Docket No. RM99-2-000 -505-

G. Transmission Ratemaking Policy for RTOs

We have concluded that the success of the Commission's efforts to have effective

and efficient RTOs is dependent in large measure on the feasibility and vitality of the

stand-alone transmission business. For that reason, and to promote economic efficiency,

the RTO transmission ratemaking policies of the Commission are an important factor of

RTO success. In light of the restructuring of markets and market institutions that is

taking place, we now believe that it will be helpful to inform the industry about what we

consider to be appropriate and inappropriate transmission pricing practices for RTOs, and

about a framework for RTOs to propose efficient and fair pricing reform. Accordingly,

we provide guidance below on a number of fundamental ratemaking issues.

We believe that it is critically important for RTOs to develop ratemaking practices

that: eliminate regional rate pancaking; manage congestion; internalize parallel path

flows; deal effectively and fairly with transmission owning utilities that choose not to

participate in RTOs; and provide incentives for transmission owning utilities to efficiently

operate and invest in their systems. In particular, the Commission encourages RTOs to

develop and propose innovative ratemaking practices, particularly with respect to

efficiency incentives. We therefore devote a significant portion of the discussion in this

section of the Final Rule to performance-based regulation (PBR) and other RTO

transmission ratemaking reforms.
Docket No. RM99-2-000 -506-

611We have adopted and expanded the regulatory text proposed by Edison Electric

Institute in its comments (see EEI, Appendix E).

In addition to the guidance offered here, we have added regulatory text

(section 35.34 (e)) with regard to PBR and other RTO transmission ratemaking

reforms, 611 which now identifies a select list of innovative transmission rate treatments. 

The Commission will consider such innovative rate treatments for entities that file

proposals under the new section 35.34 and that meet the minimum characteristics and

functions required in the Final Rule. The Applicant must explain how the proposed rate

treatment would help achieve the goals of RTOs, including efficient use of and

investment in the transmission system and reliability benefits to consumers; provide a

cost-benefit analysis, including rate impacts; and explain why the proposed rate treatment

is appropriate for the RTO proposed by the Applicant. This means that filings under

section 35.34(e) must be complete and fully explained; must demonstrate that the

resulting rates are just, reasonable, and not unduly discriminatory or preferential; must

identify how the rate treatment promotes efficiency and what benefits result; and must

demonstrate that the rate treatment does not impede the RTO from meeting the minimum

characteristics and functions required under this Final Rule. The Commission encourages

properly developed transmission pricing proposals from RTOs that comply with the

guidance set forth below and the amended regulatory text.
Docket No. RM99-2-000 -507-

612FERC Stats. & Regs. ¶ 32,541 at 33,754.

 We agree with those commenters that urge the Commission to reform its

transmission pricing policies to reflect new realities of the industry. For example, a

number of commenters point to the unbundling requirements of Order Nos. 888 and 889,

the vertical de-integration of generation and transmission for some utilities, the advent of

wholesale and retail competition in energy markets, entry into markets of a range of new

players, including independent generators and marketers, and other developments as a

signal that the Commission's traditional cost-of-service ratemaking practices for

transmission assets should be reevaluated. Some commenters suggest that the advent of

competitive power markets necessitates a more robust transmission network as well as

enhanced operating capabilities of the network, compared to the previous era of vertically

integrated utilities providing service in monopoly franchise areas. They argue that the

Commission's traditional transmission ratemaking practices are unlikely to support such a

robust transmission network and enhanced operating capabilities. 

To put our concerns about transmission pricing in perspective, the NOPR said that

"the Commission expects RTOs to reform transmission pricing, and in return we propose

to allow RTOs greater flexibility in designing pricing proposals." 612 The NOPR also

said that our willingness to provide flexibility in reviewing pricing proposals dates back

to the Transmission Pricing Policy Statement, issued by the Commission in 1994. In the
Docket No. RM99-2-000 -508-

Policy Statement, we identified five principles that transmission pricing proposals should

conform to, including the principle that pricing proposals should meet the traditional

revenue requirement. In order that this principle not undermine innovative pricing

proposals, the Policy Statement noted that non-conforming pricing proposals would be

considered, but that such proposals would have to satisfy additional factors, i.e., promote

competitive markets and produce greater overall consumer benefits. In the five years

since the Policy Statement was issued, we have approved five ISOs with innovative

transmission pricing, but otherwise have received few innovative transmission pricing

proposals. We believe that, as a general matter, sensible pricing reform that could

promote competition and efficiency in other contexts will achieve maximum benefits only

when applied on a regional, rather than a single-system basis. This is true because of the

inability of single systems to capture such efficiencies, but sensible pricing reform is one

of the efficiencies that will likely flow from RTOs. And while we do not think the

Policy Statement has been an impediment to transmission pricing innovation, we now

believe, based on the myriad comments we received, that the Commission should now

provide greater specificity on appropriate transmission pricing reforms by RTOs.

The rationale for providing greater specificity on transmission pricing for RTOs

and amending the regulatory text at this time is three-fold. First, we recognize that

transmission pricing issues are some of the most complex issues facing the industry. 

Second, a potential barrier to the development of RTOs, at least RTOs that span multiple
Docket No. RM99-2-000 -509-

transmission systems, is the difficulty that stakeholders have had reaching consensus on

transmission pricing. This is not surprising, given that transmission pricing reform to

accommodate regional needs and usage patterns can affect what customers pay for

transmission service and how transmission revenues are allocated among multiple owners

of transmission within a region. Third, we are concerned that as we move to greater

reliance on market forces, the incentives that market participants have to make efficient

operating and investment decisions for both generation and transmission facilities are

based in part on the price signals that flow from transmission pricing. That is,

transmission pricing is a key determinant of the efficient operation of energy, ancillary

service and balancing markets, and congestion management.

At the outset, we want to make clear that, contrary to the apprehensions of some

commenters, the Commission is not proposing to "bribe" transmission-owning utilities to

join an RTO. Rather, the Commission stated in the NOPR that it would consider

innovative pricing proposals because we believed then, and now believe more strongly,

that a reassessment of transmission pricing policy is warranted, given the fundamental

changes in industry structure that have already occurred as well as those which may flow

from the RTO Final Rule. In addition, as pointed out by Professor Joskow, delays in

RTO formation occasion costs because of more limited competition in generation

markets, and these costs may be avoided to the extent that the Commission considers

transmission pricing reforms. Furthermore, as discussed below, since the costs of
Docket No. RM99-2-000 -510-

transmission are a small portion of total electric costs, getting transmission pricing right

means that the industry will be able to capture significant net benefits from promoting

competitive generation markets.

While the NOPR did not propose specific rules on transmission pricing reform, we

believe it is now critical to provide further specificity to the industry. We recognize the

need to establish clear and specific requirements for RTO development, provide certainty

and clarity about our willingness to entertain transmission pricing reforms that are

appropriate for RTOs, and assure utilities that they will not be penalized for RTO

participation. To the extent consistent with ensuring that transmission rates are just,

reasonable, and not unduly discriminatory, we believe transmission pricing disincentives

to joining an RTO should be eliminated so that transmission-owning utilities will find

RTO participation to be a dynamic business opportunity. Utilities that join RTOs should

be accorded transmission pricing that reflects the financial risks of turning facilities over

to an RTO and that reflects other changes in the structure of the industry. Those risks

may increase or decrease in particular instances. At the same time, we wish to make clear

that the Commission is very concerned about potential impacts of market restructuring on

the customers in "low-cost" states, and the Commission therefore intends to monitor the

effects of RTO formation on such customers, specifically the potential for cost-shifting

effects of RTO pricing proposals.
Docket No. RM99-2-000 -511-

613See, e.g., Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591

(1944); Bluefield Water Works & Improvement Co. v. Public Service Commission of

West Virginia, 262 U.S. 679 (1923).

Traditional transmission pricing approaches reflect the industry structure as it

existed when Order No. 888 was issued: a vertically integrated industry where

transmission systems were designed primarily to meet the needs of local loads. Our

primary focus, both in terms of access and pricing was comparability; that is, all

transmission users should receive access under rates, terms and conditions comparable to

those the transmitting utility applies to itself to serve its own customers. RTOs reflect a

somewhat different approach, in which the transmission system must also be designed

and operated to meet the needs of regional markets. It is not unreasonable to expect that,

as the transmission system is restructured to meet these changing needs, significant

pricing reform may be needed as well. Indeed, since a properly developed RTO will be

designing methods to support regional congestion management and regional expansion,

transmission pricing reform is inevitable.

We caution that we do not view transmission pricing reform as a program designed

for the sole purpose of enhancing the revenues of transmission owners at the expense of

transmission customers. Nor are we abandoning the fundamental underpinnings of our

traditional transmission pricing policies, i.e., that transmission prices must reflect the

costs of providing the service. 613 While many aspects of transmission pricing reform are
Docket No. RM99-2-000 -512-

labeled incentive pricing, many are aimed at eliminating disincentives to the efficient use

and expansion of regional transmission grids to support emerging competition in

generating markets.

We view transmission pricing reform, not only as an important component of how

stand-alone transmission companies can become viable and efficient network businesses,

but also as an important means for transmission-owning utilities which maintain

ownership but cede control of their transmission assets to an RTO to capture the benefits

of more efficient system operation and additional grid investment. We believe that the 

opportunities for pricing reform identified in this Rule should have no effect on an RTO's

decision about how it will be structured. All RTOs, regardless of ownership structure,

are therefore eligible to propose transmission pricing reforms that suit their strategic and

economic objectives to the extent consistent with this Final Rule.

We also believe that the potential for any increase in transmission-related revenues

available to transmission providers that are efficient and responsive in meeting the needs

of their customers must be balanced by the potential for a decrease in profits if the

transmission provider does not meet those needs. Moreover, a properly developed RTO

can be expected to produce significant efficiencies, and we would expect that

transmission owners, transmission customers and generation market participants will

share in the economic benefits resulting from the efficient design and operation of the

RTO. 
Docket No. RM99-2-000 -513-

As the industry begins the collaborative process of establishing RTOs, it is

important that the Commission provide some certainty and specificity about the preferred

types of transmission pricing reforms, and some certainty and specificity about the types

of proposed transmission pricing reforms that appear more problematic. Accordingly, the

remainder of this section discusses eight specific transmission ratemaking topics: 

pancaked rates; reciprocal waiving of access charges between RTOs; use of single system

access charges; congestion pricing; service to transmission-owning utilities that do not

participate in an RTO; performance-based regulation; other RTO transmission ratemaking

reforms; and additional ratemaking issues.

1. Pancaked Rates

As described in the NOPR, the elimination of rate pancaking for large regions is a

central goal of the Commission's RTO policy, and has been a feature of all five ISOs the

Commission had approved. Rate pancaking occurs when a transmission customer is

charged separate access charges for each utility service territory the customer's contract

path crosses. The NOPR proposed that RTO tariffs not result in transmission customers

paying multiple access charges to recover capital costs over facilities that it controls. The

NOPR sought comments on the impact of the non-pancaked rate requirement on

voluntary RTO formation because of abrupt rate changes. It also sought comments on

how the regional configuration may relate to these potential rate changes.
Docket No. RM99-2-000 -514-

614See, e.g., NASUCA, PJM, LG&E, Industrial Consumers and WEPCO.

Comments

The overwhelming majority of the comments favor the proposed prohibition on

pancaked rates, 614 although some commenters express concern over cost shifting. Some

commenters, such as Minnesota Power, suggest that the cost shifting effect of nonpancaked rates would discourage voluntary RTO formation.

Some commenters suggest alternative approaches to the strict non-pancaked rate

described in the NOPR. For example, WPSC advocates the use of flow-based, distancesensitive rates as a replacement for pancaked rates. Allegheny argues that removing rate

pancaking can cause disruptive shifts in rates and revenue requirements which are solved

only temporarily with transitional rates. Allegheny proposes its form of locational

marginal pricing method to solve this problem. NSP favors non-pancaked rates but notes

that rates for the high-voltage system that differ from those for the low-voltage system

may be an effective long-term rate strategy. MidAmerican recommends that the

prohibition against rate pancaking be changed to allow transmission owners to charge a

home-zone rate based on local cost determination and a wide-area charge outside the

home area. MidAmerican argues that this approach would minimize cost shifting. The

pancaked rate prohibition would change to: "promote wide-area transmission rates with

due consideration to shifting of costs among transmission service providers and between
Docket No. RM99-2-000 -515-

615See New Smyrna Beach and Coalition of Alliance Users.

state and federal delivery rates. Finally, Williams recommends that the Commission also

consider other pricing methods such as those based on mileage or network usage and

market-based rates, where possible, because it considers cost of service rates inefficient

and unresponsive to the market.

A few commenters question an absolute prohibition against pancaked rates. AEP

and Florida Power Corp. warn that a strict prohibition against pancaked rates may, at

times, work against efficient solutions. There should not be a strict prohibition without

regard to size or locational factors. Florida Power Corp. argues that this approach is

consistent with the Commission's Transmission Pricing Policy Statement. Customers of

both AEP and Florida Power Corp. dispute this view. 615 Southern Company notes that

an absolute prohibition against pancaked rates may hurt retail customers whose rates are

supported by transmission revenue. Transmission owners should be assured in the final

rule that they will be able to recover their full revenue requirement in the face of any

pancaked rate prohibition. The Commission should, according to Southern Company,

also clarify that a prohibition against pancaked rates does not prevent the use of zonal or

other distance-sensitive rates. Desert STAR argues that a single region-wide rate may not

be appropriate in a large region with legitimate cost differences among companies, and

suggests that license plate rates may mitigate cost shifting but will not always eliminate it.
Docket No. RM99-2-000 -516-

616Section 35.34 (k)(1)(ii). However, see the discussion below regarding service

to transmission-owning utilities that do not participate in an RTO.

Commission Conclusion

In the NOPR, we described the elimination of rate pancaking as a central goal of

our RTO policy. After receiving comments on the subject, mostly in favor of the

proposed prohibition, we affirm that the RTO tariff must not result in transmission

customers paying multiple access charges to recover capital costs. 616

Except for transactions within the ISOs now in place, transmission customers are

faced with additional access charges for every utility border they cross. The distances

need not be great to be assessed two, three or more access charges for a single

transaction. This duplication can severely restrict the area in which generation can

economically be secured. A main reason that an RTO can expand the marketplace for

generation to a large region is that an RTO can implement non-pancaked rates for each

transaction. A wider area served by a single rate means more generation is economically

available to any customer which means greater competition for energy.

Some commenters warn that a blind adherence to non-pancaked rates can produce

inefficiencies in some circumstances. Some argue that large distances and special

conditions can add to transmission costs in a way not reflected in single system rates. 

They would leave open the option for distance-sensitive rates or completely new rate

innovations that may not fit the strict definition of a non-pancaked rate. We are sensitive
Docket No. RM99-2-000 -517-

617See, e.g., Sithe, WPSC, Minnesota Power, Ohio Commission, and Midwest ISO

Participants.

to some of these concerns, but we do not view a policy requiring non-pancaked rates as

posing the problems that some commenters describe. We take this opportunity to

reaffirm that we will continue to be receptive to distance-sensitive rates and other rate

features that can be supported.

2. Reciprocal Waiving of Access Charges Between RTOs

The elimination of pancaked rates within an RTO was intended to increase the

efficiency of trade in that region. The NOPR furthered that concept by encouraging

RTOs to agree among themselves to waive access charges on a reciprocal basis for

transactions that cross RTO borders. If accomplished, this would have the effect of

increasing effective trading areas. The NOPR sought comments on how the Commission

could facilitate reciprocal waivers of access charges, and whether there are other

impediments to inter-regional trade.

Comments

A majority of the commenters support the concept of a reciprocal waiver of access

charges to encourage inter-regional trade. 617 Of those who support waivers, some,

including Duke and SRP, specifically recommend that waivers be voluntary. Some

supporters of waiving access charges note that it is not just the pancaked charges that

inhibit inter-regional trade but also variations in business practices and procedures
Docket No. RM99-2-000 -518-

618See, e.g., Ontario Power and Oregon Office.

between RTOs. These commenters 618 recommend that the Commission ensure that such

incompatibilities not be allowed to hamper trade between RTO regions.

Several commenters, both supporting and opposed to waiver of access charges,

warn that the waivers proposed in the NOPR can cause cost shifting. Duke argues that

cost shifting can be remedied by the structure of the rate. DOE and First Energy also

express concerns about cost shifting. Southern Company generally opposes waivers of

access charges unless transmission owners' revenues are protected.

Some commenters oppose waiving access charges between RTOs for reasons other

than cost shifting concerns. South Carolina Authority claims that reciprocal agreements

between RTOs waiving access charges are discriminatory and that independent

monitoring groups would be needed to prevent gaming of reciprocity agreements. CP&L

argues that waivers create a bias to sell outside of the RTO. Tri-State proposes the use of

distance-sensitive export pricing mechanisms instead of waivers.

PP&L Companies claim that inter-regional trade solutions should be arrived at

through a collaborative effort of stakeholders. NECPUC and Desert STAR argue that the

Commission should grant deference to participants' solutions for inter-regional trade. 

Florida Commission argues that the Commission should wait until intra-regional trade

barriers are dismantled before dealing with inter-regional trade.
Docket No. RM99-2-000 -519-

Commission Conclusion

We asked in the NOPR for comments on the policy of allowing RTOs to reach

reciprocal agreements to waive access charges for transmission that crosses an RTO

border. Most commenters supported the approval of such waivers and some asked the

Commission to further support inter-regional trade by requiring uniform practices and

procedures among RTOs. Some commenters maintain that incompatible or varying

procedures between RTOs can be as dampening to inter-regional trade as multiple rates.

We will continue to encourage reciprocal waivers of access charges between

RTOs as long as they are reasonable in terms of cost recovery, cost shifting, efficiency,

and discrimination. We also encourage terms and procedures that are compatible from

region to region to the extent appropriate. Accordingly, we have added an RTO function

to integrate reliability and market interface practices with other regions, as discussed

above.

3. Uniform Access Charges

Each ISO approved by the Commission has struggled with the problem of cost

shifting among the various individual transmission owners that make up the ISO. A

single access rate would mean that the customers of low-cost transmission providers

would see a rate increase and high-cost transmission providers would be concerned about

not meeting their revenue requirements. The potential for cost shifting has been a
Docket No. RM99-2-000 -520-

619Consider that registering a car in one state, paying that state's fees, and

obtaining a license plate from that state, allows that car to be driven on the roads and

highways of all other states. 

620FERC Stats. & Regs. ¶ 32,541 at 33,754.

621See, e.g., Montana Commission, Oglethorpe, Tri-State, FirstEnergy, Alliance

Companies, AEP and DOE.

622See, e.g., Allegheny, Industrial Consumers, Northwest Council, APS, Desert

(continued...)

stumbling block for several regions seeking to establish regional transmission

organizations.

The Commission has allowed a flexible approach to this problem, and in each ISO

approved by the Commission to date the solution has been to adopt a "license plate" rate

for a transitional period of five to ten years before moving to a single uniform access

charge. A license plate rate provides access to the regional transmission system at a

single rate although that rate may vary based on where the customer is located. 619 The

NOPR proposed to continue to employ a flexible approach, including the use of license

plate rates. The NOPR requested comments on whether the license plate approach is

appropriate for the long term. 620

Comments

A clear majority of commenters favors the use of license plate rates in general,

with a nearly even split between those that would allow license plate rates only for a

transitional period 621 and those that would allow them as a permanent feature. 622 Of
Docket No. RM99-2-000 -521-

622(...continued)

STAR and SPP.

623See, e.g., Kentucky Commission, Gainesville, Big Rivers, Puget and Ontario

Power.

624See, e.g., East Kentucky and PJM.

the approximately 64 commenters who addressed this subject, only about nine were

clearly opposed to license plate rates for either the long term or for a transitional period. 

And several commenters advocate the use of license plate rates as a general concept but

did not address directly the NOPR's question concerning their long-term use. 623

Several commenters argued that the use of license plate rates should be for a 

transition period roughly coincident with the phase-in of retail competition. For example,

Duke argues that license plate rates avoid cost-shifting, and will therefore make it easier

for companies to collect their retail revenue requirements in jurisdictions without retail

competition, where state regulators may disallow higher transmission rates.

Commenters that support license plate rates as a long-term solution argue that

license plate rates are an aid to RTO formation. 624 SoCal Edison claims that license

plate rates avoid cost shifts, are administratively more efficient, provide a basis for

efficient transmission operation, and provide incentives for system expansion. SoCal

Edison favors their use in the long term.

Of those opposed to license plate rates in general, some suggest a different pricing

methodology. CMUA prefers an integrated, two-part rate. The first part of the rate
Docket No. RM99-2-000 -522-

reflects the revenue requirement of the overall RTO (principally above 200 kV) and the

second part reflects the local systems to the extent used. CMUA argues that license plate

rates do not follow the rules of cost causation, do not promote needed enhancements and

do not promote comparability in rates. Minnesota Power recommends a two-part rate

with a demand component to collect fixed costs and a variable component for losses. 

WPSC advocates the use of flow-based, distance-sensitive rates rather than license plate

rates. APPA claims that license plate rates do not go far enough. A four part approach is

suggested in their place: assure recovery of revenue requirement; honor existing

contracts and phase in regional rates; sub-functionalize the grid by voltage; and, once

trusted RTOs are in place, allow congestion rates above embedded costs and noncongestion rates below, all subject to a revenue requirement true-up. RECA recommends

that zones for transmission access charges be formed based on cost and other differences,

not on existing service areas. SMUD claims that Cal ISO’s license plate rate encourages

inefficient operation.

Some commenters provide more general reactions to the cost shifting problem. 

Wyoming Commission recommends that the Commission not codify a specific approach

to license plate rates and other measures with cost-shifting ramifications but rather defer

to regional and state processes to establish guidelines within a region. PSNM is

concerned about the impact of the loss of existing contracts on its license plate rate

calculation. Manitoba Board is concerned about shifting costs to low-cost, transmission-
Docket No. RM99-2-000 -523-

dependent areas. Platte River does not want its low costs averaged with higher cost

systems. United Illuminating encourages the Commission to continue its flexibility in

permitting different approaches in the recovery of sunk costs. Aluminum Companies

argues that the Commission needs to offer more guidance on cost shifting and that rate

increases due to cost shifting should be constrained to the benefits involved. Further, cost

shifts should not be allowed unless competition is fostered.

Commission Conclusion

We conclude that the Commission should continue to provide flexibility with

respect to RTO proposals for allocation of fixed transmission cost recovery. The

Commission will permit RTO proposals to use license plate rates, as defined above, for

several reasons. First, commenters overwhelmingly support the use of license plate rates,

and demonstrated convincingly that problems associated with cost-shifting are not easily

resolved by means other than the use of license plate rates. Second, the Commission is

concerned that the potential for cost-shifting could act as an impediment to RTO

formation, thereby denying all stakeholders the benefits that come from RTO

membership.

Moreover, although license plate rates are not necessarily an ideal method for

fixed cost recovery, we note that all ISOs have sought approval from the Commission for

license plate rates, at least during their startup phase. No commenter has provided

convincing evidence that the use of license plate rates by existing ISOs produces
Docket No. RM99-2-000 -524-

significant harms, although several commenters suggest various rate designs, including

multi-part rates, as alternatives to license plate rates.

Although commenters overwhelmingly support the use of license plate rates, they

are split on whether such rates should be used only for a transitional period, or whether

the Commission should allow them as a permanent feature. This is a difficult issue. On

the one hand, we are reluctant to require RTOs to suspend use of license plate rates after

some arbitrary date certain at which time they will be required to transition to single

system access rates; on the other hand, we are reluctant to announce generically that

license plate rates may be a permanent feature of an RTO. Furthermore, the use of

license plate rates could depend on idiosyncratic facts, e.g., the geographic makeup of the

RTO, or the transmission cost differences in various subregions of the RTO. 

We therefore believe that it is appropriate to allow RTOs to propose the use of

license plate rates for a fixed term of the RTO's choosing. However, RTOs that propose

the use of license plate rates must make clear how transmission expansion will be priced,

that is, whether license plate rates or some other mechanism will be applied to the cost of

new transmission facilities, and how such pricing affects incentives for efficient

expansion. In addition, we will require that before the end of the fixed term, the RTO

must complete an evaluation of fixed cost recovery policies based on the factual situation

of the particular RTO, and file with the Commission its recommendations on any changes

that should be instituted. We emphasize that we are not requiring that the RTO continue
Docket No. RM99-2-000 -525-

625FERC Stats. and Regs. ¶ 32,541 at 33,742.

or abandon the use of license plate rates at that time, but we will require the RTO to

justify its choice to continue or discontinue using license plate rates, or otherwise change

the method for fixed cost recovery. We believe that this approach provides participants

in RTOs significant flexibility, and is consistent with the principles articulated in the

open architecture requirement for RTOs.

4. Congestion Pricing

Congestion pricing and congestion management are closely related. Comments on

these issues have been treated jointly, and are summarized above in the discussion of

congestion management.

Commission Conclusion

With respect to congestion pricing, the Commission emphasized that it intends to

be flexible in reviewing pricing innovations, and sought comments on what specific

requirements, if any, best suited the Commission's RTO goals. A number of commenters

agreed with the Commission's conclusion in the NOPR that "markets that are based on

locational marginal pricing and financial rights for transmission provide a sound

framework for efficient congestion management." 625

We reemphasize the basic principles for congestion pricing articulated in the

NOPR, i.e., that proposals should "ensure that the generators that are dispatched in the
Docket No. RM99-2-000 -526-

626Id. at 33,754-55.

627Id. at 33,759.

presence of transmission constraints must be those that can serve system loads at least

cost, and limited transmission capacity should be used by market participants that value

that use most highly." 626

We recognize that congestion pricing, especially when complex problems

associated with parallel path flows are addressed, is in its infancy. Rather than prescribe

a specific method, we encourage experimentation with reasonable congestion

management techniques. We would expect that such experiments be consistent with the

open architecture requirements of the rule, and that information from such experiments be

made widely available to all interested parties, so that other RTOs can learn from each

others' experience.

5. Service to Transmission-Owning Utilities That Do Not

Participate in an RTO

The Commission asked commenters to discuss the treatment by an RTO of a nonparticipating transmission owner in a region if the transmission owner does not

participate in its region’s RTO. 627 For example, we asked whether it would be

appropriate to allow RTO members to provide transmission service at individual system

rates to non-participating transmission owners located in the RTO region thereby denying

non-participants the benefits of non-pancaked transmission rates.
Docket No. RM99-2-000 -527-

628Montana-Dakota, Allegheny, PG&E, Tri-State, PNGC and Empire District.

Comments

Of those commenters that generally support the proposed strategy, most argue that

non-participants should not enjoy the benefits of non-pancaked rates. 628 PG&E submits

that the reasoning the Commission applied in Order No. 888 applies here (i.e., in Order

No. 888, the Commission rejected the claim that a reciprocity requirement required

explicit Commission jurisdiction over the transmission customer finding that, as a matter

of fairness, a public utility providing open access through a non-discriminatory tariff

deserved the right to obtain comparable access over the transmission systems of its

customers). Empire District is particularly concerned that utilities on the border of an

RTO may receive many advantages of the RTO without accepting any of the burdens of

participation, yet at the same time make it more difficult for competitors to service its

load by staying out of the RTO.

Other commenters are conditional in their support. For example, Oneok wants the

Commission to draw a hard line on non-participation and be willing to employ negative

incentives; however, Oneok points out that denial of non-pancaked rates will be more

costly to marketers and consumers. South Carolina Authority suggests that the

Commission consider the extent to which the transmission owner is actually able to

participate in an RTO before permitting denial of RTO service under non-pancaked rates. 
Docket No. RM99-2-000 -528-

In the case of publicly owned utilities, there may be restrictions in the enabling act or

charter, the applicable state constitution or the utility's bond covenant that effectively

prohibit it from participating in a particular RTO. This would also apply if the RTO is

not the product of the "region's RTO" involving all stakeholders in the designated region

but is a business entity designed to advance the financial objectives of particular

sponsors. Similarly, SPRA argues that, in the event that it is unable to immediately join

an RTO, the RTO should recognize that SPRA has an OATT that provides for

comparable treatment to the RTO. And New Smyrna Beach states that, although denial

of non-pancaked rates to nonparticipants has merit, it may be a moot issue in Florida

where FP&L's transmission is so extensive that pancaked rates would be a more costly

alternative for marketers and consumers of electricity.

 Other commenters believe the proposal is a flawed concept or otherwise oppose

it. Avista and PPC argue that it is not appropriate to allow an RTO to provide

transmission service at individual system rates to non-participating transmission owners

as such a policy would deny them the benefits of non-pancaked rates and defeat the

central goal of its proposal. Metropolitan concurs that non-participating transmission

owners should share in the benefits of non-pancaked rates. Southern Company and

CP&L claim that the Commission cannot punish utilities that find it in the best interests

of their stakeholders not to join an RTO. SMUD believes that RTOs must provide

nondiscriminatory access to transmission it controls at cost-based rates to all customers,
Docket No. RM99-2-000 -529-

since they contribute to the RTO’s cost recovery. SMUD argues that the Commission,

through its NOPR has, in essence, found that pancaked rates are not just and reasonable

and that they should be corrected; thus, the Commission cannot allow an RTO to charge

pancaked rates in violation of the FPA section 205 prohibition on unjust or unreasonable

rates.

Snohomish, Turlock, Big Rivers and Dairyland all make similar arguments–

charging higher pancaked rates to utilities that do not participate in the RTO is patently

unfair, violates the Commission’s duty to eliminate discriminatory rates, and would

penalize consumers of customer-owned utilities who have no practicable choice about

whether to participate in the RTO. Dairyland says that this could open the door to

creation of RTOs that purposely do not accommodate non-public utilities. SRP posits

that imposition of pancaked rates on non-participants in an RTO would effectively turn

the Commission's stated policy goal of voluntary participation into an RTO mandate

inviting years of litigation. 

Two state commissions question the effectiveness of pancaked rate sanctions

against non-participants. Indiana Commission contends that a recalcitrant utility may not

perceive pancaked rates as detrimental and may not feel compelled to join an RTO. 

Illinois Commission feels that imposition of penalties involving restricted access to RTO

transmission rates would either be self-defeating for the Commission or detrimental to the

electricity consumers of the affected utility. In its view, the solution to this conundrum is
Docket No. RM99-2-000 -530-

629824 F.2d 981, 1024 (D.C. Cir. 1987).

630574 F.2d 610, 620 (D.C. Cir. 1978).

for the Commission to abandon its unworkable voluntary approach to RTO participation,

and utilize its authority under FPA sections 205 and 206 and examine its authority under

FPA sections 202(a), 211 and 212 to mandate participation. However, Nevada

Commission submits that the Commission must ensure that a transmission-owning utility

that refuses to join an RTO should not be allowed to derive any economic benefit from

the existence of RTOs.

ISO commenters have diverse views on this issue. Desert STAR argues that a

blanket ban on prohibiting a party that does not join an RTO from deriving any benefit

from the RTO whatsoever may be too broad an approach. NYPP, citing Associated Gas

Distributors v. FERC 629 and Richmond Power & Light v. FERC 630 for the proposition

that the Commission cannot achieve indirectly what it cannot do directly, submit that the

Commission cannot impose any coercive measure on or deny benefits to utilities that do

not participate in an RTO. In addition, NY ISO argues that previously approved ISO's

transmission-owning members should be eligible for whatever RTO participation

incentives and benefits are ultimately adopted in this proceeding. On the other hand,

PJM/NEPOOL Customers support denial of non-pancaked transmission rates to

nonparticipants.
Docket No. RM99-2-000 -531-

Canadian entities generally oppose imposition of pancaked rates against nonparticipants. Canada DNR contends that a decision not to participate in an international

RTO by a Canadian jurisdiction should not place entities in that jurisdiction engaged in

trade with the U.S. at a disadvantage relative to U.S. RTO participants. BC Hydro

concurs that the decision to join an RTO should not be made a prerequisite for

participation of Canadian provincial utilities or their affiliates to participate in the U.S.

electricity market. CEA observes, however, that Canadian utilities see access to the U.S.

market as a significant business opportunity that requires a transparent and open bulk

transmission system operating in both directions. Grand Council et al. submits, however, 

that applying no penalties or incentives to Canadian utilities, while giving them unfettered

access to U.S. markets without being subject to corresponding obligations, is inconsistent

with the RTO concept. And H.Q. Energy Services submits that, if the Commission

decides not to require RTO participation, it should strongly encourage voluntary

participation by denying certain benefits such as the use of the system-wide tariff to

nonparticipants.

