[Federal Register Volume 67, Number 168 (Thursday, August 29, 2002)]
[Proposed Rules]
[Pages 55452-55592]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-21479]



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Part II





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 35



Remedying Undue Discrimination Through Open Access Transmission Service 
and Standard Electricity Market Design; Proposed Rule

  Federal Register / Vol. 67, No. 168 / Thursday, August 29, 2002 / 
Proposed Rules  

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM01-12-000]


Remedying Undue Discrimination Through Open Access Transmission 
Service and Standard Electricity Market Design

July 31, 2002.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes 
to amend its regulations under the Federal Power Act (FPA) to modify 
the pro forma open access transmission tariff established under the 
Commission's Order No. 888 to remedy remaining undue discrimination in 
the provision of interstate transmission services and in other industry 
practices, and to assure just and reasonable rates within and among 
regional power markets. The Commission proposes to require all public 
utilities with open access transmission tariffs to file modifications 
to their tariffs to reflect non-discriminatory, standardized 
transmission service and standardized wholesale electric market design.

DATES: Initial comments are due on October 15, 2002. Comments should 
include an executive summary that does not exceed 10 pages.

ADDRESSES: Send comments to: Office of the Secretary, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:   
Alice Fernandez (Technical Information), Office of Markets, Tariffs and 
Rates, Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426. (202) 208-0089. (202) 502-6389 (after Aug. 7, 
2002).
David Mead (Technical Information), Office of Markets, Tariffs and 
Rates, Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426. (202) 208-1024. (202) 502-8028 (after Aug. 7, 
2002).
Mark Hegerle (Technical Information), Office of Markets, Tariffs and 
Rates, Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426. (202) 208-0287. (202) 502-8287 (after Aug. 7, 
2002).
David Withnell (Legal Information), Office of General Counsel, Federal 
Energy Regulatory Commission, 888 First Street, NE., Washington, DC 
20426. (202) 208-2063. (202) 502-8421 (after Aug. 15, 2002).

SUPPLEMENTARY INFORMATION: 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 contents of 
this document via the Internet through FERC's home page (http://www.ferc.gov) and in FERC's Public Reference Room during normal 
business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, 
NE., Washington, DC 20426.

                                                Table of Contents
 
 
 
                                                                                                       Paragraph
I. Introduction                                                                                                1
II. Background: Order No. 888 and Order No. 2000                                                              20
    A. Order Nos. 888 and 888-A                                                                               20
    B. Order No. 2000                                                                                         24
III. Need for Reform                                                                                          31
    A. Undue Discrimination and Impediments to Competition Remain                                             31
    B. Specific Instances of Undue Discrimination and Impediments to Competition                              36
        1. Transmission Market Power by Utilities that are Not Independent                                    38
            a. Load Growth                                                                                    41
            b. Delays in Responding to Requests for Service                                                   43
            c. Scheduling Advantages                                                                          45
            d. Imbalance Resolution                                                                           48
            e. Available Transfer Capability and Affiliates                                                   50
            f. OASIS Postings                                                                                 52
            g. Capacity Benefit Margin Manipulation                                                           55
            h. Discretionary Use of Transmission Loading Relief                                               57
        2. Lack of Common Rules Governing Transmission                                                        61
        3. Congestion Management                                                                              71
        4. Seams Problems                                                                                     80
        5. Market Design Flaws                                                                                86
    C. Reform Essential Given the Changed Nature of the Electric Industry                                     91
    D. Legal Authority and Findings                                                                          100
IV. The Proposed Remedy                                                                                      107
    A. The Interim Tariff                                                                                    117
        1. Placing Bundled Retail Customers under the Interim Tariff                                         118
        2. Additional Interim Revisions to the Pro Forma Tariff                                              121
    B. Independent Transmission and Markets                                                                  124
        1. Independent Transmission Providers                                                                125
        2. Role of Independent Transmission Companies in Standard Market Design                              132
    C. The New Transmission Service                                                                          136
        1. Basic Rights                                                                                      139
        2. Access to Transmission Service                                                                    143
        3. Service Limitations in the Existing Pro Forma Tariff                                              146
        4. Conditions for Receiving Service                                                                  148
        5. Scheduling Transmission Service and Acquiring Congestion Revenue Rights                           149
        6. Designating Resources and Loads                                                                   152
        7. Substituting Receipt and Delivery Points                                                          154
        8. System Impact and Facilities Studies                                                              157
        9. Load Shedding and Curtailments                                                                    158
        10. Trading (Reassigning) Congestion Revenue Rights                                                  162

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        11. Ancillary Services                                                                               164
    D. Transmission Pricing                                                                                  165
        1. Recovery of Embedded Costs                                                                        167
        2. Rates for Bundled Retail Customers                                                                176
        3. Inter-Regional Transfers                                                                          179
        4. Application of Inter-Regional Pricing to Parallel Path Flows                                      190
        5. Pricing of New Transmission Capacity                                                              191
    E. The New Congestion Management System                                                                  203
        1. Locational Marginal Pricing                                                                       204
        2. LMP and Energy Markets                                                                            221
        3. Congestion Revenue Rights                                                                         235
            a. General Features                                                                              237
            b. Types of Congestion Revenue Rights                                                            241
                (1) Receipt Point-to-Delivery Point Rights                                                   242
                (2) Obligations and Options                                                                  245
                (3) Flowgate Rights                                                                          246
            c. Requirement for Offering Rights                                                               248
            d. Funding for the Congestion Revenue Rights                                                     250
            e. Auctions and Resales of Congestion Revenue Rights                                             252
            f. Including Energy and Ancillary Services in the Congestion Revenue Rights Auctions             254
    F. Day-Ahead and Real-Time Market Services                                                               256
        1. Design of the Day-Ahead Markets                                                                   257
            a. Scheduling Transmission Service Day Ahead                                                     258
                (1) General Features                                                                         258
                (2) Transmission Service Across Borders                                                      264
            b. Transmission Losses                                                                           267
            c. Day-Ahead Energy Market                                                                       269
                (1) General Features                                                                         269
                (2) Bidding and Scheduling Rules                                                             270
                (3) Price Determination and Settlement                                                       277
            d. Day-Ahead Ancillary Service Markets                                                           284
                (1) General Features                                                                         284
                (2) Bidding and Scheduling Rules                                                             287
                (3) Price Determination and Settlement                                                       291
        2. Scheduling After the Close of the Day-Ahead Market                                                298
            a. Replacement Reserves                                                                          298
            b. Changes to Transmission Schedules                                                             303
        3. Design of the Real-Time Markets                                                                   305
            a. Real-Time Energy Markets                                                                      306
                (1) General Features                                                                         306
                (2) Bidding and Scheduling Rules                                                             307
                (3) Price Determination and Settlement                                                       310
            b. Real-Time Ancillary Services Markets                                                          320
        4. Market Rules for Shortages or Emergencies                                                         326
    G. Other Changes to Improve the Efficiency of the Markets under Standard Market Design                   328
        1. Capacity Benefit Margin                                                                           330
        2. Regional and Independent Calculation of Available Transfer Capability, Performance of             333
         Facilities Studies and OASIS
        3. Regional Planning Process                                                                         335
        4. Modular Software Design                                                                           351
        5. Transmission Facilities That Must be Under the Control of an Independent Transmission             361
         Provider
            a. Before Order No. 888                                                                          362
            b. Order No. 888                                                                                 365
            c. Test for Transmission Facilities                                                              367
    H. Transition to Single Transmission Tariff                                                              370
        1. Treatment of Customers under Existing Wholesale Contracts                                         372
        2. Allocation of Congestion Revenue Rights                                                           376
        3. Reciprocity Provision                                                                             383
        4. Force Majeure and Indemnification Provisions                                                      385
    I. Market Power Mitigation and Monitoring in Markets Operated by the Independent Transmission            390
     Provider
        1. Principles and Objectives                                                                         390
        2. Overview of the Market Power Mitigation Measures                                                  398
        3. Market Power Mitigation for Local Market Power                                                    406
        4. The Safety-Net Bid Cap                                                                            413
        5. Mitigation Triggered by Market Conditions                                                         415
        6. Establishing Bid Caps or Competitive Reference Bids                                               418
        7. Exemptions                                                                                        428
        8. Monitoring                                                                                        429
            a. Framework for Analyzing Market Structure and Market Conduct                                   436
            b. Data Requirements and Data Collection                                                         447
            c. Reporting Requirements                                                                        451
            d. Enforcement of the Tariff Rules                                                               454
    J. Long-Term Resource Adequacy                                                                           457
        1. The Reason for the Requirement                                                                    460

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            a. Spot Market Prices Alone Will Not Signal The Need to Begin Development of New                 462
             Resources in Time to Avert a Shortage
            b. Spot Market Prices that are Subject to Mitigation Measures May Not Produce an                 467
             Adequate Level of Investment When a Shortage Occurs
            c. Load-Serving Entities Will Underinvest in Resources Needed for Reliability if They            469
             Can Depend on the Resource Development Investments of Others
        2. Basic Features of the Requirement                                                                 474
            a. Demand Forecast                                                                               485
            b. Level of Resource Adequacy                                                                    487
            c. Load-Serving Entities                                                                         494
            d. Load-Serving Entity's Share of the Regional Resource Requirement                              497
            e. Resources That Can Satisfy the Resource Needs                                                 503
                (1) Generation and Transmission                                                              504
                (2) Demand Response                                                                          507
        3. Resource Standards                                                                                509
            a. Generation Standards                                                                          511
            b. Transmission Standards                                                                        514
            c. Demand Response Standards                                                                     517
        4. Planning Horizon                                                                                  520
        5. Enforcement                                                                                       526
        6. Regional Flexibility                                                                              542
    K. State Participation in RTO Operations                                                                 551
    L. Governance for Independent Transmission Providers                                                     556
        1. Responsibilities of the Board of Directors                                                        558
        2. Stakeholder Participation                                                                         560
        3. Initial Selection Process for Board of Directors                                                  562
        4. Succession of Board Members                                                                       569
        5. Mergers of Independent Transmission Providers                                                     573
    M. System Security                                                                                       575
V. Implementation                                                                                            580
VI. Public Comment Procedures                                                                                595
VII. Regulatory Flexibility Act                                                                              599
VIII. Environmental Statement                                                                                603
IX. Public Reporting Burden and Information Collection Statement                                             604
X. Document Availability                                                                                     612
Regulatory Text
Appendices
    A. Interim Pro Forma Tariff Revisions
    B. Standard Market Design Tariff (SMD Tariff)
    C. Examples of Flaws in the Current Regulatory Environment
    D. Conversion of the Order No. 888-A Pro Forma Tariff to the Revised Standard Market Design Pro
     Forma Tariff
    E. Standard Market Design and Trading Strategies Encountered in the Independent Transmission
     System Operators
    F. Access Charges and Congestion Revenue Rights
    G. Form for the Annual Self-Certification of Compliance with FERC Security Standards
 

I. Introduction

    1. This notice of proposed rulemaking represents the third in a 
series of initiatives undertaken by the Commission to harness the 
benefits of competitive markets for the nation's electric energy 
customers, in order to meet our statutory responsibility to assure 
adequate and reliable supplies of electric energy at a just and 
reasonable price. In 1996, the Commission issued Order No. 888, which 
required, as a remedy for undue discrimination, that all public 
utilities provide open access transmission.\1\ In 1999, the Commission 
issued Order No. 2000.\2\ The Commission's objective was ``for all 
transmission owning entities in the Nation, including non-public 
utility entities, to place their transmission facilities under the 
control of appropriate regional transmission institutions [RTOs] in a 
timely manner.''\3\
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    \1\ Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities and 
Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. & 
Regs. [para] 31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 
12,274 (March 14, 1997), FERC Stats. & Regs. [para] 31,048 (1997), 
order on reh'g, Order No. 888-B, 81 FERC [para] 61,248 (1997), order 
on reh'g, Order No. 888-C, 82 FERC [para] 61,046 (1998), aff'd in 
relevant part, remanded in part on other grounds sub nom. 
Transmission Access Policy Study Group, et al. v. FERC, 225 F.3d 667 
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 122 S. Ct. 1012 
(2002).
    \2\ Regional Transmission Organizations, Order No. 2000, 65 FR 
809 (January 6, 2000), FERC Stats. & Regs. [para] 31,089 (1999), 
order on reh'g, Order No. 2000-A, 65 FR 12,088 (February 25, 2000), 
FERC Stats. & Regs [para] 31,092 (2000), petitions for review 
dismissed, Public Utility District No. 1 of Snohomish County, 
Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).
    \3\ Regional Transmission Organizations, 64 FR 31,389 (May 13, 
1999), FERC Stats. & Regs. [para] 32,541 at 33,685 (1999) (Notice of 
Proposed Rulemaking).
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    2. Order No. 888 and Order No. 2000 set the foundation upon which 
to build regional transmission institutions and competitive electricity 
markets. However, as events have transpired, there remain significant 
impediments to competitive markets and to the infrastructure needed to 
meet our electric energy demand. Unduly discriminatory transmission 
practices have continued to occur and inconsistent design and 
administration of short-term energy markets has resulted in pricing 
inefficiencies that can cause rates to be unjust and unreasonable. At 
the same time, the nature of the electric industry has changed in a way 
that makes the development of competitive wholesale markets all the 
more critical. The electric industry has evolved from one characterized 
by large, vertically integrated utilities to an industry with 
increasing wholesale trade and increasing numbers of independent buyers 
and sellers of wholesale power seeking non-discriminatory access to 
transmission facilities. Public utilities

[[Page 55455]]

today purchase significantly more wholesale power to meet their load 
than in the past. Indeed, from 1989 through 2000, their wholesale 
purchases increased from 18 percent of their total available electric 
energy to over 37 percent, and this percentage is expected to continue 
to grow.\4\
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    \4\ See Section III.C. for a more detailed discussion.
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    3. The Commission's objectives in this third rulemaking initiative, 
therefore, are to remedy remaining undue discrimination and establish a 
standardized transmission service and wholesale electric market design 
that will provide a level playing field for all entities that seek to 
participate in wholesale electric markets. The Commission proposes to 
provide new choices through a flexible transmission service, and an 
open and transparent spot market \5\ design that provides the right 
pricing signals for investment in transmission and generation 
facilities, as well as investment in demand reduction.
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    \5\ The term ``spot market'' typically refers to a trade that 
covers a short period in the very near future. Trading in an 
independent transmission system operator (ISO) real-time or day-
ahead market is referred to here as occurring in the spot market. In 
the Western price mitigation order, the Commission defined a spot 
market trade as any trade lasting 24 hours or less, whether a 
bilateral trade or a trade occurring in an organized real-time or 
day-ahead market that does not match up particular sellers and 
buyers. See San Diego Gas and Electric Company v. Sellers of Energy 
and Ancillary Services into Markets Operated by the California 
Independent System Operator and the California Power Exchange, 95 
FERC [para] 61,418 at 64,525 n.3 (2001). We will adopt this meaning 
for this rulemaking.
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    4. When supply and demand do not support fully competitive markets, 
market design should provide protection against market power. We seek 
in this rulemaking to put in place sufficient regulatory backstops to 
protect customers against the exercise of market power when structures 
do not support a competitive market. Market monitoring at all times, 
and market power mitigation when needed, are critical pieces of this 
initiative.
    5. A significant impediment to achieving the full benefits of 
competition is that there is no single set of rules governing 
transmission of electric energy. Not only does the Order No. 888 pro 
forma tariff contain provisions that allow different types of customers 
to be treated differently, but there also are conflicting state and 
Federal rules governing the use of interstate transmission facilities. 
This provides opportunities for transmission providers to establish and 
apply rules in a way that unduly discriminates against certain classes 
of customers, leads to significant transaction costs and threatens 
reliability.
    6. To remedy undue discrimination, enhance competition, remove 
economic inefficiencies and ensure just and reasonable rates, terms and 
conditions transmission of electric energy, the Commission proposes to: 
Exercise jurisdiction over the transmission component of bundled retail 
transactions; modify the existing pro forma transmission tariff to 
include a single flexible transmission service (Network Access Service) 
that applies consistent transmission rules for all transmission 
customers--wholesale, unbundled retail and bundled retail; and provide 
a standard market design for wholesale electric markets. While it is 
critical that the same non-rate terms and conditions be applied to all 
transmission uses, including bundled retail, as soon as possible, we 
intend to work closely with our state colleagues with respect to 
transition issues involving bundled retail transmission rates
    7. The proposed Network Access Service would combine features of 
both existing open access transmission services--the flexibility and 
resource and load integration of Network Integration Transmission 
Service; and the reassignment rights of Point-to-Point Transmission 
Service. It would give a customer the right to transmit power between 
any points on the transmission system--so long as the transaction is 
feasible under a security-constrained dispatch.
    8. We expect that most if not all entities will become members of 
RTOs and that the new Network Access Service would be provided through 
these RTOs. However, this rule may become effective at a time when some 
transmission owners and operators have not yet become members of 
functioning RTOs. Thus, we propose that all transmission owners and 
operators that have not yet joined an RTO must contract with an 
independent entity to operate their transmission facilities. This 
proposed rule refers to both the RTO and those independent entities as 
``Independent Transmission Providers.'' An Independent Transmission 
Provider would have no financial interest, either directly or through 
an affiliate, as defined in section 2(a)(11) of the Public Utility 
Holding Company Act (15 U.S.C. 79b(a)(11), in any market participant 
\6\ in the region in which it provides transmission services or in 
neighboring regions. We propose that all Independent Transmission 
Providers administer the day-ahead and real-time markets. As discussed 
infra, we also have identified long-term planning and expansion, system 
impact and facilities studies and transmission transfer capability 
calculations (including postings on an Open Access Same-time 
Information System (OASIS)) as tasks that must be done on a regional 
basis. Thus, we propose that all Independent Transmission Providers 
perform these tasks.
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    \6\ A market participant means: (i) Any entity that, either 
directly or through an affiliate, sells or brokers electric energy, 
or provides ancillary services to the [RTO], unless the Commission 
finds that the entity does not have economic or commercial interests 
that would be significantly affected by the [RTO's] actions or 
decisions; and (ii) Any entity that the Commission finds has 
economic or commercial interests that would be significantly 
affected by the [RTO's] actions or decisions. 18 CFR 35.34 (2) 
(2002).
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    9. In addition to creating the new Network Access Service, the 
revised tariff would include requirements to standardize wholesale 
electric market design. The fundamental goal of the Standard Market 
Design requirements, in conjunction with the standardized transmission 
service, is to create ``seamless'' wholesale power markets that allow 
sellers to transact easily across transmission grid boundaries and that 
allow customers to receive the benefits of lower-cost and more reliable 
electric supply. For example, currently a supplier that seeks to serve 
load in a distant state may need to cross several utility systems or 
independent system operator systems (ISOs), all of which have different 
rules for such things as reserving and scheduling transmission and 
scheduling generation. This can either result in an efficient 
transaction not occurring at all or it can add significant time and 
costs to the transaction. Standard Market Design seeks to eliminate 
such impediments.
    10. Central to the Standard Market Design concept is its reliance 
on bilateral contracts entered into between buyers and sellers. The 
resource adequacy requirement strongly encourages such long-term 
contracts. The short-term spot markets set out below are intended to 
complement bilateral procurement. To handle generation imbalances and 
the procurement of ancillary services, the Commission proposes to 
require that all Independent Transmission Providers operate markets for 
energy and for the procurement of certain ancillary services in 
conjunction with markets for transmission service. These markets would 
be bid-based, security-constrained spot markets operated in two time 
frames: (1) A day ahead of real-time operations, and (2) in real time. 
The adoption of a market-based

