rates have already been found to be just and 

reasonable, it is reasonable to find that any third-party sales of the same ancillary service 

to that buyer at or below that buyer’s own approved rates for that service would also be 

just and reasonable.38 Second, they may do so pursuant to a competitive solicitation that 

meets certain requirements described in Order No. 784.39

B. OATT Schedule 2

Reactive power rates paid to generators are filed in individual rate cases and, therefore, 

are not easily identifiable in the aggregate. To better understand the magnitude of 

reactive power payments, staff reviewed the reactive power charges to transmission 

customers in Schedule 2 of several transmission providers’ OATTs. Table 1 below 

compares the rates and details of Schedule 2; further details are included in Appendix 3 

of this report. 

For the regions that pay generators for reactive power capability, the rate paid is based on 

the Schedule 2 revenue requirement, which is then typically allocated to customers based 

on a load ratio share measured in MWh of real power. The Schedule 2 revenue 

 

36 See, e.g., Bluegrass, 121 FERC ¶ 61,018, at P 14 (2007); Calpine, 119 FERC ¶ 

61,177, at P 10.

37 Avista Corp., 87 FERC ¶ 61,223, order on reh’g, 89 FERC ¶ 61.136 (1999).

38 Order No. 784, FERC Stats. & Regs. ¶ 31,149 (2013) at P 82.

39 Id. P 99-101.
14

requirement is based on the sum of the generator cost-based rates, which are generally 

based on the AEP methodology discussed above. If a transmission customer that serves 

load is able to maintain a high power factor at load delivery points, it would likely reduce 

real power losses and thus its real power load and Schedule 2 charges. Table 1 lists 

“N/A” for transmission providers that do not pay for reactive power inside the 0.95 

leading/lagging power factor range or that do not charge a rate to transmission customers 

under Schedule 2. 
15

Table 1: OATT Schedule 2 Rates

Region Rate charged to 

transmission 

customers

Capability 

Rate

Capability 

Rate 

Calculation 

Method

Payment 

for actual 

reactive 

power?

Qualification 

Process

Specific 

Provisions 

for Nongenerator 

sources?

ISO-NE Formula in tariff, 

allocated based 

on load ratio

$2.19/kVAryearSettlement 

(based on 

AEP method)

Yes, see 

Appendix 3

Yes, see 

Appendix 3

Yes, see 

Appendix 3

NYISO Formula in tariff, 

allocated based 

on load ratio

$3919/MVAryearSettlement Yes Yes, see 

Appendix 3

Yes, see 

Appendix 3

PJM Varies by zone, 

allocated based 

on load ratio

Yes, individual 

resource 

revenue 

requirement

AEP 

methodology

Yes, based 

on LMP

None None

MISO Varies by zone, 

allocated based 

on load ratio

Yes, individual 

resource 

revenue 

requirement

AEP 

methodology

Yes Yes, see 

Appendix 3

None

SPP Formula in tariff N/A Opportunity 

cost

Yes, $2.26 

per MVArh

Yes, see 

Appendix 3

None

Alabama 

Power

$1.32/kW-year N/A N/A No None None

Arizona 

Public 

Service

N/A N/A N/A No None None

Idaho 

Power

N/A N/A No separately 

identified 

cost/charges 

for this 

service. 

No None None

PacifiCorp $0 within 

PacifiCorp Zone; 

$0.18/MWh for 

service in both 

PacifiCorp & 

Mid-American

N/A N/A N/A None None

CAISO N/A N/A N/A Yes, based 

on LMP or 

RMR 

contract

Yes, CAISO 

tariff 

Appendix K 

part D

None

In addition, a uniform reactive power requirement does not account for the differences in 

cost recovery for independent and affiliated generators. This could result in disparate 

treatment of affiliated and independent generators in terms of cost recovery, since a

transmission provider’s own generators may be able to recover costs of reactive power 
16

capability through retail rates, but independent generators cannot. The Commission has 

rejected complaints on this issue by independent generators because they have not shown 

definitively that reactive power costs have been included in retail rates.40 However, 

transmission providers have argued that, given how the transmission system is planned, 

their own and affiliated facilities are, in fact, needed for reliable operation of the 

transmission system, while non-affiliated generation facilities are not always needed and 

therefore should not necessarily be paid for their reactive power capability. Some 

transmission providers also argue that their own and affiliated units can be committed by 

the transmission provider for the purpose of providing reactive power, while nonaffiliated units have no such obligation. 

Finally, a uniform requirement for reactive power capability may result in overprocurement of reactive power capability, especially in generation-rich areas that have 

sufficient reactive power capability. A fixed, uniform requirement does not allow for 

any sort of quantification of the need for or benefit of additional reactive power capability 

to determine whether more reactive power capability is needed in a specific location or is 

economically efficient. Some transmission providers argue that there should be some 

sort of needs test to determine whether reactive power from a particular generator is 

needed in order to pay generators for providing reactive power. 

IV. Alternative Approaches to Payment for Reactive Power Capability

Most static reactive power comes from capacitors, which are transmission equipment 

with costs recovered through transmission rates. In contrast, most dynamic reactive 

power, which is crucial to transmission system reliability, is provided by generators, 

sometimes without a cost recovery mechanism, i.e., at a rate of zero. This results in a 

system where transmission customers pay for the less valuable service through 

transmission rates for static reactive power but do not always pay for the more valuable 

service of generator dynamic reactive power capability available to respond to 

contingencies. 

There are benefits and disadvantages to treating provision of reactive power within the 

required power factor range as a requirement of interconnection. Benefits of this 

approach include potential lower costs of ancillary services to transmission customers 

and sufficient reactive power to meet reliability needs. Disadvantages of this approach 

include higher system costs, disparate treatment of a transmission owner’s own and 

affiliated generators versus non-affiliated (independent) generators in terms of cost 

recovery, and potential over-procurement of reactive capability since it may be required 

 

40 See, e.g., Bonneville v. Puget, 120 FERC ¶ 61,211 at PP 10-12, 21; Entergy, 113 

FERC ¶ 61,040 at PP 11, 22-23.
17

from generators in areas where additional reactive power capability is not needed for 

reliability (for example, an area with sufficient existing reactive power capability). 

Specifically, a uniform rule requires all generators to provide uniform reactive power 

capability, which could result in higher system costs than a least-cost procurement and 

provision that incents efficient investment in reactive power capability. These higher 

costs would either be reflected explicitly in power prices through higher supply offers or 

implicitly, through reduced supply, as generators are built with less inherent reactive 

power capability above the uniform (minimum) requirement because they cannot recover 

their reactive power investment costs. 

In this section, we discuss potential improvements to the AEP methodology, alternative 

approaches to cost-based payments, and the potential use of competitive procurements for 

reactive power.

A. Potential Improvements to the AEP Methodology 

As discussed above, the AEP methodology is the Commission’s current methodology for 

determining reactive power costs for generators and, while it is generally working, there 

are some areas for potential improvement. For example, while most transmission 

providers in outreach were satisfied with the payment method in their region and did not 

sense that generators had issues with it, none of the transmission providers that pay for 

reactive power capability were aware of any wind or solar generators applying to be paid 

for their capability. In addition, while generation owners were generally satisfied with 

the AEP methodology, they described some issues with determining costs to use in the 

AEP methodology, especially for generators that have been sold multiple times where 

records have not been transferred, creating uncertainty about the appropriate costs to use 

in the AEP methodology. Generation owners also generally would prefer that all regions 

pay for reactive power capability using something similar to the AEP methodology.

Another area for potential improvement has to do with the information required to 

compute reactive power costs. While some of the data required for the AEP 

methodology is contained in FERC Form 1 and are, therefore, publicly available and 

generally audited, many of the required data elements are not in FERC Form 1. In 

addition, most independent power producers have been granted waiver of the Form 1 

filing requirement and so their data are not always publicly available or audited. This 

data needs to be collected and checked, typically through discovery requests during the 

discovery phase if the reactive power rate case has been set for hearing. It might be 

possible to avoid lengthy and costly litigation of this data, including the more detailed 

breakdown needed for the AEP methodology, if independent power producers were 

required to submit such data to FERC and the data were made publicly available. 