Commission Conclusion

Regarding the question raised in the NOPR about whether a non-participating

transmission owner in an RTO region should receive all the benefits of the RTO in its

region, we share the concerns of most commenters that transmitting utilities may receive

the benefits of an RTO in its region without accepting any of the burdens of participation
Docket No. RM99-2-000 -532-

in the RTO. Accordingly, where a transmission customer of an RTO or the customer's

affiliate owns, controls or operates transmission in the RTO's region, and is not

participating in that particular RTO, we intend to permit that RTO to propose rates,

terms, and conditions of transmission service that recognize the participatory status of the

customer.

We do not intend that every such proposal will necessarily be accepted by the

Commission. Each RTO must justify any proposal on a case-by-case basis. The proposal

should recognize the various situations of non-participating transmission owners. As

pointed out by commenters, some transmission owners may face legal obstacles to

participation that may need to be taken into account in the proposal.

It is not our intent to permit an RTO to apply such a proposal to a nonparticipating transmission owner in another region. As discussed above, Empire District

expressed concern about whether this provision would apply to a non-participating owner

"on the border" of an RTO. We would permit an RTO to argue that the non-participant

should be part of its RTO region based on engineering or other objective criteria. 

An RTO will provide several benefits for parties in the region, including

elimination of individual system rates. We asked in the NOPR whether it would "be

appropriate to allow RTO members to provide transmission service at individual system

rates to non-participating transmission owners located in the RTO region." (emphasis
Docket No. RM99-2-000 -533-

631 FERC Stats. & Regs. ¶ 32,541 at 33,759.

632Id. at 33,755.

added) 631 SMUD argues that the Commission in its NOPR has found, in effect, that

individual system rates are not just and reasonable and so cannot allow transmissionowning utilities in an RTO to charge individual system rates.

SMUD is incorrect. We have not made a generic determination that individual

system rates are not just and reasonable in an RTO region. A non-participating public

utility transmission owner in an RTO region may itself file a single company rate and

argue that it is just and reasonable for use by its neighbors who join the RTO.

Instead of making a generic determination about these matters, we will permit an

RTO and its transmission-owning public utility members to make the case that it is just

and reasonable to charge individual system rates to a transmission customer who is a nonparticipating transmission owner in its RTO region. We will decide each RTO proposal

on its merits.

6. Performance-Based Rate Regulation

The NOPR suggested that, once RTOs are formed, performance based regulation

(PBR) can facilitate good grid operation. 632 We noted that PBR can incorporate

price/revenue caps, price incentives, or performance standards. The NOPR sought

comments on how PBR should be applied to an RTO and whether it should be voluntary.

Comments
Docket No. RM99-2-000 -534-

633See, e.g., EPSA, PJM, Los Angeles, Georgia Transmission, Illinois

Commission, PacifiCorp and Desert STAR.

634See, e.g., Florida Power Corp., MidAmerican, Tri-State, FirstEnergy, Alliance

Companies, Duke and PGE.

The vast majority of commenters favor PBR of some form to promote efficient

operations by RTOs. 633 And most commenters that favor PBR specifically state that

PBR should be voluntary for RTO participants. 634

Professor Joskow recommends that the Commission promote the view that PBR

will eventually be required. He suggests that there is sufficient experience with PBR,

such as in England and Wales. He argues that PBR should be based on a standard price

cap that focuses not only on direct transmission service costs, but also focuses on the cost

of congestion management, losses, ancillary services, reactive power, and connection of

new generators. EEI notes that a price cap, based on a reasonable ROE revenue

requirement, is the most widely used method. EEI argues that price caps reduce rate

cases, give an incentive to improve productivity, and share productivity savings with

customers. Brattle Group does not propose a specific PBR scheme but says that, at this

point, approval should be case-by-case. Care should be taken that a PBR is not based on

a single element, causing distortions elsewhere.

Other supporters have specific comments regarding the implementation of PBR. 

Entergy recommends that the Commission provide more specific guidance on the use of

PBR. DOE warns that PBR should not be allowed to prevent a PMA that is a part of an
Docket No. RM99-2-000 -535-

RTO to under-recover its revenue requirement. New Smyrna Beach and Oneok only

support PBR if there is a downside as well as an upside potential associated with

transmission performance. Allegheny states that the Commission must settle on a

definition of performance, the performance criterion should be economic reliability, the

owner must have an opportunity to recover investment, the Commission should recognize

that some aspects of performance will be outside of the control of the RTO, and the

particular PBR rate calculation should be considered on a case-by-case basis.

A number of commenters recommend that PBR not be instituted immediately upon

the formation of the RTO. California Board, Trans-Elect, and WPSC maintain that time

is needed to establish base year benchmarks. PG&E and APPA say that PBR should be

set aside until the RTO is up and functioning and Arkansas Consumers and Wyoming

Commission argue that the RTO should first demonstrate that it can and will provide

reliable and non-discriminatory service before PBR is established.

At least eight commenters were opposed to PBR for RTOs as a Commission

policy. Industrial Consumers, Williams, and CMUA do not think that PBR can be

effective in promoting efficiency in the operation of RTOs. Salomon Smith Barney and

East Texas Cooperatives believe that RTOs will be able to game the system and take

advantage of PBR. PJM/NEPOOL Customers, Lincoln, and NASUCA argue that PBR

should not be allowed for RTOs because they are unnecessary. NASUCA is also

skeptical of PBR for RTOs because some areas where performance is important are not
Docket No. RM99-2-000 -536-

635See, e.g., APPA, Minnesota Power and CMUA.

under the RTO's control. NJBUS argues that PBR will not put a stop to transmission

discrimination.

NEPCO et al. disagree with those commenters who oppose PBR. 635 PBR is

effective, as shown in the United Kingdom, and they are not "bribes" given freely to

transmission owners. Enron/APX/Coral Power does not agree with NASUCA and

California Board that there is not enough experience on which to base PBR. According

to Enron/APX/Coral Power, there is a large amount of experience in regulating

transmission plus a lot of experience with the ramifications of EPAct.

A few additional commenters neither strongly support nor oppose PBR, but offer

specific comments about PBR use. Project Groups recommends that the Commission

construct a way to de-couple revenues from transmission rates so that efficient

transmission service rather than total throughput determines revenue. Florida

Commission states that questions as to the advisability and particulars of a PBR

mechanism should be left to regional solutions that have the endorsement of the state

regulatory bodies. Big Rivers states that PBR is inappropriate for cooperatives and public

power utilities. WEPCO believes that RTOs should be not-for-profit and that PBR

should be available only to the for-profit transmission owner. Metropolitan is concerned
Docket No. RM99-2-000 -537-

636See, e.g., Paul Joskow and Richard Schmalensee, Incentive Regulation for

Electric Utilities, Yale Journal of Regulation, Vol. 4 at 1-49 (1986); Sanford Berg and

Rajiv Sharma, Techniques for Assessing Firm Efficiency, University of Florida Public

Utilities Research Center Working Paper (June 1999); Peter Navarro, Seven Basic Rules

for the PBR Regulator, Electricity Journal at 24-30 (April 1996); G. Alan Comnes,

Steven Stoft, et al., Six Useful Observations for Designers of PBR Plans, Electricity

Journal at 16-23 (April 1996); Lorenzo Brown and Ingo Vogelsang, Incentive Regulation:

a Research Report, Federal Energy Regulatory Commission, Office of Economic Policy,

Technical Report 89-3 (1989); and Jean-Jacques Laffont and Jean Tirole, A Theory of

Incentives in Procurement and Regulation, MIT Press (1993).

637The Policy Statement articulated five regulatory standards: (1) incentive

ratemaking must be prospective; (2) participation must be voluntary; (3) incentive

mechanisms must be understood by all parties; (4) benefits to consumers must be

quantifiable; and 5) quality of service must be maintained.

that PBR might cause RTOs to neglect needed expansions and upgrades and jeopardize

reliability.

Commission Conclusion

At the outset, we think it is important to emphasize that PBR is far from a new

concept. Over the last 10 to 20 years, a significant amount of research, primarily by

economists, has been done regarding the conceptual basis of, and efficient designs for,

PBR. 636 This research addresses its use in the electric utility industry as well as other

regulated industries. It is also important to note that the Commission has been receptive

to PBR proposals, at least since issuance of the Policy Statement on Incentive Regulation

in October 1992. In that Policy Statement, we provided guidance to public utilities as

well as natural gas and oil pipelines considering proposing some form of PBR. 637

Although the Policy Statement invited public utilities to develop and file incentive
Docket No. RM99-2-000 -538-

638We note that PBR mechanisms have been widely used by state regulators and

the FCC as applied to the U.S. telecommunications industry. See, e.g., John Kwoka,

Implementing Price Caps in Telecommunications, Journal of Policy Analysis and

Management, Vol 12, No 4 at 726-52 (1993).

regulation proposals, the Commission has not received any proposals from public

utilities. 638

The Commission's current interest in PBR stems from the proposition that PBR

will allow the Commission to rely on market-like forces, to the maximum extent possible,

to create incentives for RTOs to efficiently operate and invest in the transmission system. 

This does not mean that we expect that transmission services will be provided in

competitive markets any time soon, or at all. We recognize that transmission service will

retain most or perhaps all of the characteristics of a natural monopoly for the foreseeable

future, and that some type of explicit price regulation will therefore be required to prevent

monopoly abuse. But we believe that PBR, especially if accompanied by explicit and

well-designed incentives, may provide significant benefits over traditional forms of costof-service regulation. We believe this view of PBR is entirely consistent with other

initiatives taken by the Commission, such as Order Nos. 888 and 889, to promote

competitive power markets, and given the impracticality of competitive transmission

markets, to rely on market-like forces to the maximum extent possible.

Before providing further specificity on PBR, it is useful to restate the overarching

concerns of commenters. A large number of commenters support the use of PBR, and
Docket No. RM99-2-000 -539-

639 Professor Joskow at ES-iv.

many of them, as discussed above, believe that PBR and other forms of incentive

regulation will significantly enhance the incentives RTOs have to make efficient

operating and investment decisions. For example, Professor Joskow notes:

It is very important for the Commission to adopt regulatory mechanisms

that provide transmission owners and operators with powerful economic

incentives to operate transmission networks efficiently and to invest the

resources necessary to expand their capabilities efficiently. These

incentives should be an integral component of a performance-based

regulatory (PBR) framework for the regulation of transmission rates that

rewards transmission owners for achieving these objectives and penalizes

them for failing to do so. [639]

On the other hand, a somewhat smaller group of commenters, mostly transmission

customers, oppose the use of PBR. They express doubts about whether PBR will provide

good incentives for RTOs to operate and invest efficiently. They are also concerned that

PBR design is so difficult that RTOs will easily game the system, which will likely result

in higher revenues for RTOs and therefore higher prices for transmission services for all

transmission customers.

Commenters describe a wide array of PBR mechanisms, including some relatively

unsophisticated proposals and others which are analytically complex. For example, a

number of commenters have proposed that the Commission entertain transmission rate

moratoriums, e.g., where transmission rates are locked into their current levels for a

limited period of years. To the extent the transmission provider can achieve any
Docket No. RM99-2-000 -540-

transmission costs savings, these would be retained by the transmission provider. In this

sense, it falls within the concept of PBR.

It is argued that this rate treatment may promote the establishment of independent

transmission companies because it provides the certain revenue stream that is needed to

obtain financing for the purchase of transmission systems from existing owners. It is also

argued that this approach is analogous to a hold harmless commitment for existing

customers which may simplify the efforts of those state regulators who value transmission

rate certainty during their conversion to retail choice. This approach would also reduce

litigation at the Commission during the moratorium. Finally, if the rate level selected

takes into account the existing transmission component of bundled retail power rates, it

addresses the concern expressed by many that one deterrent to participation in RTOs is

the fear and uncertainty that transferring retail transmission services from state to

Commission jurisdiction leads to reduced revenues. 

Other commenters suggest that the essence of PBR is to set cost and performance

benchmarks and then reward or penalize an RTO based on performance relative to those

targets. Clearly, such an approach presents significant analytical challenges. Ideally, an

RTO's cost and operating performance can be compared with other, similar entities. One

benefit of setting such targets is that it overcomes the asymmetric information problem,

i.e., a transmission service provider will usually have better knowledge of the potential
Docket No. RM99-2-000 -541-

640We note that there have been some early attempts to compare the relative cost

and performance of ISOs in the U.S. See, e.g., California ISO, "A Comparative Analysis

of Operating ISOs in the United States" (Oct. 15, 1998).

efficiency gains than will regulators. Benchmarking performance helps reduce the

information imbalance. 640

We have carefully considered all of the comments about PBR. We conclude that

the Commission should encourage RTOs to consider use of PBR, although we recognize

the difficult analytical challenges that RTOs will face. To facilitate such consideration,

we are providing additional specificity on PBR. We address several threshold procedural

issues, and articulate additional design principles that should provide a framework for

RTO consideration of PBR.

A first threshold issue is whether the Commission should require that RTOs use

PBR or whether it should be voluntary. There is almost no support for making PBR

mandatory, and we therefore will not require RTO filings to include PBR proposals,

although we encourage such proposals.

A second threshold issue is what types of RTOs are eligible for PBR. As

discussed above, some commenters argue that PBR is not appropriate for cooperativelyowned and publicly-owned transmission owning utilities. Similarly, other commenters

argue that PBR is appropriate only for profit-making RTOs. We conclude that, although

the application of PBR may vary according to the type of RTO, there is no reason to limit
Docket No. RM99-2-000 -542-

641For example, PJM states that it can facilitate the application of PBRs to its

transmission owners by using the stakeholder process to set the performance parameters

and, once the parameters are in place, to independently evaluate the transmission owners'

performance and apply the PBR. 

the applicability of PBR to certain members or types of RTOs. The Commission

welcomes RTO filings with PBR proposals from any source. For example, in the context

of an ISO or a tiered ISO/transco that has been described by some commenters, the

activities that contribute to performance may be shared between the RTO and the

transmission owners. This does not invalidate the use of PBRs; however, the RTO design

would simply ensure that the rewards and penalties associated with activities performed

by transmission owners flow through to the owners to achieve the desired result. 641 In

addition, we see no impediment to the use of PBR to provide incentives for efficient

behavior by non-profit RTOs. We note that some existing ISOs have in place

performance incentives for some of their managers, and such an incentive scheme may

have application for RTOs which do not own the transmission assets they control.

A third threshold issue is how PBR proposals will be formulated and when they

will be filed. The Commission recognizes that PBR design involves highly complicated

issues, and that there is the possibility that a bad PBR proposal can result in lower quality

transmission service, at higher costs, compared with service that might prevail under

traditional ratemaking practices. One key element in the process of designing a PBR

proposal would be to ensure adequate input from all stakeholders. We believe that the
Docket No. RM99-2-000 -543-

642As noted infra, this is one of the pricing reforms that will be available for a

defined transition period during which RTOs are being established.

best PBR designs will emerge when all stakeholders have an opportunity for input, even

if a filed PBR design does not represent full consensus. We therefore conclude that

RTOs that wish to implement PBR need not necessarily file the PBR proposal at the time

the RTO makes its compliance filing if more time is needed to negotiate among

stakeholders the details of a well-designed PBR. Some commenters suggest that an

additional consideration in allowing delayed filings of PBR is the need to evaluate

operating experience of the RTO before appropriate benchmark measures for PBR can be

developed.

The Commission also believes it is appropriate to provide additional specificity on

what constitutes good PBR design. We continue to endorse the regulatory standards

included in the Incentive Regulation Policy Statement, described above. And we note

that in some regions, certain types of PBR mechanisms may be better suited than others. 

For example, where there are already state-imposed rate moratoriums, continuation of

such programs after RTO formation may be an appropriate PBR approach. Alternatively,

a transmission rate moratorium based on the existing rate level may be appropriate for a

transitional period during RTO formation. 642 Similarly, in an area that has experience

with a particular performance-based mechanism, extension and perhaps refinement of

such a program after RTO formation may be the most appropriate policy.
Docket No. RM99-2-000 -544-

643We note that a PBR system that uses a variant of price cap regulation of the

National Grid Company has been in use for nine years in England and Wales. More

recently, the price cap has been combined with a separate incentive mechanism that

focused on reducing congestion on the grid. Since this is the longest-running PBR

targeted to grid operations, we encourage any RTO that intends to propose PBR to

examine the strengths and weaknesses of the British approach.

We encourage RTOs to file fully documented PBR proposals that are consistent

with the amended regulatory text. PBR proposals should include a detailed explanation

of how the PBR mechanism will work, as well as all of the information necessary for the

Commission and all market participants to evaluate the benefits and costs of

implementing the PBR mechanism. 

Based on the comments we received in this docket, as well as our understanding of

international 643 and state experience with incentive regulation, we expand on the

considerations for PBR addressed in the amended regulatory text by offering the

following additional principles for RTOs to consider in designing PBR proposals. 

PBR should not be applied piecemeal. To the extent possible, PBR programs

should focus on the entire operation of the RTO, rather than smaller parts of the

operation. Commenters caution that PBR programs that focus narrowly, e.g., only on the

cost aspects of RTO operations, may result in inattention by the RTO to the quality of

service offered. Similarly, a focus on only one aspect of costs, e.g., short-run costs, may

result in reduced costs for that single aspect, but higher total costs for the RTO.
Docket No. RM99-2-000 -545-

PBR should encompass both rewards and penalties. Although some PBR designs

employ either rewards or penalties, but not both, most commenters suggest, and the

Commission agrees, that the most effective and most fair designs will likely encompass

both. One rationale for this is that it is not always clear what incentives an RTO will

respond to, and therefore the prospect of higher revenues as well as the threat of lower

revenues may induce an RTO to provide the best possible performance. An additional

rationale is that under the FPA, the Commission is required to set rates for transmission

service at just and reasonable levels. To the extent that rates may vary within a

range–both up and down–as a function of RTO performance, this statutory requirement

may be better satisfied.

PBR rewards and penalties should create incentives for an RTO to make efficient

operating and investment decisions, and should not compromise system reliability. A

significant concern in any PBR application is the possibility that incentives will distort

RTO decisionmaking. For example, commenters caution that an RTO may manage

congestion through a combination of generation redispatch and investment in

transmission infrastructure, and that poorly designed PBR mechanisms could distort RTO

decision-making toward the most profitable, rather than the least-cost, solution, or toward

an approach that inappropriately reduces system reliability. An additional concern is that

PBR mechanisms may create bias with respect to the trade-off between investment in
Docket No. RM99-2-000 -546-

generation and transmission, or in siting generation and transmission facilities in the most

efficient places on the grid.

The benefits of PBR should be shared between the RTO and its customers. The

Commission believes that as a matter of fairness, the efficiency gains occasioned by PBR

should be shared. This will involve difficult analytical issues, including identifying

efficiency gains, measuring them, and determining the effect of sharing such gains on the

strength of the incentives faced by the RTO. The Commission does not believe it would

be appropriate to specify the exact distribution of such gains, as such a decision is better

left to negotiation by all stakeholders.

To the extent possible, the rewards and penalties should be prescribed in advance

based on known and measurable benchmarks. PBR designs involve an inevitable tradeoff between simplicity and administrative ease on the one hand, and the potential benefits

of the program. Although relatively simple designs such as rate freezes provide

significant incentives for an RTO to reduce its costs, they produce relatively limited

incentives to maintain reliability, promote service quality, or manage congestion. PBR

mechanisms that benchmark an RTO's performance, either to its own historical 

performance, to industry performance indices, to some normative goal, or to a

combination of these, may be designed to provide incentives for more efficient operation

and investment decision-making. The Commission recognizes that designing

sophisticated PBR mechanisms will be a significant challenge for RTOs already
Docket No. RM99-2-000 -547-

644Alternatively, the RTO could seek guidance in a more formal proceeding, e.g.,

if an RTO files a petition for a declaratory order seeking approval of its PBR proposal. 

645FERC Stats. & Regs. ¶ 32,541 at 33,755.

646Id. at 33,756.

grappling with other development issues. The Commission, therefore, will make its staff

available through our pre-filing process to work with RTOs to help identify and resolve

issues on an informal basis prior to their filing a PBR proposal. 644

7. Other RTO Transmission Ratemaking Reforms

The Commission proposed in the NOPR to consider innovative pricing proposals

for transmission owners who turn over control of their transmission facilities to an

RTO. 645 The types of pricing that the Commission proposed to consider include: a

higher ROE on transmission plant; allowing the transmission owner to retain the benefits

of cost saving attributable to RTO formation; acceleration of transmission cost recovery

in rates; non-traditional valuation of transmission assets such as an estimate of

replacement costs for assets purchased at higher than net original cost; and liberalized

allowance of levelized or non-levelized rate methods. The Commission proposed that

transmission owners meet all of the requirements to become an RTO before an innovative

pricing proposal is accepted. 646
Docket No. RM99-2-000 -548-

647While we used the term incentive pricing in the NOPR, this term is an

imprecise description of the various transmission pricing reforms that will be addressed in

this Rule, and we now describe these pricing reforms as innovative rate proposals. 

However, the comments sections that follow continue to use the term incentive because

the parties used this term in their comments. 

648See, e.g., Avista, TEP, Duquesne, APS, NEPCO et al., Florida Power Corp.

Comments

A large number of commenters addressed the Commission's proposals to consider

transmission pricing reforms for RTOs. About 30 commenters expressed support, and

about 30 commenters expressed opposition. There were also a number of comments

which did not explicitly support or oppose this aspect of the NOPR.

Supporting Innovative Pricing 

647

Of the commenters that support innovative pricing, a common theme is that if

RTO formation is to be voluntary, incentives are required to encourage participation. 648

For example, Justice Department recommends that the positive and negative incentives be

designed to secure universal compliance rather than have some utilities not participate

because the advantage of continuing outside of the RTO is greater than the incentive to

join. EEI supports incentives since RTO formation will probably not generate increased

earnings for transmission owners since most of the efficiencies will be a benefit to others. 

EEI suggests that an application for RTO formation and incentives should include some

assessment of the benefits from which the incentives are generated but a precise

calculation of benefits should not be required because of the extreme difficulty in making
Docket No. RM99-2-000 -549-

such an estimate. PacifiCorp is in favor of incentives but is concerned that a "case by

case" consideration of incentives may jeopardize their realization because customers will

call for lower transmission rates in the short term once the RTO has been formed. 

PacifiCorp argues that a more detailed uniform policy on incentives "up front" is

preferred.

On the other hand, several commenters suggest that the Commission should

consider incentives only on a case-by-case basis. Desert STAR says that different RTOs

may need different sets of incentives as will public power transmission owners. 

MidAmerican supports case-by-case consideration of incentives to join an RTO, and

favors a higher ROE reflecting the fact that transmission is not limited to selling to a

captive customer base in a bundled context but is serving a wholesale marketplace at

greater risk. Duke is in favor of incentives for transmission expansion, but cautions that

incentives should not bias investment and other decisions, should be considered on a

case-by-case basis, and may not be very effective where operation is separated from

ownership. Oregon Office is in favor of incentives for meeting all of the RTO

characteristics and functions faster than the industry average, but not for average speed in

accomplishing RTO formation.

A number of commenters favor offering incentives to public utilities that are

already members of an ISO as well as to provide incentives for public utilities to join an

RTO. For example, PJM says that incentive rates should be offered to new and existing
Docket No. RM99-2-000 -550-

RTO members to reflect the benefits generated and to prevent inefficient consequences

such as transmission owners moving from an existing ISO to a new RTO to receive

incentive rates. PSE&G favors a correspondingly higher ROE and faster depreciation of

transmission assets for transmission owners who participate in RTOs, including those

who have already joined an existing organization. LG&E says that incentive plans can be

useful in promoting RTO participation and that existing members of RTOs should be

allowed to propose incentive rates as well. LG&E stresses that it is just as important not

to enact policies on rates that might jeopardize revenue requirement recovery and thus act

as a disincentive. An additional consideration is offered by PP&L Companies which

argues that existing participants in RTOs should be allowed the same incentive rates as

those which are just forming because the benefits of an existing RTO are greater than

those of a start-up RTO not yet in operation.

The proposed incentive addressed most frequently by commenters is allowing a

higher rate of return on transmission assets. Georgia Transmission believes that higher

ROEs as an incentive to voluntarily join an RTO is appropriate because of the benefits

that participation would bring. NSP and others argue that ROE must be sufficient to

attract capital and compensate utilities for the risks involved. Conectiv and EEI argue

that the current rate of return policy should be modified, arguing that the DCF method

gives results that are too low to provide adequate returns to transmission owners causing

a reduction in building at a time when more transmission is critically needed. According
Docket No. RM99-2-000 -551-

to Conectiv, the DCF method should be abandoned or its application should be modified

to account for the current industry situation and be more reflective of conditions in the

general economy and reflect reasonable transmission asset lives. Cinergy, in reply

comments contends that the record in this proceeding is sufficient to establish a

presumption of reasonableness for higher ROEs.

SoCal Edison does not believe that pure incentives in the form of ROE "awards"

are necessary for encouraging participation in RTO but it does argue that higher returns

may be justified on transmission assets controlled by an RTO because the original owner

no longer has control over planning and expansion decisions. In addition, distributed

generation and bypass may be found to increase risk. SoCal Edison says that it is very

important to prevent the move to RTO control from being a financial loss due to

Commission rate setting or because of greater risk and higher costs. SoCal Edison does

agree with the proposal to allow accelerated depreciation of transmission assets to

encourage participation.

 TXU Electric is in favor of consideration of higher ROEs for RTO participants

and thinks it is more important to take a more global look at transmission ROEs in a new

and uncertain industry environment where transmission investment is important. TXU

Electric warns that it would be inappropriate to penalize RTO participation with reduced

earning potential because unbundled transmission ROEs are lower than ROEs allowed in

bundled rates. Conlon suggests that the Commission could allow a higher return on
Docket No. RM99-2-000 -552-

assets of a transco or ISO to serve as an incentive for IOUs to transfer ownership. 

Southern Company explains that there are major tax consequences to the sale of

transmission assets to form a transco and recommends that the Commission find ways to

accommodate such a transition. As to rate incentives, Southern Company advocates a

change in the Commission's ratemaking policy in order to increase returns to be more

commensurate with non-regulated businesses. Southern claims that recent court rulings

support higher returns on transmission service.

A number of commenters argue that participation in an RTO increases financial

risk, and that incentives are therefore required to encourage RTO participation. For

example, Empire District says that turning over control of transmission assets to an RTO

increases the risk because someone else will control their operation, justifying higher

ROEs for participation. PSE&G argues that a stand-alone transmission company or an

RTO is more risky than an integrated electric utility where transmission was a strategic

asset. FirstEnergy justifies higher ROEs by noting a number of sources of risk, including

emergence of distributed generation, vulnerability of firms that are less diversified than

integrated utilities, and quicker phase out of older generation plants which may result in

stranding some transmission plants. Midwest ISO argues that RTO membership may

cause a loss in earnings due to reduced transmission revenues, higher costs, and

operational risks. United Illuminating believes that risk for transmission investment is

higher for assets controlled by an RTO and that accelerated depreciation is warranted
Docket No. RM99-2-000 -553-

because transmission companies can no longer count on captive customers, and industry

changes have the possibility to abandon transmission plant before its physical life is over. 

WPSC is in favor of higher ROEs for transmission owners who join RTOs but not as a

pure incentive. WPSC's justification for higher ROEs would be the greater risk due to

removal of pancaked rates, new generation options, loss of higher state returns, and new

technologies. WPSC supports the other rate incentives as long as the benefits exceed the

costs based on careful examination.

Some commenters address the broad range of proposed incentives. For example:

• Trans-Elect argues in favor of incentives to include: acquisition premiums,

hypothetical capital structures, higher ROE, accelerated recovery of costs, rate

moratoriums, and expedited FPA section 205 and 203 approvals. Trans-Elect

would limit incentives to those that do not harm transmission customers. It notes

that PBRs would allow transmission owners to share in cost savings but some

operating history may be needed before they are put in place. It argues that

acquisition premiums may assist in the formation of independent transcos, and

suggests that if there is a rate moratorium in place, RTOs should be allowed to

recover acquisition premiums after the moratorium.

• FirstEnergy advocates flow through of cost savings to owners, non-traditional

valuation of assets, flexibility in the use of levelized rate methodology, retention of

hourly non-firm revenues, deference to management in dispute resolution,
Docket No. RM99-2-000 -554-

649See, e.g., AEP, United Illuminating, PP&L Companies, NU, Otter Tail, NYPP,

(continued...)

elimination of codes of conduct where there is structural separation, and

simplification of filing requirements. Some of these measures should be offered

on a limited basis to RTOs not yet meeting all of the characteristics and functions. 

Incentive plans should weigh costs versus benefits. Cal DWR goes further, saying

that incentives should not be allowed until benefits are actually proven.

• Los Angeles recommends that the Commission consider several options for the

valuation of assets transferred to an RTO in order to reflect the true value of the

assets to native load customers. Selected options to explore include: an up-front

acquisition premium used to moderate rates to native load customers, provide

native load customers a congestion premium, or grant native load customers an

exemption to congestion charges.

• NYPP is in favor of sufficient ROE to provide for expansion and accelerated

depreciation to compensate for increased risks as opposed to a "bonus" type

incentive to join an RTO. Its members contend that this type of incentive should

be available to all transmission owners, not just the ones who meet the NOPR's

characteristics and functions.

A number of commenters note that incentives are needed to facilitate efficient

expansion of transmission assets. 649 Transmission ISO Participants view the incentive
Docket No. RM99-2-000 -555-

649(...continued)

FirstEnergy, Transmission ISO Participants, Allegheny and Salomon Smith Barney.

650PJM/NEPOOL Customers, Lincoln, TDU Systems, APPA, WEPCO.

needed to induce new transmission construction as more important than incentives to

encourage RTO formation. IPCF suggests that FERC should offer transmission owners

incentives to expand their networks without meeting all of the requirements of becoming

an RTO in order to reverse the trend against building caused by Order No. 888. 

Williams says that decisions to expand transmission facilities must be made by for-profit

entities, must be driven by economic considerations, and the returns allowed must be

commensurate with the greater risks today, Williams cautions that returns for RTO

participants certainly should not be at a rate that results in a penalty.

Opposing Innovative Pricing

Many commenters oppose the use of incentives for many different reasons. One

common theme is that incentives are inappropriate because RTO participation should be

mandatory. 650 PJM/NEPOOL Customers argues that the Commission should mandate

RTO formation because of the transmission owners' duty to operate in an efficient

manner, and because transmission customers will likely pay the costs of the incentives. 

Ohio Commission prefers mandatory participation and questions whether the proposed

incentives will be effective. If incentives are used, Ohio Commission recommends that

the Commission consider evaluating which incentives will be effective, balancing
Docket No. RM99-2-000 -556-

incentives with disincentives, and recognize regional differences especially in arriving at

a solution for the Midwest.

Another common theme is that the costs of incentives may well outweigh the

benefits of RTO participation. Illinois Commission argues that if the Commission finds

that there are benefits in RTO creation, they should be mandatory. According to Illinois

Commission, the examples of incentives proposed in the NOPR, i.e., ROE enhancement,

revaluation of transmission facilities at replacement cost, accelerated depreciation, and

flexibility in use of levelized cost, would consist of money transfers to transmission

owners without contributing to cost control or efficiency. South Carolina Authority is

opposed to incentives or disincentives to promote RTO participation unless a factual

determination is made that they are absolutely necessary. Similarly, RECA is generally

opposed to incentives but would recommend their consideration if savings to the public

are well established. RECA finds the rate freeze proposal the least objectionable.

