Federal Register / Vol. 65, No. 101 / Wednesday, May 24, 2000 / Notices 33537

1We note that other governmental and industry

sources share a heightened awareness to current

reliability issues. See, e.g., Report of the U.S.

Department of Energy’s Power Outage Study Team,

Findings and Recommendations to Enhance

Reliability from the Summer of 1999, at S–1, S–2

(March 2000) (‘‘the reliability events of the summer

of 1999 demonstrated that the necessary operating

practices, regulatory policies, and technological

tools for assuring an acceptable level of reliability

were not yet in place’’); Investigation Into The

Adequacy and Availability of Electric Power (Pub.

Util. Comm. of Ohio, Case No. 00–617–EL–COI,

April 10, 2000) (Ohio Commission notes that ECAR

is predicting a tight capacity situation this summer);

High Temperatures & Electricity Demand: An

Assessment of Supply Adequacy in California

Trends & Outlook (July 1999) (California Energy

Commission staff report showing decreasing reserve

margins); Northwest Power Planning Council,

Pacific Northwest Power Supply Adequacy/

Reliability Study (February 2000) (24 percent

probability of being unable to serve winter loads by

2003).

2Regional Transmission Organizations, Order No.

2000, 65 FR 809 (2000), FERC Stats. and Reg.

¶ 31,089 at 30,997–99 (1999), order on reh’g, Order

No. 2000–A, 65 FR 12,088 (March 8, 2000), FERC

Stats. and Regs. ¶ 31,092 (2000).

3Order Accepting For Filing Proposed MarketBased Rate Schedule And Granting Waivers, 90

FERC ¶ 61,329 (2000) (InPower).

4We note that while entities become ‘‘public

utilities’’ subject to the Federal Power Act when

they commence the sale of electric energy at

wholesale in interstate commerce, they cease to be

public utilities when such sales cease (assuming

they engage in no other activities that would make

them public utilities) without further Commission

action. See Century Power Corporation, 72 FERC

¶ 61,045 at 61,279 (1995).

5See, e.g., InPower, 90 FERC at 62,105; Reliant

Energy, Inc., et al., 91 FERC ¶ 61,073 at Appendix

B (2000). The Commission has generally waived for

such sellers the following parts of its regulations in

18 CFR: most of Subparts B and C of Part 35

(documentation), Part 41 (accounting verification),

Part 101 (prescribed Uniform System of Accounts),

and Part 141 (annual reports). In addition, where

requirements are statutory, the Commission has

allowed such sellers to make shortened filings to

satisfy Part 33 (disposition of facilities) and Part 45

(interlocking positions), and has granted blanket

authorizations for issuances of securities (Part 34).

Assessment (FEA). The project is

located on Ketchikan Creek and Granite

Basin Creek, near the City of Ketchikan,

in Ketchikan Gateway Borough, Alaska.

The project uses lands administered by

the U.S. Forest Service in the Tongass

National Forest. The Forest Service is a

cooperating agency on this

environmental assessment. The FEA

contains the staff’s analysis of the

potential environmental impacts of the

project and concludes that licensing the

project, with appropriate environmental

protective measures, would not

constitute a major federal action that

would significantly affect the quality of

the human environment.

Copies of the FEA are available for

review in the Public Reference Room,

Room 2A, of the Commission’s offices at

888 First Street, NW., Washington, DC

20426. This FEA may also be viewed on

the web at http://www.ferc.fed.us/

online/rims.htm (please call (202) 208–

2222 for assistance). For further

information, contact Charles Hall at

(202) 219–2853.

Linwood A. Watson, Jr.,

Acting Secretary.

[FR Doc. 00–13010 Filed 5–23–00; 8:45 am]

BILLING CODE 6717–01–M

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

[Docket No. EL00–75–000]

Notice of Interim Procedures To

Support Industry Reliability Efforts and

Request for Comments

May 17, 2000.