However, independent power producers regard much of the information collected in 

FERC Form 1 as commercially sensitive. Based on Order No. 784, a generator that does 

not have the information to use the AEP methodology could sell reactive power to its 

transmission provider at the Schedule 2 rate, which may save generators significant effort 
18

and litigation expense. In contrast, a generator in a region that pays for reactive power 

and that has the information to use the AEP methodology could calculate a cost-based 

rate based on the AEP methodology and file it with the Commission, even if that rate is 

higher than the Schedule 2 rate.

In addition, the AEP methodology may not be appropriate for asynchronous generators 

such as wind and solar photovoltaic generators, which may have completely different 

allocation issues than were addressed in the AEP methodology. Part of the reason no 

asynchronous generators have filed for reactive power compensation may be due to 

uncertainty about whether they are required to use the AEP methodology or even what 

appropriate methodology analogous to the AEP methodology could be used to compute 

reactive power rates for asynchronous units.41 There also appears to be some question as 

to whether reactive power capability should be measured at the generator terminals, as it 

is for synchronous generators, or at the high-voltage side of the generator step-up 

transformers, as it is for asynchronous units.

In addition, based on outreach, both wind and solar generators have some additional 

concerns. Wind generators were unsure how to go about applying the AEP methodology, 

and expect that the first wind generator to apply to be paid for reactive power capability 

will encounter protests in its filing at FERC. The technical qualification requirements for 

reactive power payment are similar to tests that wind generators have to undergo in order 

to operate, and wind generators did not see these as a barrier to being paid for reactive 

power capability. While solar generators have not pursued compensation for reactive 

power capability because most solar generators are located in CAISO, and CAISO does 

not pay for reactive power capability, there is a cost to solar plants providing reactive 

power.42 

In an attempt to standardize and improve transparency of the AEP methodology, the 

Commission could use the knowledge acquired from more than twenty years of 

experience with OATT Schedule 2 tariffs to establish a range of allocators that have been 

found to be just and reasonable for every thermal generation technology deployed in 

today’s bulk electric system. The Commission has extensive data in e-Library that could 

 

41 Most of the inputs to the AEP methodology are specific to synchronous 

generators, such as costs of specific parts of the generator, and thus cannot be applied to 

asynchronous generators without modification. For asynchronous generators, a new 

methodology based on the equipment that asynchronous generators use to provide 

reactive power would need to be developed.

42 April 2012 Conference transcript at 32 and 77, Docket No. AD12-10.
19

be used to establish such ranges of acceptable allocators for any given thermal generating 

technology. Additionally, the Commission could establish a spreadsheet outlining the 

AEP methodology while identifying a (tight) range of acceptable allocators. Establishing 

a Commission-approved spreadsheet with known acceptable allocators for specific 

generation technologies would have the effect of increasing the transparency of the AEP 

methodology, giving market participants better knowledge of expected revenue streams 

prior to making a FERC filing, and limiting the possible burden of litigation that many 

generators making reactive power tariff filings face.43 Drawbacks to this approach 

include that it might result in relying on out-of-date cases or rates, and it would not 

address the challenges of developing rates for newer technologies such as wind turbines 

or solar photovoltaic generators. In addition, it could lead to over-recovery of reactive 

power costs, as generators with actual reactive power costs lower than the level they 

would recover using the acceptable allocators would accept the default allocators, while 

generators with actual reactive power costs above the level they would recover using the 

acceptable allocators may choose to file a rate using the AEP methodology and go 

through litigation if necessary.

B. Alternative Cost-Based Approaches to Reactive Power Compensation

One alternative to the AEP methodology would be to tie payment for reactive power to 

some measure of variable performance, rather than based solely on capability or on the 

actual provision of reactive power. 

Economic theory of marginal cost pricing suggests the most efficient approach to pricing 

would be a multi-part payment based on both the capability and the provision of reactive 

power, rather than exclusively on one or the other. A pricing mechanism where the 

payment for reactive power capability is set to allow for the recovery of fixed costs, while 

the payment for the provision of reactive power is designed to approximate the marginal 

(or variable) cost (or value) of providing reactive power, may lead to increased efficiency 

in both production and consumption of reactive power as compared to a mechanism 

where a single price is set to compensate for both the capability and provision of reactive 

power. In addition, payments based on the amount and location of actual reactive power 

produced can incent generators to perform when they are called upon and where they are 

needed. However, there are some significant and complex issues with multi-part pricing 

for reactive power, including the proper value of reactive power production, and the 

appropriate penalty structure for non-performance.

 

43 Exelon put forward a similar proposal, suggesting a safe harbor provision of 

establishing reasonable ranges of reactive cost allocation to be accepted without a 

hearing, in its comments filed in response to the 2005 Staff Report and Technical 

Conference (Docket No. AD05-1).
20

Another issue with paying for reactive power production is the difficulty and complexity

in determining the value of reactive power in real-time. If the transmission provider 

knows the reactive power capability curve of each generator, it may be able to calculate 

the opportunity cost of providing real power.44 It may be possible to value reactive 

power production after the market runs, but co-optimizing real and reactive power in realtime markets remains an area of research. In addition, in most hours and at most 

locations on the grid, sufficient reactive power capability exists such that reactive power 

prices would usually be close to zero, yielding little incentive for generators to provide 

reactive power based on real-time prices alone. Also, real-time reactive power pricing 

may be particularly susceptible to exercise of market power or market manipulation due 

to the limited number of potential suppliers since reactive power needs are local and, 

unlike real power, reactive power does not travel very far.

However, since reactive power can be supplied by generators, transmission and load, the 

scope of potential suppliers and potential entrants is larger than just generators, 

highlighting the importance of getting the pricing of reactive power correct. For 

example, merchant transmission, demand response, or energy storage might provide 

reactive power if they could be paid. One example is the Cross Sound Cable merchant 

transmission line between New York and New England, which is paid for the reactive 

power capability it provides.45

A related issue is how to appropriately compensate generators for good performance and 

penalize them for poor performance. Commission precedent holds that reactive power 

payments are based on a generator’s reactive power capability and its ability to follow the 

dispatch instructions of the transmission operator when online and synchronized to the 

transmission grid. This capability payment, using the AEP methodology, does not 

differentiate between units that are frequently online and those that are rarely online, or 

units that are typically online during times of system stress and those that are not. If the 

AEP methodology provides sufficient revenue for a generator to recover its costs of 

reactive power production, including its investment in reactive power capability, a return 

on that investment, and operations and maintenance costs, then allowing the generator to 

recover its cost of providing reactive power capability may allow the generator to recover 

all of its costs of providing reactive power without facing any penalties for non-

 

44 See Appendix 1 of this report for discussion of the reactive power capability 

curve, or D-curve, which illustrates the tradeoff between real power and reactive power 

production for an individual generator.

45 ISO-NE OATT, Schedule 2, section B, available at http://isone.com/regulatory/tariff/sect_2/oatt/sect_ii.pdf.
21

performance. In contrast, a reduction in the capability payment based on an 

administratively determined fixed price also raises concerns because certain units may 

only run for a few hours each year but their reactive power capability may be particularly 

valuable in those hours. If reactive power compensation and/or penalties are based on an 

average value of reactive power measured over a period of time, those units may not earn 

enough to recover their costs of reactive power capability and provision. This is 

analogous to the issues surrounding payment for real power reserves.

There are some possible administrative solutions to these complex issues, such as setting 

an administratively determined price for reactive power provision, or adjusting reactive 

power capability payments based on the number of hours a generator is online or the 

quantity of reactive power it produces. One example is MISO’s approach, where if a 

generator fails to follow the system operator’s reactive power dispatch three times in one 

month, the generator no longer qualifies for compensation under Schedule 2 of MISO’s 

tariff.46 But administrative solutions pose trade-offs between efficiency, equity, 

administrative simplicity, and providing the appropriate incentives. An administratively 

determined price for reactive power with a locational component seems attractive, as 

reactive power close to load centers would typically be more valuable, while reactive 

power that is distant from load may be less valuable. However, an administratively 

determined price would not accurately reflect the true value of reactive power at all 

times, particularly during times of scarcity, and could undervalue reactive power when it 

is most needed or overvalue it when it is not needed. Further, if combined with a 

reduction in capability payments to generators, this may lead to a shortage of reactive 

power at certain times in high-value locations like load centers. Also, basing reactive 

power capability payments on the number of hours a unit is online would not align 

incentives with desired generator locations for reliability. For example, payments based 

on the number of hours a unit is online would tend to increase payments to baseload units 

which may be located far from load while, as discussed above, decreasing payments to 

intermediate or peaking units that may provide reactive power where and when it is most 

needed. Similarly, basing payments on the quantity of reactive power produced may 

result in paying more to generators in areas with weak transmission where they will be 

required to provide reactive power in order to operate than to generators in areas with 

stronger transmission where they may be able to operate at close to a unity power factor. 