APPA advocates mandatory participation in RTOs and strongly objects to the use

of incentives to achieve participation. It argues incentives would be ineffective because

of the small proportion that Commission-regulated transmission makes up of the total

utility revenue compared to the value of transmission in maximizing generation and

merchant revenue. To be effective, APPA argues that the cost would be so large that it

would not be offset by the benefits of the RTO. Also, APPA raises the participation issue

of whether to give incentives to existing ISO members. Seattle warns against
Docket No. RM99-2-000 -557-

transmission owners "dumping" transmission facilities into an RTO to receive incentives

when those particular facilities are of no benefit to the RTO being formed.

Some commenters argue that it is inappropriate for the Commission to provide

incentives for the provision of a monopoly service. Metropolitan argues that incentives

should not be offered because many of the customers who pay for the incentives are the

same customers who paid for the original transmission facilities. TDU Systems argues

that ROEs for transmission service in an RTO is less risky because of the concentration

of monopoly business and the lack of any regulatory gap since all transmission under an

RTO will be regulated by the Commission. TDU Systems notes that transmission

entities, since they are monopolies, should not earn the same return as firms in other

industries. TDU Systems argues that other NOPR proposals, including rate freezes,

accelerated recovery of costs and investment, and revaluation of assets, are also an

inappropriate enrichment of transmission owners and are unneeded to attract investors. 

And TDU Systems argues that the proposal for an acquisition premium is troublesome

because customers have already been paying for these assets for years. TDU Systems

also suggests it will be difficult to calculate what level of incentives would be required to

persuade a transmission owner to participate in an RTO and the likelihood of offering a

greater incentive than is needed.

Some commenters suggest that providing incentives would violate the

Commission's statutory requirement to set rates at just and reasonable levels. NRECA
Docket No. RM99-2-000 -558-

believes that transmission owners should not be rewarded for unjust conduct with

incentives and that the Commission should rely on standard cost-of-service based rates. 

TAPS, which favors mandatory RTO formation, argues that incentives are unnecessary

and could nullify the benefits of electric industry restructuring. TAPS argues that

incentive rates, including each of the examples suggested in the NOPR, would violate

FPA's requirement for just and reasonable rates because they do not reflect the cost of

providing transmission service. TAPS does recommend that the Commission remedy

unintended disincentives such as utilities' fear of the unknown. UAMPS also favors

mandatory participation, and argues that incentives would unfairly raise transmission

costs to the benefit of monopoly transmission owners. UAMPS also argues that it is not

feasible to divide the benefit of RTO participation before these benefits are even known. 

In response to the comments of several IOUs, UAMPS argues that the claim that standalone transmission companies are more risky is unsubstantiated and should be heard in

another proceeding. NASUCA argues that EEI and others are incorrect in saying that the

DCF method does not produce reasonable results. According to NASUCA, the DCF

method takes explicit account of the transmission owners' risk and the realities of the

current regulatory climate.

Some commenters suggest that incentives will not necessarily increase RTO

participation, or will not necessarily produce the benefits which the NOPR describes. For

example, ICUA notes that incentives cannot be relied upon to achieve participation by all
Docket No. RM99-2-000 -559-

necessary utilities. WPPI opposes incentives to participate in RTOs citing the RTO

activity that has already taken place without incentives and the contention that the

Commission should designate boundaries and require participation within one year.

Wyoming Commission does not agree that increasing the ROE will be sufficient to

encourage more transmission building. According to Wyoming Commission, low

building activity may be attributable to difficulty in meeting siting requirements,

uncertainty related to retail access and native load, and competition for more localized

generation. Wyoming Commission does not think that the Commission should rush too

quickly into some innovative ratemaking before the industry has committed to making

RTOs work as planned. And the Wyoming Commission suggests that a higher ROE for

transmission investment may discourage a balanced consideration of options.

A number of commenters generally opposed incentives, believing that sanctions or

penalties against public utilities which do not join RTOs is superior to providing

incentives. NASUCA argues that mandates or disincentives for not joining at the time of

merger or market-based rate requests should be used rather than incentives. Incentives

would not be cost based and would therefore make rates unjust and unreasonable. As to

specific incentive proposals, NASUCA says that using replacement cost for transferred

assets would allow higher rates than necessary as an incentive and would charge

customers for assets they have already paid for. Such incentives could set off a

transmission sell-off in anticipation of an adjustment and some companies may refuse to
Docket No. RM99-2-000 -560-

651PJM Interconnection L.L.C., 88 FERC ¶ 61,109 (1999).

form transcos until they were granted the same adjustment as any other company. 

NASUCA is opposed to accelerated depreciation of assets for similar reasons. NASUCA

also states that incentive rates could harm electric competition by increasing transmission

costs. And Big Rivers states that the incentives proposed in the NOPR are inappropriate

for rural electric cooperatives.

Other Comments

A few commenters did not take an explicit position on the use of incentives, but

made general comments on the Commission's proposals. For example:

• Cal ISO is more concerned that there not be disincentives to RTO participation

than offering incentives. In particular, Cal ISO points out the disincentive created

by the Commission's annual fee policy, from which temporary relief was

granted651 but a permanent solution is needed.

• New Century recommends against the use of "remedial measures" to encourage

participation such as the suspension of market-based rate authority, denial of

merger authority, and denial of non-pancaked rate access to RTO facilities.

• Entergy says that the NOPR's statements on incentives are vague and would cause

too much regulatory uncertainty. Entergy asks the Commission to provide more

explicit provisions as to what incentives would be approved.
Docket No. RM99-2-000 -561-

652Note that these mechanisms are discussed below on a thematic basis, although

(continued...)

• Canada DNR is concerned that Canadian transmission owners not be placed at a

disadvantage for non-participation in an RTO in terms of incentives and

disincentive.

• SRP supports incentives as long as they are applied to both public power entities

and investor owned companies equitably.

• Metropolitan contends that it would not receive much benefit from any incentives

offered to RTOs because it is a public entity and because its asset base is so

heavily depreciated. However, replacement cost methodology could be of use in

mitigating cost shifts from rolling in higher costs of other utilities.

Commission Conclusion

As noted earlier, the NOPR and the comments use the term incentive pricing as a

label for the transmission pricing reforms that we raised for discussion. Certainly, good

pricing affects behavior. But good pricing also achieves a valuable goal, in terms of

competition, system expansion, or efficient practices that benefit more than the

transmission owners or the RTO. In this section we provide greater specificity with

respect to certain transmission pricing mechanisms that may be appropriate for RTOs. 

These mechanisms were described in the NOPR or otherwise proposed by commenters,

and are included in the amended regulatory text. 652 We emphasize that we do not intend
Docket No. RM99-2-000 -562-

652(...continued)

the regulatory text lists them on an individual basis.

this policy guidance to be interpreted as a Commission regulatory requirement for a

specific transmission pricing method, nor should it be interpreted as a guarantee that the

Commission will approve any particular innovative pricing proposal. We emphasize that

all innovative pricing proposals filed by RTOs must be fully and adequately supported in

accordance with this Final Rule and the regulatory text. We believe that we are providing

sufficient guidance for RTOs to make critical decisions with respect to transmission

pricing policies. If industry participants believe that further guidance from the

Commission is needed to resolve transmission pricing issues, they may request such

guidance through requests for declaratory orders or further rulemakings.

As discussed earlier, transmission pricing reform is needed as a result of the rapid

restructuring of the industry that is underway, particularly with respect to changes in the

ownership and control of transmission assets, and changes in the transmission services

being provided in competitive generating markets. As a result of these changes, and

consistent with a number of commenters' arguments, we have concluded that the

Commission, at a minimum, needs to mitigate various "disincentives" that may prevent

transmission owners from efficiently operating their systems. Commenters cite to the

potential that transmission owners will earn lower returns for providing unbundled

transmission service than they earned for providing bundled service, even though risks
Docket No. RM99-2-000 -563-

653For example, Salomon Smith Barney, citing to an article by Leonard Hyman

notes that the direct, total costs of transmission service represents about six to seven

percent of the average customer's bill, and raising transmission prices even as high as 25

percent in order to attract capital adds only two percent to the overall electric bill.

associated with transmission ownership have increased. Commenters suggest a number

of sources of increased risk. One source is the potential for bypass of transmission assets

due to distributed generation and the phasing out of older generators from service. Other

sources are directly related to RTO formation. For example, some commenters assert that

stand-alone transmission companies (e.g., transcos) are riskier because they have a lessdiversified portfolio of assets than a vertically integrated utility. Other commenters argue

that participation in an RTO that is an ISO is inherently riskier, suggesting that increased

risk comes from ownership of transmission assets that are ceded for purposes of

operational control to another, non-affiliated entity.

Other commenters argue that a reevaluation of transmission pricing is needed

because it is absolutely critical that the transmission grid support competitive generating

markets, and the only way that the Commission can ensure this will happen is to pursue

pricing policies that encourage it. Some commenters suggest that because the

contribution of transmission to total costs of energy is relatively small, 653 overinvestment

in transmission will not significantly affect delivered electricity prices. Further, the

Commission should be much more concerned about underinvestment, not overinvestment,
Docket No. RM99-2-000 -564-

654Professor Joskow points out that external factors, such as licensing

requirements, the need for rights of way, and NIMBY (i.e., "not in my backyard")

opposition to transmission expansion already places significant constraints on

overinvestment in major new transmission projects.

in the transmission grid. 654 Stated another way, an efficient transmission grid is a

prerequisite to achieving competitive generating markets, and the potential benefits for

consumers far exceed any limited overinvestment that may occur on transmission service. 

A related argument is that efficiency benefits of improved transmission service will be

captured by producers and customers of generation, not transmission providers; therefore,

greater incentives for RTOs to provide good transmission operations and efficient

investments in the grid are warranted.

The NOPR sought comments on several procedural issues related to transmission

pricing reform and incentives. One issue was whether these pricing reforms should be

available to participants of existing ISOs, or be available only to transmission owners that

join RTOs as a result of the Commission's RTO initiative. We have concluded that

members of an existing ISO organization that satisfy the minimum RTO requirements in

the regulatory text should be allowed to seek transmission pricing reform as newly

formed RTOs, so that they can avail themselves of the same incentives for efficient

operation of and investment in the transmission grid. Furthermore, we believe that the

Commission's approach to evaluating innovative transmission reforms should be neutral

with respect to the organizational structure of the Applicant, so that RTOs that own
Docket No. RM99-2-000 -565-

transmission assets as well as RTOs that do not own transmission assets would be equally

eligible for such ratemaking treatments.

Another issue is whether the Commission would prescribe which transmission

pricing reforms it would accept and which it would not accept, or whether the

Commission would consider such proposals on a case-by-case basis. We conclude that a

case-by-case evaluation of transmission pricing reform proposals is appropriate, given

that such proposals are not generic in nature, and a proposal may be appropriate in some

RTO circumstances but not in others. However, the Commission believes some further

specificity on transmission pricing reform is warranted to provide industry participants

with the Commission's evolving views, as RTOs consider the appropriateness of various

reform measures.

Therefore, we provide greater specificity on three transmission pricing reform

measures: (1) ROE; (2) levelized rates; and (3) accelerated depreciation and incremental

pricing for new transmission investments. We note that some of these measures may be

useful only as transitional devices that may be necessary to spur the prompt creation of

RTOs and, therefore, we intend to offer these pricing options only for a defined period of

time, as detailed later in this Final Rule. On the other hand, other pricing reforms may be

useful as permanent features, and will not be limited only to the period during which

RTOs are forming. Finally, while certain of these innovative pricing proposals may be

more helpful to one RTO structure than another (e.g., ISO vs transco), we do not believe
Docket No. RM99-2-000 -566-

655Some commenters recommend abandoning the DCF method of calculating ROE

entirely. We are not adopting that recommendation.

that any of these pricing proposals would be incompatible with any particular structure

adopted by RTOs.

a. Return on Equity (ROE)

More commenters focused on ROE-based proposals than any other type of

transmission pricing reform. These commenters make two main points. One argument is

that higher ROEs will be demanded by the market as a matter of course as the industry

restructures and the risk of transmission business increases, and the Commission must

allow higher ROE to reflect participation in RTOs. A second argument is that joining an

RTO adds another level of risk that warrants a specific adjustment to ROE (e.g., going to

the high end in the range of reasonable ROE, or a specific basis point adjustment). 655

As discussed above, commenters urge the Commission to provide flexibility in

allowing ROE-based programs for RTOs. Many of these commenters specifically urge

the Commission to ensure that there are sufficient incentives for an RTO to make needed

investments in transmission infrastructure. On the other hand, a number of commenters

oppose ROE-based programs on the grounds that they constitute a "bribe" for utilities to

provide service that they are statutorily required to provide.

We believe that there are a number of issues surrounding ROE that must be

addressed by the Commission. For example, we believe that allowing an RTO to propose
Docket No. RM99-2-000 -567-

a formula rate for determining return on equity is consistent with our view that risks and

rewards for transmission owners should reflect market-like forces to the extent possible. 

Allowing a formula rate of return would decouple a transmission owner's earnings from

its own equity valuation, and would tie it more to external standards such as industrywide performance. Such an approach is also consistent with the benchmarking that may

occur under PBR.

We also agree that the risk profile of the transmission business is changing as the

industry restructures, and that it may vary as a function of the structure each transmission

company elects. For example, the risk associated with owning facilities that are leased

for a sum certain to another entity operating an RTO may be different from the risk

associated with operating a stand-alone transco that is facing a significant expansion

program. We therefore conclude that ROE-based initiatives–as well as other ratemaking

reforms discussed below-may be applicable to all types of RTOs, without regard to

organizational structure.

We further recognize that historical data typically used to evaluate ROEs may not

be reliable since it reflects a different industry structure from the one that exists recently. 

And we believe that as patterns of transmission ownership and control evolve, new

approaches to compensating transmission owners for different capital structure mixes

may be warranted, including allowing a transmission owner to seek a return on invested
Docket No. RM99-2-000 -568-

656As noted infra, this is one of the pricing reforms that will be available only for a

defined transition period during which RTOs are being established.

657As noted infra, moratoriums are among the pricing reforms that will be

available for a defined transition period during which RTOs are being established.

capital, independent of its exact capital mix. 656 As noted above, we are willing to

consider moratoriums tied to the rates the transmission provider earns on transmission

assets with respect to bundled retail power sales, and the moratorium option may be tied

to the existing transmission rate level, or to the existing return on equity. 657

Finally, we agree that the uncertainty associated with the transition of the industry,

and in particular participation in RTOs, may increase risks in the short-run. Certainly,

our goals have not changed, which are to ensure that customers have access to

nondiscriminatory service at just and reasonable rates, and that transmission owners have

an opportunity to earn a reasonable rate of return on their investment. We recognize that

in this era of rapid change, new approaches to setting ROE may be needed to implement

that standard. We therefore invite RTOs to submit proposals for ROE-based programs

that are in conformance with these new approaches.

We note that pricing reforms involving ROE would clearly be compatible with all

types of RTO structures that involve a determination of return on equity on transmission

rate base, e.g., transcos, ISOs, or tiered organizational structures.

.
Docket No. RM99-2-000 -569-

658See, e.g., American Electric Power Service Corp., Opinion 440, 88 FERC ¶

61,141 at 61,441-42 (1999) (AEP); Allegheny Power Service Corp., Opinion 433, 85

FERC ¶ 61,275 at 62,117 (1998); Kentucky Utilities Co., Opinion 432, 85 FERC ¶

61,274 at 62,100-03 (1998) (KU). 

659See AEP, 88 FERC at 61,441-42.

b. Levelized Rates

A number of commenters argue that the Commission should allow RTOs to adopt

levelized rates. A levelized rate is designed to recover all capital costs through a uniform,

nonvarying payment over the life of the asset, just as a traditional home mortgage

payment does. The Commission, has held in a number of recent proceedings that both

levelized and nonlevelized rates can produce reasonable results, depending on the

circumstances. 658 The Commission stated in these cases that where a utility proposes to

switch from a nonlevelized net plant rate design method, "[i]n supporting such a switch, a

utility must prove that its proposed method is reasonable in light of its past recovery of

capital costs using a different method." 659

The Commission believes that levelized rates are preferable in an RTO

environment because all customers, regardless of when they take service, face the same

price. Also, given a depreciated investment base, levelized rates based on existing

investments will be higher than non-levelized rates and will address concerns that RTO

formation will decrease revenues.
Docket No. RM99-2-000 -570-

The principal objection to allowing levelized rates for RTOs is that it may raise

RTO transmission rates in the short-run. The Commission has been reluctant outside the

RTO context to approve switches from or to levelized rates proposed by public utilities

under traditional cost-of-service ratemaking because of the opportunities that switching

may provide for utilities to over recover transmission costs. However, consistent with our

discussion above of how market restructuring may require innovation in transmission

pricing, we believe that levelized rates may be appropriate in circumstances, as here,

where an RTO reflects a fresh start with respect to the provision of transmission services,

and potentially the customers for those services. This is especially true in cases where

RTO formation occurs coincident with market restructuring, such that the transmission

customers of the RTO may be significantly different than the traditional, captive

customers, that formerly took transmission service. We therefore conclude that the

Commission should allow increased flexibility for RTO proposals that include ratemaking

practices based on levelized rates. Clearly, this pricing reform, which relates to the

method used to compute the transmission revenue requirement in the first instance, is

compatible with any type of RTO structure, e.g., transco, ISO, or tiered structure.

c. Accelerated Depreciation and Incremental Pricing for New

Transmission Investments

While a number of commenters have suggested accelerated depreciation as a

transmission pricing reform that should be considered, these arguments are premised on
Docket No. RM99-2-000 -571-

660See Order No. 888, wherein the Commission allows recovery of stranded costs

(primarily generation related) only when they are unrecoverable from customers that

depart the system, and only upon a definitive showing that the utility had a reasonable

expectation of continuing to serve the customer after the customer's departure.

the possibility that transmission costs will be stranded by changes in the industry, such as

bypass of portions of the transmission system. We think that these concerns are

speculative at this point in the industry's restructuring. For example, we are not

convinced that the problem of stranded transmission assets is anywhere near the level of

concern that stranded generating assets represents. 660 In any event, should certain

limited transmission facilities become stranded, nothing prevents proposals to recover

prudent costs under traditional ratemaking policies.

We will, however, make a distinction between accelerated depreciation for

existing transmission assets, and accelerated depreciation for new transmission facilities. 

While we will not bar proposals of this type for existing assets, we cannot give any

encouragement to them in the Final Rule. On the other hand, we believe that it is

appropriate for the Commission to provide those willing to make new transmission

investments with the flexibility to propose that such assets follow non-traditional

depreciation schedules. The purpose of providing such flexibility is to remove

disincentives for the construction of new facilities. We think such flexibility is warranted

because the fundamental nature of transmission investment may be changing with respect

to the entities that will make investments in the transmission system in the future and who
Docket No. RM99-2-000 -572-

pays for the new transmission facilities. Furthermore, given the rapid changes in market

structure and dynamics that have occurred and will likely continue, we are not certain that

traditional determinations of the economic life of new transmission facilities remain

appropriate.

In addition, we believe it is appropriate for the Commission to provide flexibility

for pricing of new facilities, such that proposals for pricing of new facilities that combine

elements of incremental prices with embedded-cost access fees will be considered. 

Although we are concerned that such ratemaking practices have the potential to lead to

higher prices for new transmission services, and also potential to lead to overinvestment

in transmission facilities, e.g., where generation redispatch could accomplish the same

objective at lower cost, we believe that such practices, if carefully constructed, will create

appropriate incentives for efficient investment in new transmission facilities. We also

believe that this pricing reform will be attractive to all types of RTO structure, e.g.,

transcos, ISOs, or tiered structures. It may also be used by any RTO that chooses to rely

on third parties to construct new facilities. 

d. Acquisition Adjustments

A number of commenters suggest that the Commission adopt new policies for

acquisition adjustments that would provide assurances to purchasers of transmission
Docket No. RM99-2-000 -573-

661See Minnesota Power & Light Company and Northern States Power Company,

43 FERC ¶ 61,104 at 61,342 (1988), for a discussion of the Commission's existing 

policies with respect to the ratemaking treatment for acquisition premiums. See also Duke

Energy Moss Landing LLC, et al. 83 FERC ¶ 61,318 (1998).

facilities that acquisition premiums would be recoverable through transmission rates. We

do not adopt this suggestion in this Final Rule. 661

8. Additional Ratemaking Issues

A number of comments on ratemaking issues address topics not specifically

enumerated in the NOPR.

Comments

• Williams, CSU, Alliance Companies and WPSC encourage the Commission to

consider rate designs based on mileage or network usage.

• Great River, NCPA and IMPA raise the concern that cooperatives and public

power entities need assurance that they will receive full customer credit and

compensation as was explicitly stated in Order No. 888. SoCal Edison claims that

full compensation will be forthcoming and will not be a problem.

• Ohio Commission recommends that a tariff for border transactions (between

RTOs) be implemented that makes the market over the combined regions seamless

to persuade some regional organizations to combine.

• PPC notes that IndeGO ran into a problem with developing rates for combined

systems with very different levels of quality and cost, and that systems at a
Docket No. RM99-2-000 -574-

position of lower quality should be required to meet combined system standards at

their own cost.

• Puget argues that RTO rates must provide for the collection of stranded costs.

• PSNM sees a problem with load-side generation customers who do not have to pay

their fair share of total system transmission costs.

• Powerex objects to the proposal to segment companies' service areas into subzones for pricing purposes.

• Alliance Companies and AEP favor the flexibility in RTO rate filings that would

allow companies to make proposals that reflect market forces. 

• Alliant Energy is concerned that RTO structures promote workable markets and

that transmission rates be permitted to include a fair accounting of RTO start-up

costs.

• East Texas Cooperatives recommends that RTO pricing structures adequately

compensate small transmission owners who join the RTO, creating an incentive to

join and be a more equitable system.

• Georgia Transmission says that ratemaking for RUS borrowers must take into

account the requirements of any RUS loans. In addition, Georgia Transmission

recommends that the cost of RTO formation be allowed in RTO rates.

• Metropolitan, Cal DWR, and SoCal Cities favor the use of time-of-use pricing or

off-peak rates for transmission.
Docket No. RM99-2-000 -575-

• Oregon Office recommends load-based fees for transmission rather than volume

based charges.

• IMEA argues that the RTO start-up and administrative costs should be allocated to

all customers including bundled native retail load. In contrast, LG&E notes that if

native load is assigned RTO administrative costs there may be under recovery

because of retail rate freezes.

• Industrial Customers argue that assets used for remote generation should be

excluded from the RTO.

• Merrill Energy says that the incremental pricing of new transmission upgrades

prevents expansion because customers are unwilling to pay.

• NERC is concerned about the recovery of costs related to reliability-related

generators.

• NRECA is concerned about compensation by an RTO for low-use transmission

facilities owned by cooperatives, because large transmission owners are opposed

to revenue sharing. NRECA notes that if a cooperative joins an RTO, transactions

for all will increase and there is more to share. Also, there should be protection

for joint use agreement income.

• Project Groups says that pricing must facilitate entry and usage by efficient,

environmentally benign resources. Grid access barriers to these resources need to
Docket No. RM99-2-000 -576-

be eliminated. NMA/WFA/CEED respond by saying that the policies that Project

Group objects to are equitable overall.

• Seattle argues that hub and spoke pricing should be used and discrete interregional tariffs are needed.

• NWCC notes that the characteristics of wind-produced power presents problems

fitting into an RTO pricing arrangement and says that wind power works best with

energy-based pricing systems.

• Detroit Edison advocates a two-part pricing structure similar to that proposed by

the Alliance RTO. It includes a local rate and a regional rate. To encourage

participation, Detroit Edison proposes that the Commission allow RTOs to

develop market-based transmission pricing methodologies.

Commission Conclusion

Commenters raise a number of important ratemaking issues that must be

considered in the establishment of RTOs. We clarify that the reasonable costs of

developing an RTO may be included in transmission rates. Other issues are at a level of

detail and specificity that we do not believe should be resolved in this Final Rule. 

Therefore, these issues will be considered as they apply to individual RTO proposals on a

case-by-case basis.
Docket No. RM99-2-000 -577-

9. Filing Procedures for Innovative Rate Proposals

We shall evaluate all RTO proposals including any innovative rate treatment based

on the applicant's demonstration of how the proposed rate treatment would help achieve

the goals of regional transmission organizations, including efficient use of and investment

in the transmission system and reliability benefits. We shall also require applicants to

provide a cost-benefit analysis, including rate impacts, and demonstrate that the proposed

rate treatment is appropriate for the proposed RTO and that the rate proposal is just,

reasonable, and not unduly discriminatory. 

In addition, pricing proposals involving moratoriums and returns on equity that do

not vary according to capital structure may not be included in RTO rates after January 1,

2005. Thus, if the Commission approves an RTO rate proposal involving, e.g., a rate

moratorium, unless otherwise ordered, the moratorium would end on or before January 1,

2005. We are limiting these rate proposals for a defined period during the formative

stage of RTOs because, while either may be appropriate as transitional rate mechanisms,

they do not promote long-term efficiency through rate design. In addition, the limited

duration for these rate treatments will encourage the earliest possible filings, while at the

same time giving some flexibility to those filings that may be delayed. 
Docket No. RM99-2-000 -578-

662FERC Stats. & Regs. ¶ 32,541 at 33,756-57.

663Id. at 33,757.

664See id.

H. Other Issues

1. Public Power and Cooperative Participation in RTOs

In the NOPR, the Commission stated its objective of encouraging all transmission

owning entities including transmission owned or controlled by public power entities and

cooperatives, including Federal Power Marketing Agencies (PMAs), Tennessee Valley

Authority (TVA), and other state and local entities to place their transmission facilities

under the control of an RTO. 662 To this end, we expressed an expectation that public

power entities would fully participate in the collaborative process for forming RTOs. 663

In addition, we noted that some public power entities filed open access tariffs with the

Commission and others are participating in ISOs and other regional institutions. The

Commission, however, is aware and concerned that public power entities face several

difficult issues regarding RTO formation and participation. 664 

The first issue is the Internal Revenue Service (IRS) Code "private use"

restrictions on the transmission facilities of public power entities financed by tax-exempt

bonds. We noted that IRS temporary regulations may allow facilities financed by

outstanding tax-exempt bonds to be used to wheel power in accordance with Order No.

888, but that these temporary regulations may not allow the issuance of additional tax-
Docket No. RM99-2-000 -579-

665Id.

666See id.

667See, e.g., Oglethorpe, Allegheny, Montana Power, CREDA, Tallahassee,

Arkansas Cities, PPC, California Board, Industrial Customers, Entergy, BC Hyrdo,

(continued...)

exempt bonds for expanded transmission or permit transfer of operational control of

existing transmission facilities financed by tax-exempt bonds to a for-profit transco. 665

The Commission asked for comments on the extent to which IRS Code restrictions may

limit the transfer of operational control or other forms of control, or ownership of public

power transmission facilities to a for-profit transco or other forms of an RTO. 

The Commission also requested comments on state and local charter limitations,

prohibitions on participating in stock-owning entities, the current policies of various local

regulatory entities that affect or impede full public power participation in RTOs and legal

restrictions or other considerations regarding PMAs that prevent their participation in

RTOs. We questioned whether the Commission should consider some forms of associate

membership or participation and other special accommodations in order for public power

entities to overcome obstacles to RTO participation. 666

Comments

Most commenters support the Commission's position that a properly formed RTO

should include all transmission owners, including cooperatives and public power, in a

specific region. 667 As EEI notes, public power participation will enhance the reliability
Docket No. RM99-2-000 -580-

667(...continued)

Powerex, Aluminum Companies, MEAG, Arizona Commission, Nevada Commission,

East Texas Cooperatives, Lincoln, NPPD, Wyoming Commission, Georgia Transmission,

WPSC, PGE, Montana Commission, SMUD, Cal ISO, MLGW, Loveland Customers,

NASUCA, Duke, LG&E, CP&L, South Carolina Authority, STDUG, NCPA, PP&L

Companies, Desert STAR, PG&E and EEI. 

668See, e.g., EEI, Snohomish, MLGW, Loveland Customers, Montana

Commission, Wyoming Commission, Aluminum Companies, Industrial Customers and

Powerex.

and economic benefits of an RTO. Furthermore, some commenters argue that in some

areas of the country, especially in the Northwest and Southeast, RTO formation may be

impractical without public power participation. 668 Virtually all commenters recognize

that regulatory and legal restrictions exist that may impede public power and cooperative

participation in RTOs. EEI, SERC and Metropolitan argue that the best way to facilitate

non-jurisdictional utility participation in RTOs is for the Commission to avoid a "onesize-fits-all approach" and to provide flexible rules in order to accommodate the unique

needs of public power entities.

Section 141 of the IRS code imposes limitations on the use of non-governmental

entities of public power facilities financed with tax exempt bonds. These private use

limitations restrain the form and extent of participation by public power systems in

RTOs. The key private use limitation that is material to RTO participation is a bar on the

sale of the output of facilities financed with tax exempt debt to non-governmental entities

on terms not available to the general public. Commenters note that in January 1998, the
Docket No. RM99-2-000 -581-

669E.g., Los Angeles, SoCal Cities, LPPC, APPA, Tacoma, NCPA, SRP, TAPS,

EEI, NPPD and East Texas Cooperatives.

670See, e.g., EEI, TAPS, SRP, Georgia Transmission, Arkansas Cities, Nevada

Commission, PP&L Companies, TANC, Desert STAR, NCPA, Montana-Dakota

Enron/APX/Coral Power and Tallahassee. 

IRS issued temporary regulations relating to the application of the private use rules to

public power entities that provide some relief for transmission facilities. These

temporary regulations permit issuers of outstanding tax exempt bonds to offer open

access transmission services and competitive access to distribution systems, and to join

RTOs, provided that certain conditions are met, particularly that the facilities continue to

be owned by the municipal entity. The temporary regulations, however, do not provide

the same relief to issuers of new tax exempt bonds. Many commenters assert that the

temporary regulations will expire in January 2001 and that these regulations are

incomplete and not permanent. 669 LPPC notes that the ability of issuers to continue to

rely on the temporary regulations after expiration is unclear and therefore, issuers taking

actions permitted under the temporary regulations risk having tainted the tax-exempt

status of their bonds on the expiration of the regulations.

Commenters offer varying solutions to the "private use" restriction problem. 

Many commenters urge the Commission to actively attempt to influence the IRS and

Congress to remove and/or mitigate the tax impediment. 670 SRP also recommends that

the Commission require all RTOs to demonstrate that they have made a good faith effort
Docket No. RM99-2-000 -582-

671See Reply Comments of Arkansas Cities at 6.

to reduce barriers to participation and to accommodate legal restrictions faced by

potential participants. Arkansas Cities proposes a transitional grandfathering of existing

tax-exempt bonds. Arkansas Cities notes that such legislation is pending in Congress and

is identified as the Bond Fairness and Protection Act (BFPA). Arkansas Cities states

"that if enacted, the BFPA would clarify tax laws and regulations governing tax exempt

bonds so that publicly owned utilities would be able to participate in the development of

competitive electric utility markets." 671 Duke asserts that the leasing of transmission

facilities to an RTO is a viable option. Moreover, LPPC states that public power entities

have to be allowed to participate in a way that permits them to retain sufficient

operational control of their transmission systems to stay within the private use limitations. 

In addition, LPPC, Snohomish, Arkansas Cities and East Texas Cooperatives argue that

public power entities need an opt-out provision if their tax exempt status is threatened. 

TEP recommends that the final rule contain a template for addressing how transactions

can be administered if they involve the use of tax exempt facilities. TEP proposes that

(1) an RTO should operate in a manner that either preserves the tax exempt status of such

facilities or provides compensation to the facilities' owner to the extent it incurs economic

harm; and (2) that an RTO should develop specific rules governing the operation and

administration of tax-exempted financed facilities.
Docket No. RM99-2-000 -583-

NRECA details the obstacles confronting cooperatives including the requirement

that in order to maintain tax exempt status under Section 501(c)(12) of the IRS Code, at

least 85 percent of a cooperative's income must come from the cooperative's members. If

such member-derived revenue does not equal at least 85 percent of total revenue, then a

cooperative would lose its tax-exempt status. Georgia Transmission argues that there is a

real risk that participation in an RTO could result in a cooperative losing its tax exempt

status if the revenue received from the RTO (assuming the RTO is not a member of a

cooperative) exceeds 15 percent of the cooperative's total income. The revenue received

from the RTO would stem from revenue attributed to use of the cooperative's

transmission facilities controlled by the RTO. 

