Getting the Transmission Planning Rules Right for Competitive Markets

Getting the TransmissionPlanning Rules Right forCompetitive Markets

The absence of region-wide transmission planning can beseen as another ‘‘seams’’ issue. This ‘‘transmissionplanning seam’’ should be eliminated as soon as possible.The development of rules specific to each RTO simplyperpetuate unnecessarily a seam among the threeNortheastern RTOs.

Charles Pratt

Charles Pratt is a Partner in theNew York office of Dickstein ShapiroMorin & Oshinsky LLP and advises

clients on energy industryrestructuring, regulatory matters,

and transmission issues. This articlerepresents the views of the author

alone and not of his firm nor itsclients. The author can be contacted

at [email protected].

I. Introduction

The Federal Energy Regula-

tory Commission has identified

transmission congestion as a

major barrier to the development

of robust energy markets.1

Transmission congestion that

does not lead to economical

changes to the bulk power

system has the effect of limiting

the geographical scope of the

market and thus weakening

competition. Nevertheless, dur-

ing the restructuring of the

electric power industry there

has been limited investment in

transmission system facilities

beyond direct generation inter-

connections.2 One reason for

such limited investment is the

slow development of trans-

mission planning rules for

competitive markets. Even

after several years’ operating

experience, the three control

area operators in the Northeast

have not yet completed adop-

tion of transmission planning

rules.3

S everal recent Commission

orders identify significant

issues that contribute to the

Northeastern RTOs’ slow

August/September 2003 # 2003, Elsevier Inc., 1040-6190/$–see front matter doi:10.1016/S1040-6190(03)00094-0 65

http://[email protected]

development of transmission

planning rules. In addition, each

of these RTOs is currently con-

sidering significant modifica-

tions to its transmission planning

rules. Thus, it is timely to con-

sider transmission planning in

these three RTOs. Resolution of

transmission planning issues in

the Northeast is likely to influ-

ence the development of plan-

ning rules elsewhere as

competitive markets develop in

other regions.

T his article, first, describes

how the three Northeastern

RTOs currently address trans-

mission planning. Second, it

explores three issues key to

establishing transmission plan-

ning rules: (a) how to select

among competing proposals to

reduce transmission congestion;

(b) how the cost of transmission

projects should be recovered; and

(c) whether RTOs should be

authorized to mandate trans-

mission expansion to resolve

congestion. Underlying these

issues is the question of the

appropriate extent of an RTO’s

authority to make system

planning decisions to address

transmission congestion. The

resolution of these questions in

this article supports the conclu-

sion that a model in which RTOs

have sufficient authority to

undertake transmission plan-

ning, but are subject to the

restraining policy of superseding

market initiatives to the mini-

mum extent possible, presents an

effective approach to transmis-

sion planning for competitive

markets.

II. TransmissionPlanning in the Northeast

A. PJM

PJM’s Operating Agreement

provides that PJM shall prepare

a Regional Transmission Expan-

sion Plan (RTEP) for the

enhancement and expansion of

transmission facilities in order

to meet the demands for firm

transmission service and to

support competition. The RTEP

‘‘shall consolidate the transmis-

sion needs of the region into a

single plan which is assessed on

the bases of maintaining the

reliability of the PJM Control

Area . . . in an economic and

environmentally acceptable man-

ner and of supporting competition

in the PJM Control Area . . ..’’4 The

RTEP is developed in consultation

with a stakeholder advisory

committee and then presented to

PJM’s Board for approval.

T he Operating Agreement’s

transmission planning pro-

visions were accepted in July 2001

by the Commission, with the

requirement that three aspects of

PJM’s transmission planning pro-

tocol be modified.5 The Commis-

sion stated that a regional

transmission plan must have a

broader orientation than main-

taining reliability, and should

make generation markets more

competitive. ‘‘[T]he planning

process should also focus on

identifying projects that expand

trading opportunities, better inte-

grate the grid, and alleviate con-

gestion that may enhance

generator market power.’’6 In

addition, the Commission directed

that all market participants should

have an opportunity for mean-

ingful participation in the plan-

ning process and that parties other

than traditional transmission

owners be permitted to sponsor

expansion plans. On rehearing,

two years later, PJM was directed

to explain how the transmission

planning process will identify

expansion projects that are needed

to support competition, as well as

to ensure reliability.7

In March 2003, PJM proposed

changes to its Open Access

Transmission Tariff (OATT) and

Operating Agreement regarding

transmission planning, which

would authorize PJM to designate

one or more transmission owners

or other entities to construct or

finance transmission enhance-

ments or expansions specified in

the RTEP to alleviate congestion.8

Such obligation would be trig-

gered when there is ‘‘unhedge-

able congestion.’’9 In addition,

the proposed transmission

enhancement or expansion must

be economically justified. These

provisions are in addition to

The underlying issue:the appropriate extent

of an RTO’s authorityto make system

planning decisions toaddress transmission

congestion.