 

46 See MISO Tariff Schedule 2 at IV.A.1: “If a Qualified Generator fails to 

comply with the Local Balancing Authority’s voltage control requirements three or more 

times in a calendar month for reasons other than planned or unscheduled outages, the 

Transmission Provider shall determine whether the Generation Resource should continue 

to be a Qualified Generator based on the criteria established in Section II.B of this 

Schedule.”
22

In addition, in ISOs/RTOs, participating generators can be committed to run for 

reliability reasons, including the provision of reactive power, and in those cases those 

units are paid uplift payments to ensure that their total payments from the ISO/RTO at 

least cover their running costs (i.e., start-up, no-load, cost of generation, minimum run 

time, shut-down); generators with a capacity obligation are also required to offer their 

supply into the day-ahead and real-time markets. Generators outside of ISOs/RTOs do 

not have the obligation to offer their units to the transmission provider and only have an 

obligation to provide reactive power when they are online, even if they are paid for their 

reactive power capability. This raises the question of whether a transmission provider 

should have the ability to require a unit that is paid for reactive power capability to run 

and provide reactive power support (assuming appropriate compensation for the running 

costs incurred by that unit). Another question is whether a generator receiving a reactive 

power payment is required to come online at the request of the system operator, or is only 

required to follow reactive power dispatch instructions when it is already online. 

C. Competitive, Market-Based Solicitation of Reactive Power

In any market for reactive power, the Commission would need to consider market power 

concerns and how to address them. Due to the localized nature of reactive power, the 

relevant geographic market for reactive power may be much smaller than a market for 

real power. If transmission technologies, demand response, and energy storage provide 

reactive power, the market might be less concentrated than if only generation sources of 

reactive power were considered. Due to these concerns, the Commission established a 

set of minimum requirements in Order No. 784 with respect to the use of competitive 

solicitations by public utility transmission providers seeking to acquire ancillary services, 

including Schedule 2 service, for purposes of satisfying their OATT obligations. 

Such competitive processes could elicit responses from a variety of resources, including 

generation, transmission, demand response, and energy storage. Transmission providers 

could use competitive solicitation to procure all or a portion of their reactive power 

needs. A competitive solicitation for reactive power production could incorporate 

mechanisms to acquire all reactive power services at least cost and to elicit desired 

performance from all reactive power resources. Alternatively, a transmission provider 

could use competitive solicitations to target the potential retirement of generation 

capacity due to economic conditions or environmental regulations that could result in a 

system need for reactive power at specific locations on the grid in the near future. In that 

case, the transmission provider could specify reactive power needs in terms of quantity, 

availability, type (static or dynamic) and location and all providers of reactive power (i.e.

generators, transmission equipment, demand response, storage, transmission lines) could 

submit bids to supply those particular needs.

V. Conclusion 

This report represents another step in the Commission’s ongoing examination of issues 

surrounding reactive power. Starting with Order No. 888’s inclusion of provision for 
23

reactive power from generators as an ancillary service in OATT Schedule 2, the 

Commission has issued a series of orders intended to ensure that reactive power is 

available and fairly compensated to support efficient and reliable operation of the 

transmission system. This report provides a discussion of issues surrounding payment for 

reactive power to facilitate discussion at the April 2014 workshop with respect to the 

technical, economic and market issues associated with Schedule 2 service. Staff invites 

parties to discuss concepts explored in this report at the workshop. 
1

Appendix 1: Technical Characteristics of Generators

This attachment provides information on the technical characteristics of reactive power 

from different types of generators.

I. Background: Reactive Power

Reactive power is a component of alternating current (AC) power that is necessary to 

control system voltages for reliability, and to enable transmission of real power from 

generators to loads.47 In an AC system, voltage and current vary sinusoidally at the 

system frequency of 60 Hz, and can be represented mathematically as phasors with a 

magnitude and phase angle. Apparent power is the product of voltage and current, and its 

magnitude is measured in volt-amperes, or MVA; this is the magnitude of a complex 

number, where real power (MW) is the real number and reactive power (MVAr) is the 

imaginary number. Power factor is the ratio of real power (MW) to apparent power 

(MVA). When voltage and current are in phase, meaning that they peak at the same time, 

power factor is one and reactive power is zero. When voltage and current are 90 degrees 

out of phase, the power factor is zero and real power is zero. Transmission operators 

control system voltages by controlling reactive power; producing (injecting) reactive 

power increases voltage, while reducing (absorbing) reactive power lowers voltage.

Reactive power can be produced or consumed by generators, power electronic equipment 

such as flexible AC transmission system (FACTS) devices, transmission lines and 

equipment, and load. When a generator produces reactive power, it raises voltage at the 

generator terminals; conversely, when a generator absorbs reactive power it lowers 

voltage at the generator terminals. Synchronous generators and FACTs devices produce 

what is called dynamic reactive power, which can be controlled instantaneously in small 

increments and is independent of transmission system voltage. In addition, 

inactive/retired generators and hydro generators can be used as synchronous condensers, 

where the synchronous machine operates to provide voltage support but the turbine and 

fuel parts of the generating unit no longer operate. Capacitors produce reactive power 

and raise or support voltage, while inductors absorb reactive power and lower voltage. 

Capacitors produce and inductors absorb what is called static reactive power, which is 

generally less expensive than dynamic reactive power, that switches on and off in fixed 

amounts, and provides less voltage support as transmission system voltage decreases. 

Capacitors, inductors, and FACTs devices can be installed anywhere on the transmission 

system.

 

47 For more detail on reactive power, see 2005 Staff Report.
2

Reactive power takes up space on transmission lines, and is dissipated by line reactance

as distance increases. Transmission line heating losses are the square of the line current 

times the line resistance. Transmission line reactive dissipation is the square of the line 

current times the line reactance. For high voltage lines, reactance is generally ten times 

larger per line mile than line resistance, meaning that reactive power dissipation on a 

heavily loaded line is much larger than real power losses. Long transmission lines 

consume reactive power when heavily loaded; this is why it is often said that reactive 

power does not travel well, and should be produced near where it is used. Loads 

consume or produce reactive power depending on the type of equipment; some 

equipment could be built with dynamic reactive capability for transmission system 

support.48

A synchronous generating unit consists of a synchronous generator and a turbine. 

Generators have a reactive capability curve that represents the tradeoff between real and 

reactive power production, which is limited by heating limits of different parts of the 

electrical generator and the mechanical limit of the turbine. These limits are often 

described by a “D curve” because it is shaped like the letter D. The size of the turbine 

determines the maximum real power the generator can produce, while the size of the 

synchronous generator determines the maximum reactive power. Traditionally, the 

turbine and synchronous generator have been matched in size so that the generator can 

continuously produce reactive power in the required power factor range of 0.95 leading 

(consuming) and 0.95 lagging (supplying) without backing off its real power production. 

This power factor range corresponds to producing or absorbing an amount of reactive 

power up to approximately 30% of real power capacity.

Wind generators use a different type of machine, known as an induction machine or 

asynchronous machine, to convert wind energy to electricity.49 Solar photovoltaic 

generators use semiconductors to convert solar energy to electricity. Both wind and solar 

are also called asynchronous generators since the electricity they produce is not 

synchronized with the AC grid. Asynchronous generators have power converters that 

convert the electrical output of the generator to synchronized AC power that can be 

transmitted on the transmission system. Power converters have power electronic 

 

48 See Grayson Heffner, Charles Goldman, Brendan Kirby, Michael KintnerMeyer, “Loads Providing Ancillary Services: Review of International Experience,” 

Ernest Orlando Berkeley National Laboratory, Report LBNL-62701, page 9, available at

http://certs.lbl.gov/pdf/62701.pdf (2007). 