As the electric industry prepares for

another summer of potentially high

peak demands, the Commission believes

it is important to identify practical steps

the Commission and others can take to

support the industry’s efforts to ensure

the continued reliability of the electric

power system.1 Accordingly, the

Commission hereby announces a

number of specific actions it will

implement on an interim basis this

summer, and requests comments on

these and other actions the Commission

could take to assist others in their efforts

to address system reliability this

summer.

Background

While the Commission does not have

direct responsibility over reliability

matters, its consistent policy has been to

assure that the exercise of its ratemaking

and other jurisdictional responsibilities

supports and facilities the continued

high degree of reliability that has

existed in the U.S. Indeed, transmission

system reliability is one of the principal

issues sought to be addressed by the

Commission’s recent rulemaking on

Regional Transmission Organizations. 2

The Commission has also been

monitoring the functioning of electricity

markets and has been encouraging good

utility practices through its Enforcement

Hotline and other programs.

Our objective is not to become

involved in the day-to-day operation of

the electric grid or to duplicate or

supplant the efforts of others in the

industry that are engaged in inquiries

about electric reliability issues.

However, it is important that the

Commission exercise its regulatory

mandate in a manner that supports, and

does not impede, efforts to enhance

reliability throughout the industry. The

Commission has identified five actions

that it can take, in exercising its

regulatory responsibilities, that may

provide such support this summer by,

for example, supporting efforts to

increase generation supply, supporting

efforts to implement demand-side

management, and supporting efforts to

maximize the amount of Available

Transmission Capability (ATC) this

summer. In addition to these actions,

the Commission will be expediting

individual cases affecting reliability

planning for this summer which are

pending before the Commission in other

dockets.

Actions Commission Will Implement

During the Summer of 2000

The Commission hereby announces

the following actions that it will

implement to support the electric

industry’s efforts in dealing with

reliability issues this summer. Although

these actions are within the

Commission’s authority to implement

on an immediate basis and will be in

effect on an experimental basis from the

date of this Notice through September

30, 2000, we invite comments on them.

1. There are many businesses that

have installed generators at their

business location to meet a portion of

their own demands or to serve as a

backstop to their purchase of electricity

from the local grid. These generators

may provide a ready source of

generation capacity during periods

when power markets are facing a

temporary generation shortage. Indeed,

we recently approved a tariff under

which the owners of such generation

could sell electricity to a power

marketer in InPower Marketing

Corporation.3 In order to facilitate the

use of existing on-site generators to meet

demand, the Commission will adopt a

streamlined regulatory procedure to

accommodate sales from such facilities

to any entity engaged in sales of electric

energy. Owners of generating facilities

located at business locations and used

primarily for back-up for selfgeneration, who would become subject

to the Federal Power Act by virtue of

sales of power from such facilities,4 will

be permitted to sell power at wholesale

from such facilities to non-affiliated

entities without prior notice under

section 205 of the FPA. Pursuant to FPA

section 205(d), we find good cause to

waive the prior notice requirements for

such sales. Further, the Commission

hereby grants waiver of its regulations

consistent with our recent orders on

market-based rates,5 and authorizes

market-based rates during the identified

time period, subject to the following

requirements: The wholesale purchasers

33538 Federal Register / Vol. 65, No. 101 / Wednesday, May 24, 2000 / Notices

6Although we are asking all wholesale

purchasers who seek to take advantage of these

special procedures to file these reports, it is not our

intent to assert jurisdiction over any wholesale

purchaser who is not otherwise subject to our

jurisdiction, and the submission of such reports

will not alter a purchaser’s jurisdictional status.

7These streamlined procedures are offered as an

option. Any jurisdictional seller may also follow

standard filing requirements if desired.

8See, e.g., Wisconsin Electric Power Company,

Docket No. ER99–2180–000.

9Capacity Benefit Margin in Computing Available

Transmission Capacity, 88 FERC ¶ 61,099 (1999)

(CBM Order).

10CBM Order at 61,237.

11NERC White Paper, Transmission Capability

Margins and Their Use in ATC Determination, 4

(June 17, 1999).