One remedy to this problem, suggested by AEPCO and Wolverine Cooperative, is

to increase an RTO's compensation to the cooperative to include a gross-up of net

margins to cover the income tax expense. Under this approach, the RTO would pay the

cooperative the full revenue requirement for the transmission facilities, including any

other taxes. East Kentucky proposes that a conduit or a pass-through relationship

between the RTO and the cooperative would satisfy the IRS restrictions and allow a

cooperative to maintain its member-derived character. According to East Kentucky, the

RTO would act as an agent for the cooperative by collecting the transmission revenues

and holding these revenues in a trust on behalf of the cooperative. Furthermore, Georgia

Transmission suggests that the Commission allow a cooperative to leave an RTO if it
Docket No. RM99-2-000 -584-

672See, e.g., LPPC, NPRB, Snohomish, Clarksdale, MEAG and CAMU.

673For example, the Nebraska Constitution provides: "No city, county, town,

precinct, municipality or other sub-division of the state, shall ever become a subscriber to

the capital stock, or owner of such stock, or any portion or interest therein of any . . .

private corporation or association."

appears that it may lose its tax exempt status because of the level of RTO and other nonmember revenue it expects to receive in a given year. 

Another impediment to public power participation in RTOs is mortgage

restrictions. AEPCO notes that under the terms of a typical RUS mortgage, either

transfer of control of transmission assets to an RTO or a sale, unless authorized by RUS,

would be an event of default. East Texas Cooperatives argues that the Commission

should require all RTOs to accommodate mortgage restrictions by allowing cooperatives

to retain control of their facilities until the mortgage restriction is lifted or a creditor or

RUS approves the transfer. In its comments, RUS recognizes that development of RTOs

may offer considerable benefits to RUS borrowers, and RUS states that it is exploring

means to facilitate borrower participation consistent with the Rural Electrification Act

and RUS's fiduciary duties to the U.S. Treasury and taxpayers.

According to several commenters, 672 many public power entities operate under

explicit state constitutional restraints with respect to their ability to participate in the

ownership of a privately-owned RTO. 673 Further, some state constitutions include
Docket No. RM99-2-000 -585-

674For example, the Colorado Constitution states: "Neither the state, nor any

county, city, town, os township shall lend or pledge credit or faith thereof, directly or

indirectly, in any manner to, or in aid of, any person, company or corporation, public or

private, for any amount, or for any purpose whatever; or become responsible for any debt,

contract or liability of any person, company or corporation, public or private, in or out of

the state."

675For example, Washington law provides: "Any two or more [Washington] cities

or public utility districts or combinations thereof may form an operating agency . . . for

the purpose of acquiring, constructing, operating, and owning plants, systems and other

facilities and extensions thereof, for the generation and transmission of electric energy

and power." 

676Nebraska law provides that : "[T]he plant, property, or equipment of a public

power district shall never . . . by outright sale, or lease, become the property or come

under the control of any private person, firm, or corporation engaged in the business of

generating, transmitting, or distributing electricity for profit." Nebraska Rev. Stat. § 70-

646.01.

restrictions on the use of public funds. 674 Several states, however, expressly authorize

public power entities to join with other public entities in the ownership and operation of

electric transmission facilities. 675 In addition, state and local laws impose additional

restrictions on the activities and operations of public power entities that could affect the

operations of any RTO in which they hold an ownership interest. For example, some

laws prohibit the sale or lease of transmission facilities to a for-profit entity. 676

In states in which laws allow a public utility district to sell or lease its transmission

facilities to an RTO, the laws impose requirements on such sale or lease. For instance,

Washington law would require the property to be offered in a competitive bidding
Docket No. RM99-2-000 -586-

677See LPPC at 17.

process, and no sale could occur without voter approval. 677 Furthermore, LPPC notes

that state and local laws in California, Florida, Nebraska, and Texas would require the

approval of the City Council, the public utility commission, the governing board, or other

governmental authority before a transfer of facilities could occur. CAMU and NPPD also

state that many municipals and power authorities have statutory authority to condemn

property and that it is unlikely that this eminent domain authority can be delegated to an

RTO.

Enron/APX/Coral Power notes that an unwillingness to participate in an RTO for

commercial reasons should render non-jurisdictional transmission owners ineligible for

RTO services and savings. Moreover, Duke argues that public power must take the lead

in resolving these issues for themselves. Duke notes that investor-owned utilities have

overcome numerous obstacles to become RTO participants. Furthermore,

Enron/APX/Coral Power argues that public power and other non-jurisdictional

transmission owners that elect to share in the benefits of an RTO must be held to the

same characteristics and functions as jurisdictional transmission owners. Cinergy

suggests that the Commission commence regional technical conferences to address legal

obstacles to public power entities' participation in RTOs and to explore possible

alternatives to operational and functional integration of public power systems into RTOs. 
Docket No. RM99-2-000 -587-

678See, e.g., LG&E, Otter Tail, WPSC, Alabama Commission, Montana

Commission, and DOE. 

679See, e.g., CAMU, CMUA, STDUG, CREDA, NY ISO, Powerex, PP&L

Companies, Desert STAR, CP&L, LPPC, MEAG and Tennessee Authority.

Commenters also address issues relating specifically to PMAs. Many commenters

support the expansion of the FPA to give the Commission jurisdiction over all

transmission owners. 678 CREDA points out that PMAs are restricted by: (1) enabling

statutes; (2) congressional appropriations; (3) the inability to grant indemnification

without congressional approval; (4) the sovereign immunity doctrine; and (5) their load

serving responsibilities. MLGW notes that other PMA restrictions include the TVA

"fence restriction," whereby, TVA's organic statute prohibits TVA from performing any

transmission service that would result in the delivery of power generated by TVA outside

the specified TVA service area. MLGW further notes that existing long-term contracts

between TVA and its distributors are another barrier to RTO participation by PMAs. To

remedy these problems, TVA and others 679 argue that the Final Rule should provide

enough flexibility to ensure that public power obstacles can be addressed and mitigated. 

On the issue of whether the Commission should consider special accommodation,

commenters disagree over whether the Commission should provide incentives to public

power entities in order to make RTO membership financially attractive. EEI and APPA
Docket No. RM99-2-000 -588-

urge the Commission to adopt an RTO policy that makes membership attractive to public

power entities in terms of efficiency and benefits.

SoCal Edison is strongly opposed to the Commission providing incentives in the

form of uniform grid-wide rates or transmission credits. SoCal Edison argues that these

incentives are nothing more than inequitable cost shifts to retail ratepayers. Likewise,

Duke argues that public power entities should not be provided with competitive

advantages in order to encourage voluntary RTO participation.

In contrast, IMPA and SoCal Cities urge the adoption of a final rule that provides

proper credits or compensation for facilities contributed to an RTO, including customerowned facilities. Furthermore, East Kentucky states that return on equity can be

mitigated by allowing cooperatives to earn a rate of return similar to investor-owned

utilities. Vernon argues that the entitlement for transmission facilities contributed to the

RTO grid and the appropriate level of compensation are matters that should not be

determined nationally on a generic basis, but rather, should be decided in the context of

each RTO. SRP supports PBRs and other incentives as long as they are applied to both

public power entities and investor owned companies equitably. Metropolitan contends

that it would not receive much benefit from any ROE incentives offered to RTOs because

it is a public entity and because its asset base is so heavily depreciated. However, a

replacement cost methodology could be of use in mitigating cost shifts for Metropolitan

due to rolling in higher costs of other utilities. Oregon Office recommends that public
Docket No. RM99-2-000 -589-

power entities be eligible for the same incentives as offered others to the extent that the

Commission regulates their rates. 

A few commenters discuss issues relating to public power and the filing

requirements. South Carolina Authority states that any RTO proposal should contain a

detailed description of the efforts made by petitioners to accommodate the transmission

facilities of publicly owned utilities. Similarly, SRP, APPA and LPPC recommend that

the Commission require each RTO proposal to demonstrate: (1) how a good faith effort

was made to accommodate public power participants, particularly deciding ownership

structure; and (2) where public power entities are not included, why there are no

reasonable terms and conditions under which the RTO could accommodate its

participation. Lincoln and Cinergy essentially concur.

Commission Conclusion

We reaffirm our preliminary determination that a properly formed RTO should

include all transmission owners in a specific region, including municipals, cooperatives,

Federal Power Marketing Agencies (PMAs), Tennessee Valley Authority and other state

and local entities. As noted by some commenters, public power and cooperative

participation in RTOs will enhance the reliability and economic benefits of an RTO. 

Furthermore, participation by public power entities and cooperatives is vital to ensure that

each RTO is appropriate in size and scope.
Docket No. RM99-2-000 -590- 

Virtually all commenters note that public power entities and cooperatives face

numerous regulatory and legal obstacles regarding RTO participation. Commenters assert

that these obstructions include: (1) IRS "private use" restrictions and the temporary

regulations enacted to mitigate the "private use" restrictions; (2) the requirement that at

least 85 percent of a cooperative's income must come from the cooperative's members

(IRS Code Section 501(c)(12)); (3) RUS mortgage restrictions; (4) state constitutional

restraints; (5) state and local laws; and (6) specific legal restrictions applicable to PMAs. 

In addition, commenters offer a variety of solutions to mitigate or eliminate these

obstacles to public power participation in RTO formation and operation. 

We acknowledge that public power entities face several difficult issues regarding

RTO participation and we appreciate the potential solutions offered by numerous

commenters. At this time, however, we will not analyze each of the specific resolutions

proposed by the various commenters. Instead, on an RTO-by-RTO basis, we will

examine submitted proposals that provide public power and cooperatives with the

flexibility to join an RTO without jeopardizing their tax or mortgage status. We note,

however, that the offered solutions must be consistent with the minimum functions and

characteristics outlined in the Final Rule. 

We are aware that some public power entities and cooperatives have found ways

to participate in existing ISOs. For example, we approved the formation of the NY ISO

contingent upon a ruling of the Internal Revenue Service that the formation and operation
Docket No. RM99-2-000 -591- 

680See Central Hudson Gas & Electric Corp., et al., 83 FERC ¶ 61,352 at 62,405

(1998).

681See Central Hudson Gas & Electric Corp., et al., 88 FERC ¶ 61,138 at 61,402-

03 (1999).

682See Midwest Independent Transmission System Operator, Inc., et al., 84 FERC

¶ 61,231 (1998).

of the NY ISO would not jeopardize the tax-exempt status of the New York Power

Authority. 680 Furthermore, we are encouraged by the recent efforts of the Member

Systems of the New York Power Pool (NYPP) to include and accommodate the

participation of Long Island Power Authority (LIPA) in the NY ISO. NYPP proposed

language in their OATT that provides LIPA will not be required to provide transmission

service where the provision of such service would result in the loss of its tax-exempt

status for its bonds. NYPP also proposed additional scheduling protocols and procedures

to ensure the continued tax-exempt status of LIPA. The Commission accepted the

proposed language as described above. 681 We also note that there are two cooperatives

Hoosier Energy Rural Electric Cooperative, Inc. and Wabash Valley Power Association

that are members of the Midwest ISO. 682 We are hopeful that similar agreements

between RTOs and public power entities and cooperatives can be reached to provide

flexibility and achieve broad regional RTO participation by all entities. 

We expect public power entities and cooperatives to participate fully in the

collaborative process for forming RTOs. During the collaborative process, the
Docket No. RM99-2-000 -592-

Commission hopes that the parties will explore, in detail, the impediments and various

solutions to public power and cooperative participation in RTOs. As discussed below

with respect to the collaborative process, we will make staff resources available to assist

in facilitating communication between all entities and in designing regional solutions to

full RTO formation and participation. Moreover, in all filings under this Rule, we require 

a description of efforts made to accommodate participation by public power entities and

cooperatives in RTOs.

We recognize that there is uncertainty regarding what may happen after the IRS

temporary "private use" regulations expire on January 22, 2001. Accordingly, we intend

to continue to support efforts to mitigate the "private use" and other tax restrictions. 

Furthermore, in its comments, RUS recognizes that the development of RTOs may offer

considerable benefits to RUS borrowers. RUS states that it is exploring means to

facilitate borrower participation in RTOs. The Commission welcomes the efforts of RUS

to facilitate borrower participation in RTOs, and also encourages RTOs to seek ways to

accommodate mortgage restrictions. It would be unfortunate if public power entities and

cooperatives were not able to participate in RTOs and share in the benefits available in a

regional organization because of tax rules and other government restrictions.
Docket No. RM99-2-000 -593-

683FERC Stats. & Regs. ¶ 32,541 at 33,758.

684Id. at 33,758-59.

685Id. at 33,759.

686See PG&E, Desert STAR, Michigan Commission and Industrial Consumers. 

2. Participation by Canadian and Mexican Entities

In the NOPR, the Commission noted that currently, electricity trading regions exist

across national borders and therefore, Mexican and Canadian involvement in RTO

formation would be beneficial to both countries, as well as to the United States. 683 The

Commission asserted that regional institutions should include all market participants in

order to provide direct access to information and the benefits of non-pancaked rates. The

NOPR also proposed that in order to prevent wasteful duplication of grid facilities,

reliability standards implemented by RTOs must be acceptable to the affected nations. 684

The Commission also emphasized that Canadian and Mexican authorities would be

responsible for approving prices and other terms and conditions of transmission service

provided over any RTO transmission facilities located in their country. 685

Comments

The U.S. entities that submitted comments on this issue support the efforts by the

Commission to encourage participation in RTOs by Canadian and Mexican entities. 686

For example, PG&E states that given the high degree of operational interconnection
Docket No. RM99-2-000 -594-

687See, e.g., Ontario Power, H.Q. Energy Services, BC Hydro and Canada DNR.

688See, e.g., Powerex, CEA, Manitoba Board, British Columbia Ministry, Alberta,

Canada DNR, BC Hydro and Ontario IMO.

689E.g., Manitoba Board, British Columbia Ministry, BC Hydro, Canada DNR,

CEA and Ontario Power.

between our national grid and components of their systems, participation by these entities

is beneficial.

Similarly, some Canadian entities believe that significant benefits can be achieved

by trading over "natural" or "appropriate" transmission regions that do not necessarily

stop at the border. 687 Other Canadian entities welcome the opportunity to participate in

the RTO proceedings and support the Commission's efforts to encourage international

collaboration. 688 

 Canadian entities are concerned with sovereignty issues and urge the

Commission to adopt flexible RTO rules that allow voluntary participation by Canadian

utilities. 689 According to the Manitoba Board and Ontario IMO, one option in this

regard would be to allow members of an RTO the freedom to conduct

transactions—through a contractual relationship—at the international border with foreign

utilities that do not join a cross-border RTO. Furthermore, Canada DNR asserts that a

decision not to participate in an international RTO by a Canadian jurisdiction should not

place entities in Canada engaged in trade with United States at a disadvantage. Grand
Docket No. RM99-2-000 -595-

Council et al. proposes that the Commission sever the Canadian issues from this

proceeding and open a separate docket to examine the international issues raised by the

restructuring of electricity markets. Grand Council et al. urges the Commission to

cooperate with Canada and Mexico to establish a genuine tri-national consultative

process in order to resolve international issues based on an adequate record. Alberta

notes that each individual Province has jurisdictional responsibility for the development

of the electrical industry within each Providence and accordingly, only the Province has

the jurisdiction to pass legislation to develop a competitive electricity market.

Commission Conclusion

After reviewing the comments, we continue to believe that Canadian and Mexican

involvement in RTO formation and operation would be beneficial to both countries, as

well as to the United States. As we stated in the NOPR, expansion of electricity trade in

the North American bulk power market requires that regional institutions include all

market participants so that everyone may enjoy direct access to market information and

the benefits of non-pancaked transmission rates. Commenters from the United States and

Canada agree that significant benefits can be achieved by trading over "natural" or

"appropriate" transmission regions that do not necessarily stop at the border. 

We note first that we are pleased with the level of participation in our proceedings

by Canadian parties, and we encourage their continued participation as RTO formation
Docket No. RM99-2-000 -596-

progresses. We especially appreciate the RTO Consultation Conference sponsored by

Natural Resources Canada in Ottawa in November 1999.

In response to Canadian comments, we point out that the Final Rule makes

participation in an RTO voluntary for U.S. transmission owners, and participation is

certainly voluntary for Canadian transmission owners. Further, we emphasize that our

RTO Rule does not in any way require competition in retail electricity markets, whether

they are located in the United States under state regulation or in Canada under provincial

regulation. For those Canadian entities that want to join an RTO, the Final Rule is

flexible: they may propose a cross-border RTO or a Canadian-only RTO that is

compatible with the Rule. The Final Rule is not exclusionary: Canadian entities are not

precluded from joining a cross-border RTO.

Several parties were concerned that a cross-border RTO would have its rates,

terms, and conditions subject to the rate jurisdiction of at least two regulators. If a crossborder RTO forms, we will be open to proposals for innovative approaches for jointly

overseeing a cross-border RTO with domestic and foreign utilities For example, one

approach might be for the cross-border RTO to try to develop a proposal acceptable to

both regulators, with the understanding that any regulatory difficulty would normally be

referred back to the RTO for resolution and resubmission to both regulators. Another

approach might be to have different but complementary rate designs in the two countries.
Docket No. RM99-2-000 -597-

In the case of a Canada-only RTO, some Canadian transmission providers believe

that having contractual and other agreements for coordination between separate RTOs

across the border is better than having a cross-border RTO. However, some Canadian

transmission customers are concerned that this would maintain a lack of standardization

of market rules across the border. The RTO Rule is intended to permit a U.S. RTO on

the Canadian border to develop contractual and other agreements for coordination with its

Canadian RTO neighbor. Further, we have added a new minimum RTO function that an

RTO must ensure the integration of reliability practices with other regions in the same

interconnection and market interface practices with other regions. We clarify here that

this provision applies to integration with interconnected regions in Canada and Mexico.

For either a cross-border or a Canada-only RTO, we acknowledge the sovereign

authority of Canadian governments over Canadian entities and transactions that take place

in Canada. Moreover, we re-emphasize that our Rule does not affect the authorities of

Canadian government entities to approve prices and other terms and conditions of

transmission service provided over any transmission facilities located in Canada. These

conclusions apply equally to Mexico. 

We encourage Canadian and Mexican entities to participate in continued RTO

consultations and, if appropriate, formation and filings for cross-border RTOs. In

particular, we urge Canadian and Mexican entities to attend the appropriate regional
Docket No. RM99-2-000 -598-

690FERC Stats. & Regs. ¶ 32,541 at 33,757.

workshops to be held in the spring of 2000. These workshops will provide a forum for

initial discussion of the issues associated with a cross-border RTOs.

Regarding the suggestion to establish a tri-national consultative process with

Canadian and Mexican authorities to resolve international electric industry issues, we

note that there are existing institutions and processes for resolving international disputes. 

The RTO process is just getting underway, and it is not clear that significant international

disputes will develop or, if they should develop, that they would require a non-traditional

method of resolution. Indeed, the RTO itself through its dispute resolution process may

provide a new and quicker way to resolve some disputes.

3. Existing Transmission Contracts

In the NOPR, the Commission asked for comments addressing what the

appropriate treatment should be for existing transmission agreements when an RTO is

formed. We noted that in Order Nos. 888 and 888-A, the Commission specifically chose

not to abrogate existing requirements contracts and transmission contracts when the

utility filed an open access transmission tariff. 690 We stated, however, that an RTO

represents an entirely different context. In the NOPR, the Commission recognized the

importance of balancing a uniform approach for transmission pricing with the equities
Docket No. RM99-2-000 -599-

691See id. at 33,757-58.

692Id. at 33,758.

693E.g., TANC, Turlock, UAMPS, Desert STAR, CMUA, Sithe, Georgia

Transmission, Lincoln, PG&E, NPRB, NCPA, Great River, NRECA, Loveland

Customers, San Francisco, Platte River, Florida Commission, Nevada Commission, DOE,

Wolverine Cooperative, Tri-State, CREDA, EPSA, Big Rivers, SPP, SoCal Cities, TEP,

PJM/NEPOOL Customers, Metropolitan, STDUG and PacifiCorp. 

inherent in existing transmission contracts. 691 Furthermore, we noted that the potential

financial impact of giving up an advantageous transmission arrangement may serve as a

disincentive to joining an RTO. In the NOPR, we proposed to address the issue of

existing transmission contracts on an RTO-by-RTO basis, rather than resolve the issue

generically. 692

Comments

Many commenters argue that the Commission should preserve and protect existing

transmission contracts. 693 These commenters note that existing contracts represent

negotiated rights and obligations achieved through mutual negotiation. SRP believes that

the Commission should grandfather existing transmission contracts in order to protect

customers from cost shifts and prevent uncertainty in the marketplace. Turlock argues

that the preservation of existing contracts, while cumbersome, is the bedrock of

predictability and reliability and a key element of contract law. NPRB states that existing

contracts should be honored until the contract expires or until the parties come to a new
Docket No. RM99-2-000 -600-

694See, e.g., Williams, EPSA, First Energy, Duke, PSNM, LG&E, PGE and

MidAmerican. 

agreement. STDUG asserts that in order to be properly inclusive, an RTO must take

members as it finds them, existing contracts, warts, and all. In contrast, CP&L asserts

that the elimination of grandfathered agreements to the greatest extent possible ensures

the most level playing field for all market participants. 

A few commenters propose a reasonable transition period to allow parties to

existing contracts to conform their arrangements to an RTO tariff. 694 EPSA notes that

the transition period should be of sufficient length to reduce the financial and other

burdens on the customer and on the original transmission provider. PSNM argues that at

a minimum, a transition period of as long as ten years is needed to move the existing

transmission contracts to RTO service. Furthermore, TAPS proposes that the

Commission provide entities with an open season for transmission customers to choose to

terminate or switch service under the terms of an RTO tariff. Alternatively, TAPS

suggests that the Commission apply a just and reasonable standard to all transmission

customers who seek contract modifications. Regarding contract modification, Southern

Company asserts that in order to promote fairness, both parties to a contract must have an

equal opportunity to modify the existing agreement. In addition, Entergy argues that the

Commission should encourage all entities to re-negotiate existing contracts. 
Docket No. RM99-2-000 -601-

695See, e.g., WPSC, Great River, DOE, ICUA, Entergy, TDU Systems, TEP,

South Carolina Authority, MidAmerican, SNWA, UAMPS and TAPS.

696See United Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 350 U.S. 332, 338

(1956); FPC v. Sierra Pacific Power Co., 350 U.S. 348, 353 (1956).

Several commenters support the Commission's preference that issues relating to

the continued validity of existing transmission contracts be addressed on an RTO-byRTO basis. 695 WPSC argues that treatment of existing transmission contracts within a

particular RTO should be consistent. Turlock urges the Commission to proceed with

caution when addressing existing contracts. On the other hand, PSE&G asserts that the

Commission should not address the treatment of existing contracts on a case-by-case

basis because this leads to arbitrary and inconsistent results. Instead, PSE&G and Dalton

Utilities argue that the Commission should address the issue of existing transmission

contracts on a generic basis consistent with Order No. 888 and the Mobile-Sierra doctrine

(recognizing the need to preserve the sanctity of contracts where possible). 696 Sithe and

NRECA concur that a generic policy is appropriate.

Cal ISO argues that the Commission's policies on existing contracts deserve

revisiting, at a minimum for the limited purpose of conforming scheduling and metering

rules to those of the RTO/control area operator. Cal ISO states that it has experienced the

challenges of workability when the ISO was required to honor existing contracts, but not

permitted to interpret them or conform their scheduling rules to those of the regional
Docket No. RM99-2-000 -602-

697E.g., CMUA, Desert STAR, Georgia Transmission, Wolverine Cooperative, Cal

ISO, Entergy, Tri-State, SNWA, Metropolitan and TEP. 

698See PJM, 81 FERC ¶ 61,257 at 62,280-81 (1997).

699See Midwest Independent Transmission System Operator, Inc., et al., 84 FERC

¶ 61,231 at 62,169-70, order on reh'g, 85 FERC ¶ 61,372 at 62,418-20 (1998).

organization. Cal ISO notes that it has experienced the most significant market

inefficiencies associated with existing contracts in the area of scheduling and information

gathering. 

A few commenters note that not honoring existing contracts would create

disincentives for both transmission customers and owners to join an RTO. 697 For

example, CMUA and Georgia Transmission argue that the financial impact of giving up

an advantageous transmission arrangement would be a significant disincentive to RTO

membership.

Commission Conclusion

At this time, we continue to believe that it is not appropriate to order generic

abrogation of existing transmission contracts. We recognize that existing contracts

represent negotiated rights and obligations achieved through mutual negotiation. 

However, in PJM 698 and the Midwest ISO 699 we adopted the rationale that it was

unreasonable and discriminatory to maintain the pancaked rates in existing contracts for

others when transmission-owning utilities had designed a non-pancaked rate approach for
Docket No. RM99-2-000 -603-

their own transactions. In our examination of existing contracts, we intend to balance the

preference for preservation of existing contracts with the importance of consistency in

transmission pricing and the elimination of pancaked rates. 

As the above comments demonstrate, there is no consensus on how the

Commission should manage the transition from existing transmission contacts to RTO

service. In fact, parties offer diverse and conflicting views as to what the Commission

should do regarding existing transmission contracts. Some commenters would have us let

all contracts run their course with no opportunity to modify or terminate. Others

advocate an elimination of existing agreements to the greatest extent possible. Yet others

argue for a transition period ranging in duration for up to ten years to move existing

transmission contracts to RTO service.

Rather than adopting one extreme position or the other, we will take a measured

approach with regard to the treatment of existing transmission contracts. We intend to

address the issue of existing transmission contracts on an RTO-by-RTO basis, rather than

resolve the issue generically. Accordingly, each RTO can propose whatever contract

reform is necessary, including the limited changes suggested by the Cal ISO for the

limited purpose of conforming scheduling, information gathering, and metering rules to

those of the RTO. To this end, we encourage each RTO to address how and when it

might convert existing contracts and submit a contract transition plan that contains
Docket No. RM99-2-000 -604-

specific details about the procedures to be utilized involving the conversion from existing

contracts to RTO service. Again, our goal in reviewing existing transmission contracts

and contract transition plans is to balance the desire to honor existing contractual

arrangements with the need for a uniform approach for transmission pricing and the

elimination of pancaked rates. 

4. Power Exchanges (PXs)

The NOPR described the apparent advantages and disadvantages of having a

power exchange coincident with an RTO. As further described in the NOPR, supporters

state that PXs can reduce price volatility by providing price transparency, reduce the

impact of defaults by spreading transaction risks among all participants through credit

standards and reserve fund requirements, facilitate risk hedging by providing a basis for a

futures market, and help facilitate retail access programs. Detractors argue that the

principal functions of a PX are not natural monopoly functions. They contend that PXs,

compared with bilateral markets, force participants to buy and sell electricity using

standardized contracts, which may not suit their particular needs. They further argue that

competition within the electricity market and its full benefits can only be achieved if there

is competition for the PX market. 
Docket No. RM99-2-000 -605-

700FERC Stats. & Regs. ¶ 32,541 at 33,760.

701See, e.g., Entergy, NJBUS, NY ISO, TDU Systems, Wisconsin Commission

and UtilitCorp. 

702See, e.g., Pennsylvania Commission, Duke and California Board.

703See, e.g., PJM, ISO-NE and TAPS.

704See, e.g., EPSA and MidAmerican.

The NOPR left it to each region to determine whether there is a need for a power

exchange and whether the RTO should operate it. 700 The NOPR said that the

Commission will accept any RTO proposal that includes a power exchange in its design

as long as its operation of the power exchange does not compromise its independence as a

transmission service provider. The Commission sought comments on a number of

questions related to power exchanges, including whether regional flexibility is

appropriate and how RTOs should deal with an independent power exchange.

Comments

Commenters' views on power exchanges are mixed. The largest group of

commenters basically agree with the NOPR. 701 A smaller group of commenters

recommend that the Commission require that RTO applications include provisions for a

power exchange, 702 with some recommending that the power exchange be internal to the

RTO 703 and some recommending that the PX be independent of the RTO. 704 CalPX

argues strongly that a power exchange should be separate from the RTO, given the
Docket No. RM99-2-000 -606-

705See, e.g., APX, SMUD, Southern Company, Tri-State and Lincoln.

continuing need to separate market and transmission functions; the need for market

transparency to facilitate determination of whether congestion is being exploited; the

need to provide a credible reference price for new retail choice market entrants; and the

potential need for the RTO and power exchange to serve differing geographic areas. 

CalPX also submits that there is no concrete evidence that an RTO-operated power

exchange will be more efficient and economical than an unrelated power exchange. 

NYMEX agrees that an RTO should be permitted to operate a power exchange, as long as

a proper code of conduct is in place. PJM points to its success with a combined

ISO/power exchange.

Another group of commenters argue that power exchanges should not be included

in RTOs, but should be allowed to occur naturally as needed. 705 Elaborating on this

point of view, Salomon Smith Barney advises that the power exchange should not be in

the RTO because it could throttle innovation and that the Commission should let the

market decide. If there are really advantages to be gained, as some claim, from the

operation of a single power exchange associated with the RTO, then such a power

exchange will naturally develop. Florida Power Corp. argues that, while a region may

prefer that its RTO closely coordinate with the power exchange, the two should not be

part of the same organization because there is a fundamental difference in the business
Docket No. RM99-2-000 -607-

706See, e.g., Duke, Florida Power Corp. and Desert STAR.

objectives of the two . Similarly, EPSA contends that the Commission's vision of an

RTO being an entity independent from all generation and power marketing interests is

fundamentally incompatible with an RTO-run power exchange. Nevada Commission

offers that a power exchange is not necessary to the formation of an RTO. And while

PG&E sees every region needing a real-time balancing market regardless of whether it is

run in-house by the RTO, PG&E also prefers that markets should otherwise be left to

develop on their own accord.

Comments were received on additional aspects of the power exchange concept. 

PG&E argues that an RTO should not be allowed to use control of a power exchange to

alter or cap prices set by the market. LG&E submits that the RTO should be required to

be the provider of last resort for ancillary services, although market participants should

not be required to purchase from the RTO. NASUCA notes that the NOPR does not

cover some important power exchange issues such as exactly which markets would be

included. NASUCA recommends that a NOI on power exchanges and related power

market issues be initiated soon after the final rule.

Several commenters state that multiple power exchanges in a region should have

equal standing before the RTO. 706 FTC, however, recommends that the Commission

assess whether competition is feasible in power exchange services. Similarly, CalPX
Docket No. RM99-2-000 -608-

notes that multiple power exchanges may hurt the market's function because each power

exchange would be small, and therefore would not offer high levels of depth, liquidity

and efficiency. NYMEX counters that there should be no credence given to the idea that

one power exchange should enjoy any form of artificial franchise vis-a-vis others.

Commission Conclusion

The NOPR proposed leaving it to each region to determine whether there is a need

for a power exchange and whether the RTO should operate the power exchange. We

have decided to adopt the NOPR proposal. As the commenters have pointed out, there

are advantages and disadvantages to the inclusion of a PX in the RTO structure. We do

not believe that including a PX as part of the RTO structure would necessarily preclude

the market benefits associated with bilateral transactions. We believe an RTO can

accommodate both a bilateral market and a PX market. As the individual structures of the

various RTOs supported by the regions are likely to be quite varied, we think that it is

best to let market preferences dictate the form of any one or more regional power

exchanges and whether the RTO should operate a power exchange.