49 Some Type IV wind generators use a synchronous machine that is not 

synchronized to the grid, and is connected to the grid through a power converter.
3

equipment, and can be designed to mimic the reactive power characteristics of a 

synchronous generator. This equipment is normally installed to regulate voltages within 

a wind or solar facility, but can also be designed to provide reactive power support to the 

transmission system. Early versions of wind generators, known as Type I/II generators, 

did not have power converters and absorbed reactive power from the transmission 

system. More recent wind generator designs, known as Type III/IV generators, based on 

doubly-fed induction generators, have power converters that allow the wind generator to 

absorb or produce reactive power in response to a control signal.

For both synchronous and asynchronous generators, reactive power capability is much 

less expensive to install when the generator is initially designed than to retrofit later.

Table 2 is based on staff research, compiled from a variety of sources.50 Additional 

information regarding reactive power capabilities of various generation technologies can 

be found in the North American Electric Reliability Corporation’s “2012 Special 

Assessment: Interconnection Requirements for Variable Generation.”51

Table 2: Reactive Power Capabilities of Generators and Transmission Equipment

Generator or 

Transmission Element

Reactive Power Range Static or Dynamic? Cost?

Conventional 

Synchronous Generator

Most common dynamic 

reactive support provider; 

normally designed to 

operate continuously 

between 0.95 

leading/lagging power 

factor and beyond that for 

short periods. When 

needed, synchronous 

generators can increase 

continuous reactive power 

output beyond the 0.95 

leading/lagging power 

factor range by decreasing 

real power output.

Dynamic All synchronous 

generators inherently 

have the components 

needed to provide 

reactive power. 

Increasing reactive 

power output (with a 

constant real power 

output) is achieved by 

incremental increases. 

 

50 2005 Staff Report; NERC, 2012 Special Assessment Interconnection 

Requirements for Variable Generation (Sept. 2012) available at

http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012_IVGTF_Tas

k_1-3.pdf (2012 NERC Report).

51 2012 NERC Report.
4

Generator or 

Transmission Element

Reactive Power Range Static or Dynamic? Cost?

Wind Type I Uses induction generators, 

which absorb reactive 

power. Static capacitor 

banks are used to counteract the reactive power

consumed and are sized to 

yield unity power factor for 

the combined wind turbine 

and capacitor system.

No dynamic reactive 

power control 

Adding reactive 

capability requires 

additional equipment.

Wind Type II Uses wound rotor induction 

generators, which absorb 

reactive power. Static 

capacitor banks are used to 

counter-act the reactive 

power consumed by the 

induction motor. These are 

sized to yield unity power 

factor for the combined 

wind turbine and capacitor 

system.

No dynamic reactive 

power control

Adding reactive 

capability requires 

additional equipment.

Wind Type III Uses wound rotor induction 

generators with power 

electronics connected to 

rotor, which allow control 

of reactive power. This is 

comparable to a typical 

synchronous generator, but 

smaller reactive power 

capability. The power 

electronics (AC to DC to 

AC conversion) act to 

convert the asynchronous 

power produced by wind 

power to the nominal AC 

frequency (60 Hz in US) by 

injecting an AC current of 

variable frequency into the 

generator rotor windings. 

The AC to DC to AC 

conversion also allows 

additional benefit for 

independent control of 

reactive power. 

Dynamic Literature suggests that a 

rating of approximately 

30% to 35% for the 

power electronics is an 

optimum size for 

obtaining the desired real 

power at the generator 

terminal while allowing 

independent control of 

the reactive power. 
5

Generator or 

Transmission Element

Reactive Power Range Static or Dynamic? Cost?

Wind Type IV Uses variable frequency 

synchronous generators 

whose entire output is 

controlled by full rated 

power electronic converters. 

Can produce independent 

control of reactive power 

equal to full rating when 

wind turbines are not in 

service. This technology 

first converts the 

asynchronous power 

produced by wind power to 

DC and then converts it 

back to nominal AC 

frequency (60 Hz in US). 

Dynamic Power electronics and 

filtering equipment must 

be sized to 100% of 

generator rating for wind 

generator operation. A 

100 MW wind unit 

would require 

installation of a 100 MW 

AC to DC to AC 

converter. In addition, to 

maintain a power factor 

of 0.9 leading/lagging at 

full real power output 

would require increasing 

the AC to DC to AC 

conversion by an 

additional 10%. This 

system would then be 

capable of maintaining 

0.9 power factor at all 

power levels.

Solar photovoltaic Reactive power limited to 

size of inverter and real 

power output of solar 

panels. If inverter is 

oversized to 110% of 

generator capacity then 

system can supply 46% 

reactive power at 100% real 

power output (0.91 

leading/lagging) and 110% 

reactive power at 0 real 

power output.

Dynamic Incremental cost of 

increasing inverter rating 

from 100% of generator 

capacity to 110% of 

generator capacity.

Switched Static Shunt 

Capacitors

Sets of capacitors mainly 

installed in substations and 

on circuits, which provide 

reactive support by 

injecting VARs into the 

power system. Reactive 

supply fluctuates with the 

square of voltage; at low 

voltage the output is lower. 

Some of the capacitors are 

fixed while others are 

switched in blocks; as a 

result the output cannot be 

controlled smoothly.

Static Lowest cost reactive 

compensation. Capacitor 

banks costs range from 

$1 million for 50 MVAr

at 115 kV to $5 million 

for 200 MVAr at 500 

kV.
6

Generator or 

Transmission Element

Reactive Power Range Static or Dynamic? Cost?

Synchronous Condenser A synchronous machine 

designed to supply only 

reactive power that 

consumes about 3% of 

capacity rating of real 

power from the network. 

Some hydro, gas turbine, 

and pumped storage units 

can operate as synchronous 

condensers when not 

generating real power.

Dynamic The conversion costs of 

recent examples range 

from $7 to $10 million, 

or approximately 

$40,000-$50,000/MVAr.

FACTS (Flexible AC 

Transmission System) 

Devices

Use a combination of power 

electronic switches and 

switched capacitors to 

regulate reactive power, 

generally considered 

dynamic devices.

Dynamic Costs are generally lower 

than new synchronous 

condensers but higher 

than capacitor banks. In 

the 115-230 kV, 0-100 

MVAr inductive and 

100-200 MVAr

capacitive range, SVCs 

cost $5 million to $10 

million.

Demand Response Can impact system reactive 

power needs by controlling 

load level; behind-the meter 

generators may also be able 

to supply reactive power.

Dynamic N/A

Hydrokinetic and Ocean 

Thermal

Reactive power capability is 

comparable to wind turbine 

generators. Hydrokinetic / 

Ocean Thermal generators 

can implement a control 

scheme similar to Type I, II, 

III, or IV wind turbine 

generators.

Static or Dynamic Depends on design

Transmission Lines Transmission lines produce 

or consume reactive power 

depending on the amount of 

power flowing on the line 

and the length of the line. 

Heavily loaded transmission 

lines use reactive power, 

while lightly loaded lines 

produce reactive power. 

Longer lines use more 

reactive power than shorter 

lines. 

N/A N/A

Almost all bulk electric power in the United States is generated, transported and 

consumed in an alternating current (AC) network. Elements of AC systems produce and 

consume two kinds of power: real power (measured in watts) and reactive power 
7

(measured in volt-amperes reactive, or vars). Real power accomplishes useful work (e.g., 

running motors and lighting lamps). Reactive power supports voltages that must be 

controlled for system reliability. Reactive power supply is essential for reliably operating

the electric transmission system. Inadequate reactive power has led to voltage collapses 

and has been a major cause of several recent major power outages worldwide. Reactive 

power can also substantially improve the efficiency with which real power is delivered to 

customers. Increasing reactive power production at certain locations (usually near a load 

center) can sometimes alleviate transmission constraints and allow cheaper real power to 

be delivered into a load pocket.

II. Generator Reactive Power Capability Curves

A synchronous generating unit consists of a synchronous generator and a turbine. 