[[Page 55456]]

locational marginal pricing (LMP) transmission congestion management 
system is designed to provide a mechanism for allocating scarce 
transmission capacity to those who value it most, while also sending 
proper price signals to encourage short-term efficiency in the 
provision of transmission service as well as wholesale energy, and to 
encourage long-term efficiency in the development of transmission, 
generation and demand response infrastructure. We expect that market 
participants will strike an appropriate balance between bilateral 
contracts and spot market transactions. Efficient spot markets with 
appropriate price signals bring bilateral and spot market prices closer 
together, helping to assure customers of efficient bilateral markets.
    11. Several changes required by Standard Market Design promote 
greater customer access to low-cost power. We note that this may raise 
concerns that cheap power may leave one region for sale in another, 
higher-priced region. This can only happen with generation that is not 
already under contract for purchase. Thus, customers in low-cost 
regions can ensure that low-cost power ``stays home'' by contracting 
for that power. This way, only excess power will leave the region to 
serve another market.
    12. The Commission proposes a pricing policy and process for 
recovering the costs of new transmission investment so as to develop 
the infrastructure needed to support competitive markets. The policy 
builds on the price signals provided by the proposed spot market 
design. However, there are cases where LMP price signals alone will not 
encourage all beneficial transmission investments. Therefore, we 
propose to require market participants to participate in a regional 
process to identify the most efficient and effective means to maintain 
reliability and eliminate critical transmission constraints.
    13. Even with good market design rules, current supply and demand 
conditions make a market monitoring and market power mitigation plan 
necessary. The market power mitigation proposed in this rule would rely 
on a combination of methods to protect against the exercise of market 
power by preventing sellers from withholding economical supplies from 
the market, while permitting prices to reflect true scarcity. The 
proposed market power mitigation method should be more restrictive at 
times or places where the exercise of market power is more likely to 
occur than at times or places where the market is sufficiently 
competitive.
    14. However, because market power mitigation may tend to suppress 
scarcity prices that signal the need for investment, a companion 
mechanism besides spot prices is needed. The Commission proposes a 
resource adequacy requirement to ensure adequate electric generating, 
transmission and demand response infrastructure, the level of which is 
to be determined on a regional basis. Recognizing that supply planning 
and retail customer demand response are the states' responsibility, the 
Commission proposes a resource adequacy requirement intended to 
complement existing state programs. In particular, the Commission 
proposes that an RTO or other regional entity must forecast the 
region's future resource needs, facilitate regional determination of an 
adequate future level of resources and assess the adequacy of the plans 
of load-serving entities \7\ to meet the regional needs. Each load-
serving entity would be required to meet its share of the future 
regional need through a combination of generation and demand reduction.
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    \7\ A load-serving entity is an entity, including a municipal 
electric system and an electric cooperative, authorized by law, 
regulatory authorization or requirement, agreement, or contractual 
obligation to supply energy, capacity, and/or ancillary services to 
retail customers located within the transmission provider's service 
area, including an entity that takes service directly from the 
transmission provider to supply its own load in the transmission 
provider's service area. See SMD Tariff Sec. 1.
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    15. In summary, in this proceeding, the Commission, pursuant to its 
authority under sections 205 and 206 of the Federal Power Act,\8\ 
proposes to:
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    \8\ 16 U.S.C. 824d and 824e (1994).
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    (1) Establish a single non-discriminatory open access transmission 
tariff with a single transmission service (Network Access Service) that 
is applicable to all users of the interstate transmission grid: 
wholesale and unbundled retail transmission customers, and bundled 
retail customers;
    (2) Require all public utilities that own, control or operate 
interstate transmission facilities to become an Independent 
Transmission Provider, turn over their transmission facilities to an 
Independent Transmission Provider or contract with an Independent 
Transmission Provider to operate their facilities. An Independent 
Transmission Provider is any public utility that owns, controls or 
operates facilities used for the transmission of electric energy in 
interstate commerce, that administers the day-ahead and real-time 
energy and ancillary services markets in connection with its provision 
of transmission services pursuant to the SMD Tariff, and that is 
independent (i.e., has no financial interest, either directly or 
through an affiliate, as defined in section 2(a)(11) of the Public 
Utility Holding Company Act (15 U.S.C. 79b(a)(11), in any market 
participant in the region in which it provides transmission service or 
in neighboring regions).
    (3) Require that an Independent Transmission Provider provide 
transmission services and administer the day-ahead and real-time energy 
and ancillary services markets;
    (4) Establish an access charge to recover embedded transmission 
costs based on a customer's load ratio share of the Independent 
Transmission Provider's costs, and would be paid by any customer taking 
power off the grid; \9\
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    \9\ As explained in section IV.D.1, current long-term point-to-
point customers that seek to receive Congestion Revenue Rights would 
also pay the access charge.
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    (5) Use LMP as the system for transmission congestion management 
and provide tradable financial rights--Congestion Revenue Rights \10\ 
as a means to lock in a fixed price for transmission service;
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    \10\ These rights were called ``Transmission Rights'' in the 
Working Paper on Standardized Transmission Service and Wholesale 
Electric Market Design, Docket No. RM01-12-000 (Mar. 15, 2002) 
(hereinafter Working Paper).
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    (6) Establish a preference for the auction of Congestion Revenue 
Rights, but initially allow regional flexibility for a four-year 
transition period in determining whether to allocate Congestion Revenue 
Rights to existing customers or auction such rights such that revenues 
are allocated to existing customers to hold them financially harmless;
    (7) Establish open imbalance energy markets to allow all market 
participants to buy or sell their imbalances in a fair, efficient and 
non-discriminatory market. Imbalance markets would be neutral towards 
fuel sources and treat demand resources on an equal footing with 
supply;
    (8) Permit customers under existing contracts to receive the same 
level and quality of service under Standard Market Design that they 
receive under their current contracts, to the greatest extent feasible;
    (9) Establish procedures to mitigate market power in the day-ahead 
and real-time markets required by Standard Market Design and mechanisms 
for market monitoring;
    (10) Establish procedures to assure, on a long-term regional basis, 
that there are adequate transmission, generation and demand-side 
resources;
    (11) Provide a formal role for state representatives to participate 
in the

[[Page 55457]]

decision-making processes of Independent Transmission Providers; and
    (12) Clarify the obligation of all users of the transmission system 
to comply with all appropriate standards for ensuring system security 
and reliability.
    16. The Commission's focus is on promoting the development of 
competitive wholesale markets and we do not intend to interfere with 
the legitimate concerns of state regulatory authorities. It remains 
within a state's authority to determine whether or not to provide 
retail access. Nevertheless, the reforms proposed in this rulemaking 
will benefit customers in states with or without retail access. In 
addition, we seek to formally involve state representatives in the 
decision-making processes of regional entities. We also recognize the 
need to permit parties to continue to rely on existing contracts and 
scheduling practices, including those involving hydroelectric power, 
and these are fully accommodated under Standard Market Design.
    17. The Commission recognizes that differences exist throughout the 
regions of the country; however, the Commission's goal is to remedy 
undue discrimination by standardizing transmission service and 
wholesale electric market design as much as possible. We propose to 
allow certain regional variations, as described infra.
    18. Finally, the Commission recognizes that implementation of a 
revised open access transmission tariff and Standard Market Design on a 
nationwide basis may take some time. Thus, the Commission proposes a 
phased compliance process. By July 31, 2003, all public utilities that 
own, operate or control interstate transmission facilities must file 
revised open access transmission tariffs (Interim Tariffs) to become 
effective September 30, 2004, that reflect the inclusion of bundled 
retail customers as eligible customers. By December 1, 2003, all public 
utilities that own, control or operate interstate transmission 
facilities must file revised open access transmission tariffs (SMD 
Tariffs), to become effective no later than September 30, 2004, or such 
other time as directed by the Commission, that reflect all of the 
remaining revisions and requirements of the Final Rule in this 
proceeding. The Commission and its staff will work with regional 
organizations and stakeholders in facilitating full and efficient 
compliance with this rule.
    19. Below in Section II we set out the relevant developments in the 
electric industry. In Section III and Appendix C we explain the need 
for further reform. In Appendix E, we discuss various allegations of 
market manipulation strategies encountered in the organized markets and 
how Standard Market Design will address these strategies. In Section IV 
we explain our specific remedy for pervasive problems in the industry 
consistent with our statutory responsibilities. In Section V, we set 
out the implementation process and dates. Finally, the glossary for the 
terms used in this document is found in the Definitions section of the 
SMD Tariff in Appendix B, and the revisions to the Interim Tariff are 
set out in Appendix A.

II. Background: Order No. 888 and Order No. 2000

A. Order Nos. 888 and 888-A

    20. In April 1996, in Order No. 888, the Commission found that 
unduly discriminatory and anticompetitive practices existed in the 
electric industry, and that public utilities that own, control or 
operate interstate transmission facilities had discriminated against 
others seeking transmission access. It determined that non-
discriminatory open access transmission services, including access to 
transmission information, and stranded cost recovery were the most 
critical components of a successful transition to competitive wholesale 
electricity markets.\11\ The Commission stated that its goal was to 
ensure that customers have the benefits of competitively priced 
generation.
---------------------------------------------------------------------------

    \11\ See Order No. 888 at 31,652.
---------------------------------------------------------------------------

    21. Order No. 888 required all public utilities that own, control 
or operate facilities used for transmitting electric energy in 
interstate commerce to: (1) File open access non-discriminatory 
transmission tariffs containing certain minimum, non-price terms and 
conditions, and (2) functionally unbundle wholesale power services from 
transmission services.\12\ Functional unbundling requires public 
utilities to: (1) Take wholesale transmission services under the same 
tariff of general applicability as they offer their customers; (2) 
state separate rates for wholesale generation, transmission, and 
ancillary services; and (3) rely on the same electronic information 
network that their transmission customers rely on to obtain information 
about the utilities' transmission systems.\13\ In Order No. 889, issued 
concurrent with Order No. 888, the Commission also imposed standards of 
conduct governing communications between the utility's transmission and 
wholesale power functions, to prevent the utility from giving its power 
marketing arm preferential access to transmission information.\14\ 
Under Order No. 889, all public utilities that own, control or operate 
facilities used in the transmission of electric energy in interstate 
commerce are required to create or participate in an OASIS that 
provides existing and potential transmission customers the same access 
to transmission information that will enable them to obtain open access 
non-discriminatory transmission service.
---------------------------------------------------------------------------

    \12\ See id. at 31,635-36.
    \13\ See id. at 31,654.
    \14\ See Open Access Same-Time Information System and Standards 
of Conduct, Order No. 889, 61 FR 21,737 (April 24 1996), FERC Stats. 
& Regs. [para] 31,035 at 31,588-91 (1996), order on reh'g, Order No. 
889-A, 62 FR 12,484 (March 4, 1997), FERC Stats. & Regs. [para] 
31,049 (1997).
---------------------------------------------------------------------------

    22. The Commission declined to require corporate unbundling at the 
time of Order No. 888, and stated instead that efforts to remedy undue 
discrimination should begin by requiring the less intrusive functional 
unbundling approach.\15\ While the Commission in Order No. 888 
encouraged the creation of ISOs and set forth eleven principles for 
assessing ISO proposals submitted to the Commission, it did not mandate 
regional organizations.\16\ The Commission in Order No. 888 stated:
---------------------------------------------------------------------------

    \15\ See Order No. 888 at 31,654.
    \16\ See id. at 31,730-32.

    [W]e see many benefits in ISOs, and encourage utilities to 
consider ISOs as a tool to meet the demands of the competitive 
marketplace. As a further precaution against discriminatory 
behavior, we will continue to monitor electricity markets to ensure 
that functional unbundling adequately protects transmission 
customers. At the same time, we will analyze all alternative 
proposals, including formation of ISOs, and, if it becomes apparent 
that functional unbundling is inadequate or unworkable in assuring 
non-discriminatory open access transmission, we will reevaluate our 
position and decide whether other mechanisms, such as ISOs, should 
be required. \17\
---------------------------------------------------------------------------

    \17\ Id. at 31,655.

Order No. 888-A reaffirmed the findings of Order No. 888. The Court of 
Appeals for the District of Columbia Circuit upheld the orders ``in 
nearly all respects.'' \18\ The Supreme Court recently affirmed.\19\
---------------------------------------------------------------------------

    \18\ Transmission Access Policy Study Group, 225 F.3d at 681.
    \19\ See New York v. FERC, 122 S.Ct. 1012.
---------------------------------------------------------------------------

    23. A number of significant developments took place in the electric 
utility industry following issuance of Order No. 888. All public 
utilities filed non-discriminatory, open access transmission tariffs 
stating rates, terms and conditions for comparable

[[Page 55458]]

wholesale transmission service to third-party users of their 
transmission systems. With the advent of OASIS systems, improved 
information about transmission systems became available to all 
participants in the bulk power market at the same time that it was 
available to utilities' own wholesale merchant functions and wholesale 
marketing affiliates (although further information improvements are 
still needed). New generation resources were developed in areas that 
had experienced generation shortages.\20\ Regional trading patterns 
have expanded. In addition, the Commission granted a large number of 
merger applications and applications to charge market-based rates, 
effecting structural changes in the industry. The industry thus became 
less localized and more regionalized, with a growing need for regional 
planning and regulation. And as part of that regionalization, the 
Commission also approved voluntary ISOs in five regions of the country-
-New England, New York, PJM,\21\ the Midwest and California (an ISO was 
also formed in ERCOT, but it is not under the Commission's full 
jurisdiction). These ISOs are the precursors to regional entities 
identified as RTOs, in the Commission's Order No. 2000, discussed 
below.
---------------------------------------------------------------------------

    \20\ See Staff Report to the Federal Energy Regulatory 
Commission on the Causes of the Pricing Abnormalities in the Midwest 
During June 1998 (1998), available in http://www.ferc.gov/electric/mastback.pdf.
    \21\ The PJM ISO takes its name from the former Pennsylvania, 
New Jersey, Maryland Power Pool, which serves New Jersey, Maryland, 
Delaware, much of eastern Pennsylvania, the District of Columbia, 
and a small area of Virginia.
---------------------------------------------------------------------------

B. Order No. 2000

    24. Order No. 2000, issued in December 1999, was the Commission's 
second major step toward establishing competitive wholesale power 
markets and eliminating residual undue discrimination in interstate 
transmission services. It identified two broad categories of 
impediments to competitive electricity markets: (1) The engineering and 
economic inefficiencies inherent in the current operation and expansion 
of the transmission grid, and (2) continuing opportunities for 
transmission owners to unduly discriminate in the operation of their 
transmission systems so as to favor their own (or their affiliates') 
power marketing activities.\22\ Further, evidence indicated that local 
management of the transmission grid by many individual vertically 
integrated utilities was inadequate to support the efficient, reliable 
regionwide operation that was needed for continued development of 
competitive markets. The Commission concluded that establishing 
independent RTOs would eliminate residual undue discrimination in 
transmission, enhance the benefits of competitive electricity markets, 
and could: (1) Improve efficiency in transmission grid management; (2) 
improve grid reliability; (3) remove remaining opportunities for 
discriminatory transmission practices; (4) improve market performance; 
and (5) facilitate lighter-handed regulation. The Commission 
anticipated that formation of regional transmission grids would result 
in a substantial cost savings to the electric utility industry and its 
customers.\23\
---------------------------------------------------------------------------

    \22\ Order No. 2000 identified four specific areas of concerns: 
(1) Calculation and posting of Available Transfer Capability in a 
manner favorable to the transmission provider; (2) standards of 
conduct violations; (3) line loading relief and congestion 
management; and (4) OASIS sites that are difficult to use. See Order 
No. 2000 at 31,005 n.69. The order also identified parallel path 
flows, planning and investing in new transmission facilities, 
pancaking of access charges, the absence of secondary markets in 
transmission service and the possible disincentives created by the 
level and structure of transmission rates. See id. at 31,014.
    \23\ See id. at 30,993.
---------------------------------------------------------------------------

    25. Order No. 2000 encouraged all transmission owners to 
voluntarily place their transmission facilities in the hands of 
appropriate RTOs. The Commission stated that RTOs could include ISOs or 
independent for-profit transmission companies (ITCs). However, all RTOs 
must meet four minimum characteristics and eight minimum functions that 
were identified in Order No. 2000, and also must have an open 
architecture framework that would permit an RTO and its members 
flexibility to improve their structures over time.\24\
---------------------------------------------------------------------------

    \24\ The four RTO characteristics are: (1) Independence; (2) 
scope and regional configuration; (3) operational authority; and (4) 
short-term reliability. The eight RTO functions are: (1) Tariff 
administration and design; (2) congestion management; (3) parallel 
path flow; (4) ancillary services; (5) OASIS, Total Transfer 
Capability and Available Transfer Capability; (6) market monitoring; 
(7) planning and expansion; and (8) interregional coordination. See 
Order No. 2000 at 30,993-94.
---------------------------------------------------------------------------

    26. Following Order No. 2000, some transmission-owning public 
utilities began to file proposals to participate in RTOs. The process 
has been slow for several reasons, one of which is stakeholder 
uncertainty about what the Commission would require for RTO approval--
not only for the RTO scope and independence characteristics, but also 
regarding such RTO functions as congestion management and market-
oriented provision of ancillary services.
    27. Order No. 2000 called for RTOs to be in operation across the 
nation by December 2001. To date, there is only one RTO fully approved 
by the Commission, the Midwest ISO, which began operating in early 
2002.\25\ The Midwest ISO is large. It stretches from an eastern 
boundary in western Pennsylvania westward to the Rocky Mountains, 
northward into Manitoba, Canada and southward to the Texas border.
---------------------------------------------------------------------------