66 # 2003, Elsevier Inc., 1040-6190/$ – see front matter doi:10.1016/S1040-6190(03)00094-0 The Electricity Journal

PJM’s assessment of the system’s

compliance with applicable relia-

bility criteria.10

T he RTEP, as proposed in the

Compliance Filing, will

include designations of cost

responsibility for each enhance-

ment and expansion project,

based upon planning analysis and

participants’ willingness to bear

cost responsibility. In the absence

of agreement to revise the default

allocation plan, PJM proposes that

costs are to be allocated to: (a)

market participants in one or

more transmission zones that are

to be responsible for a transmis-

sion enhancement or expansion as

and to the extent provided by the

PJM OATT, or (b) if cost respon-

sibility is not established by the

OATT, market participants in one

or more transmission zones pur-

suant to a rate tariff to be filed

separately by transmission own-

ers.11 Allocations under the sec-

ond of these two formulas will be

based upon PJM’s ‘‘assessment of

the contributions to the need for,

and benefits expected to be

derived from, the pertinent

enhancement or expansion by

affected Market Participants.’’12

B. New England

During the past three years, the

Commission has addressed

transmission planning in ISO-NE

in a number of orders concerning

the RTO’s proposed congestion

management—multi-settlement

system and ISO-NE’s standard

market design.13 In February

2002, the Commission accepted a

transmission planning proposal

which vested sole responsibility

for transmission planning in the

RTO.14 Pursuant to this planning

protocol, the RTO prepares a

regional transmission plan, that is,

an RTEP. Earlier references to a

Transmission Planning Commit-

tee, which provided for a signifi-

cant role for transmission owners

in transmission planning, were

deleted. The planning protocol

provides for issuance of requests

for competitive bids to build

transmission upgrades included

in the RTEP.15 In addition to such

transmission upgrades, market

participants may also propose

alternative generation, merchant

transmission facilities, elective

transmission upgrades, demand-

side management, and load

response programs that substitute

for or make unnecessary a trans-

mission upgrade. In the event such

a proposal is selected, the trans-

mission upgrade is removed from

the plan. ISO-NE’s RFP process

has a limited scope as it focuses

only on the proposed transmission

upgrades included in ISO-NE’s

RTEP.16 The tariff does not specify

whether proposals originated

by market participants will be

considered in evaluating potential

transmission upgrades, or simply

constitute another option available

to ISO-NE. Transmission owners

remain potentially responsible for

constructing reliability upgrades

and upgrades that the RTO has

exempted from the competitive

bidding requirements.17

How the cost of transmission

upgrades is to be allocated has not

been resolved. The Commission

announced in mid-2002 that

continuation of a cost allocation

methodology which socializes

costs of transmission upgrades

over a broad customer base

should be replaced with a meth-

odology which permits parties to

see and respond to market signals

in planning and locating trans-

mission upgrades.18 In the Com-

mission’s order accepting the

proposal by ISO-NE and

NEPOOL to adopt a standard

market design, the Commission

directed ISO-NE to develop a

mechanism for allocating costs of

transmission expansion projects,

when the parties cannot agree

who benefits from the upgrade.

The Commission directed that

ISO-NE adopt an objective, non-

discriminatory default cost allo-

cation method that is consistent

with the principles of cost cau-

sation.19 More recently, the

Commission stated in an order on

rehearing that New England

should develop an objective, non-

discriminatory default mechan-

ism to allocate the costs of

upgrades which do not clearly

benefit a discrete party nor are

beneficial to the entire pool.20

Howthe cost oftransmissionupgrades isto be allocatedhas notbeen resolved.


ISO-NE is considering cost allo-

cation options in stakeholder

discussions and anticipates com-

pleting such discussions and

submitting a proposal to the

Commission before the end of

summer 2003. This eventual cost

allocation mechanism will

address upgrades of transmission

facilities that function for the

benefit of the regional power grid,

i.e., Pool Transmission Facilities,

while the costs of upgrades of

other facilities are to be recovered

under each transmission owner’s

OATT.