Generators have a reactive capability curve that represents the tradeoff between real and 

reactive power production, which is limited by heating limits of different parts of the 

electrical generator and the mechanical limit of the turbine. This curve is called a “D 

curve” because it is shaped like the letter D. An example D curve is shown in Figure 1

below. The size of the turbine determines the maximum real power the generator can 

produce, while the size of the synchronous generator determines the maximum reactive 

power. Traditionally, the turbine and synchronous generator have been matched in size 

so that the generator can continuously produce reactive power in the required power 

factor range of 0.95 leading (consuming) and 0.95 lagging (supplying) without backing 

off its real power. This power factor range corresponds to producing or absorbing an 

amount of reactive power up to approximately 30% of real power capacity.

The first step in conversion of wind energy to electrical energy results in asynchronous 

electricity since the electricity produced is not synchronized with the AC grid. Wind 

generators use a machine, known as an induction machine or asynchronous machine, to 

convert wind energy into electrical energy. Similarly, solar photovoltaic generators use 

semiconductors to convert sunlight to electrical energy that is not synchronized with the 

AC grid. These asynchronous wind or solar generators are connected to power 

converters that convert the electrical output of the asynchronous generator to 

synchronized AC power that can be transmitted on the transmission system. Power 

converters have power electronic equipment, and can be designed to mimic the reactive 

power characteristics of a synchronous generator. This equipment is normally installed 

to regulate voltages within a wind or solar facility, but can also be designed to provide 

reactive power support to the transmission system. Early versions of wind generators, 

known as Type I/II generators, had less sophisticated power converters and absorbed 

reactive power from the transmission system. More recent wind generator designs, 

known as Type III/IV generators, based on doubly-fed induction generators, have power 

converters that allow the wind generator to absorb or produce reactive power in response 

to a control signal.
8

Figure 1: Synchronous Generator Capability Curve ("D curve")
1

Appendix 2: Cost of Reactive Power Equipment

This appendix provides details of the cost of reactive power from different types of 

equipment.

I. Synchronous Generators

Reactive power is produced inherently by synchronous generators. The AEP 

methodology, discussed in the body of the report, is the method the Commission has 

approved to allocate a portion of the capital costs of a synchronous generator to reactive 

power production. The range of rates that transmission providers charge for reactive 

power in OATT Schedule 2 (summarized in Appendix 3 of this report) is another 

indicator of the cost of reactive power from synchronous generators.

II. Wind Generators

AWEA indicates that Vestas, GE and Siemens captured about 70% of the market share of 

wind turbines sold in the US for the period of 2010 through 2012.52 Our review shows 

that GE predominantly offers a Type III turbine, and Siemens offers a Type IV turbine. 

Both vendors offer inherent dynamic reactive power capability measured at the generator 

terminals equal to or better than 0.95 leading/lagging. One of the contributing factors to

this inherent capability may be vendors finding it more cost effective to develop a 

standard turbine/convertor design that meets global market demand. Since there are 

many regions outside the Eastern and Western interconnections that require some 

inherent dynamic reactive power capability (e.g. Canada, ERCOT, Europe), the cost 

savings from providing a wind turbine design without dynamic reactive power capability

may not offset additional costs associated with development, manufacturing and support

of multiple product lines.

 

52American Wind Energy Association, U.S. Wind Industry Annual Market Report 

Year Ending 2012 Executive Summary, page 15 (2012), available at

http://awea.files.cmsplus.com/images/AWEA_USWindIndustryAnnualMarketReport2012_ExecutiveSummar

y.pdf.
2

A report on the cost of wind energy by the National Renewable Energy Laboratory 

(NREL)53 presents wind turbine capital costs and other component costs for U.S. wind 

projects in 2010. These costs are estimates based on a common on-shore wind turbine 

size of 1.5 MW, which contains an asynchronous generator.

NREL used its Wind Energy Cost and Scaling Model to estimate reference turbine costs 

for turbine components and balance of station areas by inputting values for specifications 

such as turbine rating, hub height, rotor diameter, and wind characteristics. The three 

major component cost categories in the NREL model are: turbine (wind turbine 

components), balance of station (e.g., permitting, transport, assembly, installation), and 

soft costs (e.g., insurance, construction finance).

NREL modeled turbines consisting of a drivetrain design with a 3-stage planetary/helical 

gearbox feeding a high-speed asynchronous generator. From the table below, the costs of 

the asynchronous generator represent approximately 4% of the installed capital cost. 

Recall that reactive power can be produced or consumed by asynchronous generators. 

These types of generators have power converters that are designed to regulate voltages 

within the wind project and provide reactive power support to the transmission system.

Similarly, Dr. John Coultate from Romax Technology, Ltd,54 finds that the cost of a 

converter represents 4% of the capital costs of a typical wind turbine project.55

Another author, Willey, states that the cost of the converter represents 5% of the capital 

costs of a typical wind turbine project.56

 

53 National Renewable Energy Laboratory, 2010 Cost of Wind Energy Review 

(Apr. 2012), available at http://www.nrel.gov/docs/fy12osti/52920.pdf.

54 Romax Technology, Ltd is a consulting firm, based in Nottingham, United 

Kingdom that specializes in wind turbine drive train design, simulation, testing and 

monitoring solutions. 

55 Dr. Coultate, Understanding Costs for Large Wind-Turbine Drivetrains (Mar. 

2012), available at

http://www.windpowerengineering.com/design/mechanical/understanding-costs-forlarge-wind-turbine-drivetrains/

56 Willey, L., “Design and development of megawatt wind turbines,” Wind power 

generation and wind turbine design, p. 248 (2010), available at

http://books.google.com/books?id=wU9bgvrl4rQC&printsec=frontcover&source=gbs_ge

_summary_r&cad=0.
3

Table 3 below summarizes data used for the cost of reactive power equipment found in 

wind generators. It is important to note that the data was derived from multiple sources, 

each consisting of a unique set of assumptions and parameters. For example, data from 

NREL’s 2010 report shows that the cost of reactive power equipment is roughly 4% of 

total capital cost. However this value does not make a distinction between the cost of the 

generator and the converter (the component providing reactive power capabilities) used 

in their model. In addition, the cost of reactive power equipment, in USD, could only be 

obtained from NREL’s 2010 report. As a result, a conclusion or trend observation cannot 

be drawn from the data summarized in Table 3.

Table 3: Summary of Cost of Reactive Power Equipment Data for Wind Generators

Source Cost of Reactive 

power equipment 

as % of total 

capital costs

Cost of reactive 

power equipment

Comments

NREL (2010) 3.9% $25.5 Million Cost of generator 

(converter included)

Romax (2012) 4% N/A Cost of converter

Tong (2010) 3.18% N/A Cost of converter

III. Solar Photovoltaic Generators

Solar photovoltaic generators use equipment very similar to type IV wind generators. At 

the April 2012 Conference, CAISO claimed that the cost of adding reactive power in the 

0.9 leading to 0.95 lagging power factor range to a solar photovoltaic plant is about 10 

percent of the cost of the converter, or 2 percent of the overall project cost.57 First Solar 

claimed that inverters account for 10-20 percent of the total project cost, depending on 

project size, and that if providing reactive power requires everything to be up-sized by 10 

percent, then reactive power accounts for about 2 percent of overall project cost.58 

However, First Solar further noted that installing a fast-acting reactive power device, 

such as a STATCOM, is more costly.

 

57 April 2012 Conference transcript at 141-142, Docket No. AD12-10.

58 Id. at 157.
4

IV. Synchronous Condensers

One method of providing reactive power is to convert an existing conventional generator,

often one that is retiring, into a synchronous condenser. The conversion involves 

decoupling the turbine from the generator, installing a starting means for the condenser 

(i.e., an on-site diesel generator), installing a new control system and making minor 

mechanical modifications to the generator. Conversion costs will typically also vary with 

the size of the generator and the number of units being converted (i.e., a five unit facility 

will typically require fewer than five on-site diesel generators to start the condensers).59

Two recent examples of conversions from a generator to a synchronous condenser are the 

Huntington Beach Units 3 and 4 in California and ATSI/First Energy’s conversion of its 

Eastlake Units 1-5 and Lakeshore Unit 18.