    \25\ See Midwest Independent System Operator, Inc., 97 FERC 
[para] 61,326 (2001).
---------------------------------------------------------------------------

    28. Although progress with Commission-approved RTOs has been slow, 
regionalization has also occurred through the ISO formation process 
that was encouraged in Order No. 888. The Northeast and California ISOs 
are engaged in a process to become Commission-approved RTOs or to join 
larger RTOs. In eastern North America, close coordination is developing 
between U.S. and Canadian transmission systems and market designs.
    29. In addition to the Midwest ISO, the Commission has 
provisionally approved other RTOs,\26\ and authorized operation of ITCs 
that operate under an RTO umbrella.\27\ The Commission also ordered 
Northeastern and Southeastern RTO applicants, including some applicants 
whose RTO proposals had been provisionally approved, into mediation 
proceedings to facilitate the formation of RTOs in those areas.\28\ The 
Commission further noted that a ``west wide RTO, or a seamless 
integration of Western RTOs, is the best vehicle for designing and 
implementing a long-term regional solution'' to the West's electric 
generation supply crisis.\29\
---------------------------------------------------------------------------

    \26\ See GridSouth Transco, LLC, 94 FERC [para] 61,273 (2001); 
GridFlorida, LLC, 94 FERC [para]61,363 (2001); and PJM 
Interconnection, LLC, 96 FERC [para]61,061 (2001).
    \27\ See TRANSLink Transmission Company, L.L.C., et al., 99 FERC 
[para]61,106 (2002) (authorizing operation of ITC within the Midwest 
ISO), reh'g pending, [Docket Nos. EC01-156-001 et al.; Alliance 
Companies, et al., 99 FERC [para]61,105 (2002) (authorizing the 
operation of an ITC).
    \28\ See Regional Transmission Organizations, 96 FERC 
[para]61,065 (2001) (initiating mediation proceedings between 
Northeastern RTO applicants); Regional Transmission Organizations, 
96 FERC [para]61,066 (2001) (initiating mediation proceedings 
between Southeastern RTO applicants).
    \29\ Removing Obstacles to Increased Electric Generation and 
Natural Gas Supply in the Western United States, 94 FERC 
[para]61,272 at 61,974 (2001). A coalition of Western utilities (RTO 
West Filing Utilities) filed a proposal on October 16, 2001 to 
create RTO West. The Commission granted several of the RTO West 
Filing Utilities' requests for declaratory order on April 26, 2001, 
finding some of RTO West's proposed characteristics and functions 
compliant with Order No. 2000. See Avista Corporation, et al., 95 
FERC [para]61,114 (2001). The RTO West Filing Utilities then filed a 
proposal for Stage 2 of RTO West's creation on March 28, 2002. The 
Stage 2 proposal is intended to enable the Commission to determine 
whether the RTO West proposal fulfills all of the Order No. 2000 
characteristics and functions. See Stage 2 Filing and Request for 
Declaratory Order Pursuant to Order 2000 at 5, Docket No. RT01-35-
000 (Mar. 28, 2002).

---------------------------------------------------------------------------

[[Page 55459]]

    30. The following section and related Appendix C discuss specific 
features of today's wholesale electricity markets that inhibit the 
development of competition and efficient regional markets, and identify 
areas in which the Commission must direct reforms to eliminate 
remaining undue discrimination and inefficiencies, and ensure just and 
reasonable rates.

III. Need for Reform

A. Undue Discrimination and Impediments to Competition Remain

    31. Since the issuance of Order Nos. 888 and 2000, it has become 
clear that additional, mandatory measures are needed to achieve the 
goals of non-discriminatory transmission access and competition in 
electricity markets. Vertically integrated transmission owners and 
operators continue to use their interstate transmission facilities in 
ways that inhibit competition in wholesale power markets as well as 
competition in those retail power markets where states have adopted 
retail choice. The discriminatory preferences that these transmission 
owners and operators give to their own uses of the interstate 
transmission grid to serve their retail customers (whether or not they 
are in retail choice states) results in discrimination against, and in 
costs being borne by, other wholesale and retail customers who also 
rely on the interstate transmission facilities to buy power. The 
discriminatory preferences also create barriers to new sellers that 
could provide lower-cost power. This could result in higher prices to 
the native load served by the transmission owner. For example, 
transmission-dependent utilities \30\ and other load-serving entities 
need the interstate transmission facilities to move power they are 
purchasing by contract from distant generators or suppliers, but allege 
that despite the requirements of Order No. 888, they are denied 
comparable access to the grid. Similarly, new generators wishing to 
compete in wholesale markets or for retail customers in retail choice 
states tell us that they are denied comparable access to the grid, thus 
inhibiting entry of new, lower-cost, efficient and environmentally 
superior power suppliers.
---------------------------------------------------------------------------

    \30\ A transmission-dependent utility is a utility that does not 
own generation and relies on its neighboring utilities to transmit 
power to it that it purchases from its suppliers.
---------------------------------------------------------------------------

    32. The Commission recently has taken additional steps to address 
some of the remaining impediments to non-discriminatory transmission 
access and competition in wholesale power markets. For example, the 
Commission's recently issued Generator Interconnection proposed rule 
seeks to remove one particular type of undue discrimination occurring 
in the marketplace--barriers to obtaining interconnections to the 
interstate transmission grid--so that new generators can compete with 
vertically integrated transmission providers to serve load.\31\ 
However, this initiative will resolve only one aspect of remaining 
discriminatory practices. Other opportunities for vertically integrated 
transmission providers to operate in ways that favor their own 
generation remain within the construct of the pro forma tariff (e.g., 
preferences for native load and network customers to reserve 
transmission capability, differing transmission services that raise 
barriers to competition, the lack of inclusion of all services under 
the same tariff). As noted in Order No. 2000, ``perceptions of 
discrimination are significant impediments to competitive markets. 
Efficient and competitive markets will develop only if market 
participants have confidence that the system is administered 
fairly.''\32\
---------------------------------------------------------------------------

    \31\ See Standardization of Generator Interconnection Agreements 
and Procedures, 67 FR 22,249 (May 2, 2002), FERC Stats. & Regs. 
[para]32,560 at 34,174 (2002) (Notice of Proposed Rulemaking). The 
proposed rule defines interconnection study time frames and grants 
all generators the opportunity to be treated as competing network 
resources in meeting load and load growth. See id. at 34,243-45.
    \32\ Order No. 2000 at 31,017. Lack of market confidence may 
lead to a reluctance on the part of market participants to share 
operational real-time and planning data with transmission providers 
because of the suspicion that they could be providing a competitive 
advantage to their affiliated power marketers. It may also deter 
generation expansion and lead to the perception that the 
transmission provider's generation is more reliable, thereby 
reducing competition and raising prices for customers. See id.
---------------------------------------------------------------------------

    33. Furthermore, it has become apparent that there are also 
opportunities to discriminate and to hinder an efficient, competitive 
marketplace due to the absence of standardization with respect to 
market rules and practices within and between regional markets. So-
called ``seams'' problems (e.g., different rules and different pricing 
systems) create transaction costs and artificial barriers to trade. 
These problems inhibit the Commission from fulfilling its statutory 
responsibility to ensure that customers receive reliable power supplies 
at the lowest reasonable costs.\33\
---------------------------------------------------------------------------

    \33\ See FPC v. Hope Natural Gas Company, 320 U.S. 591, 610 
(1944).
---------------------------------------------------------------------------

    34. Finally, innovation that the Commission expected to see with 
respect to new service offerings has been sporadic and unsteady. 
Innovations in transmission control and pricing (e.g., ISO control of 
transmission and LMP for generation and transmission services in the 
Northeast, RTO formation in the Midwest), while impressive, have been 
slow to take root in other regions of the country. The pro forma tariff 
was envisioned as the baseline above which transmission providers were 
encouraged to develop competitive and customer-responsive service 
offerings. But Florida Power Corporation's network contract demand 
service, a hybrid of Network Integration Transmission Service and 
Point-to-Point Transmission Service features,\34\ and Duke Energy 
Corporation's ``recallable long-term firm'' service \35\ are the only 
noteworthy new services accepted by the Commission for use with a 
single utility's open access transmission tariff. Other proposed pro 
forma tariff revisions amounted to little more than working around the 
edges of the existing services and procedures and did not produce more 
competitive transmission service that reduces overall electricity 
costs.
---------------------------------------------------------------------------

    \34\ See Florida Power Corporation, 81 FERC [para] 61,247 
(1997).
    \35\ See Duke Energy Corporation, 88 FERC [para] 61,184, reh'g 
denied, 89 FERC [para] 61,190 (1999).
---------------------------------------------------------------------------

    35. Most ISOs recently introduced centralized short-term real-time 
hourly markets and day-ahead markets for energy (i.e., spot markets) 
where sellers sell into the market and buyers buy from the market 
without matching a particular seller with a particular buyer. In such 
organized spot markets, there is a single market clearing price 
established that is received by all generators who bid into the market 
below that price and is paid by all load that bids in above that price. 
However, the ability of customers to bid demand reductions into the 
spot market in response to supplier prices is still limited and needs 
to be improved significantly for short-term markets to operate more 
competitively. Further, while there have been benefits of market 
development in the Northeast (PJM, New York ISO, ISO-New England), 
Texas and California (during the first two years of its restructuring), 
the Midwest ISO is still in the formative stages of operation with 
respect to markets, and few market benefits have materialized in the 
Southeast and West.

B. Specific Instances of Undue Discrimination and Impediments to 
Competition

    36. The specific reasons for requiring reform are many. Market 
participants

[[Page 55460]]

have identified, through formal complaints, hotline calls, public 
conferences, and pleadings, the difficulties they have experienced in 
gaining equal access to the transmission grid to compete with 
vertically integrated utilities to serve load. Much of this problem is 
directly attributable to the remaining ability of such vertically 
integrated utilities (and the existence of sufficient incentives) to 
exercise some degree of transmission market power in order to protect 
their own generation market share. Further complicating transmission 
access is the fact that not all transmission service is provided under 
the rates, terms and conditions of the Commission's pro forma tariff. 
Rather, over 60 percent of load has been subject to various state rules 
governing the transmission component of bundled retail transactions. 
Independent transmission service under a common set of rules would 
solve many of these problems.
    37. Nevertheless, new problems have been created by some of the 
market design experiments. In regions of the country where the 
separation of transmission from generation has been addressed through 
the creation of ISOs (which, in some instances, have placed nearly all 
load under a single tariff), market design flaws create inefficiencies 
in the marketplace and opportunities for the exercise of market power. 
Conflicting market rules and procedures in neighboring ISOs have 
created or perpetuated seams problems that impede the economic flow of 
power from one region to another. All of these problems have hindered 
the progress towards competitive regional electricity markets. Standard 
Market Design is intended to address these problems.
1. Transmission Market Power by Utilities That Are Not Independent
    38. By differing means, Order Nos. 888 and 2000 attempt to effect 
open access transmission by reducing the ability of transmission owners 
that also own generators to act in anticompetitive or unduly 
discriminatory ways against other generators. In both orders, the 
Commission attempted to move the electric industry into a competitive 
wholesale market without mandating corporate restructuring. Through 
Order Nos. 888 and 2000, the Commission required open access to public 
utility transmission systems, encouraged the formation of ISOs and, 
later, RTOs to achieve control of the transmission grid by entities 
that are independent from generation marketing or sales. However, only 
limited portions of the country have moved beyond the basic 
requirements of open access (e.g., through the voluntary divestiture of 
generation or establishment of RTOs, ISOs, or ITCs). In the rest of the 
country, the remaining corporate ties between generation and 
transmission within public utilities have proven problematic for 
transmission access. Thus, across most of the nation, barriers to entry 
remain for new generators and new load-serving entities.
    39. A large portion of this problem is directly attributable to the 
continued ability of vertically integrated transmission providers to 
exercise some degree of transmission market power to advantage their 
own or affiliated generation. The longer the vertically integrated 
transmission provider can use access to interconnection or transmission 
service to delay or prevent entry of competing generators to its 
service territory, the longer it can profit from its own generation 
sales with a limited threat of competition. Vertically integrated 
transmission providers have found numerous ways to delay or prevent 
entry of competitors, some within the existing rules and some by 
exceeding reasonable discretion afforded to the transmission provider. 
All of these are difficult to monitor or prevent with behavioral 
rules.\36\
---------------------------------------------------------------------------

    \36\ See Working Paper at 21 (Mar. 15, 2002); see also Comment 
of the Staff of the Bureau of Economics and Office of General 
Counsel of the Federal Trade Commission, Docket No. RM01-12-000 
(July 23, 2002).
---------------------------------------------------------------------------

    40. As part of Standard Market Design, we propose that an 
Independent Transmission Provider operate all transmission facilities. 
The requirement for independent control of the transmission grid, 
preferably by an RTO, resolves these types of problems.

a. Load Growth

    41. Under the current pro forma tariff, a transmission provider is 
required to plan its system to allow customers with existing long-term 
contracts to extend, or roll over, those contracts.\37\ However, the 
transmission provider has a right to recall that transmission capacity 
if it identified in the initial agreement with the customer that it had 
projected native load growth that would require that transmission 
capacity.\38\ Transmission providers have failed to identify any native 
load growth at the time of the initial agreement, and disputes have 
arisen with customers claiming they were denied the ability to roll 
over their contracts because the transmission provider claimed, well 
after the contract was executed, that the transmission capacity at 
issue was required to serve native load growth.\39\
---------------------------------------------------------------------------

    \37\ See Section 2.2 of the current pro forma tariff.
    \38\ See Order No. 888-A at 30,277.
    \39\ See Public Service Company of New Mexico v. Arizona Public 
Service Co., 99 FERC [para] 61,162 (2002), for a recent example. In 
this case, the Commission directed APS to grant PSNM's request to 
extend its contract for 60 MW of Point-to-Point Transmission 
Service. APS had attempted to deny the rollover request on the basis 
that it had verbally informed PSNM that capacity would not be 
available due to APS's future native load growth. The Commission 
restated the principle that a transmission provider can deny a 
customer the ability to roll over its long-term firm service 
contract only if the transmission provider includes in the service 
agreement a specific limitation based on reasonably forecasted 
native load needs that will use the transmission capacity provided 
under the contract at the end of the contract term.
---------------------------------------------------------------------------

    42. In Standard Market Design, we propose to eliminate the 
preference for future native load growth. Instead, since Congestion 
Revenue Rights will be used to assure price certainty, Congestion 
Revenue Rights will be apportioned based on historical use or by an 
auction, neither of which grants preference for future load growth by a 
particular supplier; this approach resolves these concerns.

b. Delays in Responding to Requests for Service

    43. Another type of anticompetitive behavior centers on a 
vertically integrated transmission provider delaying the processing of 
a competitor's request for new transmission service or interconnection 
(including the related system impact or facilities studies). 
Transmission providers have done so by failing to follow time lines or 
expansively interpreting the tariff procedures. These delays may be 
enough to cause the competing generator to lose the sale, particularly 
if the potential customer is concerned that it may lose service 
completely if it does not stay with the transmission provider.\40\
---------------------------------------------------------------------------

    \40\ See Kinder Morgan Power Co. v. Southern Company Services, 
Inc., 97 FERC [para] 61,240 (2001), reh'g denied, 98 FERC [para] 
61,044 (2002) (finding Southern's interconnection procedures delayed 
and discriminated against customer's ability to develop new 
projects).
---------------------------------------------------------------------------

    44. Under Standard Market Design, these types of delays are 
resolved through the requirement for an independent entity, preferably 
an RTO, to perform studies and calculate available transfer capability 
(ATC),\41\ since an independent entity would have no incentive to favor 
one customer over another.
---------------------------------------------------------------------------

    \41\ The Commission used the term ``Available Transmission 
Capability'' in Order No. 888 to describe the amount of additional 
capability available in the transmission network to accommodate 
additional transmission services. To be consistent with the term 
generally accepted throughout the industry, ``Available Transfer 
Capability'' will be used.