C. New York

In contrast to PJM and ISO-NE,

the NYISO does not currently

prepare a transmission plan

comparable to an RTEP.21 Nor

does the NYISO otherwise direct

construction of transmission

expansion projects by transmis-

sion owners.22 While the New

York Public Service Commission

(NYPSC) is authorized to request

the NYISO to provide transmis-

sion reinforcement options for

interfaces having significant con-

gestion, it does not appear that

this provision is used regularly.

M oreover, New York does

not have a process for

allocating the cost of transmission

upgrades, apart from intercon-

nection-related upgrades. While

the NYISO’s market participants

have considered proposals to

allocate transmission congestion

contracts to entities that expanded

the transmission system, such a

system has not been implemented.

In a joint petition to form a single

RTO, ISO-NE and NYISO

included transmission planning

provisions, but that petition was

withdrawn shortly after its filing.23

T he NYISO has initiated stake-

holder discussions of a

transmission planning protocol,

which is not expected to be

implemented before the fall of

2003. It appears that the NYISO

favors, at least for the initial phase

of a planning protocol, distin-

guishing transmission expansion

for reliability reasons from other

types of projects.24

III. Key Issues

A. How to select among

competing proposals to reduce

transmission congestion

The Commission proposed in

the SMD NOPR that RTOs iden-

tify all needs for expansion of the

transmission system, i.e., both

reliability and economic needs.

When additional resources are

required, the RTO would

request market proposals. Parties

would be permitted to propose

transmission expansion, new

generation, and increased

demand response proposals. If

such a bidding process failed to

produce adequate proposals,

transmission owners would be

required to expand the system.25

While an RTO’s selections among

transmission upgrade and other

proposals could significantly

affect market initiatives, such

intrusion can be minimized by

limiting the RTO’s exercise of

transmission planning authority.

One approach to minimizing

RTOs’ exercise of planning

authority is the adoption of a

three-tiered set of restraints on

RTO authority to undertake

planning initiatives. First, the

RTO could provide market parti-

cipants time to respond to a

defined system need that is

causing transmission congestion.

In PJM, this step is referred to as

providing a ‘‘timing trigger.’’

Only in the absence of the mar-

ket’s failure to respond to such a

trigger would the RTO consider

further steps to build economic

upgrades. Second, an RTO could

include a transmission proposal

in the RTEP to satisfy economic

needs, only provided that trans-

mission congestion is significant.

While the specification of what

constitutes ‘‘significant conges-

tion’’ will be difficult, factors that

should be considered include (1)

the ratio of the congestion asso-

ciated with the need for an

upgrade to RTO-wide congestion,

(2) the persistence of congestion,

and (3) the impact of the trans-

mission congestion caused by a

constraint on the need for market

One approach tominimizing RTOs’

exercise of planningauthority is adoption

of a three-tieredset of restraints on

RTO authority.


mitigation provisions in the con-

strained energy market. The stan-

dard set by PJM, ‘‘unhedgeable

congestion,’’ is both undefined

and may be set at too low a level to

bar unneeded intrusion into the

market.26 It does not appear that

either of these steps, or restraints,

is included in ISO-NE’s transmis-

sion planning rules, nor in the

NYISO’s limited transmission

planning provisions.