12We also understand that the National

Association of Regulatory Utility Commissioners

(NARUC) Staff Subcommittee on Electric Reliability

has various projects underway that are looking into

such matters as distribution system vulnerability to

summer heat and peak loading, and interconnection

of distributed generation.

of power from such facilities must

report to the Commission the names of

each such seller from whom power was

purchased, the aggregate amount of

capacity and/or energy purchased from

each seller, and the aggregate

compensation paid to each seller.6 To

minimize the number of required

reports, the purchaser may make one

report for all purchases through

September 30, and, if it otherwise files

quarterly transactions summaries with

the Commission, may include this

report as a separate section of its

transaction summary for the third

calendar quarter of 2000. If the

purchaser does not otherwise file

quarterly transactions summaries, it

should file this report with the

Commission by October 31, 2000.7

2. There may be opportunities during

the upcoming summer for public

utilities to make demand-side

arrangements with their wholesale

customers. For example, some

wholesale requirements customers may

have the ability to enter arrangements

with their own retail customers to

reduce load or obtain power from an

industrial generator. Or, a partial

requirements customers may have

access to generating capacity on its own

system. We want to ensure that public

utilities will be able to work with their

customers to negotiate mutually

beneficial arrangements on short notice

should the need arise during periods of

peak summer demand or should other

events occur that affect system

reliability. Since time may be of the

essence as these opportunities are

discovered and negotiated, we find good

cause to waive the FPA’s prior notice

requirement for any rate schedule

amendments that may be required to

effect these types of arrangements. Thus,

to the extent a mutually agreeable DSM

alternative changes the terms and

conditions of a contract within our

jurisdiction, we will grant waiver of the

filing of prior notice of the change. By

October 31, 2000, the public utility

supplier must amend the filed rate

schedule. The filing must consist of a

report containing the following

information: the FERC rate schedule

numbers, the load reduction negotiated

under the DSM arrangement (MW/

MWh), total compensation, and the

name of each affected wholesale

customer.

3. While most power sales are

currently transacted under market-based

rates, there are occasions when utilities

continue to operate under cost-based

rates. Often, these cost-based rate

incorporate formulas that are intended

to track the actual out-of-pocket (i.e.,

incremental) cost that was incurred to

generate or purchase the energy. During

periods of generation shortage, some

utilities may be in a position to engage

in DSM transactions with their

wholesale and retail requirements

customers in order to free up capacity

for resale to neighboring utilities. These

transactions will not take place unless

any DSM expenditures can also be

recovered under the rate formula, as are

all other out-of-pocket costs. However,

most rate schedules define out-of-pocket

or incremental cost in terms of expenses

incurred to generate power, rather than

costs incurred to compensate a

preexisting customer to reduce load. A

few jurisdictional utilities have

amended their cost-based pricing

formulas to recognize the fact that DSM

costs are a form of out-of-pocket or

incremental cost.8 In order to eliminate

any disincentive to rely on DSM as a

source of supply during generation

shortages, we clarify that DSM costs

should be treated consistently with all

other types of incremental and out-ofpocket costs.

4. In prior orders, we have noted that

the deductions from ATC to reflect

reliability needs (Capacity Benefit

Margin or CBM) can often be reduced in

the near-term as the transmission

provider gains certainty as to whether

the assumptions underlying the CBM

computation have, in fact,

materialized.9 The Commission takes

this opportunity to remind transmission

providers that they are required to

reassess CBM assumptions for the

current period and determine whether

they have, in fact, materialized, e.g.,

load, temperature and generation

outages.10 Another element of the ATC

calculation is the Transmission

Reliability Margin (TRM), i.e.,

transmission capacity that is set aside to

account for the inherent uncertainty in

system conditions and the need for

operating flexibility to ensure reliable

system operation as system conditions

change.11 Since the assumptions

underlying TRM calculations similarly

become more certain in the near-term,

we expect transmission providers to

engage in the same periodic

reassessment of TRM needs. Any

changes in CBM and TRM must, of

course, be reflected in recalculated ATC.

By keeping both CBM and TRM setaside values up to date, OASIS postings

will be more accurate. Accurate ATC is

crucial to facilitating power sale

transactions that can relieve stresses on

the Nation’s electric systems.