On November 9, 2012, AES Huntington Beach, L.L.C. and the California ISO filed a 

Reliability Must-Run (RMR) agreement with FERC. According to the filing, Huntington 

Beach Unit 3 and Unit 4 are each capable of providing up to 145 MVAr (290 MVAr 

total) of leading or lagging capability and the total conversion cost will be approximately 

$14.3 million ($5.5 million per unit plus new controls, construction costs, parts and sales 

tax), or approximately $50,000/MVAr.60

On July 16, 2012, First Energy Generation Corp. (First Energy) and American 

Transmission Systems, Incorporated (ATSI) filed an application requesting Commission 

authorization for First Energy’s transfer of certain generation assets to ATSI for the 

purpose of conversion to synchronous condensers to support the ATSI transmission 

system.61 First Energy proposed to transfer to ATSI six units, Eastlake Units 1-5 and 

Lakeshore Unit 18 capable of providing up to 1,385 MVAr of dynamic reactive voltage 

 

59 http://www.geenergy.com/content/multimedia/_files/downloads/Converting_Existing_Synchronous_Ge

nerators_into_Synchronous_Condensers.pdf

60 AES Huntington Beach, L.L.C., Tariff Filing, Docket No. ER13-351-000, at 

Rate Schedule FERC No. 2 pp. 79 and 177 (filed November 9, 2012).

61 FirstEnergy Generation Corp. and American Transmission Systems, 

Incorporated, Application For Authorization Under Section 203 of the Federal Power 

Act, Request For Expedited Action And Request For Waivers (ATSI Application), 

Docket No. EC12-119-000 (filed July 16, 2012).
5

support post-conversion with an estimated conversion cost of approximately $60 million, 

or about $43,000/MVAr.62

V. Static Var Compensators (SVC)

One example of an SVC installed on the high-voltage power grid is the SVC that was 

installed at Allegheny Power’s Black Oak substation near Rawlings, Maryland in 2007. 

This project was initiated as part of PJM’s Regional Transmission Expansion Plan and 

was designed to enhance the reliability on Allegheny Power’s 500kV Hatfield-Black 

Oak-Bedington transmission line – one of the most heavily-loaded (and, at that time, 

most congested) lines in PJM by quickly changing reactive power levels to control the 

line’s voltage. The SVC interconnects to the 500kV line and is able to provide reactive 

power in a range of 145 MVAr inductive to 575 MVAr capacitive (-145/+575) and was 

installed at a cost of approximately $50 million, or approximately $87,000/MVAr 

(capacitive).63

According to PJM’s April 2012 reliability update, the estimated cost of building a 600 

MVAr SVC at the Meadow Brook 500kV substation is $60 million ($100,000/MVAr);

64

the estimated cost of a 250 MVAr SVC on the 230 kV system is $43 million;65 the 

estimated cost of a 100 MVAr fast switched shunt and 200 MVAr shunt at Mansfield 345 

kV is $6.1 million;66 the estimated cost of a 500 MVAr SVC at Hunterstown 500 kV

 

62 Id. at 7-8. While the Commission approved the transaction, ATSI is required to 

file a rate case under FPA Section 205 where it must justify any conversion costs (in 

addition to the transfer price, etc.) that it wants to include in its Schedule 2 for these units. 

So the actual incurred (and allowed) costs may differ from the $60 million figure, which 

is an estimate. See FirstEnergy Generation Corp. and American Transmission Systems, 

Incorporated, 141 FERC ¶ 61,239, at P 30 (2012).

63 See 

http://www05.abb.com/global/scot/scot221.nsf/veritydisplay/d324da10fbb8312dc125774

50024daa7/$file/Black%20Oak%20SVC_A02-0207%20E.pdf. See ATSI Application at 

note 11 for cost data. See also

http://www.energycentral.com/gridtandd/gridoperations/news/vpr/4039/ABBCommissions-World-s-Largest-SVC-for-Allegheny-Power

64 PJM, April 12, 2012 Reliability Analysis Update, p. 89, available at 

http://www.pjm.com/~/media/committees-groups/committees/teac/20120412/20120412-

reliability-analysis-update.ashx.

65 Id. at 152.
6

substation is $82 million.

67 In comparison, the estimated cost of a 90 MVAr capacitor 

bank at the Frackville 230 kV Substation is $3M.68

 

66 Id. at 153.

67 Id. at 159.

68 Id. at 168.
1

Appendix 3: Details of OATT Schedule 2 Rates for Selected Transmission 

Providers

In the payment section of the report, Table 1 describes several transmission providers. 

This appendix has further details of OATT schedule 2 rates for selected RTO/ISOs that 

have added details for reactive power payment or qualification of non-generator 

resources beyond the pro forma schedule 2.

I. ISO-NE

Rate

ISO-NE operates qualified reactive resources to produce (or absorb) reactive power in 

order to maintain transmission voltages on the New England Transmission System.69

These qualified resources are compensated for such reactive service under Schedule 2 of 

the ISO-NE OATT. Schedule 2 currently provides for reactive power compensation 

based on four cost components: (1) the lost opportunity cost (LOC) component, which 

compensates for the value of a generator's lost opportunity in the energy market when a 

generator that would otherwise be economically dispatched is instead directed by the ISO 

to reduce real power output to provide more reactive power; (2) the cost of energy 

consumed (CEC) component, which compensates for the cost of energy consumed by a 

generator solely to provide reactive power support; (3) the cost of energy produced (CEP) 

component, which compensates for the cost of energy produced by a generator solely to 

provide reactive power support; and (4) the capacity cost (CC) component, which 

compensates the generator for the fixed capital costs it incurs with the installation and 

maintenance of equipment necessary to provide reactive power.

Calculation Method

The lost opportunity cost (LOC) for generators that are dispatched down by, or at the 

request of, ISO-NE, or a local control center for the purpose of providing reactive power 

service is calculated pursuant to Market Rule 1. Qualified non-generator reactive 

resources are eligible for payment of the LOC if the resource is dispatched down at the 

request of the ISO or a local control center for the purpose of providing reactive power 

service. The LOC of such qualified non-generator reactive resources will be calculated 

pursuant to procedures established at the time of approval of the equipment type pursuant 

to Section II.B of ISO-NE’s OATT and filed with the Commission.

 

69 See ISO-NE Open Access Transmission Tariff, Schedule 2 - Reactive Supply 

and Voltage Control Service (2012).
2

The cost of energy consumed (CEC) applies to hydro and pumped storage units, as well 

as non-generator resources. For hydro and pumped storage generating units that are 

motoring at the request of ISO-NE or a local control center for the purpose of providing 

reactive power service, the CEC will equal the cost of energy to motor and will be 

calculated in each hour as the MWh of the unit times the LMP or actual energy cost. The 

actual energy cost applies only if motoring energy is purchased through a bilateral 

contract.

Qualified non-generator reactive resources shall be eligible for payment of the CEC 

incurred by qualified non-generator reactive resources for the purpose of providing 

reactive power service (pursuant to the authority established within written operating 

protocols developed under Section II.B.4). The CEC of such qualified non-generator 

reactive resources shall be measured pursuant to procedures established at the time of 

approval of the equipment type pursuant to Section II.B of the OATT and filed with the

Commission. 

The cost of energy produced (CEP) applies to reactive resources brought on-line by the 

ISO or a local control center to provide reactive power service. For thermal generating 

units and hydro or pumped storage units, the CEP is the portion of the total net 

commitment period compensation (NCPC)

70 to be paid to that resource for a day that is 

attributed to the hour(s) during which the resource is run to provide reactive power 

service in accordance with Market Rule 1 and the ISO-NE operating documents.

Qualified non-generator reactive resources are also eligible for payment of the CEP 

incurred by qualified non-generator reactive resources for the purpose of providing 

reactive power service (pursuant to the authority established within written operating 

protocols developed under OATT Section II.B.4). The CEP of such qualified nongenerator reactive resources shall be measured pursuant to procedures established at the 

time of approval of the equipment type pursuant to OATT Section II.B and filed with the 

Commission.

The capacity cost (CC) component of the rate is based on the “VAR CC Rate,” which is 

established each year as of January 1 on a prospective basis for that calendar year, and is 

based on a base CC rate of $2.19/kVAR-yr effective January 1, 2012,71 prorated based on 

the forecast peak load for the year divided by the sum of all qualified reactive resources’ 

 

70 NCPC is ISO-NE’s term for uplift.

71 ISO New England Inc., 137 FERC ¶ 61,237 (2011).
3

summer seasonal claimed capability, and based on the leading and lagging reactive power 

available from the unit.