A third potential limitation

on centralized planning

involves the use of competitive

requests for proposal (RFP) for all

proposals addressing transmis-

sion congestion. While PJM pro-

poses to conduct cost benefit

analyses concerning proposed

economic transmission enhance-

ments and expansions,27 it

appears that such analyses will

not consider market-initiated

non-transmission options. Such

options may lead to changes in the

RTEP, but it does not appear that

they will be considered in the RFP

evaluation process. Thus, PJM’s

planning proposal may lead to the

selection of rate-base transmis-

sion options instead of more

efficient and cost effective solu-

tions, such as demand response,

merchant transmission, or gen-

eration.28 ISO-NE’s RFP process is

similarly limited to proposed

transmission upgrades.29

Transmission solutions should

not be mandated or favored in an

RTO’s planning rules, as market

solutions to congestion can

include specific generation and

demand-response alternatives

that make transmission solutions

unnecessary. Rather, in order to

avoid favoring one resource type

over others, the RTO should

review transmission enhance-

ments or expansions against

alternative market proposals,

including generation, merchant

transmission, and demand

response, in a process using spe-

cific standards available to market

participants. The transmission

planning rules should be

designed so that the most efficient

and cost effective solutions are

selected. While RTOs could

become responsible for what is

essentially integrated resource

planning if they are the gate-

keeper for selection of all types of

economic transmission upgrades,

or expansions, the three limita-

tions on the RTO’s planning role

discussed here—a trigger period

of at least one year for the market

to respond to perceived needs, the

limitation of a planned economic

upgrade to cases involving ‘‘sig-

nificant’’ congestion, and appli-

cation of rigorous economic

analysis to both market-initiated

projects as well as transmission

upgrades—constrain the RTO’s

planning power.

The limitation on the scope of

the RFP process in both PJM and

ISO-NE is compounded by a lack

of specification as to whether non-

transmission proposals origi-

nated by market participants will

serve as a threshold test for pro-

posed transmission upgrades or

as simply another option avail-

able to the RTO. Although trans-

mission projects may be removed

from the RTEP in favor of alter-

natives proposed by market par-

ticipants, such decisions would

not be made in the context of the

competitive RFP process. Thus, it

is not clear whether the decision

to replace a proposed transmis-

sion upgrade in favor of a market-

proposed option is to be made on

economic grounds or upon other

non-specific and non-quantified

grounds. The focus on the RTO as

a gatekeeper places a high pre-

mium on specifying how the RTO

will address transmission plan-

ning in documents filed with the

Commission in order to avoid

simply increasing the RTO’s dis-

cretion.

The requirement that the RTO

adopt the three substantive ‘‘self-

limiting’’ constraints discussed

above, together with making its

planning rules specific, are critical

limitations on an RTO’s power to

intrude in the market’s develop-

ment.

B. How should the cost of

transmission projects be

recovered?

The method of allocating the

cost of economic transmission

expansion projects remains


unresolved by the three North-

eastern RTOs. PJM proposes to

designate market participants, in

addition to transmission owners,

as responsible for costs of trans-

mission expansion projects.30

Such allocations would be based

upon PJM’s ‘‘assessment of the

contributions to the need for, and

benefits expected to be derived

from, the pertinent enhancement

or expansion by affected Market

Participants.’’31

W hile PJM’s proposal does

not make clear how such

an allocation of costs to particular

market participants would be

made, fewer than all transmission

customers within a transmission

zone may be designated for

recovery of the cost of a particular

transmission expansion or

enhancement. In fact, it appears

that such an allocation could be

made among a limited group of

market participants, as PJM is

required to designate the pro-

portional responsibility among

market participants. Although

upgrade costs can be allocated to

load-serving entities (LSEs),

nothing in PJM’s proposal pre-

cludes allocating such costs to

other transmission customers.

Thus, under its proposal, PJM will

assume significant authority to

allocate costs based on its assess-

ment of each market participant’s

contribution to the need for, and

benefit from, each particular

transmission upgrade.

PJM’s proposed allocation

process leaves key questions

unanswered. First, the standards

for such assessment of market

participants’ contribution to the

need for or benefit from the

upgrade are not specified, but are

left to the discretion of the RTO.

While PJM promises to thor-

oughly vet a proposed cost-allo-

cation, the absence of decision-

making standards in the tariff

indicates that such vetting will be

within the RTO’s discretion. This

failure to spell out the rules

explicitly would appear to

enlarge the planning role of the

RTO, compared to making such

allocations pursuant to specific

rules. Moreover, the indefinite-

ness of the basis for determining

the benefit from a particular

transmission upgrade may lead to

disputes and litigation before the

Commission.

S econd, transmission custo-

mers, to which such costs

will be allocated, are in quite

different positions depending on

whether they are LSEs. Imposi-

tion of the cost of a transmission

upgrade on a party incapable of

collecting them pursuant to tra-

ditional rate-setting—such as a

merchant developer—is quite

different from imposing such

costs on an LSE, which can pass

the charges on to customers

through regulated rates.

In the case of ISO-NE and the

NYISO, the RTOs and market

participants have not finally

selected a method of allocating the

cost of economic transmission

expansion projects. Moreover, at

least the NYISO’s authority to

mandate that transmission owners

assume a share of the costs of an

economic expansion project is

limited.32 Such a limitation would

appear also to bar, at least in effect,

the NYISO from allocating such

costs to other market participants,

as such an incomplete allocation

would necessarily discriminate

among market participants.