---------------------------------------------------------------------------

[[Page 55461]]

c. Scheduling Advantages

    45. A vertically integrated transmission provider has a structural 
advantage over many competitors to make economy sales or to serve its 
own load, primarily because it has a large portfolio of both generators 
and loads. A competitor with access only to generation outside of the 
control area and no native load has to identify the delivery point of 
its power before being able to secure transmission service. But a 
vertically integrated transmission provider does not have to identify a 
specific location on the grid to serve its load because its load is 
dispersed across its entire system. A vertically integrated 
transmission provider also does not have to identify a single 
generation location, but can run a combination of its own generators or 
purchase from lower cost-suppliers inside or outside of its system. It 
can schedule purchased power to one of its own loads (in place of power 
from one of its own generators) in order to secure transmission service 
for the purchase. Later, it can find a buyer for the power and schedule 
transmission service from one of its internal generators to the load. 
This often is enough of a scheduling advantage over a competing 
supplier to ensure that the transmission provider (or its affiliated 
power marketer) gets the sale.
    46. While it is true that all network customers have these same 
rights and abilities, in many areas of the country the only customer 
using network service is the vertically integrated transmission 
provider. Moreover, the vertically integrated transmission provider's 
size of resources and loads is usually much greater than any other 
network customer, giving it that much more of an advantage in 
flexibility. In addition, the vertically integrated transmission 
provider may have an advantage through access to better or more 
transmission and other related information.
    47. Under Standard Market Design, all transmission service will be 
provided under a new Network Access Service. Having one service for all 
customers will eliminate scheduling advantages of competing suppliers.

d. Imbalance Resolution

    48. Customers have also alleged that vertically integrated 
transmission providers have an advantage over competitors in the 
resolution of energy imbalances. Transmission providers with generation 
and load of their own can resolve their own energy imbalances through 
in-kind energy exchanges with neighboring systems. In contrast, other 
customers of the transmission provider face higher costs if they take 
service from other suppliers that could balance against each other. 
This difference gives the transmission provider a competitive advantage 
over other sellers of power.
    49. Under Standard Market Design, all suppliers and loads on a 
system will resolve imbalances through the same energy imbalance 
procedures. This will remove any competitive advantage the transmission 
owner with its own generation and load may have over competing power 
suppliers.

e. Available Transfer Capability and Affiliates

    50. Another source of discrimination is the calculation of 
Available Transfer Capability. A transmission provider that is not 
independent calculates its Available Transfer Capability, using its own 
proprietary data and its own equations. This discretion gives it the 
ability and the opportunity to discriminate in its own favor against 
entities that rely upon the OASIS for Available Transfer Capability 
information. In several cases, the Commission has found that utilities' 
OASIS postings reflect an inaccurate Available Transfer Capability. 
Indeed, in response to ``serious concerns about the integrity of the 
postings of ATC'' on the OASIS systems of two transmission providers, 
the Commission required the transmission providers to employ an 
independent third party to administer their OASIS systems.\42\
---------------------------------------------------------------------------

    \42\ See AEP Power Marketing, Inc., et al., 97 FERC [para] 
61,219 at 61,973 (2001), reh'g pending, Docket Nos. ER96-2495-016, 
et al. See also American Electric Power Company, Inc. and Central 
and South West Corporation, 90 FERC [para] 61,242 at 61,789 (2000) 
(requiring AEP to turn over its OASIS and ATC calculation functions 
to an independent entity as a condition of the applicants' merger). 
See also Appendix C for other examples.
---------------------------------------------------------------------------

    51. Under Standard Market Design, an independent entity will 
calculate Available Transfer Capability and schedule transmission 
service. This will eliminate this potential for undue discrimination.

f. OASIS Postings

    52. Manipulation or violation of OASIS posting requirements and the 
Commission's standards of conduct is another way vertically integrated 
transmission providers that control their own OASIS sites are able to 
engage in undue discrimination. This can occur through prohibited off-
OASIS communications between the transmission provider and its 
affiliated market participant, e.g., informing only the affiliate about 
Available Transfer Capability that will soon become available and 
posted on the OASIS so that the affiliate will be first in line to 
claim the capability.\43\ Such abuses reinforce our belief that, in the 
absence of an independent entity calculating Available Transfer 
Capability and operating a transmission provider's OASIS, ``a 
transmission provider's self-monitoring of its standards of conduct is 
not sufficient, and that it is essential for interested parties to be 
able to participate in this process'' of reviewing communications 
between market participants.\44\ Further, even with the best of 
intentions, it is not possible for a single transmission provider in a 
region to calculate Available Transfer Capability on its system alone 
without accounting for the transactions over all the other systems in 
its region and neighboring regions.
---------------------------------------------------------------------------

    \43\ See Aquila Energy Marketing Corporation v. Niagara Mohawk 
Power Corporation, 87 FERC [para] 61,328 (1999) (finding that off-
OASIS communication between utility and its marketing affiliate led 
to preferential treatment of the affiliate); The Washington Water 
Power Company, 83 FERC [para] 61,097 (1998) (finding favorable 
treatment of affiliate and expressing concern that this treatment 
may have been the result of prohibited off-OASIS communication).
    \44\ Aquila Energy Marketing Corporation v. Niagara Mohawk Power 
Corporation, 87 FERC [para] 61,238 at 62,279 (1999).
---------------------------------------------------------------------------

    53. Similarly, control over the design, function and maintenance of 
OASIS systems may also present opportunities for discrimination. The 
Commission has been concerned for some time that transmission providers 
have the ability to impede competition by making their OASIS sites 
difficult to use, limiting users' access to OASIS and limiting access 
to information about transmission curtailments and interruptions that 
would allow the Commission to identify instances of undue 
discrimination.\45\
---------------------------------------------------------------------------

    \45\ See Regional Transmission Organizations, FERC Stats. & 
Regs. [para] 32,541 at 33,713 (describing market participants' 
perceptions that transmission providers may use OASIS to 
discriminate among market participants); Open Access Same-Time 
Information System, 64 FR 34,117 (June 25, 1999), FERC Stats. & 
Regs. [para] 31,075 (1999) (articulating changes to Commission 
regulations that would make available more information about 
transmission curtailments and interruptions and limit OASIS hosts' 
ability to disconnect users).
---------------------------------------------------------------------------

    54. Under Standard Market Design, an independent entity will 
operate an OASIS on a regional basis, and thus will remove any 
advantages one seller may have over another and improve the accuracy of 
regional Available Transfer Capability postings on the OASIS.

g. Capacity Benefit Margin Manipulation

    55. The Commission has found instances of transmission providers 
taking advantage of their ability to reserve interface capability to 
serve their

[[Page 55462]]

own load while limiting the ability of competing suppliers to access 
customers on its system. For instance, transmission providers have 
reserved excessive amounts of capacity benefit margin (CBM) to serve 
their own load,\46\ and violated the pro forma tariff by reserving 
large amounts (e.g., 2,000 MW) of transfer capability at multiple 
interfaces, under the label of ``firm import for native load,'' without 
designating resources or loads associated with the reservations as 
other transmission customers are required to do.\47\ Import capability 
reserved by the transmission provider blocks a competing supplier from 
securing firm service across the interface, limiting that supplier's 
ability to compete to serve load on the system, or on neighboring 
systems. A related issue is whether those who set aside transmission 
for CBM are reserving it and paying for it under the terms of the pro 
forma tariff. When transfer capability for CBM is set aside for the use 
of one market participant, its cost is not necessarily allocated to 
that market participant alone. Because transmission facility embedded 
costs are allocated to transmission customers on the basis of use--
capacity reservation for Point-to-Point Transmission Service customers 
and load ratio share (which does not include the transmission 
capability set-aside of CBM) for Network Integration Transmission 
Service customers--all customers may unfairly subsidize the cost of the 
CBM capability.
---------------------------------------------------------------------------

    \46\ See Delegated Letter in Docket No. ER98-4410-000 (Feb. 8, 
1999); Entergy Services, Inc., 87 FERC [para] 61,156 (1999) 
(directing Entergy, which had reserved 2900 MW, to recompute ATC).
    \47\ See Aquila Power Corporation v. Entergy Services, Inc., 90 
FERC [para] 61,260, reh'g denied, 92 FERC [para] 61,064 (2000), 
appeal docketed, No. 00-1417 (D.C. Cir. Sept. 22, 2000). The 
Commission did not order a remedy in the complaint docket since the 
compliance filing in Docket No. ER98-4410 to remedy the excessive 
native load reservations would also provide a remedy for the 
improper native load reservations at the interfaces. See id. at 
61,860.
---------------------------------------------------------------------------

    56. Under Standard Market Design, entities that want to reserve 
transfer capability must pay for that capability to reach generation 
reserves across an interface. Thus, the preferential treatment would be 
eliminated.

h. Discretionary Use of Transmission Loading Relief

    57. The opportunity for anticompetitive behavior arises when 
transmission providers have discretion to dispatch their own generation 
to serve their own load in a way that requires transmission service 
curtailments through the use of transmission loading relief (TLR) 
procedures.
    58. There has been a sharp increase in the number of TLRs used in 
some regions, suggesting that transmission operators rely upon them to 
do more than simply relieve emergency transmission overloads.\48\ There 
are unmistakable financial incentives to rely on TLRs in forward 
transmission planning:
---------------------------------------------------------------------------

    \48\ In the Southeast, the incidence of TLRs increased 354 
percent from the summer of 1999 to the summer of 2000. See Staff 
Report to the Federal Energy Regulatory Commission on the Bulk Power 
Markets in the United States (Nov. 1, 2000), available in <http://www.ferc.gov/electric/bulkpower/southeast.pdf, at 3-38. 
In the Midwest, the incidence increased 472 percent over the same 
time period. See Staff Report to the Federal Energy Regulatory 
Commission on the Bulk Power Markets in the United States (Nov. 1, 
2000), available in <http://www.ferc.gov/electric/bulkpower/midwest.pdf, at 2-32. The lack of a centralized market, 
particularly in the Southeast, has limited market liquidity and, 
thus, increased the likelihood of TLRs.

    The increased incidence of TLRs may suggest that some 
transmission capacity is being oversold. Market participants have 
attributed a tendency to implement a greater number of TLRs to the 
commercial reality that transmission providers do not have to refund 
transmission reservation fees for service curtailed because a TLR is 
called.\49\
---------------------------------------------------------------------------

    \49\ Staff Report to the Federal Energy Regulatory Commission on 
the Bulk Power Markets in the United States (Nov. 1, 2000), 
available in <http://www.ferc.gov/electric/bulkpower/southeast.pdf at 3-39.

    59. When a vertically integrated transmission provider injects 
power from its own generation onto its own power lines to meet the 
constantly shifting demands of the load on its system, it has both the 
opportunity and the incentive to manipulate the transmission system for 
its own benefit. It can either dispatch generators to create a 
transmission constraint that prevents a competitor from making a sale 
that the transmission provider would also like to make, or it can 
capitalize on legitimate constraints into a load pocket to curtail a 
competitor's transmission transaction and serve the customer with its 
own generation instead. The key here is that none of the transmission 
provider's actions require direct communication with its merchant 
function or marketing affiliate. A simplified hypothetical example of 
such anti-competitive behavior is set forth in Appendix C.
    60. Several aspects of our proposed remedy address this concern, 
including the use of LMP to manage congestion and the requirement that 
transmission facilities be operated by an Independent Transmission 
Provider.
2. Lack of Common Rules Governing Transmission
    61. Some of the difficulties that come from having different rules 
as power moves across the grid are discussed later in the Seams 
Problems Section III.B.4), where a ``seam'' is a dividing line between 
different sets of grid rules.
    62. Having two or more different sets of rules governing the 
operation of a transmission system makes it difficult--if not at times 
impossible--for that system to support an efficient regional electric 
power market. If the interstate transmission system is to provide fair 
and efficient movement of power on behalf of all users of the system, 
the same general rules must govern such matters as who gets service, 
who has the right to transmission service when not all service requests 
can be accepted, how the transmission facility costs are allocated 
among transmission customers, who gets its transmission curtailed and 
by how much when a transmission outage prevents all the planned 
services from being accommodated, who plans the additions to the grid 
and who pays for these additions.
    63. Today there are not only different rules in different public 
utility systems, but there may be more than one set of rules for 
transmission owned by a single utility. This is because there are 
different rules for two types of wholesale transmission service, and 
the rules for bundled retail transmission service may differ from the 
rules for wholesale and unbundled retail transmission services.
    64. The Commission established an open access transmission tariff 
under Order No. 888 that provides for two distinct types of wholesale 
transmission services--Network Integration Transmission Service and 
Point-to-Point Transmission Service. Network Integration Transmission 
Service was designed primarily to meet the needs of the transmission 
customer that wants to integrate many generators and many loads at 
diverse locations on the public utility's grid; it was intended to be 
comparable to the service that the public utility provided to its own 
bundled retail customers. Point-to-Point Transmission Service, as the 
name implies, was designed primarily for the customer that wants to 
move power from one discrete location to another.
    65. At the time Order No. 888 issued, the Commission recognized the 
potential for problems with having two wholesale services that could 
not be truly equal, especially the problem of dealing with claims of 
undue discrimination between the services.

[[Page 55463]]

Consequently, along with the issuance of Order No. 888 the Commission 
proposed a rule to create a new tariff, called the Capacity Reservation 
Tariff.\50\ It was intended to remedy the anticipated problems by 
establishing a new tariff that would replace the two wholesale services 
with one. The Commission received many comments on the proposed rule 
and held a technical conference with representatives of diverse 
stakeholders.\51\
---------------------------------------------------------------------------

    \50\ See Capacity Reservation Open-Access Transmission Tariffs, 
61 FR 21,847 (May 10, 1996), FERC Stats. and Regs. [para] 32,519 
(1996) (Notice of Proposed Rulemaking).
    \51\ See Capacity Reservation Open-Access Transmission Tariffs, 
76 FERC [para] 61,065 (1996) (notice extending deadline for filing 
written comments and convening technical conference).
---------------------------------------------------------------------------

    66. Some parties expressed concern about moving quickly to a single 
service based on the Capacity Reservation Tariff model, while other 
parties asserted that, although a single tariff reducing the two 
services to one was a good policy, there were problems with the 
particular Capacity Reservation Tariff that was proposed. They 
recommended that the Commission delay acting on the proposed rule until 
it learned the best form of single service tariff through industry 
experience with open access. This is the approach that the Commission 
in effect followed. Since the two Order No. 888 services were adopted, 
however, there have been allegations of undue discrimination between 
customers of the two services as discussed later in this section.
    67. There are also different rules for bundled retail transmission 
service and for wholesale and unbundled retail transmission services. 
States have historically established the rules for the transmission 
component of bundled retail transactions, while the Commission has 
established the rules for wholesale and unbundled retail transmission 
services.
    68. Despite the requirement in Order No. 888 that no transmission 
customer may have any undue advantage over another, there remain real 
or perceived advantages for the customers of vertically integrated 
transmission owners. In many cases, the perceived advantage is one of 
Network Integration Transmission Service over Point-to-Point 
Transmission Service, where Network Integration Transmission Service is 
available to both bundled retail transmission customers and wholesale 
Network Integration Transmission Service customers, while Point-to-
Point Transmission Service is taken primarily for wholesale 
transmission by independent power producers and marketers.
    69. Four prominent examples highlight the alleged advantages that a 
public utility's bundled retail customers have over wholesale and 
unbundled retail customers. First, certain reliability practices 
related to keeping the transmission system balanced may allow a public 
utility that is responsible for keeping generation and load in balance 
to obtain lower costs for its own power customers. Second, a 
transmission-owning public utility may have more de facto flexibility 
to designate transmission receipt and delivery points than other 
transmission customers, if that public utility also provides power to 
customers on its transmission system. Third, the bundled retail 
customers of a transmission owner may have certain transmission 
reservation and pricing advantages regarding transmission transfer 
capability set aside for reliability. Fourth, state transmission 
curtailment rules that favor a public utility's bundled retail 
customers may conflict with the Commission's transmission curtailment 
rules, resulting in a transmission preference to customers in one state 
over customers served in other states.\52\ The first three of these 
were summarized above, and a detailed discussion with examples is set 
forth in Appendix C.
---------------------------------------------------------------------------

    \52\ We emphasize that transmission curtailment does not 
necessarily mean a power outage.
---------------------------------------------------------------------------

    70. The requirement for all services on the transmission grid to be 
taken under a common set of rates, terms and conditions will resolve 
these concerns.
3. Congestion Management
    71. Due to new transmission usage patterns and the lack of 
transmission infrastructure improvements, congestion has increased. 
However, economically sound congestion management plans do not exist in 
most parts of the country, and transmission customers have been exposed 
to transmission service interruptions and increasing generation costs 
due to the risk of interruption. The operating rules that do exist were 
not designed as a congestion management tool for allocating scarce 
transmission capacity, but were designed to keep facilities from 
overloading in an emergency, such as when a transmission facility 
unexpectedly goes out of service.
    72. Currently, under the existing pro forma tariff, congestion is 
managed primarily through a system of physical reservation of capacity, 
based on each individual transmission provider's calculation of the 
Available Transfer Capability of its grid, a calculation often made 
without knowledge of the power flows on its grid that result from 
transactions scheduled over other grids in its region. Under the 
current pro forma tariff, customers reserve capacity on either a firm 
or non-firm basis, based on the assumed contract path that the 
transaction will use. Once the customer has reserved capacity on a firm 
basis, it is supposed to receive certainty both that power will be 
delivered and the price that the customer will be charged for 
transmission. If the customer has non-firm capacity, it has no 
certainty that capacity will be available to deliver power, but does 
know that there will be no congestion charge if the delivery does 
occur.
    73. The existing pro forma tariff also provides that the redispatch 
of a transmission provider's generating units to relieve congestion is 
required only if it can be achieved while maintaining reliable 
operation of the transmission system in accordance with prudent utility 
practice. The recovery of the higher generation costs resulting from 
such generator redispatch, which are a subset of opportunity costs, 
requires that (1) a formal generator redispatch protocol be developed 
and made available to all transmission customers and (2) all 
information to calculate redispatch costs be made available to the 
customer for audit. If a transmission provider collects revenues to 
cover the redispatch costs from a specific transmission customer, it 
must credit these revenues to the cost of fuel and purchased power 
expense included in its wholesale fuel adjustment clause. Various 
tariff provisions specify how redispatch is to be implemented. For 
instance, Sections 33.2 and 33.3 of the existing pro forma tariff 
provide that the redispatch of all network resources and the 
transmission provider's own resources, on a least-cost basis without 
regard to ownership, is to be performed only to maintain system 
reliability, not for economic reasons. Under those circumstances, the 
redispatch costs would be shared among the network customers and the 
transmission provider on a load ratio basis. Sections 13.5 and 27 of 
the existing pro forma tariff permit the transmission provider to 
provide the requested transmission service and relieve a system 
constraint by redispatching the transmission provider's resources: (1) 
If this costs less than constructing network upgrades; and (2) if, 
under Section 13.5, the transmission customer agrees to compensate the 
transmission provider for any such redispatch costs on an incremental 
basis as specified in the

[[Page 55464]]

customer's service agreement prior to the commencement of service.
    74. Although the existing pro forma tariff allows the recovery of 
generating unit redispatch costs, the Commission generally has not 
accepted proposals submitted by single-utility transmission providers 
to recover such costs. For instance, the Commission rejected Bangor 
Hydro-Electric Company's (Bangor Hydro) proposed formula to recover 
opportunity costs for lack of supporting data showing that its 
opportunity cost pricing would be consistent with the principle of 
comparability and because the formula lacked sufficient detail to 
operate as a rate formula itself.\53\ The Commission directed Bangor 
Hydro to submit a separate section 205 filing with revised opportunity 
cost pricing before implementing such pricing. The Commission also 
rejected a proposal by the operating companies of Central and South 
West Corporation (CSW) regarding redispatch costs because they did not 
provide sufficient specificity to enable a customer to calculate or 
verify redispatch costs and because the formula lacked sufficient 
detail to operate as a formula rate.\54\ The Commission also directed 
CSW to submit a separate filing under section 205 before implementing 
such pricing.
---------------------------------------------------------------------------

    \53\ See Allegheny Power System, Inc., et al., 80 FERC [para] 
61,143 (1997).
    \54\ Central Power and Light Company, 81 FERC [para] 61,311 
(1997).
---------------------------------------------------------------------------