5. Effect on Retail Markets and Retail Access

The NOPR addressed the impact of RTOs and any associated PXs on retail

competition and the states' jurisdiction over retail competition. For example, the

Commission found that RTOs will enhance the effectiveness of retail competition:
Docket No. RM99-2-000 -609-

707FERC Stats. & Regs. ¶ 32, 541 at 33,704.

708See, e.g., TXU Electric, DOE, First Rochdale, Illinois Commission and

Williams.

We believe that the likelihood of success for existing and planned retail

choice initiatives is significantly enhanced if the Commission can ensure

fair and efficient access to a regional market without pancaked transmission

access charges, and that we need to take steps beyond Order No. 888 to

accomplish this. 707

In addition, the Commission found that an RTO does nothing to interfere with the state's

authority to decide retail access policy, but asked whether a PX is necessary for

successful retail competition.

Comments

Several commenters state that RTOs were either essential or of great benefit in the

implementation of retail competition. 708 Mid-Atlantic Commissions notes that PJM has

worked closely with the Pennsylvania, New Jersey and Delaware Commissions to assist

with the implementation of their retail choice legislation in an organized fashion, while

maintaining that the grid will be operated in a reliable fashion without any major

economic or operational changes. According to Mid-Atlantic Commissions, this has also

further provided those states in the region that have not implemented retail choice with a

stable organization that continues to maintain reliability.
Docket No. RM99-2-000 -610-

709See, e.g., Iowa Board and Puget.

A few commenters express concern that the Commission's RTO policy could

threaten the states' ability to control the pace of retail access and retail competition. 709

South Carolina Commission counsels that the Commission should try to avoid affecting

retail restructuring through its efforts to establish an RTO process. Central Maine raises

the concern that retail choice programs already developed in concert with existing ISOs

may be adversely impacted by any changes to such ISOs that are found to be necessary

for them to conform to the RTO requirements (e.g., energy service company and other

load serving entity contracts entered into in reliance upon the existing ISO market

structures).

Puget views allowing RTOs to make FPA section 205 filings that unilaterally

propose changes to the RTO tariff as conflicting with the Commission's commitment to

respect the retail access efforts of the individual states. Puget argues that a unilateral

decision by an RTO to provide transmission service to a retail customer and make that

customer an eligible customer under the pro forma tariff would force states without retail

access to accept such access as a fait accompli. Puget also fears that the term "market

participant" as ultimately defined may include any entity that buys or sells electric energy

in the RTO's region or in any neighboring region that might be affected by the RTO's

actions. If so, since market participants must also have the option of self-supplying or
Docket No. RM99-2-000 -611-

acquiring ancillary services from third parties, this further suggests that retail customers

may have the ability to acquire transmission service regardless of whether the affected

state has yet decided retail choice and stranded cost recovery issues. Industrial

Customers, however, question the legal basis for Puget's apparent suggestion that utilities

be allowed to decide which retail customers may access RTO transmission.

EPSA contends that, while states tout each state's rights to protect its retail native

load customers, some actions taken under this banner to limit exports of power actually

disadvantage adjoining state's retail customers or participants in the bulk power markets. 

Therefore, the Commission should move forward with a rulemaking to assure full

transmission comparability for retail customers of all states, and to prevent individual

states from continuing to disadvantage each other and to prevent individual utilities from

continuing to disadvantage other market participants. New York Commission also

submits that this proceeding is not the place to address the issue of preemption of state

jurisdiction over bundled retail electric sales.

TAPS raises the question of jurisdictional conflict as to which facilities need to be

regulated at the federal or state level, and whether the policies of the Commission toward

open access will be undercut by transmission owners using the seven factor

transmission/distribution classification test to place new generation at a disadvantage

relative to existing generation owned by the transmission provider. TAPS contends that

the Commission must take steps to ensure that RTOs contain the appropriate facilities and
Docket No. RM99-2-000 -612-

710See, e.g., LG&E and Southern Company.

that refunctionalization of transmission to distribution does not interfere with competition

by creating RTOs that control little or no transmission. 

Another concern expressed is that RTOs may cause cost shifting to retail

customers that could interfere with restructuring. 710 As to the impact of the power

exchange on retail competition, both CalPX and MidAmerican argue that power

exchanges assist in the effectiveness of retail competition programs by providing

transparent and credible reference prices.

Commission Conclusion

We continue to be persuaded that RTOs can positively affect each state's

implementation of its retail choice program, without interfering with those states that

have not yet adopted such programs. As noted by commenters, existing ISOs have

already successfully facilitated retail choice programs in areas where only some of the

states have adopted such programs, and the ISOs were able to do so without clashing with

or frustrating the other states that have not undertaken such programs. We do not believe

that an RTO could interfere with a state’s decisions on whether or how fast to implement

retail choice within its borders, either through the RTO's Section 205 filing authority or

otherwise through the RTO's jurisdictional obligation to provide non-discriminatory and

non-preferential transmission service. 
Docket No. RM99-2-000 -613-

711See supra section III.G.

Commenters pointed to potentially extensive reclassification of transmission

facilities to local distribution as part of the unbundling of retail rate schedules to

implement retail choice programs, and how this might lead to RTOs that are "empty

vessels" with little significant transmission under their control. We agree that RTOs must

control all transmission facilities that are necessary to support competitive wholesale

power markets. For this reason, we specified the scope, configuration and operational

control requirements adopted in this Final Rule. We will judge any proposed

reclassification on a case-by-case basis. We note that any reclassification of transmission

facilities to local distribution will require Commission approval and will not remove from

the Commission's jurisdiction any facilities used to deliver power to wholesale customers. 

Furthermore, under the principle of open architecture (discussed supra in section III.F ),

the Commission expects RTOs to remain flexible such that, if over time circumstances

should change and certain facilities need to be reclassified as transmission, procedures

will be in place to do so. 

With regard to RTO pricing causing transmission cost shifting that adversely

affects retail choice customers, this issue is discussed in the Transmission Ratemaking

section of this Final Rule. 711 The Commission will continue to review transmission rate

proposals to ensure that they are just and reasonable, and not unduly discriminatory.
Docket No. RM99-2-000 -614-

712For a further discussion of PXs, see supra section III.H.4.

713FERC Stats. & Regs. ¶ 32,541 at 33,722.

714See id.

Finally, on the matter of whether a power exchange is needed to facilitate states' 

retail choice programs, it is our view that, to the extent that a region forming an RTO

chooses to voluntarily establish an RTO-affiliated power market, we anticipate that any

such power exchange would provide retail choice customers with transparent and credible

reference prices for power and other information that otherwise might not be available.

712

6. Effect on States with Low Cost Generation

In the NOPR, we recognized that states with relatively low cost power are

concerned that an RTO would result in local utilities selling their low cost power to other

states. 713 However, we noted that a state that is low cost today may not be low cost

tomorrow without an RTO in its area. 714 In addition, we stated that utilities that now

have low cost generation will help assure access to future low cost generating plants by

participating in an RTO and that new low cost generation plants are more likely to be

attracted to regions with a well-functioning regional market governed by an RTO. We

sought comment from state commissions regarding how an RTO in their state would

affect power costs.
Docket No. RM99-2-000 -615-

Comments

A number of commenters raise concerns about the effect of RTOs on states with

low cost electricity. These concerns center around one issue—that the costs of creating

an RTO may outweigh the benefits.

South Carolina Commission argues that customers in South Carolina enjoy very

high quality service and pay some of the lowest rates. Duke power concurs, noting that,

it is not necessarily true that North Carolina and South Carolina will conclude that

sufficient long-term benefits exist for these states to justify costs of RTO membership. 

Duke argues that any proposed RTO should be shown to provide tangible benefits to the

relevant region.

Alabama Commission believes that RTOs will cause states to lose the efficiency of

integrated systems and lead to retail competition, whether it is in the interest of customers

or not. Southern Company agrees, noting that due in large part to the low cost status of

southeastern states, they are proceeding cautiously with retail competition and

restructuring initiatives. This does not mean that these states are ignoring the potential

benefits of restructuring. Indeed, Southern Company notes that states in its service

territory are actively studying the potential advantages and disadvantages of retail

competition but have not yet concluded that the potential benefits outweigh the costs and

risks associated with changing the current industry structure.
Docket No. RM99-2-000 -616-

SMUD points out that it has not joined the Cal ISO over similar concerns. It

indicates that its customers already enjoy low cost electricity and that participation in the

Cal ISO could not ensure that SMUD's retail rates would be any lower, and on the

contrary, the cost of participation would cause rate increases.

Kentucky Commission indicates that inefficiencies may occur for a variety of

reasons and examples of inefficiencies include: multiple RTOs in a small region; several

layers of governance within one RTO; and too many tasks shifted from the RTO members

to the RTO itself. Kentucky Commission argues that if the proposed transmission

organizations are not operated at levels of maximum efficiencies and minimum

reasonable costs, the Commission will have failed to promote one of its primary

objectives, the growth and success of the wholesale power market. Kentucky

Commission further argues that the Commission must be mindful of these costs in

developing rules for the establishment of RTOs

Commission Conclusion

We are mindful of the potential costs of setting up and running an RTO, but we

anticipate that the collaborative process will result in an RTO proposal that incorporates a

design that, overall, increases the existing level of transmission system and market

efficiency for each region. As we discuss more fully in the Scope, Implementation and

Benefits sections of this Final Rule, we are taking a results-oriented, practical approach to

establishment, organization, implementation and operation of RTOs. We do not expect
Docket No. RM99-2-000 -617-

that regions with no existing institutions will necessarily invest in new, high-cost RTO

infrastructure. Instead, such a region may propose an RTO that relies on existing

infrastructure to accomplish its mission. However, we expect the RTO to satisfy the

minimum characteristics and functions and to improve the efficiency of regional

transmission service.

In response to the concern of low cost states that RTOs could result in exports of

their low cost power to other states, we do not believe that an RTO will cause utilities to

sell their lowest cost power out of state. While retail choice arguably might lead to low

cost power being sold out of state because incumbent utilities no longer have an

obligation to serve local in-state loads, this would occur with or without an RTO in the

region. Where there is no retail choice, our Final Rule does not affect a state

commission's authority to require a utility to sell its lowest cost power to native load, as it

always has. We point out that, if the utility's transmission is operated by an RTO and its

higher cost power can be sold more readily to new, more distant customers, this will lead

to recovery of more capital costs and lower retail rates. In the long term, low cost states

may benefit from an RTO that facilitates expanded access to wholesale electricity

markets, increasing the choice of low cost resources available to utilities as they acquire

new power resources. 
Docket No. RM99-2-000 -618-

715FERC Stats. & Regs. ¶ 32,541 at 33,724.

7. States' Roles with Regard to RTOs

In the NOPR, we noted that states want a role in the governance of any RTOs for

their states, and we proposed to be flexible in accommodating the states' needs. 715 The

NOPR encouraged RTO design to accommodate appropriate state oversight, especially

with regard to planning and siting new multi-state transmission facilities. We sought

comments on the appropriate state role in RTOs on these and other RTO matters.

Comments

Comments on the states' roles in RTO development and governance were fairly

extensive, with by far the greater percentage of comments supporting a strong and clearly

defined state role. Comments can be grouped into four primary categories: (1)

governance; (2) formation; (3) siting and planning authority; (4) regional regulation.

Governance

Almost all commenters on this issue expressed support for a clear state role in

governance; however, there were differences as to exactly what that role should be. 

Some commenters believe that states should be allowed to determine their own role in

governance, either as members of advisory panels to the board of directors, as voting

members of the board, as non-voting members of the board, or having authority to
Docket No. RM99-2-000 -619-

appoint board members. Some commenters, however, feel strongly that states should not

be permitted to be voting members of boards.

Commenters argue that the appropriate state role in an RTO is a matter of local

control. For example, Northwest Council states that the Commission should not set

restrictive rules on the type of state participation in RTO governance, but should allow

the states to propose to the Commission the kind of roles they view as appropriate, e.g.,

voting members of a stakeholder board, ex officio status on an independent board, and so

forth. 

The California Board suggested that state officials should be allowed as either

voting or non-voting members. Los Angeles has no objection to state board membership,

either voting or non-voting, if a state has determined that a government official can best

represent that state's interests. The Washington Commission agrees that states should be

able to define their own role. Mid-Atlantic Commissions note that they have a

Memorandum of Understanding with the PJM ISO Board of Managers to facilitate

communication and promote a cooperative relationship.

Some commenters, however, think that state officials should not have voting

membership on boards of directors since that could raise conflict of interest problems

where the state official would have to approve decisions of the board while sitting as a

regulator. For example, Minnesota Power believes that state cooperation will be

enhanced if state officials participate as members of an RTO advisory board, but they
Docket No. RM99-2-000 -620-

716See also MidAmerican, Montana-Dakota, PSNM, East Kentucky and NPRB. 

717E.g., ISO-NE, PJM, Midwest ISO, MidAmerican, Project Groups, PSNM, Iowa

Board, Arizona Commission and UAMPS. 

should not participate as voting members of an RTO because the RTO process could be

compromised by parochial state politics. ISO-NE agrees, pointing out that some states'

conflict of interest laws may expressly prohibit such service, and that it might be difficult

for an official from one state to make decisions as a board member that are good for

residents of all states encompassed by the RTO. 716 WEPCO believes the appropriate

role of the states in RTO governance includes active participation in regional planning

efforts and continued oversight of siting of new transmission facilities. In addition, many

commenters supported an advisory role for state officials, through advisory boards. 717

Formation

Numerous commenters supported a role for states in the formation of RTOs. ISONE points out that the states in its region had a significant role in the development of the

ISO. In addition, the California Board argues that states should have a role in

determining the structure of the RTO and any other market institutions that are formed to

serve the citizens of their respective states. California Board further notes that

mechanisms to ensure that states' interests are protected might include statutory or

regulatory reliability criteria; independent market monitoring by the states or requiring
Docket No. RM99-2-000 -621-

market monitoring reports to be provided to the state; and accountability to the states to

ensure adequacy of transmission and generation planning.

The Michigan Commission notes that most states have little direct authority to

order the development of an RTO, especially when the RTO encompasses several states. 

According to the Michigan Commission, at best state commissions should serve in an

advisory role as the utilities develop the structure and guidelines of the RTO proposal. 

The Michigan Commission, however, joins a few other states in urging the Commission

to defer to state recommendations once the basic RTO characteristic and functional

guidelines have been met.

NARUC comments extensively on the potential collaborative process and the

importance of state participation in this process and other steps in the formation of RTOs. 

To achieve the public policy goal of assuring reliable service at an affordable cost,

NARUC argues that states should fully participate in RTO development and formation,

particularly in matters for end-use native load customers. NARUC notes that based on

some states’ retail choice or ISO experiences, state oversight can play a significant role in

assuring a well-functioning ISO and competitive wholesale and retail markets .

NARUC further suggests that once RTOs are formed, continuing interaction is

necessary, and market development and evolution will be continuous. NARUC believes

that RTO formation must continue to be a dynamic process requiring continuing dialogue

between FERC and the states. NARUC further believes that once organizations are
Docket No. RM99-2-000 -622-

formed and approved, some type of formal reporting to FERC and the states by the

organizations on an annual basis would be appropriate. 

Nine Commissions suggests that state commissions are well positioned to balance

the competitive motivations of utilities in the RTO formation process with the interests of

all other stakeholders in defining markets in their respective regions and conforming the

RTO boundaries to those markets. According to Nine Commissions, the state

commissions' continued cooperation with FERC will ensure that the mutual public

interests of providing reliable electric service will be met, and that market participants in

every region of the country will be treated comparably. 

Siting, Planning and Reliability

A number of commenters, many state commissions, and quite a few other parties,

argue strongly that the Commission should be careful not to preempt traditional state

regulatory authority in promulgating its rule. In particular, commenters suggest that the

Commission should not usurp state authorities over siting, planning, and reliability of the

transmission system. Some commenters proposed solutions to state/Federal jurisdiction

issues in the RTO context, such as joint state/Federal review bodies. The Alabama

Commission suggests that FERC should not take any action that would infringe on state

jurisdiction.

South Carolina Commission asserts that transmission siting should remain in the

hands of the states and local governments. South Carolina Commission further asserts
Docket No. RM99-2-000 -623-

that states must continue to have a significant role with regard to matters of reliability for

end-use native load customers. The Iowa Board concurs and suggests that the

Commission’s RTO policies cannot alter states’ continued interest in local matters such

as transmission and generation siting, local transmission and distribution interface issues,

adequacy of generation and transmission, service quality, and retail rates.

The Montana Commission notes that in roughly half the states with siting laws the

function is not vested in the regulatory commission, but rather in a separate energy

policy, environmental or commerce agency. They recommend that the Commission

amend the language in the Final Rule to make it clear that the Commission does not

intend to preempt state siting authority as part of this NOPR.

UAMPS warns that RTOs may create a separation between generation planning

and transmission planning that endangers reliability. UAMPS argues that states must be

left with authority to assure reliability and that retail competition issues should also be

left to the states. UAMPS suggests that because state cooperation and participation will

be so critical to an RTO's effectiveness, in addition to the four minimum characteristics

the Commission has proposed, RTOs should be required to provide specifically for

significant state involvement in their development and operation. Allegheny, on the

contrary, states that system operations in an RTO will be pursued for the good of the

RTO service area, not of any one state. Allegheny notes that if that fact yields a dilution

of state authority it must be the price paid for RTO benefits.
Docket No. RM99-2-000 -624-

Regional Regulation

A number of commenters propose or support regional regulatory cooperation or

joint state/Federal sharing of jurisdiction. The Kentucky Commission proposes the

creation of a Federal/state “joint board,” that is styled similarly to the Universal Service

Joint Board currently used by the Federal Communications Commission, state utility

commissions, and other parties. The Kentucky Commission suggests creating this

voluntary Board to develop and review standards for transmission expansion. The Joint

Board would include participation from FERC, state commissions, RTOs, and other

interested parties. The Joint Board would also convene ad hoc committees to review

specific transmission expansion proposals. These committees would include the

participants described above, and would include representatives from regulatory

commissions in states where the expansion is proposed. The RTO would present the ad

hoc committee with a plan for transmission expansion with appropriate documentation for

need, cost effectiveness, and alternatives. The committee would in turn pass on its

recommendation or refusal of support for the plan to the specific state commissions for

their official approval. The Kentucky Commission believes that such an arrangement

could avoid Federal/state conflict while allowing both levels of government to exercise

appropriate jurisdiction. In addition, ISO-NE points to existing regional regulatory

groups such as NECPUC that could continue to provide valuable assistance to the
Docket No. RM99-2-000 -625-

Commission in the collaborative process to encourage RTO formation envisioned in the

NOPR.

Nine Commissions argues that an appropriate regional oversight venue will lead to

more consistent treatment of issues and parties between state and Federal regulatory

forums. With appropriate deference by both FERC and the states, such a regional venue

could obviate the need for many parties to expend redundant resources to participate in

multiple state and Federal regulatory processes for matters relating to transmission and

RTOs. 

Nine Commissions notes that one possible mechanism to effectuate such a regional

venue is interstate compacts, which are provided for in the Administration’s proposed

electric industry restructuring legislation. Nine Commissions argues that regional

regulatory organizations have the advantage of being able to coordinate state interests for

providing regional recommendations to FERC. State oversight functions (e.g. siting,

local outages, customer complaints) would not change. According to Nine Commissions,

such regional regulatory organizations would provide greater coordination among states

within the region, allowing for ADR processes that could satisfy multiple state

jurisdictional requirements, and such organizations would monitor markets that have

evolved beyond state borders and facilitate joint FERC and multi-state facilities siting. 

Pennsylvania Commission prefers a joint Federal/state approach toward regulating

RTO siting approvals, expansion, innovation and customer service. Pennsylvania
Docket No. RM99-2-000 -626-

Commission notes that a joint approach would resolve the vexing problem of

Federal/state jurisdictional uncertainty and a joint Federal/state approach would avoid the

potential for creative forum shopping by individual stakeholders, who will always seek to

cast a dispute in jurisdictional terms so as to dictate a jurisdictional resolution to the

perceived favorable outcome. A joint Federal/state approach has been used with success

in other areas, such as the Susquehanna River Basin Commission, the Delaware River

Basin Commission and the Joint Pipeline Office for the Trans-Alaska Pipeline System. 

Likewise, the Virginia Commission believes that there is no conflict between state goals

and Commission goals and that the two levels of government should be able to work

together and avoid conflict as long as both parties recognize that the common goal is the

public interest. 

Commission Conclusion

We continue to believe that states have important roles to play in RTO matters. 

For example, most states must approve a utility joining an RTO, and several states have

required their utilities to turn over their transmission facilities to an independent

transmission operator. Also, states must approve the siting of transmission facilities that

are called for in an RTO expansion plan.

We believe, however, that it is not appropriate to try to set out a full set of states'

roles in this Rule. It is difficult, and not necessary, to reach generic conclusions about

states' roles given the diversity of possible RTO forms and state authorities. For example,
Docket No. RM99-2-000 -627-

a state's role may be different for an ISO, transco, and other organizational form, and it

may be different for a multistate RTO and a single-state RTO, if any. States differ

regarding the authorities they have vested in their regulatory and siting agencies. Further,

states differ regarding their jurisdiction over municipal and cooperative utility owners of

transmission facilities.

Regional interests forming an RTO should consult with the states about what state

roles best fit the agencies' authorities and preferences and the organizational form of the

RTO. This role could vary from state to state within an RTO. Therefore, this Rule takes

a flexible approach that allows states to play appropriate roles in RTO matters, consistent

with this Commission's exclusive responsibilities and authorities under the FPA..

We note that we have discussed the role of states for particular RTO functions

elsewhere in this Final Rule. Regarding RTO formation, the Background discussion

above discusses the role that several states played in creating many of the existing ISOs. 

It also describes our initial consultations with state regulators on RTO formation and our

roles in FPA section 202(a) implementation; in those consultations we offered to continue

the RTO dialogue with states in the future. The form of consultation to be used should be

decided based on the issues and the region so we will not endorse or reject here any

particular form of collaboration. However, in the Collaborative Process discussion

below, we set out our plans to invite states and others to work with us to foster RTO

formation beginning early next year.
Docket No. RM99-2-000 -628-

In our discussion above of the Independence characteristic, we discuss the role of

state agencies in governance, making the point that states will play a key role in RTO

formation and development but declining to specify generically a state's role in

governance. Also, in our discussion above of the RTO Planning and Expansion function

we recognize the exclusive authority of state and local governments and regulatory

agencies over the siting of transmission facilities, and we include in our regulations the

standard that an RTO must accommodate efforts by state regulatory commissions to

create multi-state agreements to review and approve new transmission facilities.

8. Accounting Issues

Although not discussed in the NOPR, EEI commented on some accounting aspects

of RTOs. It urges the Commission to address two primary accounting issues for of

RTOs: (1) the need to revise the Uniform System of Accounts (USofA) and related

reports to reflect new RTO and other unbundled rate structures; and (2) the ability of

RTOs to use regulatory accounting.

a. Revision of the Uniform System of Accounts

Comments

EEI contends that because the Commission's USofA was developed when utilities'

products were bundled and fully regulated, it needs to be revised to support the

Commission's adopted policies and this proposed rule. EEI believes that with unbundling
Docket No. RM99-2-000 -629-

718Another significant area cited is whether the Commission should modify its

original cost accounting requirements for property acquisitions to conform with the

evolving fair value requirements of the Financial Accounting Standards Board (FASB). 

See Appendix I to EEI Comments at 11.

of rates, the USofA will need to be revised to reflect, among other things, 718 cost

functionalization (e.g., by generation, transmission, distribution, etc.). EEI also believes

that the Commission should specifically address the accounting to be used for RTO

reporting purposes, as the current USofA was not designed for use by RTOs. EEI states

that it is very willing to work with the Commission's staff to address the specific changes

that should be made to the USofA.

Commission Conclusion

 The Final Rule permits the various regions to select different organizational forms

for RTOs. Our open architecture structure for RTOs permits applicants to select the

business organization best suited to the needs of its members and RTO participants. It

would therefore be difficult to prescribe in this proceeding specific changes to our

existing USofA that would accommodate the needs of all RTOs. 

We believe a better course at this juncture would be to require RTOs to conform

their accounting to our USofA (as have ISOs) and to submit questions of doubtful

interpretation to the Commission for individual or generic rulings on particular

transactions, events and circumstances. 
Docket No. RM99-2-000 -630-

719The special accounting rules are primarily contained in Statement of Financial

Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation

(SFAS 71). One of the primary accounting differences is the ability to defer expense

recognition of an incurred cost if it is probable that the utility will recover that cost in

future cost-based regulated rates.

720Conversely, according to EEI, the inability of an entity to use SFAS 71

accounting could have an adverse effect on earnings, which may be viewed unfavorably

by investors. According to EEI, one example would be where the Commission approves

a rate levelization plan (e.g., under capital lease transactions) under which rate recovery

of certain costs would be deferred until future years. If a utility could not defer expense

(continued...)

However, we agree with EEI's observation that unbundling of utility services, and

other changes in the industry require the Commission to re-examine its existing

accounting and related reporting requirements. This is true not only for the new types of

utilities that have emerged in the industry such as ISOs, PXs and RTOs, but also for

traditional public utilities. The Commission staff has been and will continue to meet with

EEI and others, and will continue its efforts to address the specific changes that may be

needed as the industry restructures. 

b. Ability to Use Special Accounting

Comments

EEI asks the Commission to consider the impact of its actions on the ability of

RTOs to use the special accounting rules applicable to cost-based rate-regulated

entities. 719 EEI believes that the ability to use regulated accounting would be

advantageous to RTOs and viewed favorably by the investment community. 720 EEI
Docket No. RM99-2-000 -631-

720(...continued)

recognition of such costs, earnings would be depressed in the early years of the

levelization plan. 

urges the Commission to structure alternative ratemaking methods (e.g., price and

revenue caps, incentive-based rates and price indexing) to allow RTOs to continue to use

the special accounting of SFAS 71. In this regard, EEI believes that if the Commission

decides it is advantageous to stimulate the establishment of RTOs by ensuring that all

start-up costs are ultimately recovered through FERC jurisdictional rates, it could issue

ratemaking orders that defer expense recognition of these costs, and allow for future

ratemaking recovery. Similarly, EEI urges the Commission to address the time frame

over which software development costs could be recovered through rates and to allow

utilities to defer expense recognition of such costs. To enhance cash flows from

operations, EEI suggests that the Commission accelerate the amortization of all

capitalized software costs. These actions, according to EEI, would likely be viewed

favorably by the investment community. 

Commission Conclusion

RTOs may propose and we are willing to consider alternative ratemaking methods

including proposals to delay rate recovery of certain expenses. We will not prescribe any

specific requirements at this time but allow RTOs to propose those methods which are

appropriate for each RTO's facts and circumstances. In this regard, we intend to take a
Docket No. RM99-2-000 -632-

721The Commission has already given considerable guidance on numerous market

design issues in a number of orders. See Pennsylvania-New Jersey-Maryland

Interconnection, L.L.C., 81 FERC ¶ 61,257 (1997); Central Hudson Gas & Electric

Corp., et al. 86 FERC ¶ 61,062 (1999); New England Power Pool, et al. 87 FERC ¶ 

61,045 (1999); AES Redondo Beach, et al., 87 FERC ¶ 61,208 (1999).

722See Staff Report to the Federal Energy Regulatory Commission on the Causes

of Wholesale Electric Pricing Abnormalities in the Midwest During June 1998

(September 28, 1998).

flexible regulatory approach toward approving RTO rate design proposals and strive to

include adequate information in our rate orders on the appropriate accounting treatments.

9. Market Design Lessons

We expect that bid-based markets will be a central feature in many RTO

proposals. To date, the Commission has analyzed and approved, with various

modifications, bid-based market designs for four ISOs. The purpose of this section is to

summarize the lessons learned from these real-world market experiments. The summary

provided below is not intended to favor one market design over another, but is intended to

assist RTOs in evaluating existing market designs and meeting the deadlines set forth in

this rule. 721 

Cal ISO, PJM and ISO-NE have had operational experience with their respective

market designs. For the most part the markets operated by these ISOs have functioned

well, and they have not experienced many of the problems encountered in the bilateral

markets in the Midwest and the Southeast. 722 However, each of the operational ISOs has
Docket No. RM99-2-000 -633-

723The NY ISO has had little operational experience with the particulars of its

markets design.

724See New England Power Pool, et al., 87 FERC ¶ 61,055 (1999); AES Redondo

Beach, et al., 87 FERC 61,208 (1999); New York Independent System Operator, Inc. et

al., 88 FERC ¶ 61,228 (1999).

725For example, energy and operating reserve products may be offered in realtime.

encountered some market design problems that have resulted in unexpected or

undesirable market outcomes. 723 These outcomes have led some ISOs to file many

market design changes and requests for temporary remedies or protections until

permanent design changes can be implemented. 724

a. Multiple Product Markets

The bid-based markets that we have approved to date are premised on the

assumption that acceptance of voluntary supply and demand bids which maximize overall

net benefits will also maximize efficiency. Each approved ISO design employs some

bid-based mechanism to ramp resources up and down to balance the system, manage

congestion, and to supply some ancillary services. Employing bids that indicate a

generator's willingness to be ramped down, ramped up, or placed in reserve is an

economic way to balance the system, manage congestion and maintain appropriate

reserves, both in real time and in any day-ahead markets. However, if more than one

product is being sold in the same temporal market, 725 efficiency is maximized when

arbitrage opportunities reflected in the bids are exhausted (i.e., after the RTO's markets
Docket No. RM99-2-000 -634-

726One would expect that services with more stringent technical requirements 

ordinarily have higher costs for providing those services. The prices of these services

should reflect the costs. For example, spinning reserves have more stringent requirements

and would be expected to command a higher price than non-spinning reserves. 

727See Report of the Market Surveillance Committee of the California Independent

System Operator, October 18, 1999 (MSC October Report). Both ISOs have seen prices

for services such as non-spinning reserve products, which do not require a unit to be

running, higher than the energy price. Also, according to the Market Surveillance

Committee (MSC) of the Cal ISO, market participants have an incentive to submit

schedules that will cause congestion so that their units can be called upon to relieve the

congestion and receive payments for not generating that are greater than payments

received for generating. 

have cleared, no technically qualified market participant would have preferred to be in

another of the RTO's markets). In addition, efficient bid-based markets elicit prices that

are consistent with technical and cost requirements. 726 For example, a situation where

generating units are paid more for not generating than for generating as has happened in

ISO-NE and the Cal ISO may be an indication of an inefficient market. 727

b. Physical Feasibility

Proper design of the market clearing procedures ensures that prices balance the

supply and demand for energy, and all transactions, in the aggregate, are physically

feasible with appropriate levels of reserves. Some market designs have allowed ISOs to

accept schedules that have not been physically feasible (e.g., Cal ISO), while other ISO

market designs include mechanisms to ensure the physical feasibility of transactions (e.g.,

the NY ISO and PJM). Some ISOs have encountered instances where transmission
Docket No. RM99-2-000 -635-

728See MSC October Report, at 67, 74-75.

constraints have prevented the use of needed reserves, 728 and this is inconsistent with the

operator's obligation to make certain that reserve requirements are met and that reserves,

along with necessary transmission, are available to respond appropriately to

contingencies.

c. Access to Real-Time Balancing Market

Real-time balancing refers to the moment-to-moment matching of loads and

generation on a system-wide basis. Real-time balancing is usually achieved through the

direct control of select generators (and, in some cases, loads) that increase or decrease

their output (or consumption in the case of loads) in response to instructions from the

system operator. Over the last several years, the Commission has seen an increasing use

by system operators of market mechanisms that rely on bids from generators to achieve,

overall, real-time balancing. In order to maintain system balance, the operator also

manages congestion while maintaining the appropriate level of reserves. It is expected

that any RTO balancing markets will be available to all grid users, i.e., including

individual grid users that engage in bilateral transactions. The fact that the overall system

must be in balance moment-to-moment does not mean that there must be a moment-tomoment balance between the specific load and resources involved in individual bilateral

transactions. Making a real-time balancing market available to all grid users ensures that
Docket No. RM99-2-000 -636-

729Costs and benefits associated with self-schedules are congestion costs created

by the transaction or congestion relief that the transaction makes possible.