For qualified non-generator reactive resources, the seasonal claimed capability is 

calculated as 2.5 times the maximum dynamic reactive power capability on a lagging 

basis demonstrated by the resource during the testing of its reactive power capability 

consistent with ISO-NE procedures for measurement of such capability in megawatts.

In addition, if a non-generator source of reactive power service responds to identified 

needs for dynamic reactive power on the New England Transmission System, as 

identified in the regional system plan, and is confirmed by the ISO as a dynamic reactive 

power resource that will meet the identified need, and such non-generator source of 

reactive power service meets the criteria to be a qualified non-generator reactive resource 

but cannot recover its costs of providing dynamic reactive power under Schedule 2, then 

such non-generator may submit a separate schedule to the ISO OATT to be filed with the 

Commission for a rate to be paid to allow such resource to recover its costs related to 

providing reactive power service.

Qualification Process

The criteria for becoming a qualified reactive resource for generators are: (1) the entity 

owning or controlling the reactive power capability of the generator reactive resource is a 

Market Participant; (2) the generator is interconnected to the New England Transmission 

System, or interconnected to the distribution system but participating in the New England 

Markets, and is metered and dispatchable by ISO-NE or otherwise subject to operational 

control by ISO-NE; (3) the generator provides measurable reactive power voltage support 

to the New England Transmission System, as determined from time-to-time by ISO-NE, 

and has its automatic voltage regulator status and control mode (including power factor, 

reactive power output and voltage control) telemetered to ISO-NE and the applicable 

local control center; (4) the generator meets the reactive power testing requirements 

applicable to generators, as determined from time-to-time by ISO-NE and specified in the 

ISO New England Operating Documents; and (5) the installation of the generator has 

been approved in accordance with the requirements of Section I.3.9 of ISO-NE’s OATT 

or its predecessor or successor provisions under the New England regional transmission 

arrangements.

For non-generator resources, the criteria are: (1) the entity owning or controlling the 

reactive power capability of the non-generator reactive power resource is a market 

participant; (2) the non-generator reactive power equipment provides measurable 

dynamic reactive power voltage support to the New England Transmission System, as 

determined from time-to-time by ISO-NE; (3) the type of dynamic reactive power 

equipment is within a category of equipment that has been approved by ISO-NE, with 

advisory input from the reliability committee; (4) the dynamic reactive power equipment 

is subject to the operating authority of ISO-NE and all necessary operating protocols for 
4

provision of reactive power voltage support from such equipment have been agreed to, in 

writing, between ISO-NE and the non-generator reactive power resource; (5) such 

equipment is interconnected to the New England Transmission System and metered and 

dispatchable by ISO-NE or otherwise subject to operational control by ISO-NE, and has 

its automatic voltage regulator status and control mode (including power factor, reactive 

power output and voltage control) telemetered to ISO-NE and the applicable local control 

center; (6) the non-generator reactive resource meets the reactive power testing 

requirements applicable to such non-generators, as determined from time-to-time by ISONE and specified in the ISO New England operating documents; and (7) the installation 

of such equipment shall have been approved in accordance with the requirements of 

Section I.3.9 of the OATT or its predecessor provisions under the New England regional 

transmission arrangements.

II. NYISO

Rate

The NYISO calculates payments for voltage support service annually, and makes 

payments monthly. Suppliers that qualify to receive payments and whose generators are 

under contract to supply installed capacity receive one-twelfth of the annual payment 

calculated by the NYISO. Suppliers whose generators are not under contract to supply 

installed capacity, suppliers with synchronous condensers, and qualified non-generator 

voltage support resources receive one-twelfth of the annual payment calculated by the 

NYISO, pro-rated by the number of hours that the generator, synchronous condenser, or 

qualified non-generator provides voltage support resources.

Calculation Method

For generators and synchronous condensers, the annual payment for voltage support 

service is equal to the product of $3919/MVAr and the tested reactive power capacity of 

the generator or synchronous condenser. For qualified non-generator voltage support 

resources, the annual payment for voltage support service is equal to the product of 

$3919/MVAr and their tested reactive power capacity as determined pursuant to the ISO 

procedures.72 If a synchronous condenser or qualified non-generator voltage support 

resource energizes in order to provide voltage support service in response to a request 

from the NYISO, the NYISO compensates the facility for the cost of energy it consumes 

to energize converters and other equipment necessary to provide that service.

When the NYISO directs the generator to reduce its real power output below its 

economic operating point in order to allow the generator to produce or absorb more 

 

72 New York Indep. Sys. Operator Inc., 117 FERC ¶ 61,137 (2006).
5

reactive power, the generator receives a payment for lost opportunity costs (LOC). The 

LOC payment is calculated as the maximum of zero or the difference between: (1) the 

MW of the generator’s output reduction (in order to produce or absorb additional reactive 

power) multiplied by the real-time location-based marginal price at the generator bus; and 

(2) the generator’s energy bid for the reduced output of the generator multiplied by the 

time duration of reduction in hours or fractions thereof.

Qualification Process

To qualify for payments, a voltage support service supplier must be able to: produce and 

absorb reactive power within its tested reactive capability range; maintain a specific 

voltage level under both steady-state and post-contingency operating conditions, subject 

to the limitation of its tested reactive capability; automatically respond to voltage control 

signals; for a generator, a functioning automatic voltage regulator (AVR) is required; be 

under the operational control of the NYISO or a transmission owner; and successfully 

perform reactive power capability tests in accordance with the procedures described in 

Section 3.6 of the NYISO ancillary services manual.73

If the resource is precluded from running in “lead” mode in which it can absorb reactive 

power, then the unit is not eligible to provide voltage support services. However, the 

requirement to absorb reactive power may be set aside by the NYISO with input from the 

transmission owner in whose transmission district the resource is located. To grant an 

exemption from the requirement that the resource be able to absorb reactive power, the 

NYISO shall have determined that: (1) the resource is unable, due to transmission

system configuration, to absorb reactive power; (2) the ability of the resource to produce 

reactive power is needed for system reliability; and (3) for purposes of system reliability 

the resource does not need to have the ability to absorb reactive power.

III. PJM

Rate

PJM determines the amount of reactive supply and voltage control that must be supplied 

by the transmission provider with respect to the transmission customer’s transaction 

based on the reactive power support necessary to maintain transmission voltages within 

limits that are accepted and adhered to by the transmission provider. The transmission 

provider administers the purchases and sales of reactive supply and voltage control with 

PJM designated as a counterparty. Market sellers that provide reactive services at the 

direction of PJM are credited for such services. Generation or other source owners that 

 

73 See NYISO Ancillary Services Manual, Section 3 – Voltage Support Service 

(2013).
6

provide reactive supply and voltage control are paid monthly by the transmission 

provider, equal to the generation or other source owner’s monthly revenue requirement as 

approved by the Commission.

Calculation Method

The generator or other source owner’s monthly revenue requirement is generally 

calculated using the AEP methodology, and filed with the Commission.

In addition to the capability payment, PJM also pays market sellers that provide reactive 

services at the direction of PJM, based on the difference between locational marginal 

price and the unit’s offer price, depending on whether the active energy output of a 

market seller’s resource is reduced or raised.74

In addition, if a market seller’s steam-electric generating unit or combined cycle unit 

operating in combined cycle mode is not committed to operate in the day-ahead market, 

but is directed by PJM to operate solely for the purpose of maintaining reactive 

reliability, it will be credited in the amount of the unit’s offered price for start-up and noload fees. The unit will also receive, if applicable, compensation based on the difference 

between LMP and the unit’s offer price.

Finally, to the extent a synchronous condenser operates to provide reactive services and 

provides synchronized reserve, a market seller will be credited for providing synchronous 

condensing in an amount equal to the higher of (1) the hourly synchronized reserve 

market clearing price for each hour a generating unit provides synchronous condensing,

multiplied by the amount of synchronized reserve provided by the synchronous 

condenser or (2) the sum of (a) the generating unit’s hourly cost to provide synchronous 

condensing, calculated in accordance with the PJM Manuals, (b) the hourly product of 

MW energy usage for providing synchronous condensing multiplied by the real time 

locational marginal price at the generating unit’s bus, (c) the generating unit’s startupcost of providing synchronous condensing, and (d) the unit-specific lost opportunity cost 

of the generating resource supplying the increment of synchronized reserve, as 

determined by the office of the interconnection in accordance with procedures specified 

in the PJM manuals.