5. The Commission will be responsive

throughout the summer period to

suggestions and questions regarding

actions that relate to electric system

reliability. The Commission is directing

its staff to assist with regulatory

questions related to practical ideas

about what the Commission can do to

support the electric industry’s efforts

with respect to reliability issues. The

Commission staff, including the Hotline

staff, will be available to respond to

questions and suggestions in this regard.

Actions Others Could Take

There are likely other actions that

could be taken, either by industry

participants or state regulators, that

could alleviate potential reliability

problems during this summer. These

include using demand-side management

and applying market mechanisms to

stimulate demand-side response;

eliminating any regulatory disincentives

to customers’ integrating on-site supply

and demand solutions; promoting

energy efficiency; and improving

coordination and preparation for

electricity emergencies.12 Where the

Commission does not have a direct role

in such matters, we seek suggestions

from state authorities and industry

organizations as to how we could assist

in these, or other, areas.

Request for Comments

The Commission seeks the views of

industry participants, organizations, and

state regulatory authorities on the

actions identified herein and on

identifying what other short-term

measures the Commission and others

could take to alleviate reliability stress

during peak periods.

For example, in the short term, are

there any Commission regulations that

Federal Register / Vol. 65, No. 101 / Wednesday, May 24, 2000 / Notices 33539

13See supra note 1.

1See, e.g., Coalition Against Private Tariffs, 83

FERC ¶ 61,015, reh’g denied, 84 FERC ¶ 61,050

(1998); North American Electric Reliability Council,

85 FERC ¶ 61,353 (1998), order on reh’g, 87 FERC

¶ 61,161 (1999).

the Commission should consider

waiving to facilitate electricity

commerce during periods when

electricity markets are stressed? Can the

Commission do more in the short-term

to facilitate interconnections? We note

that the Public Utilities Commission of

Ohio has opened an inquiry into the

readiness of its electric utilities to

respond to higher demands for

electricity this summer.13 Is there

anything the Commission should do to

support such efforts?

In addition, while our request for

comments is directed primarily toward

interim initiatives to alleviate reliability

concerns for this summer, would it be

useful for the Commission to convene a

public conference later in the year to

discuss longer-term initiatives relating

to electric system operation during peak

demand periods? Are there longer-term

initiatives that the Commission should

consider, such as initiating a review of

regional market rules with the goal of

clarifying aspects that are ambiguous?

The Commission is interested in hearing

from such organizations as state

regulatory authorities, trade groups,

independent system operators, and the

North American Electric Reliability

Council as to what longer-term

measures they or the Commission

should consider to deal with reliability

stresses.

We request that any comments on

short-term interim measures be

submitted to us by June 2, 2000. Such

comments should be concise and

specifically focused on either the

specific actions implemented in this

Notice or other specific actions capable

of being accomplished in the short term.

We request that any comments on

longer-term initiatives or actions be

submitted to us by June 30, 2000.

Interested persons should submit an

original and 14 copies of any comments

to the Office of the Secretary, Federal

Energy Regulatory Commission, 888

First Street, NE, Washington, DC 20426,

and should reference Docket No. EL00–

75–000.

The Commission orders:

(A) For entities meeting the

qualifications set forth in Paragraph 1 of

this Notice, and who satisfy the

reporting requirements set forth in that

Paragraph, the following advance

waivers and authorizations are hereby

granted for the period beginning the

date of this Notice until September 30,

2000:

(1) The prior notice requirement of

section 205 of the Federal Power Act is

hereby waived.

(2) Waiver is hereby granted for Parts

35, 41, 101, and 141 of the

Commission’s regulations.

(3) Authorization is hereby granted to

issue securities and assume obligations

and liabilities, provided that such issue

or assumption is for some lawful object

within the corporate purposes of the

eligible entities, compatible with the

public interest, and reasonably

necessary or appropriate for such

purposes.