730Thin markets refers to a situation in which the amount bid into the market is

either not enough to match demand, or just enough to match demand.

all users are treated equally for purposes of settling their individual imbalances. The four

operating ISOs approved by the Commission already operate such markets.

d. Market Participation 

Markets are most efficient when generators and loads, whether internal or external

to the RTO, are allowed full and flexible participation in the markets. While generators

and loads have the option to choose between participating in any RTO-facilitated markets

or other markets, the RTO must have generation and ancillary service quantity

information, and any necessary technical information, from self-schedulers in order to

balance the system and ensure reliability. This allows bilateral and forward financial

markets and independent PX markets to co-exist and complement RTO physical markets. 

Participants that self-schedule would be expected to pay for the costs that they impose on

the physical system at market prices and be paid for the benefits that they supply to the

physical system at market prices. 729

 Unnecessary constraints on the imports of services can lead to increases in price

volatility due to thin markets. 730 Allowing exports will give generators flexibility to take

advantage of opportunities outside of the RTO boundaries, while allowing load serving
Docket No. RM99-2-000 -637-

731The flexibility of demand-side bidding may be limited unless real-time meters

are installed. Otherwise, demand-side bidding can simply take the form of interruptible

load.

entities external to the RTO a chance to purchase services. Broadening market

participation deepens the market and enhances overall efficiency.

e. Demand-Side Bidding

Existing ISO markets offer generators flexible participation, but they often do not

offer customers demand-side bidding options. Demand-side bidding is desirable to the

extent it is technically feasible, because without it, demand response decreases and

market power is easier to exercise. 731 The availability of price responsive demand also

reduces price volatility in the markets. 

f. Bidding Rules 

A market that provides the flexibility for all generators to bid a reasonable

approximation of the costs they incur including start-up, minimum load, energy, and

ramping costs will be efficient. Whether it is cost-effective to start up a generator and

make it available for dispatch depends on the prices and scheduled quantities over the

multiple hours and services for which the generator is committed, not on the prices in any

single hour or for any single service. Allowing participants to bid these costs helps

provide for a more efficient dispatch of generating units to meet load and other services,

because it allows the start-up decisions underlying the dispatch schedules to be based on
Docket No. RM99-2-000 -638-

prices and quantities for a period greater than a single hour. Not permitting start-up and

minimum load bids can reduce efficiency because the decision to start up and dispatch

generators is made separately for each hour, resulting in start up decisions that can cause

losses for generators. Also, when the start-up and minimum load bids are submitted

along with minimum run and down times, generators are ensured that they will not be

dispatched in a way that is physically damaging to the unit. 

g. Transaction Costs and Risk

Transaction costs associated with participation in well functioning RTO markets 

should be low, and market participation should involve no unnecessary risks. For

example, in sequentially clearing markets, bidders are exposed to the risk that they may

be chosen in one of the markets that clears first, yet would have preferred to have been

chosen in a market that cleared later. In order to hedge against such risks, bidders may

undertake expensive and time consuming bid preparation strategies to decrease the

likelihood that such profitable opportunities would be missed. 

h. Price Recalculations

In some instances, it may be necessary to post prices on a preliminary basis while

the final price calculations are verified. For example, in ISO-NE, the computer

algorithms generate new dispatch points every five minutes, and preliminary market

clearing prices are based on these dispatch algorithms. However, the actual dispatch

instructions are issued manually. In circumstances where time does not permit all
Docket No. RM99-2-000 -639-

732See ISO New England, Internal Review of Operations, June 7-8, 1999, Report

issued August 20, 1999. Electronic dispatch is under consideration in ISO-NE.

changes in dispatch to be communicated and effected through manual processes in a

timely manner, the market clearing price resulting from the computer algorithm must be

adjusted to reflect the actual dispatch in the hour. 732 While an RTO must ensure that the

final market clearing prices are correct, market clearing procedures should minimize price

recalculations. Also, any price recalculation should be done quickly. Otherwise, market

participants could incur large transaction costs in attempts to hedge against such risk. 

Risk exposure can be further reduced if market participants can engage in bilateral

transactions, or participate in other markets, to lock in prices prior to participating in the

RTO-facilitated markets.

i. Multi-Settlement Markets

Multi-settlement markets may involve a day-ahead and real-time market. For realtime markets, prices are determined by real-time dispatch quantities, and deviations from

day-ahead schedules are priced at the real-time price. When day-ahead schedules are

financially binding, they are financial commitments subject to payments for deviations at

the real-time price. If market participants adhere to day-ahead schedules, they need not

participate in the real-time markets. If needed for reliability, bids need to be physically

binding and may be subject to Commission-approved penalties for failure to adhere to the

bid. Without financially binding commitments in the day-ahead market, the riskiness of
Docket No. RM99-2-000 -640-

733Portfolio bidding refers to bids that aggregate all generating units under the

same ownership. This is in contrast to generation owners bidding in each unit separately.

734Report of the Market Surveillance Committee of the California Independent

System Operator, August 19, 1998 at 35-36 (MSC August Report).

market participation increases since the day-ahead bids could be changed before real-time

dispatch. If bids for ancillary services are accepted, the accepted capacity must be

physically ready to meet reliability commitments when called upon. The lack of a

physical capacity commitment has been a problem in some ISOs.

j. Preventing Abusive Market Power

 An efficient market design does not favor market participants that have the

potential to exercise market power and minimizes the incentives for market participants to

engage in abuse of market power. For example, since large players are more likely to

cause market power problems, a market design that favors large players (e.g., portfolio

bidding 733) may create an incentive for consolidation and resulting market power

problems. Fewer restrictions on imports of services will help guard against thin markets,

which in turn will help mitigate market power. ISO's have experienced problems with

thin markets, and easing restrictions on imports should help. 734 Also, artificially

segmenting a product market into separate geographic markets for the same product can
Docket No. RM99-2-000 -641-

735The Cal ISO at one time segmented their product markets into separate

geographic markets that corresponded to the defined congestion zones even when no

congestion existed. It has since reformed this practice. See MSC August Report, at 32-

33. 

also create additional price volatility and opportunities for the exercise of market

power. 

735

 

If market participants are allowed to submit bids which can then be changed before

financial settlements are completed, these non-binding bids can be used as a signaling

device to facilitate collusive behavior. 

k. Market Information and Market Monitoring

 One property of an efficient market has market clearing prices and quantities

being made available immediately. This information enables market participants and

potential future market participants to assess the market and plan their businesses

efficiently. It will also allow market participants to spot errors in the market clearing

process and get them corrected.

Disclosure of individual bids could be made eventually, but not immediately. 

Such disclosures will allow detection of market design and implementation flaws, and

allow study of the market by independent analysts and market participants. It may lead to

the exposure of the exercise of market power. To detect the withholding of capacity, a

simple screen is to provide the output, reserve quantities, and maximum capacity of each

generator. Immediate disclosure of individual bids is undesirable because it might
Docket No. RM99-2-000 -642-

736The Commission approved the disclosure of bid information in the following

orders. See PJM Interconnection, L.L.C., 86 FERC ¶ 61,247 at 61,890, order on reh'g, 88

FERC ¶ 61,274 (1999); Central Hudson Gas & Electric Corp. et al. 86 FERC ¶ 61,062 at

61,204, order on reh'g, 88 FERC ¶ 61,138 (1999).

737Socialization of costs means that costs that could be assigned to a particular

market participant(s) are instead spread over all participants regardless of whether or not

they caused the costs.

738While it is desirable from an efficiency standpoint to eliminate the averaging of

costs, the costs associated with calculating cost causation in some instances could be

shown to outweigh the benefits of eliminating averaging.

facilitate collusion by the market participants. It also might affect the bids of market

participants who wish to keep their costs confidential. However, after six months or a

year, the information on individual bids has essentially no value for collusion and

discloses little new information about any bidder's current costs. Nonetheless, the

information's value for market monitoring remains high. 736

l. Prices and Cost Averaging

Market designs that base prices on the averaging or socialization of costs, 737 may

distort consumption, production, and investment decisions and ultimately lead to

economically inefficient outcomes. Where possible and cost effective, cost causality

principles can be used to price services and eliminate averaging. 738 

For example, in some congestion management mechanisms, the cost of alleviating 

congestion is spread over all loads. This scheme could have some generators creating

monetary benefits for other generators. In addition, it could lead to over-consumption of
Docket No. RM99-2-000 -643- 

739MSC October Report, at 112.

power by some loads and under-consumption by other loads. Moreover, such averaging

mechanisms for congestion management do not send the correct price signals for the

location of new generation, thus leading to problems with long-term implications. 739

Moreover, if pass-throughs or uplift charges are paid by all load to ensure bid-cost

recovery, as in some approved ISO market designs, it may be appropriate to couple these

pricing mechanisms with incentive mechanisms for the RTO to control them. 

I. Collaborative Process

The Commission proposed a regional collaborative process to facilitate the

creation of RTOs. State commissions had encouraged the Commission to sponsor

activities in each region of the country that will bring together representatives of public

and private electric utilities, state regulators, consumer groups, representatives from

Canada or Mexico, as appropriate, and any other interested parties that need to be part of

such a process. The Commission proposed that regional workshops be held after the

Final Rule is issued to determine what, if any, impediments exist to the formation of

RTOs in a particular region and how the Commission staff could help to overcome those

impediments. Staff resources that will be available for the collaborative process include

technical staff, dispute resolution staff, and any other staff assistance that would be

beneficial.
Docket No. RM99-2-000 -644- 

740See, e.g., Nine Commissions, Illinois Commission, Indiana Commission,

Michigan Commission, Montana Commission, Nevada Commission, South Carolina

Commission, Wisconsin Commission and Wyoming Commission.

741See, e.g., APPA, NRECA, CMUA, SRP, Snohomish, Seattle, RUS, East Texas

Cooperatives, IMEA, and Arkansas Cities.

742See, e.g., Powerex, BC Hydro and Canada DNR.

Comments

Almost all commenters support the Commission's collaborative proposal. Of the

49 comments that addressed this issue, 47 are generally supportive. These commenters

include a number of state commissions. 740 In addition, NARUC supports the

continuation of a "dynamic process requiring continuing dialogue between FERC and the

states." A number of public power entities also support the process. 741 Numerous

Canadian entities also filed comments regarding the usefulness of a collaborative process

for the international aspects of RTO formation. 742

Only Florida Commission and CP&L are not fully supportive. Florida

Commission suggests that FERC collaboration will not work in Florida but may work in

other regions of the country. CP&L is not supportive because the collaborative process

could be used by the Commission "as a means of forcing utilities to develop RTO

proposals on the Commission's timetable" which results in the Commission "being

disingenuous when it describes its RTO policy as 'voluntary'." Otherwise, CP&L believes

the conferences will only serve as an opportunity for participants to "posture" and that
Docket No. RM99-2-000 -645- 

limited Commission resources should not be used for meetings that "are not likely to

produce positive results."

Specific comments about the collaborative process address three basic issues:

inclusiveness, process and procedures, and outcomes.

Inclusiveness

The NOPR stated that "the Commission expects public utilities and non-public

utilities, in coordination with appropriate state officials, and affected interest groups in a

region to fully participate in working to develop an RTO." It further stated that the

regional public workshops will be convened in cooperation with the affected state

officials and that transmission owners and operators will be invited.

Many commenters advocate an open collaborative process that would include a

full complement of participants. They suggest that the regional meetings include

representatives of all stakeholders, for-profit transmission companies, not-for-profit

transmission entities, state regulators, state legislators, state Governors, state energy

officials, state and non-state consumer advocates, state economic and environmental

regulators, environmental action interests and public power/municipals. Some

commenters indicate that in certain regional efforts to form an RTO, the deliberations

have excluded key interests and, as a result, the outcomes were not widely supported. 

For example, PJM/NEPOOL Customers note with respect to the PJM formation process

that "[O]nly after all stakeholders were included in organizational discussions was true
Docket No. RM99-2-000 -646- 

progress made toward implementing an ISO that adequately addresses all parties' needs." 

PNGC states that "[I]f other users do not have a seat at the table while merchant functions

do, obviously a level playing field is not created." New Orleans cites Entergy's "failure to

even attempt to build a regional consensus concerning its transco as a reason that

inclusive regional conferences are needed."

Process and Procedures

Commenters raise a number of questions regarding the collaborative process and

specifically with respect to the regional public workshops. Many commenters support the

use/availability of the Commission's Dispute Resolution Service (DRS) staff or the use of

outside facilitators. Some commenters request that the Commission clarify that the

meetings will be open meetings that can be attended by any person. Several commenters

urge the Commission to take the cost and travel time to attend meetings into account in

planning the regional public workshops. Some specific locations are suggested for sites

for the regional workshops: New Orleans, Minneapolis/St. Paul, and Seattle or Portland.

Several commenters suggest that the collaborative process begin prior to spring

2000 in at least one region of the country—the Upper Midwest. Commenters suggest that

there is no need to wait and that the region would benefit by immediate assistance from

Commission staff as described in the NOPR.

Some commenters ask the Commission to be mindful that the number of regional

meetings scheduled may not only be costly but unproductive as well. Two commenters
Docket No. RM99-2-000 -647- 

specifically say that we must not allow the "death by meetings" syndrome to be realized. 

Some interests may want to stall RTO formation by promoting an "endless" series of

meetings that are not productive but are designed to "preserve the status quo." A few

commenters suggest that the role of Commission staff at the regional events should not be

that of meeting referee but primarily to provide policy guidance on key RTO issues and

proposals. NRECA proposes the creation of several Commission staff teams to "facilitate

and informally monitor each RTO formation process" and provide "neutral guidance" in

the regions. Some commenters ask that the Commission establish procedural rules in

writing in advance of the regional workshops so that all parties will know and understand

the rules prior to the meetings. Some commenters also request that all reports,

information and data produced for the meetings be readily available to all participants.

Outcomes

The Project Groups suggest that the Commission should "clearly delineate the

substantive results expected" from the collaborative process. They suggest that

collaboration progress reports be filed with the Commission and that "work products" be

required, including: (1) identification of RTO boundaries; (2) a list of all transmission

owners and facilities in the region; (3) a draft operating agreement; (4) a draft governance

structure and bylaws; (5) proposed operating protocols; (6) a proposed budget/financial

structure; (7) a draft tariff; and (8) how the proposals meet the Commission's guidelines,

including a timetable.
Docket No. RM99-2-000 -648- 

Commission Conclusion

A key element of this Final Rule is our commitment to the use of the collaborative

process to assist in the voluntary formation of RTOs. By collaborative process, we mean

a process whereby transmission owners, market participants, interest groups, and

governmental officials can attempt to reach mutual agreement on how best to establish

RTOs in their respective regions. We reiterate our commitment of Commission staff

resources, to the extent possible, to assist parties in developing RTO proposals.

We are encouraged that state Commissions, public utilities, public power entities

and cooperative utilities, power marketing interests, and consumer and environmental

groups support the use of a collaborative process. We are further encouraged that efforts

to develop RTOs continue in the West and Midwest, and that other areas are reviewing

the potential benefits of RTOs in their respective areas. We believe that this represents a

growing recognition throughout the nation that RTOs will improve competition in electric

markets and enhance the reliability of the nation's electric grid.

We welcome participation in the RTO collaborative process by our sovereign

neighbors, Canada and Mexico. We believe that it is in our mutual best interest to have

electricity flow efficiently and economically across our international boundaries. We

pledge to continue to work cooperatively with officials from Canada and Mexico to

encourage the operation and improvement of an international electric system that benefits

all consumers. 
Docket No. RM99-2-000 -649- 

The Commission believes that the collaborative process must accommodate the

fact that different regions of the country are in different stages of RTO formation and

must be flexible enough to allow for these differences. Therefore, we will initiate the

collaborative process with a series of five workshops in the Spring of 2000. The primary

objective of each workshop will be to develop a consensus agreement by regional

participants establishing a strategic process and a schedule for any further collaboration. 

The appropriate collaboration process will depend on whether the region is considering

formation of an ISO, transco, or other form of RTO. To achieve this objective,

participants will share information about the status of RTOs or RTO proposals in the

region, identify impediments to RTO formation in the area, explore which process(es)

could most expeditiously advance agreements on RTO formation, and determine what

role(s), if any, Commission staff should play in advancing discussions in each region. 

One result of these discussions may be regional decisions that more than one RTO would

be appropriate in the area encompassed by participants at the workshop. Therefore, the

collaborative processes that follow the various workshops may differ significantly. This

includes possible variations in the role that will be played by Commission staff in each

RTO formation effort.

The Commission believes that regional workshops in the Spring of 2000 will

expedite the RTO formation process. In selecting locations for the initial Spring 2000

workshops, we recognize trends in the broader regionalization of the nation's electric
Docket No. RM99-2-000 -650- 

system. We also consider the evolving electric markets as well as the configuration of the

regional grid. We emphasize that the selection of locations for initial workshops is not to

indicate a preference for specific RTO boundaries, but to provide convenient workshop

locations. With these considerations in mind, we designate the following workshop

locations. Parties may attend more than one regional workshop. We expect all

transmission owners to attend at least one workshop.

Workshops will be held in the following cities in February, March or April, 2000:

1. Philadelphia, Pennsylvania 

2. Cincinnati, Ohio

3. Atlanta, Georgia

4. Kansas City, Missouri

5. Las Vegas, Nevada

Workshops are expected to last for two days. Additional information about the

regional workshops will be provided in January 2000.

At the request of parties, the Commission staff may play a role in the formation of

RTOs. Commission staff will convene the regional RTO workshops and provide policy

and technical guidance consistent with this rule. The Commission will supply meeting

space for the five initial Spring 2000 workshops. Regional participants are expected to

bear the costs of collaborative meetings after the initial five workshops. Commission

staff time and staff travel expenses will be provided as resources allow.
Docket No. RM99-2-000 -651- 

We believe that it is critical to make the Spring 2000 Workshop phase of the

collaborative process open to all interested parties. In order to promote an open process,

we will provide public notice of Spring 2000 Workshop events to allow all interested

parties to attend. We shall also make available agendas and procedural rules to all parties

in advance of the regional workshops. Agendas may vary from one workshop to another.

The Spring 2000 Workshops represent the initial step of the collaborative process. 

We expect that other meetings will be convened following the workshops by parties in

each region to bring the parties together to form an RTO in each region. Commission

staff may also convene additional meetings if this would help RTO formation. The postworkshop meetings of parties in regions may be held with or without Commission staff

participation. We will make available the Commission's Alternative Dispute Resolution

staff upon the request of an RTO group in formation. At the request of such a group,

independent private professional facilitation services may be arranged by Commission

staff and must be sponsored by the parties within the region. As needed and requested by

parties forming an RTO in a region, Commission staff members will be available to act as

settlement judges, mediators, facilitators or observers. 

We believe that the best interests of the nation's electric consumers will be served

by the formation of RTOs. Therefore, we encourage parties to establish strategic

schedules at the Spring 2000 Workshops and to convene subsequent meetings with the
Docket No. RM99-2-000 -652- 

743FERC Stats. & Regs ¶ 32,541 at 33,761-63.

goal of forming an RTO expeditiously. Commission staff will monitor progress with

respect to the results or outcomes in each region.

We expect that, following the initial Commission-sponsored workshops, parties in

each region will work collaboratively to identify the appropriate RTO regions, identify all

transmission owners and facilities in each region, and develop a timely application in

accordance with the Final Rule.

We have designated James Apperson of the Commission Staff to serve as the

collaborative process contact. He may be contacted at (202) 219-2962 with any questions

or comments about the RTO collaborative process.

J. Implementation Issues

1. Filing Requirements

In the NOPR, the Commission proposed that all public utilities that own, operate

or control interstate transmission facilities (except those already participating in a

regional transmission entity in conformance with the eleven ISO principles enumerated in

Order No. 888) must file with the Commission by October 15, 2000 either (1) a proposal

to participate in an RTO that will be operational no later than December 15, 2001, or (2)

an alternative filing describing efforts to participate in an RTO, obstacles to RTO

participation, and any plans and timetable for future efforts. 743 For those public utilities
Docket No. RM99-2-000 -653- 

that file an RTO proposal on or before October 15, 2000, we proposed to permit them to

file a petition for a declaratory order asking whether a proposed transmission entity that

would be operational by December 15, 2001, would qualify as an RTO, with a

description of the organization and operational structure, a list of the intended

participants of the institution, an explanation of how the institution would satisfy each of

the RTO minimum characteristics and functions, and a commitment to submit necessary

FPA section 203, 205 and 206 filings promptly after receiving the Commission’s

determination on the declaratory order petition. Finally, we proposed that the

requirements not apply to a public utility that owns, operates or controls transmission that

also is a member of an existing transmission entity that the Commission has found to be

in conformance with the Order No. 888 eleven ISO principles; instead, each such public

utility would be required to make a filing no later than January 15, 2001, that (1) explains

the extent to which the transmission entity in which it participates meets the minimum

characteristics and functions of an RTO; (2) proposes to modify the existing institution to

become an RTO; or (3) explain efforts, obstacles and plans with respect to conforming to

these characteristics and functions.

Comments

Most commenters responding on this issue oppose one or more aspects of the

proposed filing requirements. For example, a number of public utilities and two state

commissions argue that the October 15, 2000, filing requirement does not provide enough
Docket No. RM99-2-000 -654- 

time. Southern Company contends that the proposed filing deadline requirement is likely

to be counterproductive because it imposes an artificial deadline that may interfere with

regional discussions. Moreover, once established, a prematurely formed RTO may itself

prove to be an obstacle to more effective transmission organizations. Southern Company

also claims that the proposed mandatory filing requirements are inconsistent with a truly

voluntary approach. If the requirement is retained, Southern Company suggests that the

Commission clarify that the alternative filings will be treated as status reports and not be

subject to deficiency orders or otherwise lead to proceedings in which punitive measures

might be taken, because any consideration or use of penalties seriously undermines the

Commission commitment to the voluntary nature of RTOs.

Wyoming Commission recommends that the deadlines not be made mandatory in

any way in the Final Rule because RTO formation is supposed to be voluntary. Since it

is unclear as to what happens to those entities who file an explanation as to why they did

not join an RTO, Wyoming Commission urges the Commission to defer to each region's

process and timetable in developing an RTO and acknowledge that not all regions are

processing at the same pace. It recommends that the Commission convert the October 15,

2000, deadline into a milepost for reporting RTO development.

CP&L submits that the time frame is unrealistic because it contemplates that new

RTOs can be developed, approved by the Commission, set up, and begin operation in less

than two years. Experience has shown that almost every RTO to date has taken at least
Docket No. RM99-2-000 -655- 

four years to go through that process. Therefore, the Commission should modify the

filing requirements to simply require informational filings on the status of RTO

development.

Sierra Pacific is concerned about insufficient time being allowed for transcos to

form. It points out that the precedent regarding ISOs is much more well-developed than

that regarding transcos. The certainty surrounding ISOs makes them more attractive

particularly when a decision to form the entity must be made relatively quickly to meet

the proposed October 15, 2000, filing date. To lessen the incentive to rush to join an

ISO, Sierra Pacific suggests that: (1) the date for filing an RTO proposal should be

extended to June 15, 2002; (2) the Commission permit transition mechanisms that will

allow transmission owners to eventually join transcos; and (3) the Commission not

require participation in an ISO to become a trap from which a transmission owner cannot

extricate itself. ComEd provides supporting arguments, noting that where divestiture of

transmission assets is involved to form transcos, the necessary transition period will

largely be dictated by the sheer complexity—legal, financial (bonds and mortgage), real

estate (titles/easements), taxation—of separating a designated portion of any electric

utility that has historically been a vertically integrated utility.

Based on its experience with the Midwest ISO formation process, Kentucky

Commission also argues that the proposed date to join an RTO or respond with reasons

for not joining is too short. It points out that, if the Commission completes the Final Rule
Docket No. RM99-2-000 -656- 

by the end of 1999, transmission owners will have less than one year to make a final

decision on participation. Kentucky Commission urges the Commission to give

transmission owning utilities additional time to look into joining an RTO, so that RTOs

are not pushed so quickly that the best model fails to materialize as a result of market

evolution that remains underway. South Carolina Commission and Big Rivers share the

concern that the proposed timeframe is too ambitious, given the complexity of RTO

related matters and the need to reach some level of consensus among those with vested

interests.

Several commenters noted that meeting the October 15, 2000, filing requirement

will depend on the Commission's standard of review of those filings. For example, TDU

Systems observes that the proposed filing requirements have no teeth. TDU Systems

contends that a public utility that decides not to participate in an RTO can make an

alternative filing setting out the reasons why it is not doing so and what plans it has to

work towards participation. In TDU Systems' view, while the proposed regulations are

consistent with voluntary participation, they are inconsistent with full and effective

participation in RTOs. TDU Systems counsels that the Commission should resist calls to

water down the RTO regulations even more, so as to treat alternative filings as mere

status reports that allow transmission monopolists to hold on to their monopolies.

Duke submits that if the Commission is willing to accept valid, well-justified

explanations as to why a utility has not become an RTO member, the October 15, 2000,
Docket No. RM99-2-000 -657- 

filing requirement is reasonable, noting that until state commission review of

restructuring and RTOs is completed, it may be premature for a utility to commit

resources to RTO membership. Similarly, Iowa Board suggests that, where transmission

providers are making legitimate progress, a report to that effect should not be received

with automatic disfavor. Alternative filings are legitimate progress reports should be

given equal validity with definitive proposal filings.

A few commenters explicitly support the October 15, 2000, filing requirements. 

For example, SRP believes it to be an acceptable balance between mandated participation

and the status quo. PJM/NEPOOL Customers also support the filing by a date certain

because this would expedite the collaborative process and ensure that no entity can

effectively block RTO formation by engaging in inappropriate negotiation tactics. And

Oglethorpe views the October 15, 2000, time frame as necessary to assure the timely

development of RTOs and help develop fully competitive efficient wholesale markets. 

Cinergy, noting that only after the Commission has had opportunity to review the October

15, 2000, filings will it be able to determine whether it should order participation in or

reconfiguration of particular RTOs, suggests that by April 15, 2000, all public utilities be

required to file a statement of position in which each utility identifies each state in which

it owns transmission, and the RTO in which it is considering membership and its

potential scope and configuration to the best of its knowledge.
Docket No. RM99-2-000 -658- 

744See, e.g., NY ISO, Cal ISO, NYPP and ISO-NE.

A number of commenters address issues and treatments relating to existing ISOs. 

Virtually all of the existing ISOs assert that the Commission should allow the previously

approved ISOs to continue to develop without undue interference in order to foster

experimentation and testing of proposals. 744 Cal ISO argues that the Commission should

find that existing regional entities generally meet the RTO criteria and that the

Commission should confirm its determination not to require substantial changes in

approved ISOs that would undermine difficult to reach consensus on critical issues. 

Similarly, the Pennsylvania and New York Commissions recommend that FERC

grandfather the existing ISOs that meet the RTO characteristics and functions. The

Pennsylvania Commission states that it does not want to tinker with the inner workings of

PJM, nor constantly revisit and revise operations and functions. The New York

Commission is concerned that the New York ISO tariff may have to incorporate the

"ordinary negligence" liability and indemnification provisions set forth in the pro forma

tariff if the ISO becomes qualified as an RTO, and that this will increase the ISO's

exposure to litigation. The South Carolina Commission supports NARUC's position

urging the Commission to grandfather existing ISO boundaries that are satisfactory to the

states. Similarly American Forest, CalPX and Mid-Atlantic Commissions want the

Commission to respect existing ISOs.
Docket No. RM99-2-000 -659- 

Furthermore, PJM/NEPOOL Customers contend that their ISOs are in basic

conformance with the minimum functions and characteristics. To the extent that any

deficiencies are found, the ISOs should be allowed to engage in continued

experimentation without interference from the Commission. The Wyoming Commission

also fails to see why existing ISOs, already having gone through a rigorous approval

process, should have to re-certify as RTOs. Moreover, EEI notes that the Commission

should weigh the incremental gains achieved through economies of scale, efficiency, and

additional savings against the potential incremental costs of reorganization, new computer

programming, infrastructure changes, and changes required to achieve effective

communication and coordination. NYPP proposes that ISOs be allowed to evaluate the

costs and benefits of forming an RTO after some years of market experience; hence, they

oppose putting members of existing ISOs on the same time frame for compliance as nonmembers of ISOs/RTOs. United Illuminating recommends that the Commission continue

to honor and not abrogate pricing arrangements of existing ISOs. United Illuminating

also contends that, since existing ISO members have no opportunity to discriminate

because they have turned control of their transmission over to their respective ISO, the

Commission cannot generically abrogate existing ISO pricing arrangements pursuant to

its FPA section 206 authority in this rulemaking. Central Maine offers that consolidating

the PJM, New England and New York ISOs into a super-ISO will require costly

expansion of telemetry, communication, and computer equipment, that it could result in a
Docket No. RM99-2-000 -660- 

745E.g., Illinois Commission, New Orleans, SMUD and Turlock.

746See, e.g., SMUD, PJM/NEPOOL Customers, NYPP, Cal DWR, MEAG,

American Forest and Central Maine. 

decrease in reliability, and that simple interregional coordination could accomplish the

Commission’s goals without consolidation.

A few non-ISO entities oppose any grandfathering of existing regional

transmission organizations. 745 For example, New Orleans argues that the Commission

should not exempt existing regional transmission entities from requirements of RTO

formation because only through universal application will all regions of the country

receive the benefits of open and competitive electric markets. H.Q. Energy Services

suggests that a larger territory, such as the combined territory served by existing the New

York, PJM and New England ISOs, would be more effective than the NY ISO standing

alone. PG&E counsels that freezing the existing ISO structures in place would not serve

reliability or the marketplace and would be inconsistent with the open architecture

requirement. It believes that the Commission has struck an appropriate balance imposing

a reporting requirement on existing ISOs.

Most commenters agree that existing operational transmission entities should

gradually evolve toward RTOs during a transition period, rather than making immediate

and drastic changes. 746 According to SMUD, a transition period will enable customers

to avoid bearing unnecessary costs. 
Docket No. RM99-2-000 -661- 

A few commenters address the specific filing requirements outlined in the NOPR. 

The New York Commission asserts that the NY ISO should not have to make a filing

because it possesses the requirements of an RTO. In addition, the Cal ISO argues that

existing entities, rather than individual public utilities, should be responsible for the RTO

filing requirements. Likewise, PJM suggests that existing ISOs report to the Commission

prior to any report by its public utility members, as the existing ISO is in a better position

to provide the Commission with the most accurate information by which to evaluate

whether the ISO satisfies the minimum characteristics and functions for RTOs. PJM

suggests that existing ISOs and existing transmission entities file reports no later than

December 31, 2000, explaining whether they satisfy the Commission's requirements for

RTOs and identifying any additional authority they may require for this purpose. On the

other hand, EPSA welcomes the proposal requiring a showing of how the existing

transmission institutions meet the minimum characteristics and functions by January 15,

2001, as a way to help address and solve continuing discrimination within current ISOs

and address whether these institutions should be combined into larger groupings. 

Similarly, NYC wants the NY ISO's January 15, 2001, filing to demonstrate how its

efforts to improve regional cooperation will overcome the institutional impediments that

have contributed to the city’s load pocket condition.

Finally, commenters raise a number of miscellaneous issues: Puget questions

whether there will be negative implications for any entity the choose to cease
Docket No. RM99-2-000 -662- 

participation in an RTO; DOE points out that RTOs may need to fund pensions for

transferred employees, and existing transmission providers may need to fund early

retirements or other compensation for displaced employees; UMPA recommends that

recourse to the Commission in a de novo capacity must be part of all RTO dispute

resolution procedures; and Indiana Commission, Snohomish and Midwest ISO express

concern about how the Commission intends to handle multiple RTO proposals covering

approximately the same region.

Commission Conclusion

The Commission will adopt the NOPR proposal requiring that all public utilities

that own, operate or control interstate transmission facilities (except those already

participating in an approved regional transmission entity) file by October 15, 2000, either

a proposal to participate in an RTO or an alternative filing describing efforts and plans to

participate in an RTO. As proposed initially, we will consider a petition for declaratory

order setting forth the items listed in section 35.34(d)(3) as a proposal to participate in an

RTO.