The broad RTO discretion over

cost allocation proposed by PJM

may lead to numerous disputes

regarding cost allocation to non-

consenting market participants.

This potential for continued dis-

pute suggests, however, that the

existence of the parties’ mutual

agreement to an allocation of costs

of transmission upgrades may be

a de facto limit on RTOs’ ability to

allocate the cost of new economic

transmission projects. In the event

that the benefits from a trans-

mission upgrade are obvious,

market participants are likely to

undertake the expense. On the

other hand, upgrades with less

clear benefits to market partici-

pants may be constrained by

market participants’ opposition.

Thus, RTOs may find it expedient

to favor projects for which there is

a voluntary agreement to assume

the costs. To the extent RTOs are

effectively restricted to such

voluntary allocations, there is an


effective limit on RTOs’ power to

allocate the cost of transmission

projects, and thus a reduction in

RTO’s power to conduct centra-

lized planning. Such a result is

consistent with the premise of this

article that an RTO’s power to

undertake economic planning

should be limited.

T he scope of the RTO’s role in

transmission planning is

reduced to the extent the stan-

dards for cost allocation are spe-

cified. Moreover, to the extent that

disputes over allocation formulas

limit the allocations to cases in

which there is voluntary agree-

ment of market participants, the

scope of the RTO’s discretion

would appear to be limited

and thus its role in centralized

transmission planning would be

limited.

C. Should RTOs be

authorized to mandate

transmission expansion to

resolve congestion?

PJM’s Operating Agreement

authorizes the designation of one

or more transmission owners to

construct or finance transmission

enhancements or expansions

specified in the RTEP.33 Certain

transmission owners, however,

have challenged PJM’s author-

ity—and by implication, RTOs’

authority generally—to direct a

transmission owner to construct a

transmission enhancement or

upgrade.34 Moreover, the recent

decision in Atlantic City Electric

Company v. FERC,35 concerning

PJM’s authority with respect to

transmission owners, may

encourage transmission owners to

challenge RTOs’ assumption of

authority. Further, the NYPSC has

argued that an RTO should not be

authorized to approve transmis-

sion expansions or to solicit pro-

posals to expand the transmission

grid, add generation, or imple-

ment demand response, but

should simply make the results of

any needs assessment available

and allow the market to

respond.36

It is not necessary to resolve

these questions, however, as they

are beside the point to the extent

that the RTO’s planning rules

provide a basis for participants to

support needed expansions of the

transmission grid voluntarily. In

fact, the failure of market parti-

cipants to agree to fund trans-

mission upgrades may reflect the

absence of an effective device to

realize the apparent benefits. If

appropriate means of realizing

the benefits of transmission

upgrades can be created, market

participants are increasingly

likely to be willing to undertake

transmission upgrades on a

voluntary basis.37 There is thus a

priority need to create means of

realizing the benefits of trans-

mission upgrades in order to

capture the full value of the

upgrade.38 Development of such

market rules that permit parties to

realize the benefits of transmis-

sion upgrades would limit RTOs’

control of system planning, as it

would be unnecessary for RTOs to

mandate expansion projects in

such cases.

In the absence of effective

means of realizing the benefits of

transmission upgrades, a practi-

cal remedy for RTOs seeking to

secure an expansion of the trans-

mission grid would be for the

RTO to make specific requests to

the Commission for approval of

mandated transmission

upgrades. This approach avoids

the necessity for an RTO to contest

whether it has authority to man-

date new construction. Such

requests would also assist the

RTO, which is undertaking

nuanced decisions concerning

economic upgrades, from having

to review its own decision-mak-

ing. To the extent that a particular

upgrade is controversial, a case-

specific approval would free the

balance of the RTEP from the risk

that a complaint would retard its

being made effective.

IV. Conclusion

While the three key issues dis-

cussed in this article hardly

address all matters of concern

regarding transmission planning,

adoption of a model in which

RTOs are authorized to undertake


transmission planning, while

being subject to a policy limiting

intervention in the market to the

minimum extent possible, pro-

vides a basis for transmission

planning. Thus, RTOs would be

able to carry out the essential task

of transmission planning, for

which they are uniquely suited.

At the same time, adoption of the

requirement that transmission

congestion be ‘‘significant’’

would limit the RTO from con-

sidering a number of cases.

Further, RTOs’ economic analysis

of potential changes to the grid in

an RFP process should not pre-

clude consideration of options

that do not involve transmission

upgrades, but are sponsored by

market participants.