    75. Because it is difficult for a single-utility transmission 
provider to develop a formula that specifies the costs of redispatch 
and protects transmission customers' interests, generation redispatch 
has not been used as extensively as it could be used to relieve 
congestion. A transmission provider will not redispatch generating 
units if it cannot collect its higher generation costs, and less 
transmission transfer capability will be available to the energy 
market.
    76. In 1998, the Commission called on public utilities to work with 
the North American Electric Reliability Council (NERC) to develop a 
congestion management system based on redispatch.\55\ NERC responded 
with its pilot Market Redispatch program that relied on counterflow 
transactions, i.e., power transfers against the prevailing flows on the 
constraint, to relieve the congestion.\56\ Although the program has 
been in place for several years, it has been implemented only 
infrequently because of the difficulty in establishing counterflow 
transactions and the limited availability of data to the transmitting 
customer.\57\
---------------------------------------------------------------------------

    \55\ The NERC rules for protecting the system were designed to 
adapt the Commission's Order No. 888 individual utility transmission 
curtailment requirements to multi-system transactions and parallel 
flows. See North American Electric Reliability Council, 85 FERC 
[para] 61,353, 62,363-64 (1998).
    \56\ See North American Electric Reliability Council, et al., 87 
FERC [para] 61,160 (1999).
    \57\ NERC identified several problems with the program in a 
January 31, 2002 submittal to the Commission: (1) The Market 
Redispatch customer cannot easily anticipate and specify in advance 
which facilities will overload and require transmission curtailment; 
(2) the Market Redispatch transaction must provide a counterflow for 
the entire protected transaction even though the required 
transmisssion curtailment may be only a portion of the original 
protected transaction; and (3) the Market Redispatch customer cannot 
easily discover the availability of generator pairs for counterflow 
transactions. See Report on Market Redispatch Pilot Program by NERC 
Market Interface Committee and Motion to Continue Market Redispatch 
Program, Docket No. ER02-933-000, at 3 (Jan. 31, 2002).
---------------------------------------------------------------------------

    77. In 1998, Commonwealth Edison Company (ComEd) proposed a similar 
voluntary redispatch program, which predated NERC's Market Redispatch 
Program.\58\ In November 1998, ComEd submitted the first of two interim 
reports to the Commission summarizing its experience with the 
program.\59\ It determined that a single utility cannot effectively 
offer redispatch over other systems, especially where other generation 
owners do not participate.
---------------------------------------------------------------------------

    \58\ See Commonwealth Edison Company, et al., 83 FERC [para] 
61,145 (1998).
    \59\ Interim Report on Non-Firm Redispatch, Docket No. ER98-
2279-000 (Dec. 17, 1998).
---------------------------------------------------------------------------

    78. The overall result of the Order No. 888 congestion management 
system is that the transmission system is not utilized in the most 
efficient manner. Customers can be denied access to lower-cost supplies 
that could be made available if the congestion management and pricing 
system had an efficient and fair method of recovering the cost of 
generator redispatch.
    79. Managing congestion using an LMP system, coupled with a single 
transmission service that relies on price (rather than first-come, 
first-served) to allocate limited transmission capacity, will resolve 
these problems.
4. Seams Problems
    80. A lack of common transmission rules inhibits competition in 
power markets not only when there are different rules for different 
customers under one public utility's tariff or one RTO's tariff, but 
also when there are different rules from one public utility to the 
next, or from one RTO to the next. The term ``seam'' has come into 
common use in the electric power industry over the last several years 
to refer to a boundary between areas with different transmission or 
other market rules. Market participants assert that it can be difficult 
to move power ``across a seam'' from one area to another.
    81. Seams issues include differences in transmission rules as well 
as differences in power market rules. They include such diverse matters 
as different operating rules (e.g., rules for recalling firm 
transmission capacity; coordination of generation and transmission 
maintenance schedules; how parallel path flows are determined to affect 
other regions); different market rules (e.g., bidding rules; market 
product definitions); different market designs (e.g., congestion 
management procedures; demand response rules; market price intervention 
practices); different business practices (e.g., scheduling practices; 
reservation practices; OASIS designs; processes to verify transactions 
between ISOs and market participants; transmission and generation 
outage information dissemination, compensation, and coordination rules; 
generation interconnection practices; liability provisions); and 
different electronic and telephonic communications protocols.
    82. Market participants have called for a ``seamless market,'' by 
which they mean a market whose operation is not encumbered by 
differences in rules at public utility or RTO boundaries. To achieve a 
seamless market, some assert that rules may differ but only in ways 
that the differences are invisible to power sellers and buyers. Others 
assert that such management of differences rarely works in practice and 
that the rules must be the same everywhere to achieve a seamless 
market.
    83. The Commission has long recognized the need for more 
coordination and uniformity throughout a region in transmission 
matters. Our Regional Transmission Group Policy Statement of 1993 \60\ 
encouraged public utilities to develop a common set of rules for 
regional expansion planning, and our Transmission Pricing Policy 
Statement of 1994 \61\ encouraged the development of a common pricing 
policy for a region that would internalize and rationalize the pricing 
of parallel path flows. As explained above, Order Nos. 888 and 2000 
recognized the need to bring the various public utility

[[Page 55465]]

transmission systems in a region under a common set of transmission 
rules. Order No. 888 not only applied a common set of open access 
transmission rules to public utility transmission systems, but included 
a reciprocity provision that conditioned a non-public utility's use of 
a public utility's open access transmission tariff on the non-public 
utility's agreement to provide comparable transmission service to the 
public utility. Indeed, Order No. 888 also encouraged the formation of 
ISOs not only to bring all the transmission systems in a region under 
common rules, but also under unified operation. Many parties in Canada 
have stressed the necessity of having a common set of rules for 
reliability and trading protocols for cross-border transmission 
facilities.\62\ Order No. 2000 built on this theme by strongly 
encouraging the formation of RTOs to bring all facilities in a region 
under a common set of transmission rules. However, RTOs have not 
developed at the pace anticipated when Order No. 2000 was issued and 
seams problems continue to exist. In June 2001, the Commission held a 
technical conference on seams issues.\63\ Participants to the seams 
conference explained that resolution of seams issues is critical for 
making the inter-RTO transmission systems and power markets work.
---------------------------------------------------------------------------

    \60\ Policy Statement Regarding Regional Transmission Groups: 
Policy Statement, 58 FR 41,626 (August 5, 1993), FERC Stats. & Regs. 
[para] 30,976 (Jul. 30, 1993).
    \61\ Inquiry Concerning the Commission's Pricing Policy for 
Transmission Services Provided by Public Utilities Under the Federal 
Power Act, 59 FR 55,031 (November 3, 1994), FERC Stats. & Regs. 
[para] 31,005 (Oct. 26, 1994), order on reconsideration and 
clarifying policy statement, 71 FERC [para] 61,195 (1995).
    \62\ See, e.g., Ambassador Michael Kergin (Canada) letter to 
Honorable Thomas A. Daschle, Senate Majority Leader, dated November 
2, 2001:
    Canadian electricity companies are linked to their counterparts 
in the U.S. through a number of major connections crossing our 
common border. We share a truly international electricity grid. This 
interconnectedness itself enhances our respective energy security, 
but it also places an onus on our countries to act together to 
manage the grid. Nowhere is that more important than in the area of 
electricity reliability. * * * Because uniformity in reliability 
standards is required to enable effective electricity trade, 
variations in standards would impede electricity trade and balkanize 
markets.
    \63\ Conference on RTO Interregional Coordination, Docket No. 
PL01-5-000, June 19, 2001. Called by many the ``FERC Seams 
Conference,'' this technical conference on the RTO interregional 
coordination requirements of Order No. 2000 helped the Commission 
learn about seams issues and about how uniform standards for some 
rules could benefit power markets.
---------------------------------------------------------------------------

    84. We set forth in Appendix C a number of examples of differences 
in rules that can create seams problems, and a discussion of efforts at 
the Commission or within the industry to address seams problems.
    85. The requirement under Standard Market Design for a single 
tariff and a single market design operating with the same set of rules 
throughout the entire interconnection resolves the seams problems 
discussed above.
5. Market Design Flaws
    86. Poorly designed market rules, or market rules with unforeseen 
or unintended consequences, can have a debilitating effect on markets, 
market pricing and overall confidence in the markets of the market 
participants. Moreover, differences in market designs in neighboring 
regions can also lead to problems such as the exercise of market power 
through the exploitation of the differences.
    87. Wholesale electricity markets are complex, with multiple 
products traded at multiple locations on different time-frames, while 
subject to the unique physical characteristics of electricity (e.g., 
non-storable, need for system stability and balancing, physics of power 
flows). Market rules have been affected by the variation in generation 
mix, the transmission network layout and the local and regional 
regulatory history in different regions of the country. For example, 
the initial California markets had a design quite different from the 
designs of the markets in the Northeast region (PJM, New York and New 
England).
    88. In the regions where voluntary, organized ISO markets for 
energy, transmission and ancillary services have been established under 
the existing tariff, problems due to the design choices have been 
characterized as ``market design flaws.'' A market design flaw is a 
market rule--including product specification, bid format, auction rules 
and pricing rules--that allows distortions in the market prices or 
availability of a product or service, whether energy, ancillary 
services, transmission service or installed capacity. In the years 
since the ISO markets have been operating, dozens of market design 
flaws have been identified, ranging from minor problems that cause 
temporary inconveniences to major problems that require markets to be 
re-designed. No region has been exempt from market design flaws of one 
type or another. We set forth in Appendix C examples of specific design 
flaws.
    89. These problems have resulted in markets that are inefficient 
and do not produce the lowest reasonable prices for electric power. 
These problems cannot be resolved on a case-by-case basis because that 
will maintain and exacerbate the problems due to local differences in 
rules. Only standardization of electricity market design will solve 
these problems. In the parts of the country in which markets are most 
mature, including the Northeast, Midwest and California, there is broad 
consensus on the principal elements of market design and business 
practices. A standard market design rule will help advance this process 
and extend it to other regions. Our goal is to use the Standard Market 
Design rulemaking to address and remedy many of the market design flaws 
identified to date and to raise the quality of all electric markets 
simultaneously.
    90. Market rules will need to be flexible and have the ability to 
evolve over time. However, consistent rules across the entire 
interconnection based on best practices, coupled with sound market 
monitoring to promptly identify and correct any design flaws will 
provide the necessary foundation for future market innovation and 
improvement.

C. Reform Essential Given the Changed Nature of the Electric Industry

    91. The need to address the instances of discrimination described 
above is all the more critical given the changing nature of the 
electric industry. The United States electric power industry is in the 
middle of a transition from a predominantly monopoly industry to a 
predominantly competitive industry. The fundamental economic driver of 
change has been, and continues to be, the reduction of economies of 
scale in new generation construction, combined with environmental 
restrictions that encourage gas-fired units. This is due in large part 
to the introduction during the 1980s of highly efficient gas turbines 
and combined cycle generators that produce much more electricity from a 
given amount of gas. A relatively small gas-fired generator can compete 
effectively with power from a large central generating station. 
Additionally, small distributed generation is becoming economic, and 
some renewable energy resources, especially wind power generation, are 
also on the verge of becoming competitive.\64\ In the right locations, 
wind generating units can compete with the much larger coal, nuclear 
and hydroelectric units.\65\
---------------------------------------------------------------------------

    \64\ See, e.g., International Energy Agency, Distributed 
Generation in Liberalized Electricity Markets, International Energy 
Agency (June 2002); and Ann Chambers, et al., Distributed 
Generation: A Nontechnical Guide (PennWell Corp. 2001).
    \65\ See Christine Real de Azua, Wind Power: Poised for Take 
Off? A Survey of Projects and Economics, Pub. Util. Fort., Aug. 2001 
at 38.
---------------------------------------------------------------------------

    92. Because of these fundamental changes in industry technology, 
small producers of electricity can compete with large producers, and 
both the smaller utilities and the retail customers of a number of 
utilities have demanded access to competing power suppliers in hopes of 
lowering their electric bills,

[[Page 55466]]

improving service and harnessing new technologies. The pressures for 
retail access have been greater in regions with higher rates, which are 
typically regions with few low-cost natural resources for generating 
electric power, such as nearby coal mines, gas fields, and 
hydroelectric areas.\66\ Many of these regions have taken the lead in 
retail restructuring, while regions with historically low electricity 
production costs have proceeded more cautiously or even affirmatively 
decided not to change their retail access policies or to support their 
local utilities' participation in regional programs at this time.\67\
---------------------------------------------------------------------------

    \66\ See Energy Information Administration, The Changing 
Structure of the Electric Power Industry 2000: An Update, at 81-82 
(2000), available in http://www.eia.doe.gov/cneaf/electricity/chg_stru_update/update2000.pdf (hereinafter Electric 
Power Industry 2000 Update).
    \67\ See id.
---------------------------------------------------------------------------

    93. One hallmark of electric industry restructuring has been the 
growth of wholesale trade. In the past, wholesale power purchases made 
up a small fraction of a large vertically integrated utility's power 
supply, with most of its power needs met by its own generation. Today, 
however, even large vertically integrated utilities rely increasingly 
on wholesale purchases for their energy supplies. For example, as shown 
in Table 1, between 1989 and 2000, generation by investor-owned 
utilities grew from 2,132 thousand GWh to 2,230 thousand GWh, an 
increase of less than 5 percent. During this time, wholesale power 
purchases by these utilities almost tripled. Table 1 also shows that in 
1989 wholesale power purchases provided 18 percent of the total 
electric energy available to investor-owned utilities from both 
wholesale purchases and their own generation. By 2000, wholesale 
purchases provided over 37 percent of investor-owned utility electric 
energy. This percentage has steadily increased since 1989, and is 
expected to continue to grow as utility-owned plants are sold or 
retired and new power supplies are acquired competitively in most parts 
of the country.

  Table 1.--Investor-Owned Utilities' Total Purchases, 1989-2000, As a Percentage of Energy Purchased and Self-
                                                    Generated
----------------------------------------------------------------------------------------------------------------
                                                                                                     Purchases
                                                                       IOUs'           IOUs'     ---------------
                              Year                                   purchases      generation     (purchases +
                                                                       (GWh)           (GWh)        generation)
                                                                                                        (%)
----------------------------------------------------------------------------------------------------------------
1989............................................................         460,627       2,132,065            17.8
1990............................................................         530,325       2,134,429            19.9
1991............................................................         635,015       2,145,435            22.8
1992............................................................         671,758       2,143,847            23.9
1993............................................................         718,876       2,216,724            24.5
1994............................................................         732,710       2,237,652            24.7
1995............................................................         786,676       2,269,958            25.7
1996............................................................         916,087       2,308,156            28.4
1997............................................................       1,080,538       2,321,225            31.8
1998............................................................       1,073,638       2,402,571            30.9
1999............................................................       1,083,892       2,353,639            31.5
2000............................................................       1,324,558       2,229,617           37.3
----------------------------------------------------------------------------------------------------------------
 Source: RDI POWERDAT Database.


    Note: Data for 2001 is not yet available. Investor-owned utility 
purchases include purchases from affiliates.

    94. Table 1 demonstrates the increasing importance of competitive 
wholesale energy acquisition in the United States electric power 
industry, and the need for this Commission to ensure that transmission, 
market rules and institutions are reformed as necessary to support the 
new environment. It also makes clear that a retreat from competitive 
markets to a cost-regulated vertically integrated world would be 
difficult--the nation now depends increasingly on wholesale interstate 
electricity markets.
    95. Similar data are presented in Tables 2 and 3 for large public 
power utilities and generation and transmission cooperatives that 
generate at least some of their own power.\68\ These tables show that 
wholesale purchases, on average, provide about 40 percent of the power 
needs of these large utilities. Data are not presented for the smaller 
public power and cooperative utilities because they typically do not 
self-generate but buy all of their power at wholesale.
---------------------------------------------------------------------------

    \68\ Note that the data available for large public power and 
cooperative utilities is not complete but represents a sampling of 
these utilities. The sample size typically grew each year so that an 
apparent growth in the wholesale purchase percentages could reflect 
the addition of smaller utilities that purchase more power at 
wholesale.

  Table 2.--Large Public Power Utilities' Total Purchases, 1992--2000, As a Percentage of Energy Purchased and
                                                 Self-Generated
----------------------------------------------------------------------------------------------------------------
                                                                                                     Purchases
                                                                    Utilities'      Utilities'   ---------------
                              Year                                   purchases      generation     (Purchases +
                                                                       (GWh)           (GWh)        generation)
                                                                                                        (%)
----------------------------------------------------------------------------------------------------------------
1992............................................................         297,076         520,348            36.3
1993............................................................         314,472         549,810            36.4
1994............................................................         331,643         555,198            37.4
1995............................................................         332,962         586,737            36.2
1996............................................................         350,880         645,740            35.2

[[Page 55467]]

 
1997............................................................         349,641         674,725            34.1
1998............................................................         364,434         676,698            35.0
1999............................................................         394,617         634,548            38.3
2000............................................................         429,369         631,143           40.5
----------------------------------------------------------------------------------------------------------------
Source: RDI POWERDAT Database.

    ``Large Public Power Utilities'' includes municipals, federal power 
authorities. Data for 2001 is not yet available.

     Table 3.--Generation & Transmission Cooperatives' Total Purchases, 1992--2000 As a Percentage of Energy
                                          Purchased and Self-Generated
----------------------------------------------------------------------------------------------------------------
                                                                                                     Purchases
                                                                   Cooperatives'   Cooperatives' ---------------
                              Year                                   purchases      generation     (Purchases +
                                                                       (GWh)           (GWh)        generation)
                                                                                                        (%)
----------------------------------------------------------------------------------------------------------------
1992............................................................          85,226         136,417            38.5
1993............................................................          93,756         149,783            38.5
1994............................................................          96,148         156,589            38.0
1995............................................................          99,909         166,099            37.6
1996............................................................         117,455         172,161            40.6
1997............................................................         112,822         176,689            39.0
1998............................................................         115,003         177,534            39.3
1999............................................................         122,151         172,323            41.5
2000............................................................         127,785         171,198           42.7
----------------------------------------------------------------------------------------------------------------
Source: RDI POWERDAT Database.


    Note: ``Generation & Transmission Cooperatives'' includes 
cooperatives with generation and transmission facilities, but 
excludes distribution cooperatives. Data for 2001 is not available 
yet.