 

74 See PJM Open Access Transmission Tariff, Schedule 2 - Reactive Supply and 

Voltage Control from Generation or Other Sources Service, section 3.2.3B of Appendix 

to Attachment K (2013).
7

Qualification Process

The PJM tariff does not include a specific qualification process for reactive power 

compensation, nor a qualification process or specific compensation formulas for nongenerator sources.

IV. MISO

Rate

MISO determines the amount of reactive supply and voltage control that generation 

resources or other services must supply based on the reactive power support necessary to 

maintain transmission voltages within the voltage range and the resulting reactive power 

range that are generally accepted in the region and consistently adhered to by MISO. 

MISO arranges this service with the local balancing authorities that acquire the service 

for MISO’s transmission system.

MISO calculates rates for the service for each pricing zone, which represent a pass 

through of costs, based on the annual cost-based revenue requirements or cost-based rates 

of qualified generators. Qualified generators file their annual cost-based revenue 

requirement and/or cost-based rates for voltage control capability with the Commission. 

MISO collects a charge from each transmission customer monthly by multiplying the 

applicable rate by the transmission customer’s reserved capacity. MISO provides each 

qualified generator monthly a pro rata allocation of the amount collected based upon the 

qualified generator’s share of the rate within its pricing zone.

Calculation Method

MISO distinguishes its calculation of rates between service provided for load within the 

transmission system and for transactions exiting the transmission system. MISO 

determines the rate for service within the transmission system by summing the annual 

revenue requirements for voltage control capability, using this sum to determine the 

monthly reactive power revenue requirement for the pricing zone and then dividing this 

amount by the rate divisor for each pricing zone.75 MISO states that any qualified 

generator seeking compensation for reactive service must file with the Commission to 

justify its cost-based revenue requirements. For qualified generators with a cost-based 

rate schedule on file with the Commission that does not include an annual revenue 

requirement, the above calculated amount is added to the stated rate. For transmission 

customers with loads located outside the transmission system, the rate is calculated as an 

average of all of the pricing zones within MISO’s transmission system.

 

75 The rate divisor is found in MISO’s Attachment O, Page 1, Line 15.
8

Qualification Process

To qualify as a generation resource a generator must be able to: (1) operate with its 

voltage regulators in automatic mode and respond to voltage schedules set forth by MISO 

or the local balancing authority for the pricing zone which it is located in; (2) maintain 

voltage support within its design limits; (3) maintain a reactive power range of 95% 

leading to 95% lagging at the Point of Interconnection unless otherwise stated in the 

generation resource’s generation interconnection and operating agreement; (4) respond 

to changes in voltage on the system and to changes in voltage schedules if the facility is 

operating; (5) provide voltage control specified by MISO or local balancing authority 

immediately, if intra-day system conditions require additional reactive power supply to 

maintain reliability, or as instructed by the transmission provider prior to the operating 

day based on forecasted system conditions, taking into consideration the unit’s operating 

characteristics, and whether the generation resource is not operating at the time of the 

request as a result of an unscheduled or planned outage. In addition, the generator must 

have met the testing requirements for voltage control capability required by the regional 

reliability council where the generation resource is located within the past five years; and 

must have submitted a request to MISO for qualified generator status.

V. SPP

Rate

SPP requires all qualified generators to maintain reactive supply pursuant to a voltage 

schedule it provides or one provided by the applicable local balancing authority. SPP 

does not compensate generators operating within a standard range of 0.95 leading to 0.95 

lagging for supplying reactive power.

SPP compensates all existing generation owners eligible to collect charges for reactive 

supply connected to the transmission system under a cost-based rate schedule on file with 

the Commission as of October 1, 2006. Qualified generators are paid monthly based on 

actual usage with no true-ups. SPP will post the applicable monthly charges to 

transmission customers after it possesses the data necessary to calculate the charges for a 

transmission customer based on multiplying the applicable rate by the transmission 

customer’s reserved capacity.

Calculation Method

SPP charges a reactive compensation rate of $2.26 per MVAr-hour, which is multiplied 

by the monthly amount of reactive power provided by a qualifying generator outside of 
9

the standard range76 to calculate monthly payments to each individual qualified 

generator. SPP sums these payments by zone and subtracts the revenue collected for 

through and out transactions for a particular zone to calculate the charges to be collected 

per zone. Rates charged to transmission customers are based on monthly, weekly and 

daily time periods with on-peak and off-peak rates.

Qualification Process

To qualify as a qualified generator a generator must: (1) designate the entity that is to 

receive dispatch instructions and the entity to receive compensation; (2) be able to 

produce reactive power outside the standard range at its Point of Interconnection with the 

Transmission System; (3) maintain the capability to provide MWh, MVArh and voltage 

data, by such means of transmittal, at such intervals and at such accuracy level as SPP 

shall require; and (4) follow a voltage schedule and respond to dispatch instructions from 

SPP and/or the local balancing authority.

VI. CAISO

Rate

CAISO determines, on an hourly basis for each day, the quantity and location of voltage 

support required to maintain voltage levels and reactive margins within NERC and 

Western Electric Coordinating Council reliability standards, and requirements of the 

Nuclear Regulatory Commission using a power flow study based on the quantity and 

location of scheduled demand. CAISO issues daily voltage schedules to participating 

generators, transmission owners, and utility distribution companies, which are required to 

be maintained for reliability. All participating generators that operate asynchronous 

generating facilities subject to the LGIA shall maintain the CAISO specified voltage 

schedule if required under the LGIA, while operating within the power factor range 

specified in their LGIA. CAISO “shall be entitled to instruct Participating Generators to 

operate their Generating Units at specified points within their power factor range. 

 

76 SPP calculates the reactive power provided outside of the standard range by 

determining the reactive power inside the standard range that the Qualifying Generator 

would have had to produce or absorb to maintain a power factor of 0.95 at its actual real 

power output level. SPP then subtracts the absolute value of this number from the 

absolute value of the actual reactive power output. If the absolute value of the reactive 

power inside the standard range is greater than the absolute value of actual reactive power 

output, the total reactive power provided is zero.
10

Participating Generators shall receive no compensation for operating within these 

specified ranges.”77

If CAISO requires additional voltage support, it shall procure this either through 

reliability-must-run contracts or, if no other more economic sources are available, by 

instructing a generating unit to move its MVAr output outside its mandatory range. 

“Only if the Generating Unit must reduce its MW output in order to comply with such 

instruction will it be eligible to recover opportunity cost...”78

Calculation Method

The total payments for each scheduling coordinator for voltage support in any settlement 

period shall be the sum of the opportunity costs of limiting energy output to enable 

reactive energy production in response to a CAISO instruction. The opportunity cost 

shall be calculated based on the product of the energy amount that would have cleared the 

market at the price of resource-specific settlement interval LMP minus the higher of the 

energy bid price or the default energy bid price. If applicable, the scheduling coordinator 

shall also receive any payments under any long-term contracts due for the settlement 

period. Exceptional dispatches for incremental or decremental energy needed for voltage 

support procured through exceptional dispatch will be paid the higher of: (1) resource 

specific settlement interval LMP, (2) energy bid price, or (3) default energy bid (if the 

unit was mitigated). Reliability-must-run units providing voltage support are 

compensated in accordance with their reliability-must-run contract.79 

Qualification Process

Any participating generator who is producing energy shall, upon CAISO’s specific 

request, provide reactive energy output outside the participating generator’s voltage 

support obligation. CAISO shall select participating generators’ generating units which 

have been certified for voltage support to provide this additional voltage support. Subject 

to any locational requirements, CAISO shall select the least costly generating units from 

a computerized merit order stack to back down to produce additional voltage support in 

each location where it is needed.80

 

77 CAISO tariff, section 8.2.3.3, Voltage Support.

78 Id.

79 CAISO tariff, section 11.10.1.4

80 CAISO tariff, section 8.3.8