We believe that the October 15, 2000, date for filing proposals is realistic. It is not

overly aggressive, given the amount of guidance we have provided in this Rule and the

amount of flexibility we are permitting in how to satisfy the minimum characteristics and

functions. In addition, the collaborative process that we are promoting in this Rule will

provide an opportunity for all interested parties with their varied interests to resolve many
Docket No. RM99-2-000 -663- 

747Of course, these reports may be filed prior to October 15, 2000.

of their differences, in advance, and reach consensus on the RTO solution that best fits

the overall needs of their respective region. The October 15, 2000, filing date should

help keep the parties focused and accelerate their efforts toward selecting an appropriate

RTO model.

The October 15, 2000, date for filing is also reasonable because, even if a public

utility is unable to file an RTO proposal at that time, we are permitting the public utility

to make an alternative filing reporting on the status of pertinent RTO formation and

development, the obstacles that have prevented the filing of an appropriate RTO proposal,

and any of the public utility's plans and timetable for future efforts directed toward RTO

formation and participation. 747 Given the importance that the Commission places on

RTO development, it is important for us to understand no later than October 15, 2000 just

how much progress the industry is making on forming RTOs. If the October 15, 2000,

filings reveal obstacles that prevent serious progress toward RTO formation are reported

for a given region, we will be able to act early enough to provide guidance on what steps

we think are appropriate to help address the obstacles (e.g., further collaborative efforts). 

And where serious regional progress is reported, but more time is requested in connection

with meeting a particular RTO requirement, we will be able to act early enough to try to
Docket No. RM99-2-000 -664- 

accommodate the local needs, complications and complexities that the particular region

faces.

Some concern has been expressed that the October 15, 2000, filing date is too

short to allow transcos to form because of the inherent legal, financial, real estate and

taxation complexities associated with the transfer of ownership of the affected

transmission assets. We are not proposing that the restructuring be completed by October

15, only that a proposal be filed, or an alternative filing as described in this Rule. 

Moreover, we take note of the fact that other forms of major corporate restructuring,

including mergers, have proceeded from initial idea to formal proposal in a shorter time

when the motivation is sufficient. Therefore, we do not think the time allowed is too

short for transco proposals.

We also reaffirm the proposed January 15, 2001, filing date for transmitting public

utility members of an existing approved transmission entity to address the extent to which

that entity conforms to the minimum characteristics and functions of an RTO, any plans

to make it conform, and any obstacles to full conformance with our Final Rule. We note

that RTOs will not be "starting from scratch." There is significant information available

about both the good and bad experiences with ISOs, and this information should help

RTOs meet this filing deadline.

While we are allowing a later filing date for existing transmission institutions to

file (January 15, 2001, versus October 15, 2000), we do this because, in general, the
Docket No. RM99-2-000 -665- 

transmission owners in those regions have already made substantial progress in

establishing regional entities. Nonetheless, the Commission needs to know, for all

regions, including those covered by existing approved transmission institutions, the extent

of progress toward formation of fully functional RTOs. To the extent that an existing

ISO, for example, is less than adequate with regard to one of the necessary characteristics

or functions, we would expect the existing institution to be working on a plan of action to

make the remedial improvements that are required to bring it into conformance with the

Final Rule. 

In sum, we continue to believe that the October 15, 2000, and January 15, 2001,

filing dates represent an acceptable balance between the need to move toward RTOs as

soon at possible and the need for sufficient time for transmission owners and market

participants to develop proposals.

2. Deadline for RTO Operation

The Commission proposed that all public utilities participate in an RTO that will

be operational by December 15, 2001. In addition, we contemplated implementation of

the congestion management function within one year after startup (by December 15,

2002), and implementation of inter-regional parallel path flow coordination and

transmission planning and expansion functions within three years after startup (by

December 15, 2004).
Docket No. RM99-2-000 -666- 

Comments

Most commenters suggest the December 15, 2001, deadline should be changed to

a later date or that the Commission provide greater flexibility in meeting the deadline. 

On the other hand, Oregon Commission explicitly favors the December 15, 2001,

deadline, arguing that the time line is designed in stages so that the easiest requirements

come earliest. EPSA fears that further delay of any of the operational deadlines for any

of the required RTO functions (i.e., for initial startup, congestion management, parallel

path flow coordination, or transmission planning and expansion) will only encourage

further debate and dialogue without driving the industry towards acceptable resolutions,

and prolong the problems of residual discrimination and remaining market inefficiencies.

Two commenters propose an earlier deadline. PG&E contends that the transition

period for RTOs to meet all requirements must be as short as possible—no more than one

or two years to fully operational RTOs may be reasonable. Sithe similarly argues that,

while the negotiations and proceedings associated with voluntarily RTOs can take years

to complete, the California experience suggests that an RTO can be established quickly if

a deadline exists. Sithe recommends that the Commission reconsider its time frame and

do everything it can to hasten the process of putting in place RTOs with all minimum

characteristics and functions. It observes that, as proposed in the NOPR, an RTO could

defer for up to three years the filing of a plan for transmission planning and grid
Docket No. RM99-2-000 -667- 

expansion. The details may not be finally approved by the Commission for at least

another year such that a delay of over five years could result.

SRP and American Forest express concern about who will be responsible for

building and paying for new transmission facilities until the RTO takes on this

responsibility. In particular, SRP suggests that the Commission require each RTO filing

to describe who will be responsible for financing and building transmission expansions

during the interim.

Most commenters, however, view the proposed deadline as too aggressive, and

recommend that it be eliminated or extended. CP&L views the operating deadline as

arbitrary and capricious, and argues that the deadline will impose higher implementation

costs and inefficiency that will not benefit the public or the industry. South Carolina

Authority believes that to assume that a large group of stakeholders with diverse interests

can somehow come together and agree on a particular RTO model and configuration by

October 15, 2000 that is up and running by December 31, 2001, is unrealistic. East

Kentucky suggests that the timetable be extended approximately two years. Montana

Power encourages extension by one year because areas like the Pacific Northwest will

probably need significant infrastructure to be developed or re-deployed and the 14 month

time frame contemplated after RTO proposals are due on October 15, 2000, is not

sufficient time.
Docket No. RM99-2-000 -668- 

748Note that a number of comments opposing deadlines are based on the difficulty

of attaining specific RTO functions. These comments are also addressed in the sections

regarding the specific functions.

A number of commenters favor a flexible approach and allowing provisional RTO

status. Cinergy offers that, to overcome obstacles such as legal impediments to public

power participation, alternative means of RTO participation be considered such as joint

operations without the functional integration of public systems’ facilities to allow them to

control the private use of their systems. SERC generally concurs. Williams contends that

not all RTOs will be able to develop at the same pace, and supports provisional RTO

status with dates certain respecting those functions not able to be performed at startup. 748

SNWA recommends that, if necessary, a phase-in approach should be used in the

implementation of an RTO to smooth the implementation process. Project Groups

contends that, given the California experience, the cost of attempting to do everything at

once is significant. Transmission ISO Participants urges flexibility for transmission

owning members of exiting ISOs since the current structure represents an imperfect and

probably unfinished agenda. EEI contends that the Commission should allow flexible

timetables to establish RTOs that are transcos, contending that a vertically integrated

utility that selects the option of moving transmission assets to a transco faces complex

financial and tax issues. Nevada Commission urges the Commission to clarify that there

is no prohibition against forming interim organizations such as an independent system
Docket No. RM99-2-000 -669- 

administrator until such time as a viable RTO for the region is formed. South Carolina

Commission claims that each RTO proposal should be reviewed on a case-by-case basis

for general adherence to the Commission’s overall policy goals.

Indiana Commission cautions, however, that careful consideration should be given

to what will be lost by the acceptance of an RTO "lite." It argues that existing

transmission entities may see little value in maintaining relatively high standards and

could view the Commission acceptance of lower standards as an incentive to gravitate to

lower standards. PG&E recommends the Commission grant waivers from its

requirements only in limited cases and only for short durations. AEPCO, contends that

there should be a reasonable basis for granting waivers, particularly for non-jurisdictional

entities. In particular, a request for waiver should consider: (1) how much additional

RTO transmission would result from inclusion of the facilities in an RTO; and (2)

whether the RTO would be functional without inclusion of the entity's facilities. Sithe

argues that care should be taken when considering whether to permit RTOs to go into

effect without meeting functions and in granting waivers, and suggests that the

Commission establish clear requirements for RTO approval, strictly scrutinize proposals,

and not hesitate to reject inadequate proposals.

Commission Conclusion

We have decided to retain the originally proposed startup and other functional

implementation deadlines (RTO startup by December 15, 2001, implementation of
Docket No. RM99-2-000 -670- 

congestion management by December 15, 2002, and implementation of the parallel path

flow coordination and transmission planning and expansion functions by December 15,

2004).

As a general proposition, we believe that, given the urgent needs of electricity

markets as discussed elsewhere in our Final Rule, we have an obligation to promote RTO

operation at the earliest feasible date. Even where a market may already be served by an

ISO or other approved transmission entity, we are concerned that such market may

remain hampered to the extent that the approved entity has yet to fully conform with our

Final Rule.

In response to those who contend that December 15, 2001, is too ambitious for

RTO start-up, we note several points. First, we, and the industry, now have had the

benefit of the experience of the formation of five ISOs under Commission jurisdiction, an

ISO in ERCOT, some international experience with regional transmission entities, and

substantial discussion of the subject of regional transmission entities within the industry. 

While the time-frame we are suggesting for RTO formation may have been unrealistic

several years ago, much has been learned since then which should facilitate more rapid

formation. 

Second, our Final Rule is providing substantial flexibility that should permit an

RTO to satisfy the minimum characteristics and functions in a cost efficient manner. For

example, we are not requiring control area consolidation; we are not requiring the
Docket No. RM99-2-000 -671- 

establishment of a PX; we are allowing an RTO to meet its operational control obligation

through indirect or hierarchical control arrangements via contractual agreements with the

existing infrastructure such as transmission owners and control area operators; and we are

allowing an RTO to satisfy its security coordinator functions through contractual

arrangements with an external security coordinator, as long as it is independent. An

acceptable RTO structure need not be a monolithic organization that requires an extended

period of time to become fully set up so that it can directly "push all of the buttons." 

Moreover, we are allowing a longer phase-in period for functions that may be more

difficult to establish, such as congestion management, parallel path flow measures, and

transmission planning and expansion. 

With respect to the comments that question the December 15, 2002, deadline for

implementing the congestion management function, we believe that lack of effective and

market-oriented congestion management is a critical issue in the industry, and that it

needs attention soon. We acknowledge that developing a sophisticated congestion

management program can be an extremely complex and time consuming matter. 

However, implementation of economic approaches to congestion management by some of

the approved ISOs shows the feasibility of these concepts where there is an institution to

undertake the organization of this function over a large area.

Some say that transmission congestion is not a serious problem in their regions,

and that they therefore should not be required to develop a complex congestion
Docket No. RM99-2-000 -672- 

management plan within a short time-frame. We agree that an RTO should not have to

expend large resources to address a problem that does not exist. However, we are

concerned that an RTO fully analyze the extent to which transmission congestion does or

could interfere with electricity sales in its region, and that it be prepared to address

congestion if it becomes a more serious problem through changing markets. As markets

become more competitive and the volume of discrete transaction increases, transmission

congestion may become serious unless action is undertaken beforehand. Where

transmission congestion is infrequent, this Rule does not preclude the establishment of

relatively less complex forms of market-compatible congestion management such as

generation redispatch protocols.

In sum, we think that the phased startup and other functional implementation

deadlines are reasonable.

3. Commission Processing Procedures

The Commission recognized that RTO formation would be complicated by the

requirements for Commission approval of transfer of control of jurisdictional facilities

under FPA section 203 and Commission approval of RTO transmission rates, terms and

conditions under FPA section 205. In the NOPR, the Commission requested comments

on whether the Commission should provide expedited or streamlined processing
Docket No. RM99-2-000 -673- 

749FERC Stats. & Regs. ¶ 32,541 at 33,759.

procedures for RTO filings and asked for suggestions regarding how the Commission can

further expedite and streamline procedures. 749

Comments

Views on streamlined and expedited processing of RTO filings are mixed. 

Commenters that generally favor streamlining include Desert STAR and TEP, which

suggests that filing requirements be kept simple and flexible.

A number of commenters offer specific suggestions for streamlining and

expediting the process, including:

• Florida Commission believes that once an RTO or other structure has been agreed

upon by a group of entities, the Commission should expedite all required processes

in order to allow the participants to start implementing the agreed upon changes.

• Tallahassee recommends that the Commission should clarify that it is not

revisiting the functional test for distinguishing transmission and distribution

facilities addressed in Order No. 888.

• Entergy asserts that significant delay in obtaining Commission approvals will

make it difficult for Entergy to institute a transco within the time-lines established

by state restructuring laws in Arkansas and Texas. Providing clear rules on the

required and permissible features of RTOs as the Commission did in its July 30,
Docket No. RM99-2-000 -674- 

1999 Declaratory Order for Entergy and providing clear standards on pricing

policies will help. Entergy argues that the Commission should make explicit its

willingness to consider requests for expedited approval when a showing is made

that expedition is necessary, as it has done for California ISO.

• Trans-Elect notes that if a transfer of facilities cannot close under Section 203

until the related FPA section 205 proceeding is concluded, an expedited Section

205 filing must also take place. One way to do this is to waive an Initial Decision

and set a date certain for the Commission’s section 205 decision.

• PJM/NEPOOL Customers recommend that a standard RTO governance structure

be adopted that allows participation by all stakeholder groups. It would expedite

processing by requiring that any RTO filing demonstrate that all stakeholders were

included in the formation process.

• SMUD recommends that the Final Rule require that RTOs be designed, developed

and implemented in a manner that does not require numerous tariff amendments to

remedy market ills that could be addressed prospectively or at a speed that does

not dramatically increase RTO development costs.

On the other hand, some commenters urged the Commission to exercise caution

regarding streamlining and expediting:

• East Texas Cooperatives observes that a poorly configured RTO can potentially be

more harmful to the industry than the status quo, by allowing large transmission
Docket No. RM99-2-000 -675- 

owners to dominate regional grid management, maintain pancaked rates and

discriminate in allocating transmission revenue.

• Indiana Commission recommends that state commissions and other interested

parties have full opportunity to thoroughly review, comment, and have an impact

on the RTO proposals once they are filed with the Commission.

• Puget indicates that a negative implication of allowing streamlined filing and

approval procedures for RTO participants is that regulatory burdens will be

leveled against nonparticipants while those who join an RTO will be freed from

what the Commission implicitly recognizes are unnecessary requirements. A truly

voluntary system would not continue to impose unnecessary regulatory

requirements on nonparticipants and there is no reason for the Commission to

delay implementing these regulatory reforms now before a final decision is made

regarding the wisdom or efficacy of RTOs, or to condition the implementation of

such reforms on an entity's participation in an RTO. 

• Duke contends that, given the size and complexity of the typical section 203 and

205 of the FPA filings, it is not clear that reducing the time that parties are granted

to review such filings and provide initial comments may be appropriate. 

Nonetheless, the Commission should work to dismiss irrelevant issues used as

leverage to extract concessions unrelated to RTO formation, it should consider use

of less formal hearing procedures for issues that do not require discovery, and the
Docket No. RM99-2-000 -676- 

Commission should limit the time period allowed for evidentiary hearings. Duke

acknowledges that the effect of streamlined filing and approval procedures could

be to reduce costs that would otherwise be born by market participants.

Commission Conclusion

While there is broad-based consensus for simplifying the Commission’s RTO

filing process and responding to RTO proposals expeditiously, we must maintain an

appropriate balance between streamlining and expediting the filing and processing of

RTO proposals and ensuring due process and the development of an adequate record. 

Given the amount of flexibility we have built into the Rule as to organizational structure,

it is difficult to predict what issues will be raised by the RTO proposals and the degree of

complexity raised by such issues. Accordingly, while the Commission has the goal of

ensuring the rapid formation of RTOs, and will attempt to process each RTO proposal as

expeditiously as possible, certain RTO proposals will take longer to analyze and review

depending upon the complexity of the issues and the level of support among the affected

parties. Therefore, in addition to the specific guidance provided elsewhere in this Rule,

we provide further guidance and note the following factors which are intended to assist

public utilities in streamlining their required filings and help expedite the processing of

the RTO proposals. 

One factor that should facilitate faster processing is that the Final Rule permits

delayed implementation dates for various highly complex FPA section 205 related RTO
Docket No. RM99-2-000 -677- 

provisions (congestion management by December 15, 2002, and parallel path flow

coordination and transmission planning and expansion each by December 15, 2003). 

Therefore, initial RTO proposals need not contain the details for these provisions, but

need only contain a commitment to complete the provision and a timetable for submitting

appropriate future filings. Likewise, we need not act on those matters initially in our

RTO orders. 

Expeditious processing of an RTO submittal is more likely to occur if the RTO

proposal is the result of a comprehensive and open collaborative process with widespread

support from transmission owners, market participants, and affected state commissions. 

While we cannot pre-approve unopposed proposals, many of our potential concerns could

be minimized to the extent the proposal has broad support.

Another potential streamlining measure is that public utilities are permitted to file

RTO proposals jointly with other entities. For example, in the case of existing ISOs and

other approved regional transmission entities, the regional entity may file on behalf of the

individual public utilities. This will reduce the volume of submittals that must be

developed by public utilities and be reviewed by the Commission. 

We note that, with the exception of governance, experience gained from past ISO

proceedings, will be directly transferable whether the form of RTO is an ISO or a transco. 

For transcos, as discussed elsewhere in the Final Rule, restrictions on ownership of
Docket No. RM99-2-000 -678- 

750We recognize that, while there is no statutory deadline to act on section 203

filings, there is a 60-day statutory clock requiring action on section 205 related filings

within 60 days from the date of filing, in the absence of a proposed effective date

extending beyond the 60-day time frame. However, in most instances, we expect that the

RTO submittals will typically propose FPA section 205 effective dates that will be

beyond the 60-day nominal clock. 

751This proposed time frame refers to applications that are consistent with the

guidance provided in this Rule and that provide all the necessary information. We further

note that the Commission’s review process will restart in the event that applicants modify

their proposal or supplement the supporting information in their application.

transcos that we have adopted are designed to work in tandem with restrictions on

governance in order to ensure adequate levels of independence.

We believe that RTO proposals that reflect the above factors, should allow the

Commission to minimize the amount of time necessary to analyze and process the

submittal. While the Commission cannot guarantee that we will be able to respond to

every proposal within a pre-set period of time, we will make every reasonable effort to

issue an initial order on an RTO proposal within 60 days, 750 after the comment period

closes. 751 With respect to RTO proposals that present contested issues or problematic

RTO provisions, we will make every effort to expedite consideration of the proposed

RTO and we will continue to consider alternatives to formal procedures (e.g., ADR

procedures), where warranted, to avoid initiating a hearing.

What the Commission has approved for ISO forms of governance can be used as

models for governance of RTOs that are ISOs. Nothing in this Rule prohibits the types of
Docket No. RM99-2-000 -679- 

independent governance structures we have approved to date. All of the ISOs approved

to date, except one, have a two-tier form of governance wherein a non-stakeholder board

at the top generally has final decision-making authority on most issues. Below this board

are advisory groups or committees comprised of stakeholders that provide advice and may

share some decision-making authority. With regard to the second-tier, the Commission

has required that no one constituency in any group or committee be allowed to dominate

the recommendation or decision-making process over the objection of the other classes,

and that no one class holds veto power over the will of the remaining classes. The

California ISO's governance structure is different. It has a single-tier hybrid decisionmaking board comprised of both stakeholders and non-stakeholders. No two classes can

push through a decision over the objection of other classes, and no one class has veto

power over the will of the remaining classes.

4. Other Implementation Issues

Commission Conclusion

An additional issue some commenters raised in connection with implementation

concerns how the Commission intends to handle multiple RTO proposals that pertain to

the same or overlapping regions. We expect that proper adherence to the collaborative

process and the RTO scope and configuration factors we have identified, in the first

instance, will bring order to the formation of RTOs such that the Commission will not

need to step in and decide the matter of competing RTOs at the filing stage. 
Docket No. RM99-2-000 -680-

Several miscellaneous RTO implementation issues that were raised by some

commenters concern the terms of withdrawal for members from an RTO, the RTO’s

funding of staff compensation in connection with transfers of personnel from other

entities, and the Commission serving as a backstop for RTO’s ADR processes. These

matters, however, are best left to case-specific determinations in response to particular

RTO proposals.

In response to those who argue for or against rejection or waiver in connection

with less-than-fully-conforming RTO submittals, we believe the concepts of rejection and

waiver are not appropriate. We have provided a significant degree of flexibility in the

minimum characteristics and functions, and in many instances specifically allow for

alternative ways to satisfy those characteristics and functions. Proposals that do not

satisfy the minimum characteristics and functions will not be approved as RTOs. That

does not mean that such a proposal would be summarily rejected; in fact, it may still be

an improvement over the status quo as long as it is consistent with the FPA requirements. 

However, it may be questioned the extent to which entities that are not participating in

RTOs have acted to eliminate the impediments to competition we have identified in this

Final Rule. 

IV. ENVIRONMENTAL STATEMENT

This section reviews and adopts the Environmental Assessment (EA) prepared by

the Commission staff in connection with this Final Rule. It identifies the alternatives
Docket No. RM99-2-000 -681-

considered by the agency in reaching its decision; analyzes and considers whether and to

what extent, if any, the chosen alternative—adoption of this Final Rule—affects the

quality of the human environment; and states the Commission's decision.

Summary

The analysis compares generation and emission trends under the Final Rule to

baseline trends without the Final Rule. The analysis indicates that the Final Rule will

result in little generation change on a net national basis, but there may be shifts in

regional generation. Economic benefits of the Final Rule can be realized with no

significant, adverse environmental impacts. Further, the potential exists for

environmental benefits to be realized, through the encouragement of newer, cleaner

resources.

Discussion

A. Background

To further the policies and goals of the National Environmental Policy Act of 1969

(NEPA), Commission staff prepared an EA in order to examine potential impacts that

could result from implementing the Commission's Rule, and to serve as the basis for

considering whether the Final Rule will have significant impacts on the quality of the

human environment. On May 14, 1999, the Commission issued a notice of intent to

prepare an EA, and a request for comments on the scope of the issues that should be
Docket No. RM99-2-000 -682-

752As noted in the EA, a number of comments filed during scoping relate to

matters outside the scope of the EA, and for the most part deal with policy issues that are

addressed in the Rule.

addressed in the EA. On July 8, 1999, a public scoping meeting was held at the

Commission. On October 22, 1999, the Commission issued an EA, and invited interested

parties to comment on the EA. Comments were due on November 22, 1999.

The Commission received two filed comments on the EA (NMA/WFA/CEED and

Project Groups on behalf of multiple public interest groups). Specific comments are

addressed in the relevant sections below. 752

B. Scope of the Analysis

The EA examines potential environmental impacts that could result from

implementing the Commission's Final Rule. The impacts are necessarily uncertain

because they would be the product of changes in economic regulation that may alter the

future behavior and perhaps the future structure of electricity supply markets. In turn,

these behavioral and structural changes could lead to a different set of environmental

conditions than would otherwise be the case. The analysis recognizes the uncertainty of

the Rule's potential effects on future markets. It presents a systematic view of possible

future market changes and assesses a range of possible responses to market changes, but

should not be seen as predictive of specific market or environmental outcomes. 
Docket No. RM99-2-000 -683-

The EA addresses a broad range of potential economic changes that could result

from the Rule. These impacts include changes in the mix of electric generating plants

built in the future, shifts in the utilization of existing plants, and increases in interregional

transmission. The analysis, therefore, includes major air pollutants: sulfur dioxide (So2),

nitrogen oxides (NOx), mercury, and carbon dioxide associated with various types of

generating plants and fuels. The EA addresses potential environmental impacts at

national and regional levels. 

Project Groups expressed concern that the EA does not retrospectively analyze the

impacts of open access policies to date. As stated in 1.3.2 of the EA, we believe it is

neither possible nor desirable to analyze such changes. Data collection lags, and the short

period of time that has elapsed since the issuance of Order No. 888, would preclude us

from drawing meaningful conclusions.

Project Groups also stated that economic impacts are not specifically reported in

the EA, making it more difficult to evaluate the impacts of the Rule. We note, however,

that the modeling and analysis conducted for the EA are the basis for the economic

discussion contained in the Final Rule. These economic results do not provide a

complete analysis of the potential economic impacts because the analysis considers only

economic effects which may relate to operating decisions or new capacity, and thus may

lead to environmental consequences. However, there are other economic benefits from
Docket No. RM99-2-000 -684-

competitive wholesale electric power markets which have little or no effect on the

environment. 

C. Analytic Approach

Because the impacts that could result from the rulemaking are uncertain, an

analytic approach known as scenario analysis was used. In this approach, alternative

views of the future are postulated and analyzed with and without the Final Rule. 

Potential environmental impacts are evaluated by comparing the analytic results of the

scenarios. First, an analytic base case was developed. This base case relies on the

assumption that the Commission would pursue current policy with respect to wholesale

electric competition using existing rules and procedures, including case-by-case

implementation of regional market arrangements.

Having established an appropriate base case, the EA analyzed future impacts

assuming that the Rule is in effect. Staff adopted the assumption that the Final Rule,

although voluntary, would result in the establishment of RTOs throughout the study area

with the characteristics and functions set forth in the Final Rule. Three scenarios were

developed to reflect a range of possible economic and environmental outcomes: 

Transmission Efficiency Scenario; Transmission/Generation Efficiency Scenario; New

Entry Scenario. 
Docket No. RM99-2-000 -685-

D. Alternatives to the Rule

The primary alternative to the Final Rule is for the Commission to maintain the

status quo, that is, to continue its existing open access policies. The result of this noaction alternative, without implementing the Final Rule, is that the Commission would

effectuate an open transmission grid, but not address changes in the industry that have

occurred since Order No. 888 was adopted. However, the no-action alternative describes

what is likely to happen if the Commission takes no action over and beyond

implementation of existing policies. Once this baseline is established to portray what is

likely to happen in the electric industry during the study period, the projected impacts of

the Final Rule can then be determined against this backdrop.

In addition to the Final Rule and the no-action alternative, several alternative

approaches were considered and ultimately rejected. The alternative of analyzing

mandatory RTOs, as compared with voluntary RTOs as set forth in the Final Rule, was

rejected as moot, since the EA assumes that voluntary RTO formation proceeds with little

delay and is successful in creating RTOs with the functions and characteristics contained

in the Rule. Hence, assumptions for voluntary RTOS and mandatory RTOs are

analytically indistinguishable in terms of their effects on the transmission grid and on the

electric sector generally. 

The other major alternative considered was the analysis of alternative fuel price

assumptions. Project for Sustainable FERC Energy Policy suggested that we prepare
Docket No. RM99-2-000 -686-

such an analysis. However, as we noted in the EA, this alternative was ultimately

rejected for two reasons. First, as reflected in scenarios analyzed in the EIS for Order

No. 888, plausible variation in gas prices relative to coal prices is unlikely to have a

major impact on the environmental effects of the Final Rule. Therefore, a gas price

scenario was selected that had the general characteristics of other forecasts, namely, that

gas prices will rise relative to coal prices. The selection of this gas price scenario does

not represent an endorsement of this particular gas price path. Although we believe it to

be a reasonable projection, it is a merely a representative projection of gas prices for

purposes of the EA. Second, there is no need to consider an alternative where

competition favors gas over coal because such a scenario would have little adverse

impact, especially when compared with scenarios that tend to favor increased coal use

relative to gas use. In the rule scenario we selected, we included, therefore, a number of

improvements in coal technology as a result of the RTO Rule, to ensure that the potential

impacts of any increased coal use relative to the base case would be considered in

assessing the environmental consequences of the rule. 

E. Analytic Framework and Assumptions

It is expected that the impacts of the Final Rule will result primarily from changes

in the types and locations of power plants and transmission facilities constructed in the

future and changes in the operating patterns of existing power plants, including changes

in the fuel mix. To examine the impacts thoroughly, the modeling approach chosen
Docket No. RM99-2-000 -687-

includes detailed representations of electric power plants and the electric transmission

grid, and allows for an economic (least-cost) compliance with existing and future

environmental regulatory requirements. 

Computer modeling capable of simulating regional electric utility dispatch and

capacity expansion over time was used to characterize electric power markets in the base

case and rule scenarios. We used a large supply optimization model of the U.S.

electricity supply sector, which emphasizes pollution estimation and pollution control. It

has been used for Environmental Protection Agency (EPA) regulatory analysis in publicly

accessible proceedings since 1996.

Analytic assumptions are a critical part of the modeling. Because the model

cannot tell us directly what the RTO-related changes will be, it must assess how a set of

assumed changes in the cost and/or physical properties or the electricity system could

lead to changes in the use of the system, and hence to changes in emissions. 

A series of specific assumptions were developed to model the base case and

scenarios. Assumptions common to all modeled cases include current and future prices

of fossil fuels, particularly coal and natural gas, and current and future requirements

imposed on the electric sector by environmental laws and regulations. These

requirements include: for SO2, continuation of the Title IV Acid Rain Program, with

Phase II coverage and levels of permitted emissions; for NOx, Title IV requirements on

coal-fired boilers (Phase I and Phase II); emissions cap restrictions in the Ozone
Docket No. RM99-2-000 -688-

Transport Region starting in 1999, and implementation of the Final Rule governing ozone

transport issued by the EPA in 1997, modeled in accordance with the EPA's guidance. 

This EPA Rule imposes a cap on NOx on large utility boilers in 22 states in the eastern

United States and limiting summer NOx emissions to 543,800 tons; no regulatory

restrictions are assumed for mercury or CO2.

 Project Groups commented that, since assumptions made in the EA about future

environmental regulations are critical in determining the outcome of the analysis, changes

in future environmental regulations (particularly due to legal challenges) from those

assumed in the EA could result in different environmental impacts. Accordingly, the

comment states that the EA should reflect possible changes. We note that there are many

important analytic assumptions embodied in the modeling for the EA. Environmental

regulations are directly represented in the analysis, and changes in these assumed

regulations do have a large effect on the results of the modeling. In particular, the

presence or absence of SO2 and NOx caps is a key assumption. Nevertheless, these

assumptions are based on regulations which are final, as opposed to proposed regulations

or speculative regulatory actions. These rules and associated regulatory analyses from

EPA were used as the basis for the EA assumptions. Accordingly, it would be premature

and speculative to consider changes, if any, from pending legal challenges or speculative

future regulatory changes. 
Docket No. RM99-2-000 -689-

In a broader sense, it is clear that successful competitive energy markets will be

complemented by cost-effective environmental regulation, because the incentives for

efficient behavior on the part of market participants can be decentralized and the need for

intrusive regulatory action is lessened. Emissions trading programs such as those for SO2

and NOx are an important example of such cost-effective regulation.

Other invariant assumptions include: net electric demand growth (with the

exception of New Entry Scenario); load shape (how demand varies with season and time

of day within each model region); costs and performance of new power plants; and

capacity and generation of nuclear, hydroelectric, pumped storage, and import supply.