(4) The full requirements of Part 45 of

the Commission’s regulations, except as

noted, are hereby waived with respect to

any person now holding or who may

hold an otherwise proscribed

interlocking directorate involving any

eligible entity. Any such person instead

shall file a sworn application providing

the following information:

(a) full name and business address;

and

(b) all jurisdictional interlocks,

identifying the affected companies and

the positions held by that person.

(B) The prior notice requirement for

rate schedule changes described in

Paragraph 2 of this Notice is hereby

waived, conditioned on the public

utility complying with the filing

requirements set forth in that Paragraph.

By direction of the Commission.

Commissioner He ́bert concurred with a

separate statement attached.

Linwood A. Watson, Jr.,

Acting Secretary.

Notice of Interim Procedures To Support

Industry Reliability Efforts and Request for

Comments

[Docket No. EL00–75–000]

Issued May 17, 2000.

HE ́BERT, Commissioner, concurring

I certainly agree with my colleagues that

the Commission’s actions should promote the

continued reliability of the electric power

system. And I agree that the Commission

should take affirmative steps, to the extent

consistent with its jurisdictional authority, to

enhance the reliability of the system this

summer and future summers. Because

today’s notice does not appear to hurt our

reliability efforts, and might offer some slight

marginal benefit, I concur with its issuance.

But I write separately to lament the lost

opportunity this notice represents.

Unfortunately, the Commission today offers

little that will significantly enhance the

reliability of the electrical grid. The

Commission could be doing so much more to

address the perceived problem. All today’s

notice actually accomplishes is to announce

that the Commission is doing its job, and

deflect blame for any disruptions this

summer to Congress. In my judgment, any

blame should be directed at this Commission

for not taking decisive action last summer

and two summers ago, and in all previous

seasons, to promote capital investment in our

energy infrastructure and new entry into

emerging competitive markets.

I find peculiar the timing of today’s notice.

In the 21⁄2 years I have served as

Commissioner, the Commission has refrained

from moving too ambitiously and directly

into the reliability arena. I have admired the

Commission’s restraint. For example, the

Commission admirably resisted the

temptation to demonstrate its regulatory

muscle in responding to the Midwestern

‘‘price spikes’’ during the summer of 1998.

Despite pleas from some that temporarily

high prices suggested a system on the verge

of collapse, the Commission resisted the urge

to intercede into emerging competitive

wholesale markets by, among other things,

developing reliability and financial integrity

standards.

Rather, the Commission historically has

left matters of reliability to the true experts

in the field—the North American Electric

Reliability Council, the various regional

reliability councils around the country, and

all affected industry participants. Realizing

that the issue of reliability is complex and

requires intimate familiarity with local

facilities and institutions, the Commission

historically has left this matter to industryled groups, working in concert with all

affected stakeholders. The Commission has

interceded only when its review of

reliability-based practices was necessary to

ensure the availability and quality of open

access transmission service. Recent orders,

such as those addressing the issue of

‘‘tagging’’ customer requests for service and

the circumstances in which utilities may

invoke line loading (i.e., curtailment)

procedures when the system is

oversubscribed, attest to the Commission’s

limited role.1 Another order, involving the

Western Systems Coordinating Council,

attests to the Commission’s willingness to

support regional industry and stakeholder

efforts to promote mandatory compliance

33540 Federal Register / Vol. 65, No. 101 / Wednesday, May 24, 2000 / Notices

2See Western Systems Coordinating Council, 87

FERC ¶ 61,060 (1999).

3A Department of Energy report, providing

documentation for the Secretary’s opinion, is cited

in footnote 1 of today’s notice.

4My experience as a state commissioner shows

the difficulty of creating effective DSM programs. I

am skeptical of the hasty decision the notice makes

on guaranteeing DSM cost recovery.

5See ISO New England, Inc., 88 FERC ¶ 61,316

at 61,973–74 (1999); California Independent System

Operator Corporation, 89 FERC ¶ 61,169 at 61,513–

15 (1999); ISO New England, Inc.; New England

Power Pool, 90 FERC ¶ 61,170 at 61,555–57 (2000).

6See Alliance Companies, et al., 91 FERC ¶ ___

(2000).