    96. The transition to competitive electricity markets is 
characterized by opportunity and uncertainty. The promise of 
competition is the opportunity to develop more innovative technologies, 
improve services, lower average electric rates and provide more 
customer choice than is likely under a strictly regulated monopoly 
environment. During the transition to competition, these promises are 
only partly fulfilled, and results vary regionally as a result of 
different choices about retail restructuring. Additionally, the 
California electricity crisis of 2000-2001, allegations of improper 
trading practices, the collapse of Enron Corporation in December 2001 
and the deteriorating financial health of many electric suppliers and 
marketers at this time have added unprecedented uncertainty about, and 
lack of confidence in, today's electric markets.
    97. In addition to general concerns about adequate constraints on 
the exercise of market power by power sellers, there is uncertainty in 
the industry about impediments to new generators entering the market, 
adequacy of incentives to build much needed generation and transmission 
infrastructure, availability of non-discriminatory transmission service 
for all sellers and buyers in a regional market and the risk of making 
long-term commitments when market rules are subject to frequent 
experiment and change. Differences in market rules between regions make 
it difficult to transact business across regions and thus also lead to 
increased uncertainty in the industry and the risk of market 
manipulation.
    98. Investors, generators and transmission providers are reluctant 
to invest in new generation and transmission infrastructure if the 
rules for setting energy or transmission prices are not yet known or 
are subject to frequent revision.\69\ Thus, uncertainty about the 
direction of competition policies inhibits the development of the very 
infrastructure needed both to allow competition to work and to assure 
reliability in a competitive environment. Customers are reluctant to 
sign contracts for power or to change suppliers if long-term power 
markets are unnecessarily volatile and they cannot obtain price 
certainty.
---------------------------------------------------------------------------

    \69\ See generally U.S. Department of Energy, National 
Transmission Grid Study (May 2002), available in <http://tis.eh.doe.gov/ntgs/ (hereinafter DOE National 
Transmission Grid Study).
---------------------------------------------------------------------------

    99. The promise of wholesale competition may go unfulfilled--or at 
best continue to be delayed at great cost--unless many of these 
uncertainties are resolved. This proposed rule is intended to help 
resolve generically many of the uncertainties facing the electric power 
industry and to restore confidence in future power markets.

D. Legal Authority and Findings

    100. The primary purposes of the Federal Power Act are to curb 
abusive practices by public utilities and to protect customers from 
excessive rates and charges. To achieve these ends, section 205 of the 
Federal Power Act requires that no public utility shall ``make or grant 
any undue preference or advantage to any person or subject any person 
to any undue prejudice or disadvantage,'' with respect to the 
transmission of electric energy in interstate commerce or wholesale 
sales.\70\ Section 206 of the Federal Power Act authorizes the 
Commission

[[Page 55468]]

to investigate and remedy unduly discriminatory or preferential rules, 
regulations, practices or contracts affecting public utility rates for 
transmission in interstate commerce and for sales for resale of 
electric energy in interstate commerce.\71\ It also authorizes the 
Commission to investigate and remedy unjust and unreasonable rates, 
charges or classifications, and any rules, regulations, practices or 
contracts affecting such rates, charges or classifications.
---------------------------------------------------------------------------

    \70\ 16 U.S.C. 824d.
    \71\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    101. Moreover, the Commission's regulatory authority ``clearly 
carries with it the responsibility to consider, in appropriate 
circumstances, the anticompetitive effects of regulated aspects of 
interstate utility operations pursuant to [Federal Power Act sections] 
202 and 203, and under like directives contained in [Federal Power Act 
sections] 205, 206, and 207.'' \72\ The Commission's authority to 
remedy undue discrimination and anticompetitive effects is broad.\73\
---------------------------------------------------------------------------

    \72\ See Order No. 888 at 31,669 (quoting Gulf States Utilities 
Co. v. FPC, 411 U.S. 747, 758-59, reh'g denied, 412 U.S. 944 
(1973)). See also City of Huntingburg v. FPC, 498 F.2d 778, 783-84 
(D.C. Cir. 1974) (finding that the Commission has a duty to consider 
the potential anticompetitive effects of a proposed interconnection 
agreement).
    \73\ See Order No. 888 at 31,669 (the Federal Power Act fairly 
bristles with concern for undue discrimination (citing Associated 
Gas Distributors v. FERC, 824 F.2d 981, 998 (D.C. Cir. 1987), cert. 
denied, 485 U.S. 1006 (1988))).
---------------------------------------------------------------------------

    102. The Court of Appeals for the District of Columbia Circuit 
reviewed challenges to Order No. 888 and found that the ``open access 
requirement is authorized by and consistent with the [Federal Power 
Act],'' and upheld the order.\74\ On appeal, the Supreme Court affirmed 
the Commission in applying its open access requirements to transmission 
used for wholesale and unbundled retail sales of electric energy in 
interstate commerce, but also concluded that the Commission had 
jurisdiction over transmission used for bundled retail sales of 
electric energy in interstate commerce. The Supreme Court further 
stated that the Commission may regulate bundled retail transmission of 
energy as a means of addressing undue discrimination. While the Court 
did not adopt the appellants' suggestions that the Commission's finding 
of discrimination in the wholesale electricity market suggested the 
presence of discrimination in the retail electricity markets,\75\ it 
stated that ``[w]ere FERC to investigate this alleged discrimination 
and make findings concerning undue discrimination in the retail 
electricity market, Sec. 206 of the FPA would require FERC to provide a 
remedy for that discrimination * * * And such a remedy could very well 
involve FERC's decision to regulate bundled retail transmissions'' of 
energy.\76\
---------------------------------------------------------------------------

    \74\ Transmission Access Policy Study Group v. FERC, 225 F.3d at 
685.
    \75\ See id. at 1028.
    \76\ Id.
---------------------------------------------------------------------------

    103. We find that undue discrimination and anticompetitive behavior 
persist, as detailed in Section III and Appendix C, in both wholesale 
and retail transmission of energy. Pursuant to our statutory mandate to 
remedy undue discrimination and anticompetitive effects in these 
markets, as interpreted by the Supreme Court, we will apply the 
requirements of this rule to the transmission component of bundled 
retail transactions. At a minimum, all transmission service in 
interstate commerce must be subject to the same non-discriminatory non-
rate terms and conditions in order to eliminate undue discrimination in 
wholesale markets and in retail choice markets. With respect to rates 
for bundled retail transmission service, however, we will work with 
states to address difficult transition rate issues.
    104. In light of these statutory responsibilities and authorities 
under the Federal Power Act, we have assessed the state of the electric 
utility industry and determined that it is necessary to act promptly to 
provide stability to the industry and to assure that customers receive 
adequate supplies of electric energy at the lowest reasonable price. 
During the past six years, the implementation of open access 
transmission under Order No. 888 has fundamentally altered the 
landscape of the electric utility industry by removing major 
discriminatory barriers to the use of the interstate transmission grid 
and thereby opening the door to competition in wholesale electric power 
markets. However, even with the Order No. 888 open access pro forma 
transmission tariff and Order No. 889 transmission standards of conduct 
in place, there continues to be undue discrimination in the provision 
of interstate services. Experience under the pro forma tariff has 
demonstrated that unduly discriminatory transmission practices continue 
today. Further, existing trading rules and design of wholesale power 
markets do not consistently prevent market manipulation or send proper 
price signals to participants or allocate scarce resources to those who 
value them most and thus could result in unjust and unreasonable rates. 
Thus, competition either does not exist in many areas of the country or 
competition is distorted.
    105. We find that:

    (1) the operation of the Commission's pro forma transmission tariff 
(which is administered by vertically integrated as well as non-
vertically integrated public utilities such as ISOs) contains 
provisions that, in practice, permit undue discrimination in the 
provision of transmission services;
    (2) public utilities that own, operate or control transmission 
facilities and also participate in power markets continue to possess 
substantial transmission market power and retain the ability to unduly 
discriminate in the provision of transmission service and spot market 
energy services;
    (3) lack of standardized wholesale electric market design allows 
undue discrimination within and across regions, can result in unjust 
and unreasonable pricing and allocation of transmission and permits the 
exercise of market power (and thus unjust and unreasonable rates) in 
power markets; and
    (4) proper price signals are not being sent to the marketplace, 
with the result that market-based rates in many places are distorted, 
and reasonably accurate price signals necessary for infrastructure 
additions are not being sent.
    106. To remedy remaining undue discrimination in the provision of 
interstate transmission services and in other industry practices, and 
to ensure just and reasonable rates for sales of electric energy within 
and among regional power markets, the Commission proposes to modify the 
Order No. 888 pro forma tariff to reflect non-discriminatory, 
standardized transmission service and require standardized wholesale 
electric market design. The Commission also proposes to expressly 
exercise jurisdiction over all transmission in interstate commerce by 
public utilities.

IV. The Proposed Remedy

    107. The Commission's goal in Order Nos. 888 and 2000 was to 
harness the benefits of competition for the nation's electricity 
customers by assuring adequate and reliable supplies of electricity at 
a just and reasonable price. As discussed above in the Need for Reform 
section (Section III), the current rules and regulations have prevented 
the full attainment of that objective. To address these problems in the 
current system, we are proposing a comprehensive package of reforms 
that are described more fully in this section.
    108. Section III and Appendix C provide numerous examples of ways 
that an entity that owns both

[[Page 55469]]

transmission and generation can discriminate in favor of its own 
customers or generation under the current tariff. The problem stems 
from the differences in the sets of rules that apply to users of the 
transmission system. First, the current regulatory system allows 
vertically integrated utilities to discriminate in favor of their 
bundled retail load at the expense of wholesale customers. This occurs 
because transmission service for bundled retail customers is subject to 
different rules and rates than service for wholesale customers. Second, 
the current distinction between Point-to-Point Transmission Service and 
Network Integration Transmission Service also creates opportunities for 
undue discrimination in favor of generation owned by the transmission 
owner or an affiliate.
    109. To remedy this discrimination we propose to place all 
transmission customers under the same set of rules. We propose to place 
transmission service for bundled retail customers under the same terms 
and conditions of service as wholesale transmission service. To 
accomplish this we propose to revise the existing pro forma tariff to 
remove provisions that grant preferential treatment to transmission 
service for bundled retail customers. We propose that all public 
utilities that own, control or operate interstate transmission file 
these interim changes no later than July 31, 2003. We also propose that 
no later than September 30, 2004, or such date as the Commission may 
establish, only Independent Transmission Providers would operate 
Commission-jurisdictional facilities. This requirement will apply 
whether or not the public utility that owns, controls or operates 
interstate transmission facilities has joined an RTO.\77\ We are 
proposing specific governance requirements that must be met by the 
Independent Transmission Provider.
---------------------------------------------------------------------------

    \77\ A Commission-approved RTO would meet the requirements of an 
Independent Transmission Provider.
---------------------------------------------------------------------------

    110. Also, no later than September 30, 2004, or such date as the 
Commission may establish, we propose to eliminate the distinction 
between Point-to-Point and Network Integration Transmission Services by 
having one service, Network Access Service, that contains elements of 
both types of service--the flexibility of Network Integration 
Transmission Service and the tradability of Point-to-Point Transmission 
Service. We propose these time periods to provide sufficient time for 
the development of the necessary new software systems. Network Access 
Service is based on an open spot market for imbalance energy and a 
uniform congestion management methodology, i.e., LMP, to more 
efficiently manage the transmission grid. The spot energy market and 
LMP rely on management of the transmission system and bidding by supply 
and demand resources attached to the transmission grid under market 
rules and protocols.
    111. To provide the price signals needed to manage congestion, the 
Independent Transmission Provider will be required to operate a day-
ahead and real-time market for energy. To provide customers with a 
mechanism for achieving price certainty under the new congestion 
management system, we also propose to require that customers be given 
Congestion Revenue Rights for their historical uses that protect 
against congestion costs when specific receipt and delivery points are 
used.
    112. LMP and Congestion Revenue Rights will provide price signals 
to indicate where new investment is needed; however, the price signals 
alone may not guarantee sufficient investment. We also propose to 
require a regional transmission planning and expansion process to 
provide a backstop process for ensuring that needed transmission 
construction is undertaken. We propose that this process begin six 
months from the effective date of the Final Rule, even though much of 
the country will not have had the opportunity to respond to LMP and 
Congestion Revenue Rights for another few years.
    113. At this stage of the industry's evolution, structural barriers 
to competitive markets remain, so to address this we are proposing 
market power mitigation measures for the spot markets that will be 
operated by the Independent Transmission Provider. These measures are 
designed to address the two significant structural problems in 
wholesale energy markets--the existence of localized market power that 
arises from transmission constraints, and the lack of price-responsive 
demand. The market power mitigation proposal is a framework that can be 
tailored to reflect the competitive conditions of the particular 
region. It is designed to be reexamined annually and adjusted as needed 
to reflect changes in the competitive structure of the region, 
including a phasing out of mitigation measures as resource adequacy and 
demand response develops. Because market power mitigation of spot 
market prices will tend to suppress the price signals for new entry, we 
are also proposing a non-price mechanism to assure that load meets a 
long-term resource adequacy requirement.
    114. To avoid the market design flaws discussed in the Need for 
Reform section (Section III) and Appendix C and market manipulation in 
Appendix E, and to minimize the potential for seams issues, we propose 
a standardized tariff that incorporates the best practices and builds 
on the lessons from our experience with organized markets. In Appendix 
B, the proposed SMD Tariff standardizes many aspects of the basic 
market design. However, it also allows flexibility in a number of areas 
to customize the basic market design to meet regional requirements 
where such customization will not lead to further discrimination or 
inefficiencies.
    115. We propose to permit small entities to seek waiver of the 
Standard Market Design Final Rule requirements. The regulations we 
propose include waiver provisions under which public utilities, and 
non-public utilities seeking exemption from the reciprocity condition, 
may file requests for waivers from all or part of the Commission's 
regulations.
    116. Finally, while we have attempted to standardize the basic 
aspects of the market design policy, this proposed rule does not 
include detailed business practices and communication protocols that 
will be needed to administer Standard Market Design. We fully 
appreciate the benefits of business practice standardization and, as we 
did in the natural gas industry, we believe it is best if industry 
participants develop these types of highly detailed and technical 
standards. Thus, we are proposing a process, similar to that used in 
the natural gas industry, that could be used for standardization of 
business practices, data sets and communication protocols that includes 
representation of all affected market participants. Upon its formation, 
the Wholesale Electric Quadrant of the North American Energy Standards 
Board (NAESB), working closely with Independent Transmission Providers 
who would collectively serve in an advisory capacity to the board, 
would produce business practice and electronic communication standards. 
NAESB would notify the Commission when it has adopted standards, and 
the Commission would then use rulemaking proceedings to propose the 
incorporation of these standards by reference into the Commission's 
regulations. If the industry is unable to reach consensus on a 
particular standard, the Commission would be available to resolve the 
dispute, so that the industry process can continue, or the Commission 
could develop its own standards if necessary. Consistent with gas 
industry regulation, issues of policy that affect significant resources 
or that

[[Page 55470]]

may cause cost-shifting would be resolved at the Commission rather than 
through the standard setting body.

A. The Interim Tariff

    117. Standard Market Design is intended to cure undue 
discrimination, in part, with respect to the use of the transmission 
grid. As we discussed in Section III.B.2, there are different rules for 
bundled retail transmission service and for wholesale and unbundled 
retail transmission services. These differences result in unduly 
discriminatory preferences for the vertically integrated transmission 
owner's bundled retail customers.
1. Placing Bundled Retail Customers Under the Interim Tariff
    118. We propose that to eliminate this undue discrimination, the 
transmission component of bundled retail service must be taken under an 
open access transmission tariff. Under the current pro forma tariff, a 
vertically integrated utility is required to designate the resources it 
uses to serve bundled retail customers in the same manner as wholesale 
customers are required to designate network resources under the Network 
Integration Transmission Service. We propose to use these designations 
of network resources in converting service used to meet retail 
obligations. The existing level of service would be provided pursuant 
to the new Network Access Service. The load-serving entity or the 
retail customer would receive either Congestion Revenue Rights or the 
auction revenues for these rights for the currently designated 
resources. In Section V of this Notice of Proposed Rulemaking, the 
Commission sets forth a proposed time-line and implementation process 
for this conversion process.
    119. In the interim, however, we propose to require that bundled 
retail load be placed under the existing pro forma tariff. While many 
of the revisions required by Standard Market Design are dependent on 
the production and adoption of software to determine locational 
marginal prices and to operate markets, placing bundled retail load 
under the existing pro forma tariff can be done immediately. This will 
remove certain discriminatory practices and is the first step towards 
placing all transmission service under one tariff. This will require 
several revisions to the existing pro forma tariff to modify provisions 
that define the different treatment granted to the service of bundled 
retail load. Among the revisions that the Commission proposes to 
require public utilities to file are revisions to Sections 1.19, 13.5, 
13.6, 14.2, 22.1(a), 22.1(a), 28.2, 28.3, 33.2, 33.3, 33.3 and 33.5. 
The specific changes are identified in Appendix A.
    120. We propose that the public utilities file these revisions to 
their tariffs and execute service agreements to take Network 
Integration Transmission Service on behalf of their bundled retail load 
no later than July 31, 2003. We recognize, however, that some public 
utilities (e.g., ISOs) may already be serving bundled retail load under 
the pro forma tariff. Accordingly, to the extent that a public utility 
can demonstrate that it complies with this requirement, it may so 
indicate in its compliance filing.
2. Additional Interim Revisions to the Pro Forma Tariff
    121. Since the implementation of the existing pro forma tariff, the 
Commission has offered clarifications to various provisions of the 
tariff. Perhaps the most important of these dealt with a customer's 
right to roll over its existing contract for long-term firm service 
(Section 2, Initial Allocation and Renewal Procedures).
    122. In several orders, the Commission clarified three significant 
points: (1) A customer must submit a request to roll over its contract 
no later than sixty days prior to the date the current service 
agreement expires;\78\ (2) the public utility may only deny a customer 
its right to roll over a contract due to future load growth if the 
public utility includes in the original service agreement a specific, 
reasonably forecasted need for the transfer capability to serve load 
growth for network customers at the end of the term of the service 
agreement;\79\ and (3) a long-term firm customer that requests to use 
alternate point(s) of receipt or delivery retains its right of first 
refusal for service at the original point(s) of receipt and delivery at 
the time the current service agreement expires.\80\
---------------------------------------------------------------------------

    \78\ Entergy Power Marketing Corporation v. Southwest Power 
Pool, 91 FERC [para]61,276 (2000).
    \79\ Order No. 888-A, as clarified by Public Service Company of 
New Mexico, 85 FERC at 62,006 (1998); Public Service Company of New 
Mexico v. Arizona Public Service Company, 99 FERC [para]61,162 
(2002); Exelon Generation Company, LLC v. Southwest Power Pool, 99 
FERC [para] 61,235 (2002).
    \80\ Commonwealth Edison Company, 95 FERC [para] 61,027 (2000).
---------------------------------------------------------------------------

    123. These revisions have a significant impact on the rights of 
current transmission customers and will continue to do so up until the 
time the SMD Tariff, including auctions of Congestion Revenue Rights, 
is in place.\81\ We propose to require public utilities to make the 
tariff changes to Section 2.2 of the existing pro forma tariff, as 
outlined in Appendix A.
---------------------------------------------------------------------------

    \81\ The protections offered by rollover rights are of value in 
a first-come, first-served priority system, and are valuable for a 
direct allocation of Congestion Revenue Rights. Once Congestion 
Revenue Rights are fully auctioned, and access to transmission 
service will be based on a willingness to pay congestion costs (and 
losses), it may no longer be necessary.
---------------------------------------------------------------------------

B. Independent Transmission and Markets

    124. Another form of undue discrimination is the lack of 
independence of the transmission provider in many regions of the 
country. As discussed in Section III.B.1, remaining corporate ties 
between generation and transmission within public utilities are 
problematic since they allow the vertically integrated utility to 
exercise market power to advantage its affiliated generation.
1. Independent Transmission Providers
    125. To remedy this undue discrimination, transmission service must 
be provided by an independent entity. Therefore, we propose to require 
all public utilities that own, control or operate facilities used for 
the transmission of electric energy in interstate commerce to: (1) Meet 
the definition of Independent Transmission Provider, (2) turn over the 
operation of its transmission facilities to an RTO that meets the 
definition of Independent Transmission Provider, or (3) contract with 
an entity that meets the definition of Independent Transmission 
Provider to operate its transmission facilities.
    126. An Independent Transmission Provider is any public utility 
that owns, controls or operates facilities used for the transmission of 
electric energy in interstate commerce, that administers the day-ahead 
and real-time energy and ancillary services markets in connection with 
its provision of transmission services pursuant to the SMD Tariff, and 
that is independent (i.e., has no financial interest, either directly 
or through an affiliate, in any market participant in the region in 
which it provides transmission services or in neighboring regions).
    127. We propose that affected public utilities must inform the 
Commission which Independent Transmission Provider will operate the 
public utility's transmission facilities no later than July 31, 2003. 
However, a public utility that is a member of an approved RTO or ISO or 
other entity that meets the definition of Independent Transmission 
Provider may file a request for a waiver of the filing requirements of 
this paragraph on the ground that it has already complied with the 
requirement.