T he standards upon which an

RTO makes cost allocation

decisions should be made explicit

and included in filings with the

Commission. This reduces the

discretion of an RTO. Alterna-

tively, costs should be collected,

to the maximum extent possible,

pursuant to agreements among

affected parties. This approach

both follows the Commission’s

policy of looking to funding by

participants, and recognizes pos-

sible limitations on an RTO’s

authority to impose cost collec-

tion. Instead of simply directing a

transmission owner to undertake

a transmission upgrade on the

RTO’s own authority, RTOs

should make the creation of an

effective means of realizing the

value of the upgrade a priority.

Finally, absent an effective means

of realizing the benefits of trans-

mission upgrades, RTOs seeking

to secure an expansion of the

transmission grid to address

economic needs should request

approval from the Commission of

mandated transmission

upgrades.

W hile references to

‘‘seams’’ often refer to

differences in transaction-related

market rules where conflicting

rules burden the development of

a regional market, the absence of

region-wide transmission plan-

ning is another form of a seam.

The lack of consistent transmis-

sion planning rules across the

Northeast’s RTOs will bias mar-

ket participants’ choice of loca-

tions for new plants and may

retard development of a single

large market. Moreover, signifi-

cant differences in the way RTOs

address transmission planning

may result in decisions by market

participants to switch from one

RTO to another. This ‘‘transmis-

sion planning seam’’ should be

eliminated as soon as possible.

The development of rules specific

to each RTO simply perpetuate

unnecessarily a ‘‘seam’’ among

the three Northeastern RTOs.&

Endnotes:

1. Remedying Undue Discriminationthrough Open Access Transmission Ser-vice and Standard Electricity Market De-sign, Notice of Proposed Rulemaking,RM01-12-000 (SMD NOPR), at para.191–195 (July 31, 2002). On April 28,2003, the Commission issued a WhitePaper on a Wholesale Power MarketPlatform in Docket No. RM01-12-000,which identifies modifications to themarket design announced in the SMDNOPR (White Paper).

2. SMD NOPR, supra note 1, at 335;Leonard Hyman, The Next Big Crunch:T&D Capital Expenditures, POWER DAILY

N. AM., March 12, 2003, at 1.

3. PJM Interconnection, LLC (PJM);ISO New England Inc. (ISO-NE); andNew York Independent System Op-erator, Inc. (NYISO). The term regionaltransmission organization (RTO) isused in this article to describe all threecontrol area operators.

4. PJM Operating Agreement, Sche-dule 6, § 1.4(a).

5. PJM Interconnection, LLC, 96 FERC �61,061 (2001) (July 2001 Order).

6. July 2001 Order, at 61,240.

7. PJM Interconnection, LLC, 101 FERC� 61,345 (2002), at para. 24.

8. PJM Operating Agreement, Sche-dule 6, §§ 1.5.6(e) and 1.5.6(f) (asmodified by PJM’s March 2003 Com-pliance Filing) (Compliance Filing).PJM’s modified transmission planningprovisions are currently before theCommission but at the time of publi-cation of this article, the Commissionhas not accepted or otherwise acted onPJM’s proposal.

9. PJM proposes that it identifytransmission upgrades to addresscongestion only in cases in whichcongestion is ‘‘unhedgeable.’’ The term‘‘unhedgeable congestion,’’ however,is not defined in the Compliance Filingand there is considerable uncertaintyas to its meaning.

10. Compliance Filing letter, at 4. PJMargued in its comments on SMD NOPRthat solicitation of proposals would notprovide timely solutions to existingviolations of baseline reliability criteria.


SMD NOPR, PJM’s Additional Com-ments, at 12–14 (Jan. 10, 2003).

11. PJM Operating Agreement, pro-posed Schedule 6, § 1.5.6(g). The costof transmission upgrades caused bynew interconnections are borne by theparties requesting interconnection, tothe extent that such costs would nothave been incurred under the RTEP.PJM’s OATT § 37.2.

12. PJM Operating Agreement, pro-posed Schedule 6, § 1.5.6(g).

13. ISO New England, Inc., 91 FERC �61,311 (2000); ISO New England, Inc., 95FERC � 61,384 (2001) (June 2001 Order);ISO New England, Inc., 98 FERC � 61,173(2002) (February 2002 Order); ISO NewEngland Inc., 100 FERC � 61,029 (2002)(July 2002 Order); New England PowerPool, 100 FERC � 61,287 (2002) (Sep-tember 2002 Order); New England PowerPool, 101 FERC � 61,344 (2002) (De-cember 2002 Order); and New EnglandPower Pool, 102 FERC � 61,112 (2003).