7See, e.g., Independence Pipeline Company, et

al., 91 FERC ¶ ___ (2000) (dissenting statement).

(through contracts) with reliability

standards.2

In my opinion, little operationally has

changed to motivate the Commission to

take a more activist role on reliability.

I suspect the real reason for the

Commission’s enhanced interest is

politics and public opinion. Today’s

newspapers are ablaze with headlines

screaming of looming energy crises and

impending blackouts and brownouts.

Much of this hysteria, unfortunately,

has been fed by the Clinton/Gore

Administration. Indeed, in a front page

article in the Wall Street Journal, dated

May 11, 2000, captioned ‘‘Gloom and

Doom: New Rules, Demands Put

Dangerous Strain on Electricity

Supply,’’ the Secretary of Energy is

quoted as saying that the United States

has ‘‘the grid of a Third World nation.’’ 3

I am not so pessimistic. The United

States long has enjoyed the most reliable

electrical delivery system in the world.

The advent of competitive markets and

increasing reliance on competitive

forces—rather than command and

control regulatory policies—to regulate

energy markets do not alter this

judgment.

It is true that increased competition,

and the emergence of a myriad of

market participants and offerings, is

placing strains on a electrical network

that was not designed for such

competitive forces. I agree with the rest

of the Commission, as well as Secretary

Richardson, that something more should

be done to enhance reliability and to

avoid unexpected outages. I simply

disagree as to the means to accomplish

this result.

Today’s notice offers various

measures intended to promote supply,

enhance deliverability, and temper

demand. My personal opinion is that

offering market-based rates to the

owners of on-site generation will

introduce precious few megawatts into

the interstate grid. Demand-side

measures to conserve energy are almost

entirely within the purview of the

states.4 Transmission providers already

have an obligation to update

periodically their calculation and

posting of available transmission

capability. And Commission staff,

identified to ‘‘assist with regulatory

questions related to practical ideas’’

about reliability, will have limited

ability to offer any real help.

My strong preference would be for the

Commission, if now inclined to act on

reliability, to take decisive action in an

area that clearly lies within its existing

jurisdiction—the pricing of wholesale

power and transmission services. As I

have been advocating ever since I first

came to the Commission, the

Commission has within its jurisdiction

the ability to promote reliability—if it

really means what it now states. For

starters, if the Commission is serious

about increasing generation supply, it

should act immediately to withdraw all

price caps in generation markets. I have,

unfortunately, written in dissent on

many occasions as to the harmful

supply effects of price caps.5 They

distort price signals and inhibit entry

into competitive markets. By facilitating

efforts to minimize short-term price

disruptions, and placing regulatory

shackles on what should be competitive

markets, the Commission is inhibiting

precisely the type of investment in the

grid that it claims it is now supporting—

and that is crucial to assuring true

electrical reliability.

Another important means of

enhancing reliability is to give

transmission providers an incentive to

provide reliable, efficient service.

Conventional pricing methods provide

no such incentive. It is my strong

preference to afford utilities some type

of performance-based measure of

accountability to their customers and

their regulators. Consistent with its

existing authority, the Commission

could—and should—tie earnings and

profits to reliability-based and

performance-based criteria (such as the

number and duration of service

interruptions, customer satisfaction, and

throughout).

Despite my urgings, the Commission

has refused to adopt performance-based

pricing measures. I was tremendously

gratified when the Commission made its

first tentative moves in this direction

when it adopted its Order No. 2000

rulemaking on the development of

regional transmission organizations. As

the Commission explained, a RTO that

meets the enumerated characteristics

and functions—and that has

demonstrated a commitment to promote

grid reliability and efficiency—will be

eligible for a number of incentives.

These incentives include performancebased rates, accelerated depreciation,

and return on equity enhancements

(formula and risk-based).

While I appreciate the Commission’s

baby steps on performance-based

pricing, it will take awhile for RTOs to

develop, win the Commission’s

approval, and qualify for innovative

pricing. If it were up to me, I would

adopt pricing measures now that would

give both regional and individual

transmission providers an incentive to

minimize or eliminate service

disruptions this summer and future

summers.