[[Page 55471]]

    128. Any entity meeting the definition of Independent Transmission 
Provider would file the SMD Tariff to provide transmission services, 
including ancillary services, and to administer the day-ahead and real-
time energy and ancillary services markets. As discussed further below, 
an Independent Transmission Provider would also perform market 
monitoring and market power mitigation, long-term resource adequacy and 
transmission planning and expansion on a regional basis.
    129. An Independent Transmission Provider would also file under 
section 205 any changes to transmission rates necessary to implement 
Standard Market Design, no later than 60 days prior to the date on 
which it proposes to implement Standard Market Design.
    130. In addition, one or more public utilities may jointly file an 
application to meet the requirements of Standard Market Design. Also, 
an Independent Transmission Provider may make necessary filings on 
behalf of public utilities required to meet the requirements of this 
paragraph.
    131. We seek comment on whether this remedy is adequate to remove 
the potential for unduly discriminatory behavior on the part of a 
vertically integrated transmission provider. Can the requirements of 
Standard Market Design be satisfied either by performing the function 
through an RTO or contracting with an independent entity to perform 
them? Given that most transmission providers have filed proposals to 
join an RTO, is a non-RTO compliance option necessary to cure undue 
discrimination and produce just and reasonable rates for transmission 
service and the sale of electric energy?
2. Role of Independent Transmission Companies in Standard Market Design
    132. We have long recognized that the Independent Transmission 
Company (ITC) business model can bring significant benefits to the 
industry. Their for-profit nature with a focus on the transmission 
business is ideally suited to bring about: (1) Improved asset 
management including increased investment; (2) improved access to 
capital markets given a more focused business model than that of 
vertically integrated utilities; (3) development of innovative 
services; and (4) additional independence from market participants. We 
believe that these characteristics of ITCs can have significant 
benefits for the implementation of Standard Market Design, particularly 
in the areas of development of transmission infrastructure and 
structural independence from market participants.
    133. The Commission recently approved a proposal by several 
transmission owners to form an ITC, TRANSLink Transmission Company, LLC 
(TRANSLink), to share responsibility with the Midwest ISO Regional 
Transmission Organization (the Midwest ISO) \82\ and other regions for 
the RTO functions prescribed in Order No. 2000. In that proceeding, the 
Commission approved a hybrid RTO formation under which specific RTO 
functions were delegated to either the RTO or the ITC. Regarding the 
delegation of functions we stated:
---------------------------------------------------------------------------

    \82\ TRANSLink Transmission Company, L.L.C., et al., 99 FERC 
[para] 61,106 (2002).

    Our rulings on the allocation of functions issues are based on 
our belief that for effective RTO operations, regional trading, and 
one-stop shopping, a single transmission provider must have overall 
authority and ultimate responsibility for transmission service in 
the region. We further believe that the security-constrained, 
economic dispatch needed for an efficient and reliable market is 
best operated by an independent regional transmission provider. 
However, we believe that it is acceptable for some functions with 
predominantly local characteristics to be delegated to an ITC so 
long as the RTO has oversight authority in the event that local 
actions have a regional impact. We find that this is critical to 
successful RTO development and especially important given the 
characteristics of the interstate transmission grid. It has become 
increasingly evident in recent years that even seemingly local 
issues, such as generator location or isolated transmission 
bottlenecks, can and do impact the larger grid, and that is why we 
believe that centralized RTO oversight is needed.
    We also remain concerned that vesting control into sub-regional 
entities may create seams which could easily lead to re-
balkanization. These difficult delegation decisions are made with 
our firm belief that ITCs can flourish under the RTO umbrella and 
that in performing certain delegated functions, ITCs will be able to 
effectively manage their assets, protect their value, and bring 
their expertise to increase efficiencies and enhance the value of 
their business. Nevertheless, these delegation decisions should not 
prevent ITCs from seeking additional authority, subject to 
Commission approval, at a later date after ITCs have gained 
experience under RTO operations.\83\ We are also guided by the 
premise that any delegation of functions to an ITC must be 
consistent with and further the Commission's goals in the SMD 
Proceeding. We assume in this order that the Midwest ISO will be the 
transmission provider in the TRANSLink area and will operate a real-
time and day-ahead market, or any functions that are required under 
the SMD final rule.\84\

    \83\ We recognize that as the Midwest ISO and ITCs gain 
experience, they should, from time to time, reassess the assignment 
of the functions and reevaluate whether some that have been 
delegated to a local level need to be performed at a regional level 
and vice versa. Likewise, after SMD is implemented, the assignment 
of functions may need to be reassessed. (Footnote 37 in original).
    \84\ TRANSLink, 99 FERC at 61,463.
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    134. We seek comment on the functions that an ITC should perform 
under Standard Market Design. Should the Commission retain the same 
delegation of functions that was approved in TRANSLink? Are there 
elements of the proposed Standard Market Design that would justify a 
different delegation of functions? Should an ITC qualify as an 
Independent Transmission Provider?
    135. We seek comment on whether an ITC that has no ties to a Market 
Participant, as defined in this proposal, is sufficiently independent 
to act as the Independent Transmission Provider. The ITC may hold grid 
assets such as transmission facilities and Congestion Revenue Rights 
and may be allowed a performance-based ratemaking program. Thus the 
Commission is concerned that the ITC may unduly discriminate in favor 
of its own transmission interests when carrying out operational and 
planning decisions in its role as Independent Transmission Provider. We 
seek comment on whether such ITC interests in transmission investment 
may cause the ITC to unduly discriminate in day ahead or real time 
markets operations or to discount generation, demand response, and 
other transmission owners' (e.g., merchant transmission) solutions to 
grid problems. On the other hand, generation and demand response 
solutions are likely to have the first opportunity to respond to LMPs 
if it makes economic sense to do so, given the difficulty in siting 
transmission. Given the planning process and stakeholder input, as well 
as the Commission's authority to set rates, we seek comment on what 
specific ways an ITC could make such unduly discriminatory decisions? 
The Commission is convinced that, if its role is appropriately defined, 
and opportunities for undue discrimination are addressed, the ITC shows 
great promise to address grid problems through profit driven 
activities. One such activity could be reducing congestion where an ITC 
with properly structured performance based rates would have an 
incentive. What is the appropriate role for the ITC?

C. The New Transmission Service

    136. To address the discrimination described in Section III above 
and in Appendix C, we will require Independent Transmission Providers 
to provide a nondiscriminatory, standard transmission service to all 
customers.

[[Page 55472]]

This new service, Network Access Service, combines features of both the 
existing open access transmission services--Network Integration 
Transmission Service and Point-to-Point Transmission Service. The 
Network Access Service is grounded in the flexibility of network 
integration transmission service, but adds a measure of reassignability 
similar to that available under firm Point-to-Point Transmission 
Service. Thus, Network Access Service will give all customers the 
opportunity to have tradable Congestion Revenue Rights \85\ that will 
expand their transmission options and enhance competition in wholesale 
electric markets. It also will result in all transmission services 
being performed under a single set of rules.
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    \85\ Congestion Revenue Rights entitle the holder to receive 
specified congestion revenues in the day-ahead market. To the extent 
that a customer's real-time schedule coincides with its day-ahead 
schedule and its Congestion Revenue Rights, these rights offer 
complete protection against uncertain congestion charges.
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    137. To complement Network Access Service and implement the 
Standard Market Design, Independent Transmission Providers will manage 
congestion using LMP. Management of transmission grid congestion is 
difficult to do through bilateral transactions alone; thus a spot 
market is required to manage congestion efficiently. We believe that 
congestion management, balancing of load and generation in real time, 
and the provision of ancillary services can be accomplished most 
reliably and efficiently by a bid-based, security-constrained spot 
market.
    138. In addition to administering a spot market to manage 
congestion, the Independent Transmission Provider will also use it to 
handle imbalances and the procurement of ancillary services. The 
Independent Transmission Provider would operate markets for energy, 
regulation, operating reserve--spinning and operating reserve--
supplemental. These markets would be security-constrained, bid-based 
markets operated in two time frames: (1) A day ahead of real-time 
operations, and (2) in real time. Transmission services will be 
scheduled through the day-ahead and real-time markets. The Independent 
Transmission Provider would establish schedules for transmission 
service, and sales and purchases of energy, regulation, and both 
operating reserves, to ensure the most efficient use of the 
transmission grid. Although the Independent Transmission Provider will 
not be required to operate an organized market for either short- or 
long-term bilateral transactions, its scheduling process must 
accommodate such bilateral trades.
1. Basic Rights
    139. Network Access Service builds upon the existing Order No. 888 
Network Integration Transmission Service and will be available to all 
eligible customers. As with Network Integration Transmission Service, 
Network Access Service offers flexible use of the transmission grid--it 
allows the load-serving entity to choose to serve its load with any 
available resource on the system (or access any interface to import 
power from a neighboring system), consistent with the Network Resource 
Interconnection Service discussed in the Generator Interconnection 
proposed rule.\86\ Network Access Service allows a customer to have the 
Independent Transmission Provider integrate, dispatch and regulate the 
customer's current and planned resources to serve its load as is 
currently done under the pro forma tariff. Customers, including 
generators and marketers, can also use this service for through-and-out 
service, to aggregate resources for resale, and to perform hub-to-hub 
transactions similar to Point-to-Point Transmission Service. In 
addition, Network Access Service allows the customer (1) to trade 
(reassign) its Congestion Revenue Rights and (2) to access points, 
which, under the current pro forma tariff, are secondary points that 
may be fully subscribed, by paying all applicable congestion charges.
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    \86\ Standardization of Generator Interconnection Agreements and 
Procedures, FERC Stats. & Regs. [para] 32,560. Network Resource 
Interconnection Service requires that sufficient network upgrades be 
built so that interconnecting generators can serve load as a Network 
Resource, as defined by the existing pro forma tariff.
---------------------------------------------------------------------------

    140. Network Access Service is premised on dispatching of the 
regional transmission grid so that the customers that value 
transmission service the most will get it. All requested transactions 
must be physically feasible under a security-constrained dispatch. 
Where there are transmission constraints, the LMP system we propose 
will price out all transactions and redispatch available generation as 
needed to accommodate all requests for service.\87\
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    \87\ In all but limited cases, this should allow the Independent 
Transmission Provider to satisfy all requests for service by 
customers willing to pay the applicable congestion charges.
---------------------------------------------------------------------------

    141. Network Access Service gives the customer the right to 
transmit power between any number of combinations of receipt and 
delivery points. A receipt point is defined here as the location where 
a transaction originates, and a delivery point is defined as the 
location where a transaction terminates. Receipt and delivery points 
include both individual nodes as well as aggregated points, e.g., 
trading hubs. Thus, a Network Access Service customer could use this 
service to move power from a generator (receipt point) to a load 
(delivery point), from a generator (receipt point) to a trading hub 
(delivery point), from one trading hub to another, or from a trading 
hub (receipt point) to a load (delivery point). A Network Access 
Service customer would have access to all receipt and delivery points 
on the system and would be able to substitute receipt points on a daily 
or hourly basis through the day-ahead and real-time scheduling 
processes.
    142. Any customer using transmission service, whether a load-
serving entity, generator, or marketer, would take Network Access 
Service. However, as explained more fully in Section IV.D.1, only those 
customers taking power off of the grid would pay the access charge. 
(All customers would pay congestion costs and losses associated with 
their particular transaction.) We expect that, in most instances, it 
would be a load-serving entity, rather than a generator or marketer, 
that would be the customer for transactions that result in power 
leaving the grid, and thus, the load-serving entity would be the entity 
paying the access charge.\88\
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    \88\ An end-use customer in a state with retail access could be 
the entity taking transmission service and paying the access charge.
---------------------------------------------------------------------------

2. Access to Transmission Service
    143. Under the existing pro forma tariff, ``firm'' transmission 
service implies certainty both with respect to delivery and price. Once 
a customer taking firm service under the existing pro forma tariff 
agrees to pay the transmission rate and schedules service, it has full 
assurance that it will be able to transmit power between its chosen 
receipt and delivery points without service interruption (absent force 
majeure or curtailment) and without being subject to any additional 
costs (e.g., redispatch). However, there are times when a transmission 
provider cannot offer a guarantee of service availability (absent the 
long-term solution of a customer agreeing to pay for system expansion). 
At these times, under the existing pro forma tariff, only non-firm 
transmission service (which can be interrupted for economic 
reasons)\89\ is available at the stated maximum rate. Thus, the 
existing pro forma transmission service begins with the basic premise 
of price certainty, but includes a measure of uncertainty

[[Page 55473]]

regarding service availability that is resolved only if firm service 
can be secured. In sum, the customer is generally assured of the rate 
it will pay for transmission service, but, unless it has secured firm 
transmission service between the specified points, is not necessarily 
assured that it will receive transmission service.
---------------------------------------------------------------------------

    \89\ All services, including firm service, can be curtailed for 
reliability reasons.
---------------------------------------------------------------------------

    144. With Network Access Service, all customers who want physically 
feasible service will be able to receive service; however, uncertainty 
can arise as to the rate paid to receive the service. In addition to 
the access charge (which recovers the embedded costs of the 
transmission system), the customer would be subject to the cost of 
congestion between its chosen receipt and delivery points. To achieve 
certainty with respect to price and avoid congestion costs, the 
customer would have to acquire the Congestion Revenue Rights associated 
with its specific receipt point-delivery point combination(s).\90\ 
Thus, Network Access Service, coupled with Congestion Revenue Rights 
for the desired points, provides the customer with certainty with 
respect to delivery and price, comparable to the existing pro forma 
tariff's firm service.
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    \90\ Congestion Revenue Rights provide the rights holder with 
the revenues associated with congestion between the associated 
points; thus, any congestion costs it pays are fully offset by these 
revenues. To the extent the Congestion Revenue Rights holder opts 
not to schedule transmission service at those points, it would still 
receive the congestion revenues.
---------------------------------------------------------------------------

    145. Accordingly, customers desiring service comparable to (but 
actually more dependable than) existing firm transmission service would 
need to acquire Congestion Revenue Rights for their receipt and 
delivery points and schedule service between those points in the day-
ahead market. With the allocation process we propose in Section IV.H.2, 
customers under existing contracts will receive Congestion Revenue 
Rights that match their current use of the system, which will ease and 
simplify the conversion process. Customers using non-firm transmission 
service under the existing pro forma tariff could request service when 
needed in the day-ahead or real-time markets. To the extent the 
customer is willing to pay congestion costs and transmission losses, 
its requested transmission service would be available and provided.\91\ 
A customer also has the option of placing a limit on the amount of 
congestion charges it is willing to pay--to the extent that amount is 
exceeded, the customer would not take transmission service for that 
receipt point-delivery point combination during the requested time 
period. This means no separate non-firm transmission service option is 
needed under Network Access Service.
---------------------------------------------------------------------------

    \91\ As discussed in Section IV.D.3, customers exporting power 
from or transmitting through one region would not be subject to that 
region's access charge, but would be liable for the cost of 
congestion and transmission losses associated with its transaction.
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3. Service Limitations in the Existing Pro Forma Tariff
    146. The existing pro forma tariff limits how the Network 
Integration Transmission Service and Point-to-Point Transmission 
Service can be used. It limits the use of interface capability by 
Network Integration Transmission Service customers to the amount of the 
customer's load. Under the LMP system that we are proposing, 
transmission service would be available to any customer up to the full 
amount of the transfer capability, so long as the customer is willing 
to pay the applicable congestion charges. The specifics of scheduling 
power across interfaces is discussed in a later section.
    147. The existing pro forma tariff also requires the network 
customer to take Point-to-Point Transmission Service for any additional 
third-party sales transaction or to serve load on another transmission 
provider's system. This will no longer be necessary with Network Access 
Service, which will be used for all transmission services, including 
third-party sales transactions and transmission service for load on 
another transmission provider's system. A customer, however, may prefer 
to have separate service agreements for service to particular loads for 
accounting or tracking purposes.
4. Conditions for Receiving Service
    148. To receive Network Access Service, a customer must meet the 
same requirements as those under the existing pro forma tariff for 
acquiring the right to schedule transmission service: all customers 
must meet creditworthiness and other eligibility standards, complete an 
application for service, and meet certain operating standards (e.g., 
reliability maintenance of customer-owned facilities for integration 
with the transmission provider's system, including metering and 
communications equipment) as defined in the current pro forma tariff. 
Similarly, the customer must have a service agreement to take service 
under the tariff. A load-serving entity would also need a network 
operating agreement, which would detail how the Independent 
Transmission Provider's system under the SMD Tariff and the load-
serving entity's system would work together (similar to a generator 
interconnection agreement).\92\ These standards are largely unchanged 
from the existing pro forma tariff. In addition, the customer must 
agree to pay any congestion charges and transmission losses associated 
with its request \93\ and any customer serving load located within the 
Independent Transmission Provider's system must agree to pay the 
applicable access charge.
---------------------------------------------------------------------------