14. February 2002 Order, at para. 1,and ordering provision ‘‘A.’’

15. NEPOOL OATT, § 51.6(a).

16. Id.

17. NEPOOL OATT, §§ 51.6(e) and51.7.

18. July 2002 Order, at para. 8.

19. The September 2002 Order, atpara. 144.

20. December 2002 Order, at para. 51.

21. The NYISO does conduct areatransmission reliability assessments inaccord with the procedures of theregional reliability council.

22. The NYISO appears to be pre-cluded from directing a transmissionowner to construct new facilities or tomodify existing facilities pursuant toSection 18.01 of the NYISO Agreement.A transmission owner may be requiredto construct transmission facilities inconnection with new interconnections,provided that such transmission owneris compensated in rates. NYISO OATT,Attachment S, Second Revised SheetNo. 663.

23. Joint Petition for Declaratory Or-der Regarding the Creation of aNortheastern Regional TransmissionOrganization, filed Aug. 23, 2002, in

Docket No. RT02-3-000. The JointPetition was withdrawn three monthslater in the face of stakeholder oppo-sition. In the case of transmissionupgrades required because of newinterconnections, however, New Yorkhas adopted a process to allocate costsamong sponsors of new projects andthe transmission owner. This costallocation approach is subject to acomplaint before the Commission.Docket No. EL02-125-000.

24. SMD NOPR, NYISO’s AdditionalComments, at 4 (Jan. 10, 2003).

25. SMD NOPR at para. 347–348. Inaddition, if an entity proposing aproject is willing to assume the marketand regulatory risk, it should be free toundertake the project.

26. PJM has reported informally thatits standard is intended to apply to allelectrical demand that does not havedirect access to inexpensive energy,either locally or at a distance coupledwith existing hedges. William W.Hogan, Transmission Market Design,April 2003, at 21, available at http://ksgwww.harvard.edu/hepg/in-dex.html.

27. PJM Operating Agreement, §1.5.6(d) (as set forth in the pendingCompliance Filing).

28. National Transmission Grid Study,U.S. Dept. of Energy, May 2002, at 51–52.

29. NEPOOL OATT, § 51.6; New York,as noted above, does not have acomparable transmission planningprotocol.

30. PJM Operating Agreement, §1.5.6(g); pending Compliance Filingletter, 12. PJM transmission ownersfiled changes to PJM’s Schedule 12providing for collection of the costof economic transmission upgrades.Filing Letter, Docket No. ER03-738-000(April 11, 2003) 103 FERC � 61,3192003.

31. PJM Operating Agreement, §1.5.6(g); and see proposed Schedule 12,which provides for the allocation ofthe cost of a transmission enhancementor expansion among responsible cus-tomers.

32. See Note 22.

33. PJM Operating Agreement, Sche-dule 6, § 1.7 (as modified in itspending Compliance Filing).

34. ‘‘Application for Rehearing andRequest for Clarification of the NewYork Transmission Owners,’’ PJM In-terconnection, LLC, RT01-2-005 (Jan. 21,2003). The owners contend that theCommission’s (and by extension anRTO’s) authority to mandate con-struction under Sections 210 and 211Federal Power Act is limited. Othershave argued that the Commission maynot direct the construction of newtransmission facilities without makingcase specific findings, and that theCommission is not authorized tomandate construction of economictransmission upgrades on the basis ofremedying undue discrimination assuch upgrades do not appear likely toaddress discrimination. The Commis-sion has not ruled on the application.

35. 329 F.3rd 856 (D.C. Cir. 2003).

36. SMD NOPR, NYPSC’s AdditionalComments, Jan. 31, 2003, at 7–12.

37. See, for example, Energy SecurityAnalysis, Inc., Occasional Memo(March 27, 2003), in which there is adiscussion of a ‘‘locational capacityreduction payment right’’ as a meansto accelerate the development of mer-chant AC transmission projects.

38. The existing approach to fundingtransmission upgrades in PJM and theNYISO, the award of transmissioncongestion revenues to the party re-sponsible for an expansion project, doesnot appear to create sufficient incentiveto encourage such construction.


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Getting the Transmission Planning Rules Right for Competitive Markets

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