I can think of numerous other

measures the Commission can adopt to

promote reliability, without delay and

without additional authority conferred

by Congress. The Commission could

afford transcos an additional incentive

to build transmission facilities by

providing a higher rate of return on

transmission assets. The Commission

could articulate greater receptivity to

proposals to build and invest in

merchant transmission facilities. The

Commission could pique additional

interest in investment and corporate

restructuring by allowing acquisition

adjustments on the sale of transmission

assets that confers benefits on

ratepayers.

In addition, the Commission could

greatly advance the cause of reliability

by indicating its support for stand-alone

transmission companies. (In another

order on today’s agenda, I express

serious concern as to the Commission’s

rejection of the proposed ownership

structure for the proposed Alliance

transco.) 6 As I have oft-stated, a

transco—much more so than any other

type of regional institution—has a

strong economic incentive to provide

reliable and efficient service. I wish the

Commission would give a transmission

company the chance to operate—and

give an unequivocal green light to other

utilities that might be considering

participation in similar for-profit

ventures.

And the Commission—if truly

committed to providing supply

alternatives—could do much more to

promote the development of

hydroelectric facilities and the

construction of natural gas transmission

facilities.7 The answer to our nation’s

energy reliability needs lies not in the

development of additional regulatory

bodies and responsibilities—as the

Administration, with the acquiescence

of a majority of this Commission, now

argues. Rather, the answer lies in

Federal Register / Vol. 65, No. 101 / Wednesday, May 24, 2000 / Notices 33541

promoting policies that encourage capital

investment in all types of energy

technologies and that allow competitive

markets to operate as they should.

I recognize that certain of my suggestions,

to some, might fall into the category of ‘‘longterm’’ measures that, even if implemented

immediately, would not help this upcoming

summer. Of course, if the Commission had

adopted such reliability-based measures in

prior years, it would not have realized the

urgency to issue today’s notice. And further

delay merely exacerbates the conditions

identified in the notice. For this reason, I do

not see the advantage of differentiating

between short-term and long-term fixes, or

awaiting the filing of comments on the

subject. Nor do I see any value in convening

a ‘‘public conference’’ on the subject of

reliability initiatives. The Commission held

such a conference in February of 1998, and

has since received numerous comments and

pleadings on the topic.

In short, there’s not need to await further

action by Congress. The Commission already

has all the authority it needs to effect real

reform that will promote reliable and

efficient utility service. And there is no need

to delay to allow for further grandstanding by

industry participants. By this point, after

several summers of experience under

competitive markets, we all know the way to

promote reliability and efficiency—by

encouraging investment and by allowing

competitive markets to operate.

Therefore, I respectfully concur.

Curt L. He ́bert, Jr.,

Commissioner.

[FR Doc. 00–13008 Filed 5–23–00; 8:45 am]

BILLING CODE 6717–01–M

DEPARTMENT OF ENERGY

Western Area Power Administration

Proposed Rates for Transmission

Service on the Central Arizona Project

115–kV and 230–kV Transmission

Lines

AGENCY: Western Area Power

Administration, DOE.

ACTION: Notice of proposed rates.

SUMMARY: The Western Area Power

Administration’s (Western) Desert

Southwest Customer Service Region

(DSW) is proposing rate methodologies

to calculate the rates for firm point-topoint transmission service, nonfirm

point-to-point transmission service, and

Network Integration Transmission

Service (NITS) on the Central Arizona

Project (CAP) 115–kV and 230–kV

transmission lines. The proposed

calculated rates will provide enough

revenue to pay all annual costs,

including interest expense, and repay

the required investment within the

allowable period. The proposed rate

methodologies are scheduled to go into

effect on October 1, 2000, and will

remain in effect through September 30,

2005. This Federal Register notice

initiates the formal process for these

proposed rate methodologies.

DATES: The consultation and comment

period will begin from the date of

publication of this Federal Register

notice and will end August 22, 2000.