Because of the importance of the transmission system in the Rule, assumptions

were made about potential changes that may come about either because of the Rule's

requirements or because of its increased incentives for better grid operation and

investment. In addition, the Final Rule is expected to develop more competitive bulk

electric power markets. Competition is expected to increase the incentives for efficient

behavior among market participants. To assess the potential effects of such increased

efficiencies on the environment, some assumptions affecting new and existing power

plants were changed. Finally, to respond to concerns expressed by parties in the scoping

process regarding the role of new entrants in developing competitive power markets,

particularly the RTOs, a model scenario was developed that specifically addresses new

entry and enhanced consumer choice. 
Docket No. RM99-2-000 -690-

F. Impacts

The EA analyzes the electric power capacity and generation projections on a

national and regional level for the base case, and presents the corresponding

environmental impacts. Projected trends in generating capacity, including economic

additions, retirements and modifications, and generation by plant type for the base case,

are analyzed for the years 2005, 2010, and 2015. The data indicate that virtually all

future capacity additions are expected to be gas-fired combined cycle or combustion

turbine units; coal will nevertheless remain the dominant fuel for generation. Growth in

natural gas, however, will be rapid, with the share of generation increasing from 13

percent in 1997 to 32 percent in 2015; total generating capacity is expected to grow at a

slower rate than demand, resulting in plants that will generally be operated at higher

capacity factors; regional patterns of generation reflect regional demand growth as well as

changes in interregional trade in electricity. In most regions, growth in demand is met by

gas-fired (or oil/gas switching) plants, although in the Midwest existing coal-fired

capacity meets part of the growth in the early years of the forecast.

The EA projects national emissions in the base case for SO2, NOx, mercury, and

CO2. There are also regional emissions projections for NOx. The analysis indicates the

following: 

1. SO2 emissions will decline gradually to 9.5 million tons in 2015. Variations in

such emissions during the forecast period primarily reflect economic use of the
Docket No. RM99-2-000 -691-

Title IV emissions banking program, under which emitting parties may elect to

over-control SO2 in any year and bank the extra reductions as emission credits for

later use; 

2. Regional SO2 emissions generally will follow the same pattern as the national

emissions total. However, emissions reductions and shifts are not expected to

occur uniformly across regions because the SO2 emissions trading program allows

emitting parties with higher costs of pollution control to purchase allowances from

emitting parties with lower control costs. This can lead to increases in emissions

from certain regions; 

3. NOx emissions are projected to decline to 4.1 million tons in 2015. These

reductions are due to the development of NOx regulations under the Clean Air Act. 

Furthermore, summer or 'ozone season' (May to September) NOx emissions are

projected to decrease to 1.3 million tons in 2015; 

4. Regional NOx emissions are projected to follow a pattern similar to the national

trend; however, the implementation of NOx controls is assumed to take the form

of an emission cap and permit trading program similar to the Title IV SO2

program. Consequently, certain regions may experience different NOx emissions

trends because of the relative costs of controlling NOx and the possibility of

trading between emitting parties; 
Docket No. RM99-2-000 -692-

5. CO2 is projected to increase throughout the analysis period by 27 percent. 

Because CO2 is an unregulated pollutant at the present time, and because both coal

and natural gas emit CO2, the rise in both coal and gas-fired generation leads to a

substantial increase in CO2 emissions during the analysis period; and 

6. Mercury emissions range between 50.6 and 53.2 tons during the forecast period

with no clear trend distinguishable. Mercury is also uncontrolled at the present

time, but emissions are closely linked to coal use (with considerable variation of

mercury content in coal from specific seams). The relative stability of coal-fired

generation in later years of the analysis period leads to the observed pattern of

mercury emissions.

The analysis indicates that the Midwest is expected to produce slightly more

power, the East Coast to produce slightly less power. These changes are likely to be

greatest in the near-term, and to decline toward baseline levels over time. The Final Rule

would result in the slight shifting of the baseline fuel mix projections toward coal and

away from fuel oil and, to some extent, natural gas; these changes are small relative to the

overall trend in the fuel mix, in which natural gas remains the most rapidly growing fuel. 

This is consistent with the change in regional levels of generation.

The analysis shows that the overall emissions of SOx, NOx, mercury, and CO2, are

directionally consistent with the observed changes in power generation and fuel mix. 

That is, emissions tend to increase early in the forecast period and then decline over time,
Docket No. RM99-2-000 -693-

753See 5 U.S.C. 604. 

with several instances of emissions reductions. The greatest change in any regulated

pollutant (a rise of 3.6 percent or 381,000 tons of SO2 in one scenario) occurs as a result

of changing patterns of emissions banking and trading, which is consistent with the

design of the SO2 cap and trade regulatory program. Regional variations in annual and

summer NOx are also possible and are also consistent with regulatory program design. 

Emissions budgets are met at all times. Other emission changes are relatively small

because coal-fired plants, which contribute a disproportionate share of these emissions,

are already heavily utilized and so are unable to increase their output significantly in the 

rulemaking scenarios. In one scenario designed to examine increased new entry and

demand flexibility, substantial emissions reductions occur as a result of lower demand for

electricity combined with cleaner new supply options.

V. REGULATORY FLEXIBILITY ACT CERTIFICATION

The Commission received no comments on its certification, in the NOPR, that the

proposed rule would not have a significant economic impact on a substantial number of

small entities and that an initial regulatory flexibility analysis is not required by 5 U.S.C.

§ 603. The Commission adheres to its earlier reasoning and thus concludes that a final

regulatory flexibility analysis also is not required. 753 In making this determination, the

Commission is required to examine only the direct compliance costs that a rulemaking
Docket No. RM99-2-000 -694-

754Mid-Tex Elec. Coop. v. FERC, 773 F.2d 327 (D.C. Cir. 1985) (Commission

need only consider small entities "that would be directly regulated"); Colorado State

Banking Bd. v. RTC, 926 F.2d 931 (10th Cir. 1991) (Regulatory Flexibility Act not

implicated where regulation simply added an option for affected entities and did not

impose any costs).

7555 CFR 1320.11, 44 U.S.C. 3507(d).

imposes upon small businesses. It is not required to consider indirect economic

consequences, nor is it required to consider costs that an entity incurs voluntarily. 754

This rulemaking does not impose significant compliance costs upon small entities. 

Instead, it leaves them with the choice of whether to join an RTO. The only costs that are

mandated are the minimal costs associated with filing a statement, in the event a public

utility does not make an RTO filing, explaining its efforts to join an RTO, any barriers it

encountered, and any future plans to join an RTO. Thus, this rulemaking will not have a

significant economic impact upon any small entities.

VI. PUBLIC REPORTING BURDEN AND INFORMATION COLLECTION

STATEMENT

The OMB regulations require OMB to approve certain reporting and

recordkeeping (collections of information) imposed by agency rule. 755 The NOPR was

submitted to OMB at the time of issuance. OMB did not comment nor did it take any
Docket No. RM99-2-000 -695-

756Electric Rate Schedule Filings.

757Application for Sale, Lease, or Other Disposition, Merger or Consolidation of

Facilities or for the Purchase or Acquisition of Securities of a Public Utility.

action on the proposed rule. FERC identifies the information provided under Part 35 as

FERC-516 756 and under Part 33 as FERC-519. 757

No comments from the public on the burden estimate were received. The filing

requirements remain essentially the same as those in the NOPR so, therefore, the

estimated annual filing burden remains the same. The burden estimates for complying

with this proposed rule are set out in Table 1. The total annual hours for collection

(reporting + recordkeeping, (if appropriate)) is 7,600.

Information Collection Costs:

The Commission has projected the average annualized cost for all respondents to be:

Annualized Costs (Operations & Maintenance):

$401,518 (7,600 hours ÷ 2080 hours per year x $109,889 =$401,518).

The cost per respondent is $7,722 (participants and non-participants).

Table 1: Estimated Annual Burden

Data Collection Number of

Respondents

Number of

Responses

Hours Per 

Response

Total

Annual

Hours

FERC-516 112 1 300 3,600

FERC-516 240 1 40 1,600
Docket No. RM99-2-000 -696-

FERC-519 112 1 200 2,400

Totals 7,600

1

Filings to propose participation in an RTO under § 35.34 (d).

2Alternative filings under § 35.34 (g).

Comments were solicited on the Commission's need for this information, whether

the information will have practical utility, the accuracy of the provided burden estimates,

ways to enhance the quality, utility, and clarity of the information to be collected, and

any suggested methods for minimizing respondents' burden, including the use of

automated information techniques.

Title: FERC-516, Electric Rate Schedule Filings;

FERC-519 Application for Sale, Lease, or Other Disposition, Merger or

Consolidation of Facilities or for the Purchase or Acquisition of Securities of a

Public Utility.

Action: Proposed Data Collections.

OMB Control No.: 1902-0096 and 1902-0082.

The applicant shall not be penalized for failure to respond to this collection of

information unless the collection of information displays a valid OMB control number.

Respondents: Business or other for profit, including small businesses.

Frequency of Responses: One time.

Necessity of Information: The Final Rule revises the requirements contained in 18 CFR

part 35. The Commission is promoting the voluntary establishment of RTOs nationwide

by December 2001. In particular, the Commission will establish in this rule
Docket No. RM99-2-000 -697-

characteristics and functions which applicants must meet to become Commissionapproved RTOs. The Commission will engage in a collaborative process with state

officials and others to facilitate RTO development. The rule will require that each public

utility that owns, operates or controls transmission facilities participate in one-time filings

proposing an RTO or make a filing explaining why they are not participating in an RTO

proposal.

Internal Review: The Commission has assured itself, by means of internal review, that

there is specific, objective support for the burden estimates associated with the

information requirements. The Commission's Office of Markets, Tariffs and Rates will

use the data included in filings under 18 CFR 35.34 to evaluate efforts for the

interconnection and coordination of the U.S. electric transmission system and to ensure

the orderly formation of RTOs as well as for general industry oversight. These

information requirements conform to the Commission's plan for efficient information

collection, communication, and management within the electric power industry.

The Commission received approximately 334 comments and reply comments on

its NOPR but none on its reporting burden. The Commission's responses to the

comments are addressed in the preamble of the this Final Rule. The Commission is

submitting a copy of the Final Rule along with information collection submissions for the

data collections identified above to OMB for its review and approval.
Docket No. RM99-2-000 -698-

7585 U.S.C. 804(2).

Interested persons may obtain information on the reporting requirements by

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE,

Washington, DC 20426 [Attention: Michael Miller, Office of the Chief Information

Officer, Phone: (202) 208-1415, fax: (202)208-2425, E-mail: mike.miller@ferc.fed.us]

or send your comments to the Office of Management and Budget, Office of Information

and Regulatory Affairs, Washington, DC 20503, [Attention: Desk Officer for the Federal

Energy Regulatory Commission, phone: (202)395-3087, fax: (202)395-7285].

VII. EFFECTIVE DATE AND CONGRESSIONAL NOTIFICATION

This rule will take effect [on the 60 th day after publication in the Federal

Register]. The Commission has determined, with the concurrence of the Administrator of

the Office of Information and Regulatory Affairs of the Office of Management and

Budget, that this Rule is a "major rule" within the meaning of section 351 of the Small

Business Regulatory Enforcement Act of 1996. 758 The Rule will be submitted to both

Houses of Congress and the Comptroller General prior to its publication in the Federal

Register. 

VIII. DOCUMENT AVAILABILITY

In addition to publishing the full text of this document in the Federal Register, the

Commission provides all interested persons an opportunity to view and/or print the
Docket No. RM99-2-000 -699-

contents of this document via the Internet through FERC's Home Page

(http://www.ferc.fed.us) and in FERC's Public Reference Room during normal business

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A,

Washington, D.C. 20426.

From FERC's Home Page on the Internet, this information is available in both the

Commission Issuance Posting System (CIPS) and the Records and Information

Management System (RIMS).

• CIPS provides access to the texts of formal documents issued by the

Commission since November 14, 1994. CIPS can be accessed using the

CIPS link or the Energy Information Online icon. The full text of this

document will be available on CIPS in ASCII and WordPerfect 8.0 format

for viewing, printing, and/or downloading.

• RIMS contains images of documents submitted to and issues by the

Commission after November 16, 1981. Documents from November 1995

to the present can be viewed and printed from FERC's Home Page using the

RIMS link or the Energy Information Online icon. Descriptions of

documents back to November 16, 1981, are also available from RIMS-onthe-Web; requests for copies of these and other older documents should be

submitted to the Public Reference Room.
Docket No. RM99-2-000 -700-

User assistance is available for RIMS, CIPS, and the Website during normal

business hours from our Help line at (202) 208-2222 (e-mail to WebMaster@ferc.fed.us)

of the Public Reference Room at (202) 208-1371 (e-mail to

public.referenceroom@ferc.fed.us).

During normal business hours, documents can also be viewed and/or printed in

FERC's Public Reference Room, where RIMS, CIPS, and the FERC Website are

available. User assistance is also available.

List of Subjects in 18 CFR Part 35

Electric power rates, Electric utilities, Reporting and recordkeeping requirements

By the Commission.

(S E A L )

 David P. Boergers,

 Secretary.
Docket No. RM99-2-000 -701-

In consideration of the foregoing, the Commission amends Part 35, Chapter I, Title

18 of the Code of Federal Regulations, as follows:

PART 35 - FILING OF RATE SCHEDULES

1. The authority citation for Part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-

7352.

2. Part 35 is amended by adding a new Subpart F and a new § 35.34 to read as

follows:

Subpart F - Procedures and Requirements Regarding Regional 

Transmission Organizations

§ 35.34 Regional Transmission Organizations.

(a) Purpose. This section establishes required characteristics and functions for

Regional Transmission Organizations for the purpose of promoting efficiency and

reliability in the operation and planning of the electric transmission grid and ensuring

non-discrimination in the provision of electric transmission services. This section further

directs each public utility that owns, operates, or controls facilities used for the

transmission of electric energy in interstate commerce to make certain filings with respect

to forming and participating in a Regional Transmission Organization.
Docket No. RM99-2-000 -702-

(b) Definitions. 

(1) Regional Transmission Organization means an entity that satisfies the

minimum characteristics set forth in paragraph (j) of this section, performs the functions

set forth in paragraph (k) of this section, and accommodates the open architecture

condition set forth in paragraph (l) of this section.

(2) Market participant means:

(i) Any entity that, either directly or through an affiliate, sells or brokers electric

energy, or provides transmission or ancillary services to the Regional Transmission

Organization, unless the Commission finds that the entity does not have economic or

commercial interests that would be significantly affected by the Regional Transmission

Organization's actions or decisions; and 

(ii) Any other entity that the Commission finds has economic or commercial

interests that would be significantly affected by the Regional Transmission Organization's

actions or decisions.

(3) Affiliate means the definition given in section 2(a)(11) of the Public Utility

Holding Company Act (15 U.S.C. 79b(a)(11)). 

(4) Class of market participants means two or more market participants with

common economic or commercial interests.

(c) General rule. Except for those public utilities subject to the requirements of

paragraph (h) of this section, every public utility that owns, operates or controls facilities
Docket No. RM99-2-000 -703-

used for the transmission of electric energy in interstate commerce as of [effective date of

Final Rule] must file with the Commission, no later than October 15, 2000, one of the

following: 

(1) A proposal to participate in a Regional Transmission Organization consisting

of one of the types of submittals set forth in paragraph (d) of this section; or 

(2) An alternative filing consistent with paragraph (g) of this section. 

(d) Proposal to participate in a Regional Transmission Organization. For purposes

of this section, a proposal to participate in a Regional Transmission Organization means: 

(1) Such filings, made individually or jointly with other entities, pursuant to

sections 203, 205 and 206 of the Federal Power Act (16 U.S.C. 824b, 824d, and 824e), as

are necessary to create a new Regional Transmission Organization;

(2) Such filings, made individually or jointly with other entities, pursuant to

sections 203, 205 and 206 of the Federal Power Act (16 U.S.C. 824b, 824d, and 824e), as

are necessary to join a Regional Transmission Organization approved by the Commission

on or before the date of the filing; or

(3) A petition for declaratory order, filed individually or jointly with other entities,

asking whether a proposed transmission entity would qualify as a Regional Transmission

Organization and containing at least the following:

(i) A detailed description of the proposed transmission entity, including a

description of the organizational and operational structure and the intended participants;
Docket No. RM99-2-000 -704-

(ii) A discussion of how the transmission entity would satisfy each of the

characteristics and functions of a Regional Transmission Organization specified in

paragraphs (j), (k)and (l) of this section; 

(iii) A detailed description of the Federal Power Act section 205 rates that will be

filed for the Regional Transmission Organization; and

(iv) A commitment to make filings pursuant to sections 203, 205 and 206 of the

Federal Power Act (16 U.S.C. 824b, 824d, and 824e), as necessary, promptly after the

Commission issues an order in response to the petition.

(4) Any proposal filed under this paragraph (d) must include an explanation of

efforts made to include public power entities in the proposed Regional Transmission

Organization.

(e) Innovative transmission rate treatments for Regional Transmission

Organizations.

(1) The Commission will consider authorizing any innovative transmission rate

treatment, as discussed in this paragraph (e), for an approved Regional Transmission

Organization. An applicant's request must include:

 (i) A detailed explanation of how any proposed rate treatment would help achieve

the goals of Regional Transmission Organizations, including efficient use of and

investment in the transmission system and reliability benefits to consumers;

(ii) A cost-benefit analysis, including rate impacts; and
Docket No. RM99-2-000 -705-

(iii) A detailed explanation of why the proposed rate treatment is appropriate for

the Regional Transmission Organization.

The applicant must support any rate proposal under this paragraph (e) as just, reasonable,

and not unduly discriminatory or preferential.

(2) For purposes of this paragraph (e), innovative transmission rate treatment

means any of the following: 

(i) A transmission rate moratorium, which may include proposals based on

formerly bundled retail transmission rates; 

(ii) Rates of return that (a) are formulary; (b) consider risk premiums and account

for demonstrated adjustments in risk; or (c) do not vary with capital structure; 

(iii) Non-traditional depreciation schedules for new transmission investment; 

(iv) Transmission rates based on levelized recovery of capital costs; 

(v) Transmission rates that combine elements of incremental cost pricing for new

transmission facilities with an embedded-cost access fee for existing transmission

facilities; or

(vi) Performance-based transmission rates.

(3) A request for performance-based transmission rates under this paragraph (e)

may include factors such as: 

(i) A method for calculating initial transmission rates (including price caps and any

provisions for discounting); 
Docket No. RM99-2-000 -706-

(ii) A mechanism for adjusting initial rates, which may be derived from or based

upon external factors or indices or a specific performance measure; 

(iii) Time periods for redetermining initial rates; and 

(iv) Costs to be excluded from performance-based rates. 

(4) An innovative transmission rate treatment or any other rate proposal made for

an approved Regional Transmission Organization may be requested as part of any filing

that is made under paragraph (d) of this section or in any subsequent rate change proposal

under section 205 of the Federal Power Act (16 U.S.C. 824d). Unless otherwise ordered

by the Commission, an approved Regional Transmission Organization may not include in

rates any innovative transmission rate treatment under paragraphs (e)(2)(i) and

(e)(2)(ii)(c) of this section after January 1, 2005.

(f) Transfer of operational control. Any public utility's proposal to participate in a

Regional Transmission Organization filed pursuant to paragraph (c)(1) of this section

must propose that operational control of that public utility's transmission facilities will be

transferred to the Regional Transmission Organization on a schedule that will allow the

Regional Transmission Organization to commence operating the facilities no later than

December 15, 2001.

Note to paragraph (f): The requirement in paragraph (f) of this section may be

satisfied by proposing to transfer to the Regional Transmission Organization ownership

of the facilities in addition to operational control. 
Docket No. RM99-2-000 -707-

(g) Alternative filing. Any filing made pursuant to paragraph (c)(2) of this section

must contain:

(1) A description of any efforts made by that public utility to participate in a

Regional Transmission Organization; 

(2) A detailed explanation of the economic, operational, commercial, regulatory,

or other reasons the public utility has not made a filing to participate in a Regional

Transmission Organization, including identification of any existing obstacles to

participation in a Regional Transmission Organization; and 

(3) The specific plans, if any, the public utility has for further work toward

participation in a Regional Transmission Organization, a proposed timetable for such

activity, an explanation of efforts made to include public power entities in the proposed

Regional Transmission Organization, and any factors (including any law, rule or

regulation) that may affect the public utility's ability or decision to participate in a

Regional Transmission Organization.

(h) Public utilities participating in approved transmission entities. Every public

utility that owns, operates or controls facilities used for the transmission of electric

energy in interstate commerce as of [effective date of Final Rule], and that has filed with

the Commission on or before [effective date of Final Rule] to transfer operational

control of its facilities to a transmission entity that has been approved or conditionally

approved by the Commission on or before [effective date of Final Rule] as being in
Docket No. RM99-2-000 -708-

conformance with the eleven ISO principles set forth in Order No. 888, FERC Statutes

and Regulations, Regulations Preamble January 1991-June 1996 ¶ 31,036 (Final Rule on

Open Access and Stranded Costs), must, individually or jointly with other entities, file

with the Commission, no later than January 15, 2001:

(1) A statement that it is participating in a transmission entity that has been so

approved; 

(2) A detailed explanation of the extent to which the transmission entity in which

it participates has the characteristics and performs the functions of a Regional

Transmission Organization specified in paragraphs (j) and (k) of this section and

accommodates the open architecture conditions in paragraph (l) of this section; and

(3) To the extent the transmission entity in which the public utility participates

does not meet all the requirements of a Regional Transmission Organization specified in

paragraphs (j), (k), and (l) of this section, 

(i) A proposal to participate in a Regional Transmission Organization that meets

such requirements in accordance with paragraph (d) of this section, 

(ii) A proposal to modify the existing transmission entity so that it conforms to the

requirements of a Regional Transmission Organization, or 

(iii) A filing containing the information specified in paragraph (g) of this section

addressing any efforts, obstacles, and plans with respect to conformance with those

requirements.
Docket No. RM99-2-000 -709-

(i) Entities that become public utilities with transmission facilities. An entity that

is not a public utility that owns, operates or controls facilities used for the transmission of

electric energy in interstate commerce as of [effective date of Final Rule], but later

becomes such a public utility, must file a proposal to participate in a Regional

Transmission Organization in accordance with paragraph (d) of this section, or an

alternative filing in accordance with paragraph (g) of this section, by October 15, 2000 or

60 days prior to the date on which the public utility engages in any transmission of

electric energy in interstate commerce, whichever comes later. If a proposal to participate

in accordance with paragraph (d) of this section is filed, it must propose that operational

control of the applicant's transmission system will be transferred to the Regional

Transmission Organization within six months of filing the proposal.

(j) Required characteristics for a Regional Transmission Organization. A Regional

Transmission Organization must satisfy the following characteristics when it commences

operation:

(1) Independence. The Regional Transmission Organization must be independent

of any market participant. The Regional Transmission Organization must include, as part

of its demonstration of independence, a demonstration that it meets the following:

(i) The Regional Transmission Organization, its employees, and any nonstakeholder directors must not have financial interests in any market participant. 
Docket No. RM99-2-000 -710-

(ii) The Regional Transmission Organization must have a decision making process

that is independent of control by any market participant or class of participants.

(iii) The Regional Transmission Organization must have exclusive and independent

authority under section 205 of the Federal Power Act (16 U.S.C. 824d), to propose rates,

terms and conditions of transmission service provided over the facilities it operates. 

Note to paragraph (j)(1)(iii): Transmission owners retain authority under section 205 of

the Federal Power Act (16 U.S.C. 824d) to seek recovery from the Regional Transmission

Organization of the revenue requirements associated with the transmission facilities that

they own. 

(2) Scope and regional configuration. The Regional Transmission Organization

must serve an appropriate region. The region must be of sufficient scope and

configuration to permit the Regional Transmission Organization to maintain reliability,

effectively perform its required functions, and support efficient and non-discriminatory

power markets.

(3) Operational authority. The Regional Transmission Organization must have

operational authority for all transmission facilities under its control. The Regional

Transmission Organization must include, as part of its demonstration of operational

authority, a demonstration that it meets the following: 

(i) If any operational functions are delegated to, or shared with, entities other than

the Regional Transmission Organization, the Regional Transmission Organization must
Docket No. RM99-2-000 -711-

ensure that this sharing of operational authority will not adversely affect reliability or

provide any market participant with an unfair competitive advantage. Within two years

after initial operation as a Regional Transmission Organization, the Regional Transmission

Organization must prepare a public report that assesses whether any division of

operational authority hinders the Regional Transmission Organization in providing

reliable, non-discriminatory and efficiently priced transmission service.

(ii) The Regional Transmission Organization must be the security coordinator for

the facilities that it controls. 

(4) Short-term reliability. The Regional Transmission Organization must have

exclusive authority for maintaining the short-term reliability of the grid that it operates. 

The Regional Transmission Organization must include, as part of its demonstration with

respect to reliability, a demonstration that it meets the following:

(i) The Regional Transmission Organization must have exclusive authority for

receiving, confirming and implementing all interchange schedules. 

(ii) The Regional Transmission Organization must have the right to order

redispatch of any generator connected to transmission facilities it operates if necessary for

the reliable operation of these facilities.

(iii) When the Regional Transmission Organization operates transmission facilities

owned by other entities, the Regional Transmission Organization must have authority to
Docket No. RM99-2-000 -712-

approve or disapprove all requests for scheduled outages of transmission facilities to

ensure that the outages can be accommodated within established reliability standards.

(iv) If the Regional Transmission Organization operates under reliability standards

established by another entity (e.g., a regional reliability council), the Regional

Transmission Organization must report to the Commission if these standards hinder it

from providing reliable, non-discriminatory and efficiently priced transmission service.

(k) Required functions of a Regional Transmission Organization. The Regional

Transmission Organization must perform the following functions. Unless otherwise

noted, the Regional Transmission Organization must satisfy these obligations when it

commences operations.

(1) Tariff administration and design. The Regional Transmission Organization

must administer its own transmission tariff and employ a transmission pricing system that

will promote efficient use and expansion of transmission and generation facilities. As part

of its demonstration with respect to tariff administration and design, the Regional

Transmission Organization must satisfy the standards listed in paragraphs (k)(1)(i) and

(ii) of this section, or demonstrate that an alternative proposal is consistent with or

superior to satisfying such standards.

(i) The Regional Transmission Organization must be the only provider of

transmission service over the facilities under its control, and must be the sole administrator

of its own Commission-approved open access transmission tariff. The Regional
Docket No. RM99-2-000 -713-

Transmission Organization must have the sole authority to receive, evaluate, and approve

or deny all requests for transmission service. The Regional Transmission Organization

must have the authority to review and approve requests for new interconnections.

(ii) Customers under the Regional Transmission Organization tariff must not be

charged multiple access fees for the recovery of capital costs for transmission service over

facilities that the Regional Transmission Organization controls . 

(2) Congestion management. The Regional Transmission Organization must ensure

the development and operation of market mechanisms to manage transmission congestion. 

As part of its demonstration with respect to congestion management, the Regional

Transmission Organization must satisfy the standards listed in paragraph (k)(2)(i) of this

section, or demonstrate that an alternative proposal is consistent with or superior to

satisfying such standards.

(i) The market mechanisms must accommodate broad participation by all market

participants, and must provide all transmission customers with efficient price signals that

show the consequences of their transmission usage decisions. The Regional Transmission

Organization must either operate such markets itself or ensure that the task is performed

by another entity that is not affiliated with any market participant.

(ii) The Regional Transmission Organization must satisfy the market mechanism

requirement no later than one year after it commences initial operation. However, it must

have in place at the time of initial operation an effective protocol for managing congestion.
Docket No. RM99-2-000 -714-

(3) Parallel path flow. The Regional Transmission Organization must develop and

implement procedures to address parallel path flow issues within its region and with other

regions. The Regional Transmission Organization must satisfy this requirement with

respect to coordination with other regions no later than three years after it commences

initial operation.

(4) Ancillary services. The Regional Transmission Organization must serve as a

provider of last resort of all ancillary services required by Order No. 888, FERC Statutes

and Regulations, Regulations Preamble January 1991-June 1996 ¶ 31,036 (Final Rule on

Open Access and Stranded Costs), and subsequent orders. As part of its demonstration

with respect to ancillary services, the Regional Transmission Organization must satisfy the

standards listed in paragraphs (k)(4)(i)-(iii) of this section, or demonstrate that an

alternative proposal is consistent with or superior to satisfying such standards.

(i) All market participants must have the option of self-supplying or acquiring

ancillary services from third parties subject to any restrictions imposed by the Commission

in Order No. 888, FERC Statutes and Regulations, Regulations Preamble January 1991-

June 1996 ¶ 31,036 (Final Rule on Open Access and Stranded Costs), and subsequent

orders.

(ii) The Regional Transmission Organization must have the authority to decide the

minimum required amounts of each ancillary service and, if necessary, the locations at

which these services must be provided. All ancillary service providers must be subject to
Docket No. RM99-2-000 -715-

direct or indirect operational control by the Regional Transmission Organization. The

Regional Transmission Organization must promote the development of competitive

markets for ancillary services whenever feasible.

(iii) The Regional Transmission Organization must ensure that its transmission

customers have access to a real-time balancing market. The Regional Transmission

Organization must either develop and operate this market itself or ensure that this task is

performed by another entity that is not affiliated with any market participant.

(5) OASIS and Total Transmission Capability (TTC) and Available Transmission

Capability (ATC). The Regional Transmission Organization must be the single OASIS

site administrator for all transmission facilities under its control and independently

calculate TTC and ATC. 

(6) Market monitoring. To ensure that the Regional Transmission Organization

provides reliable, efficient and not unduly discriminatory transmission service, the

Regional Transmission Organization must provide for objective monitoring of markets it

operates or administers to identify market design flaws, market power abuses and

opportunities for efficiency improvements, and propose appropriate actions. As part of its

demonstration with respect to market monitoring, the Regional Transmission Organization

must satisfy the standards listed in paragraphs (k)(6)(i)-(iii) of this section, or demonstrate

that an alternative proposal is consistent with or superior to satisfying such standards.
Docket No. RM99-2-000 -716-

(i) Market monitoring must include monitoring the behavior of market participants

in the region, including transmission owners other than the Regional Transmission

Organization, if any, to determine if their actions hinder the Regional Transmission

Organization in providing reliable, efficient and not unduly discriminatory transmission

service.

(ii) With respect to markets the Regional Transmission Organization operates or

administers, there must be a periodic assessment of how behavior in markets operated by

others (e.g., bilateral power sales markets and power markets operated by unaffiliated

power exchanges) affects Regional Transmission Organization operations and how

Regional Transmission Organization operations affect the efficiency of power markets

operated by others.

(iii) Reports on opportunities for efficiency improvement, market power abuses and

market design flaws must be filed with the Commission and affected regulatory

authorities. 

(7) Planning and expansion. The Regional Transmission Organization must be

responsible for planning, and for directing or arranging, necessary transmission

expansions, additions, and upgrades that will enable it to provide efficient, reliable and

non-discriminatory transmission service and coordinate such efforts with the appropriate

state authorities. As part of its demonstration with respect to planning and expansion, the

Regional Transmission Organization must satisfy the standards listed in paragraphs
Docket No. RM99-2-000 -717-

(k)(7)(i) and (ii) of this section, or demonstrate that an alternative proposal is consistent

with or superior to satisfying such standards.

(i) The Regional Transmission Organization planning and expansion process must

encourage market-driven operating and investment actions for preventing and relieving

congestion.

(ii) The Regional Transmission Organization’s planning and expansion process

must accommodate efforts by state regulatory commissions to create multi-state

agreements to review and approve new transmission facilities. The Regional Transmission

Organization's planning and expansion process must be coordinated with programs of

existing Regional Transmission Groups (See § 2.21 of this chapter) where appropriate.

(iii) If the Regional Transmission Organization is unable to satisfy this requirement

when it commences operation, it must file with the Commission a plan with specified

milestones that will ensure that it meets this requirement no later than three years after

initial operation.

(8) Interregional coordination. The Regional Transmission Organization must

ensure the integration of reliability practices within an interconnection and market

interface practices among regions.

(l) Open architecture.

(1) Any proposal to participate in a Regional Transmission Organization must not

contain any provision that would limit the capability of the Regional Transmission
Docket No. RM99-2-000 -718-

Organization to evolve in ways that would improve its efficiency, consistent with the

requirements in paragraphs (j) and (k) of this section.

(2) Nothing in this regulation precludes an approved Regional Transmission

Organization from seeking to evolve with respect to its organizational design, market

design, geographic scope, ownership arrangements, or methods of operational control, or

in other appropriate ways if the change is consistent with the requirements of this section. 

Any future filing seeking approval of such changes must demonstrate that the proposed

changes will meet the requirements of paragraphs (j), (k) and (l) of this section.