DSW will present a detailed explanation

of the proposed rate methodologies and

will make available a rate brochure at a

public information forum scheduled for

June 16, 2000, beginning at 10 a.m.

MST, at the DSW office. Western will

receive oral and written comments at a

public comment forum on July 17, 2000,

beginning at 10 a.m. MST, also to be

held at the DSW office.

ADDRESSES: Written comments are to be

sent to: Mr. J. Tyler Carlson, Regional

Manager, Desert Southwest Customer

Service Region, Western Area Power

Administration, P.O. Box 6457,

Phoenix, AZ 85005–6457, or by e-mail:

carlson@wapa.gov. Western should

receive written comments by the end of

the consultation and comment period to

be assured consideration. Western’s

DSW office, is located at 615 South 43rd

Avenue, Phoenix, Arizona.

FOR FURTHER INFORMATION CONTACT: Mr.

Maher A. Nasir, Rates Team Lead,

Desert Southwest Customer Service

Region, Western Area Power

Administration, P.O. Box 6457,

Phoenix, AZ 85005–6457, telephone

(602) 352–2768, or by e-mail:

nasir@wapa.gov.

SUPPLEMENTARY INFORMATION: The CAP

115–kV and 230–kV transmission lines

have been used almost exclusively to

provide power to the CAP water pumps.

The planned construction of a number

of independent power plants in Arizona

and Nevada creates a potential demand

for use of surplus transmission capacity

on the CAP 115–kV and 230–kV

transmission lines.

The proposed rate methodologies for

point-to-point transmission service and

NITS on the CAP 115–kV and 230–kV

transmission lines are based on a

revenue requirement that recovers the

CAP 115–kV and 230–kV transmission

lines costs for facilities associated with

providing transmission service and the

non-facilities costs allocated to

transmission service. The methodology

for calculating the rates for point-topoint transmission service on the CAP

115–kV and 230–kV transmission lines

is determined by combining the annual

amortization costs with the annual

operations and maintenance costs,

divided by the annual average contract

rate of delivery. Implementing the

proposed rate methodology results in a

firm point-to-point CAP 115BkV and

230–kV transmission line rate of $8.37

per kilowattyear and a nonfirm point-topoint CAP 115–kV and 230–kV

transmission line rate of 0.96 mills/

kWh.

NITS allows a transmission customer

to integrate, plan, economically

dispatch, and regulate its network

resources to serve its native load in a

way comparable to how a transmission

provider uses its own transmission

system to service its native load

customers. The monthly charge

methodology for NITS on the CAP 115–

kV and 230–kV transmission lines is the

product of the transmission customer’s

load-ratio share times one-twelfth of the

annual transmission revenue

requirement. The customer’s load-ratio

share is calculated on a rolling 12-

month basis (12CP). The customer’s

load-ratio share is equal to that

customers’ hourly load coincident with

the CAP 115–kV and 230–kV

transmission lines monthly

transmission system peak divided by

the resultant value of the CAP 115–kV

and 230–kV transmission lines monthly

transmission system peak minus the

CAP 115–kV and 230–kV transmission

lines coincident peak for all firm pointto-point transmission service plus the

CAP 115–kV and 230–kV transmission

lines firm point-to-point transmission

service reservations.

The proposed rate methodologies

include the costs for scheduling, system

control, and dispatch service.

These rate methodologies for

transmission service on the CAP 115–kV

and 230–kV transmission lines are being

set following the Department of Energy

Organization Act, 42 U.S.C. 7101–7352;

the Reclamation Act of 1902, ch. 1093,

32 Stat. 388, as amended and

supplemented by subsequent

enactments, particularly section 9(c) of

the Reclamation Project Act of 1939, 43

U.S.C. 485h(c); and other acts

specifically applicable to the project

involved.

By Amendment No. 3 to Delegation

Order No. 0204–108, published

November 10, 1993 (58 FR 59716), the

Secretary of Energy delegated (1) the

authority to develop long-term power

and transmission rates on a

nonexclusive basis to the Administrator

of Western; and (2) the authority to

confirm, approve, and place into effect