    \92\ Consistent with the existing pro forma tariff, a Network 
Access Service customer would retain the right to request that the 
Independent Transmission Provider file an unexecuted transmission 
agreement or network operating agreement if the two parties cannot 
agree on the terms and conditions of service.
    \93\ As noted earlier and more fully explained in Section 
IV.E.3., a customer can protect itself against the costs of 
congestion by acquiring Congestion Revenue Rights in the amount of 
its load and between the receipt/delivery points where its desired 
resources and loads are located.
---------------------------------------------------------------------------

5. Scheduling Transmission Service and Acquiring Congestion Revenue 
Rights
    149. As noted above, a customer would acquire Congestion Revenue 
Rights to assure price and delivery certainty for its transactions. 
Anyone can hold Congestion Revenue Rights. Congestion Revenue Rights 
can be acquired through a variety of means, including: (1) Direct 
allocation that is based on some measure of current or historical 
rights to the system; (2) periodic auctions; or (3) some combination of 
these methods. The initial process for acquiring these rights is 
discussed in Section IV.H.2.
    150. Transmission service will be scheduled through the day-ahead 
market with deviations accounted for in the real-time market, as 
discussed in later sections. These scheduling opportunities are 
comparable to the existing pro forma tariff's requirements (e.g., firm 
point-to-point transmission service scheduled by no later than 10 a.m. 
the day before, with schedules submitted after that time accommodated, 
if practicable, and allowance to make changes to that ``day-ahead'' 
schedule prior to the start of the next clock hour). However, the new 
service synchronizes the scheduling of transmission service and energy, 
and relies on a transmission customer holding Congestion Revenue Rights 
or its willingness to pay the cost of congestion, rather than on a 
firm/non-firm, first-come, first served method, to ration capacity.
    151. A Network Access Service customer would have to indicate the 
location of its receipt and delivery points when it schedules service 
in the day-ahead or real-time markets.\94\ If a

[[Page 55474]]

customer holds Congestion Revenue Rights between a set of receipt and 
delivery points in the day-ahead market, but later decides to take 
transmission service between a different set of points, the customer 
would no longer have full protection against congestion costs for its 
transaction in the day-ahead market and could incur different 
congestion costs than the congestion revenues associated with the 
Congestion Revenue Rights it holds. Similarly, to the extent that a 
customer's real-time transactions differ from its day-ahead schedule, 
the customer would be liable for any redispatch costs that occur in 
real time that are necessary to accommodate its real-time transactions.
---------------------------------------------------------------------------

    \94\ Further, consistent with the existing pro forma tariff and 
the Commission's decision regarding ``tagging,'' the customer must 
identify the ultimate source and sink so that the various system 
operators in an interconnection can assess the simultaneous 
feasibility of all scheduled power flows. See Coalition Against 
Private Tariffs, 83 FERC [para] 61,015 at 61,040, reh'g denied, 84 
FERC [para] 61,050 (1998).
---------------------------------------------------------------------------

6. Designating Resources and Loads
    152. The existing pro forma tariff allows a Network Integration 
Transmission Service customer to designate resources that the customer 
owns or has committed to purchase pursuant to an executed, non-
interruptible contract. The transmission provider must then plan and 
operate its system to be able to provide firm transmission service from 
these resources to the customer's load. Under the proposed Standard 
Market Design, the reservation of capacity for service is no longer 
required, since a transmission customer pays the congestion cost for 
transmission service. Thus, there is no longer a need for a Network 
Access Service customer to designate network resources to get 
transmission service. While the integration of resources and loads 
(including behind-the-meter generation) that occurs under Network 
Integration Transmission Service will continue, a Network Access 
Service customer will now request receipt and delivery points through 
the day-ahead scheduling process and real-time transactions.
    153. Thus, we believe that the requirement to designate network 
resources to receive transmission service may no longer be needed. 
Further, we note that under the existing pro forma tariff the 
designation of network resources was used in addressing long-term 
resource adequacy concerns and in the planning process undertaken to 
ensure that the resources could be integrated. Because we are now 
proposing a resource adequacy requirement and a regional planning 
process to meet these requirements, the requirement to designate 
network resources may no longer be needed. (See Section IV.J). We 
request comment on whether designating network resources and loads is 
necessary for Network Access Service, particularly with respect to 
performing the integration of resources and loads.\95\ Similarly, with 
respect to the information required to complete an application for 
service (Section 2 of the SMD Tariff), is it necessary for the 
Independent Transmission Provider to request information beyond the 
identity of and contact information for the customer, service term and 
commencement date, and receipt and delivery points for the requested 
service? Does the Independent Transmission Provider need to collect for 
each service request (but not for each transaction) the location and 
characteristics of the generation serving the load, detailed 
descriptions of the load and the customer's transmission system and 
owned generation?\96\ In sum, do we need separate procedures for 
service to customers such as marketers, who do not serve load or own 
generation, or transmission systems and load-serving entities that have 
all these things? Does the integration aspect of Network Access Service 
require different information to be provided to the Independent 
Transmission Provider in order to initiate service? Should this 
information be provided through other means, and what would that be?
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    \95\ The relevant sections of the SMD Tariff are Sections B.3 
and B.4. While we believe that they may no longer be necessary, they 
remain in the tariff for ease of reference during the proposed 
rulemaking process. In the Final Rule, the Commission will determine 
if these or similar provisions need to be included in the SMD 
Tariff.
    \96\ See Sections B.2.2.1(iv) and (v), and Sections B.2.2.2(iii) 
through (vi) of the SMD Tariff.
---------------------------------------------------------------------------

7. Substituting Receipt and Delivery Points
    154. Under the existing pro forma tariff, choosing alternate 
resources to meet load required, in effect, placing a request in the 
queue for new service. If firm capacity were available, the customer 
would be permitted to use alternate points of receipt (or delivery) on 
a firm basis. If firm capacity were not available, the customer could 
choose the point(s) on a secondary, or non-firm, basis.
    155. With Network Access Service, this process is no longer 
necessary. A Network Access Service customer can essentially access any 
point simply by requesting it through the day-ahead scheduling process 
or real-time transactions (and be willing to pay congestion costs and 
losses). To the extent the customer wanted to avoid the cost of 
congestion for the transaction, it could retain its existing Congestion 
Revenue Rights and acquire additional Congestion Revenue Rights for its 
new receipt and delivery points through an auction or secondary market.
    156. Alternatively, the customer could request a 
``reconfiguration'' of the Congestion Revenue Rights it holds, i.e., 
the customer could turn in the Congestion Revenue Rights for the old 
receipt and/or delivery point and request Congestion Revenue Rights 
from the new receipt point or to the new delivery point. We seek 
comment on the MW quantity of reconfigured Congestion Revenue Rights 
that the customer should be entitled to receive. There are at least 
three options. One option is to allocate to the customer the MW 
quantity that is available specifically as a result of turning in the 
old Congestion Revenue Rights. Under this option, the customer would 
receive rights that become available by turning in the old Congestion 
Revenue Rights. In such a case, the MW quantity of new Congestion 
Revenue Rights might be different (either larger or smaller) than the 
MW quantity of the old Congestion Revenue Rights.\97\ A second option 
is to allocate any MW quantity of new Congestion Revenue Rights that 
are physically feasible (i.e., it does not adversely affect the 
Congestion Revenue Rights held by any other customer), including 
Congestion Revenue Rights that were available before turning in the old 
Congestion Revenue Rights. The MW quantity of new Congestion Revenue 
Rights under this option could also be different (either larger or 
smaller) than the MW quantity of older Congestion Revenue Rights. A 
third option is to allocate a MW quantity of new Congestion Revenue 
Rights that is either equal to the MW quantity of the old Congestion 
Revenue Rights, or, if that is not physically feasible, the

[[Page 55475]]

largest MW quantity that is physically feasible. Under this third 
option, the MW quantity of new Congestion Revenue Rights could never 
exceed the MW quantity of the old Congestion Revenue Rights. The 
process for acquiring and reconfiguring Congestion Revenue Rights is 
further described in Section IV.E.3.
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    \97\ For example, a customer holding a 10 MW Congestion Revenue 
Right from A to B may want to exchange its existing rights for 
Congestion Revenue Rights from C to D. Suppose that both the A-to-B 
and C-to-D Congestion Revenue Rights relied on a common congested 
flowgate, so that the amount of A-to-B Congestion Revenue Rights and 
C-to-D Congestion Revenue Rights is limited by the capacity of the 
flowgate. However, suppose that the A-to-B Congestion Revenue Right 
relies more heavily on the congested flowgate than the C-to-D 
Congestion Revenue Right. That is, the proportion of the power flow 
(known as the ``power flow distribution factor'') over the flowgate 
in transmission service from A to B is greater than the proportion 
in transmission service from C to D. Thus, giving up 10 MW of A-to-B 
Congestion Revenue Rights may create the ability to award more than 
10 MW of Congestion Revenue Rights (e.g., 15 MW) from C to D. 
Conversely, a customer with 15 MW of C-to-D Congestion Revenue 
Rights could exchange them for only 10 MW of A-to-B Congestion 
Revenue Rights.
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8. System Impact and Facilities Studies
    157. Most service requests will be resolved through the day-ahead 
security-constrained dispatch. Nevertheless, the Independent 
Transmission Provider will need to conduct system impact and/or 
facilities studies for service involving the interconnection of a new 
load or generator. The Independent Transmission Provider will also 
routinely perform simultaneous feasibility studies to determine the 
configurations of Congestion Revenue Rights that can be accommodated. 
Thus, except for adding references to the simultaneous feasibility 
studies that will be performed in response to requests for Congestion 
Revenue Rights, sections of the existing pro forma tariff addressing 
various studies will remain largely unchanged. However, as discussed in 
Section IV.C.8, these studies are now required to be performed by an 
Independent Transmission Provider.
9. Load Shedding and Curtailments
    158. Under the existing pro forma tariff, load shedding and 
curtailment procedures were developed for inclusion in individual 
network operating agreements. These procedures should be uniform and, 
therefore, will be included in the SMD Tariff. In addition, we expect 
that the majority of constraints will be resolved through the LMP-based 
congestion management system, with only localized emergency/reliability 
contingencies (transmission line outage into a load pocket) needing to 
be addressed through load shedding or curtailment procedures.
    159. This is a major improvement over the current tariff, as it 
should eliminate most or all TLRs. To the extent practicable, when 
system conditions require curtailment (in real time) that cannot be 
resolved through the congestion management system, the Independent 
Transmission Provider should curtail the customers whose transactions 
contribute to the constraint on a pro rata basis.\98\ In addition, we 
propose that to the extent the Independent Transmission Provider is 
unable to schedule all requests for service made through the day-ahead 
scheduling process, those customers with Congestion Revenue Rights for 
their requested receipt point-delivery point combinations should be 
scheduled first. We seek comment as to whether this scheduling priority 
is appropriate. While it would grant Congestion Revenue Rights holders 
an additional measure of certainty of delivery, would this undermine 
the benefits of having a single transmission service for all customers?
---------------------------------------------------------------------------

    \98\ Because we are now proposing to exercise our jurisdiction 
over the transmission component of bundled retail transactions and 
to provide a single set of rules and regulations that apply to all 
transmission service, the limitation imposed by the United States 
Court of Appeals for the Eighth Circuit on the Commission's 
curtailment authority over bundled retail customers is no longer 
relevant. See Northern States Power Company (Minnesota) and Northern 
States Power Company (Wisconsin), 83 FERC [para] 61,098, order on 
clarification, 83 FERC [para] 61,338, reh'g denied, 84 FERC [para] 
61,128 (1998), Northern States Power Co., et al. v. FERC, 176 F.3d 
1090 (8th Cir. 1999), cert. denied, 528 U.S. 1182 (2000), order on 
remand, 89 FERC [para] 61,178 (1999).
---------------------------------------------------------------------------

    160. We propose that an Independent Transmission Provider can 
assess a penalty for failure to curtail if a transmission customer 
fails to curtail after reasonable notice. The proposed penalty is the 
locational marginal price plus $1000 per MWh. The Commission has 
approved a minimum notice period of ten minutes if the curtailment is 
for reliability purposes.\99\ We request comment on whether the 
Commission should continue this practice.
---------------------------------------------------------------------------

    \99\ See Allegheny Power System, Inc., 80 FERC [para] 61,143 at 
61,546 (1997), order on reh'g, 85 FERC [para] 61,235 (1998).
---------------------------------------------------------------------------

    161. We also note that the Commission required transmission 
providers to incorporate procedures for addressing curtailment of 
parallel flows involving more than one transmission system (i.e., the 
Transmission Loading Relief Procedure developed by NERC) as a single 
generic amendment to the pro forma tariff.\100\ Under Network Access 
Service, procedures for addressing non-discriminatory curtailment of 
parallel flows will continue to be needed under emergency conditions 
when the use of a regional congestion management procedure set out in 
this proposed rule does not completely relieve a constraint.\101\ 
Language has been added to Section 9.3, Curtailments of Scheduled 
Deliveries, to reflect this change.
---------------------------------------------------------------------------

    \100\ See North American Electric Reliability Council, 87 FERC 
[para] 61,160 (1999).
    \101\ Such procedures may need to be refined in light of 
Standard Market Design.
---------------------------------------------------------------------------

10. Trading (Reassigning) Congestion Revenue Rights
    162. Network Access Service adds the tradability that currently 
exists for ``firm'' Point-to-Point Transmission Service, but was not 
available under Network Integration Transmission Service. Customers may 
be able to acquire Congestion Revenue Rights from a particular receipt 
point to a particular delivery point directly from the Independent 
Transmission Provider, through a formal auction, or through secondary 
markets. Once a customer has these point-specific Congestion Revenue 
Rights, the customer may sell them at any time to another entity, 
whether or not that entity intends to transmit power. The sale could be 
for all or a portion of the amount or duration of the Congestion 
Revenue Rights. All resales of Congestion Revenue Rights must be 
reported on and conducted through the OASIS. As is currently the case 
in some ISOs, Congestion Revenue Rights will be traded at the price at 
which purchasers value the rights. The procedures for the auctions and 
resale of Congestion Revenue Rights are discussed in Section IV.E.3.
    163. We seek comment as to whether all Congestion Revenue Rights 
must be sold through the OASIS, or whether some bilateral sales may be 
made and only reported through OASIS after the sale.
11. Ancillary Services
    164. The ancillary services provided as part of the current pro 
forma tariff will largely remain the same under Network Access Service. 
However, certain ancillary services will be provided through organized 
markets with appropriate market power mitigation, as discussed infra. 
The ancillary services markets are discussed in Sections IV.F.1.d and 
IV.F.3.b.

D. Transmission Pricing

    165. The Commission seeks to ensure transmission owners the 
opportunity to recover their revenue requirements for their 
transmission systems under Network Access Service. This charge could 
either be a license plate rate (charge depends on zone of delivery) or 
a postage stamp rate (same rate applies for all load within the 
Independent Transmission Provider's service area) and would be paid by 
all entities serving load within the Independent Transmission 
Provider's service area. Moreover, to facilitate trading across 
regions, we are proposing to change our policy on pricing of 
transactions that start and end in different transmission systems.
    166. In addition, we are proposing to refine our policy on pricing 
of transmission expansions to provide incentives for market-driven 
solutions. To facilitate the addition of much needed transmission 
infrastructure, we

[[Page 55476]]

propose a regional approach to transmission expansion which includes 
extensive participation by Regional State Advisory Committees \102\ to 
identify the beneficiaries of a proposed expansion and how costs for 
that expansion should be recovered.
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    \102\ Regional State Advisory Committee as discussed more fully 
in Section IV.K.
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1. Recovery of Embedded Costs
    167. Under the existing pro forma tariff, there are two types of 
transmission services--Network Integration Transmission Service, which 
is designed for the integration of resources and loads, and Point-to-
Point Transmission Service, which is generally used to export power 
from one transmission system to another (through-and-out service).
    168. To recover the embedded costs of the transmission grid, the 
Commission has historically permitted transmission providers to assess 
an access charge, in the form of a load ratio share charge or a per kW 
per month charge, on all transactions taking place on the transmission 
provider's system.\103\ For a single transmission utility, these 
charges usually take the form of a ``postage stamp'' rate (i.e., the 
same charge for all customers'' use of the utility's grid) and, for an 
ISO or RTO, a ``license plate'' rate (i.e., a different charge for the 
use of the entire regional transmission system that is based on the 
revenue requirement of the transmission owner's facilities, or 
``zone,'' where the transaction sinks).\104\ The access charge is 
assessed on all transactions making use of the transmission provider's 
system, including transactions where the generator and load are located 
within the transmission provider's system and where either the 
generator or the load (or both) are located outside of the transmission 
provider's system.
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    \103\ A Network Integration Transmission Service customer pays a 
monthly demand charge based on its load ratio share of the 
transmission provider's monthly transmission revenue requirement. 
The customer's load ratio share is based on the customer's hourly 
load coincident with the transmission provider's monthly 
transmission system peak. The firm Point-to-Point transmission 
customer pays a monthly demand charge for each unit of capacity that 
it has reserved.
    \104\ Both PJM and New York ISO use a license plate rate design. 
PJM and New York ISO have different rate designs for exports and 
wheel-through services. PJM uses a weighted average of the charges 
of all transmission for these types of transactions. New York ISO 
uses the transmission charge of the owner of the intertie that 
serves as the point of delivery to the adjacent system.
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    169. While this method of pricing has been effective in recovering 
a transmission provider's revenue requirement, some changes are 
required to reflect the new Network Access Service and to address 
unintended consequences of the current rate design. First, we propose 
that transmission owners recover embedded costs through an access 
charge assessed mainly to load-serving entities, based on their 
respective shares of the system's peak load, i.e., their load ratio 
shares. Our goal is to minimize the distorting effects that an access 
charge can have on economic choices. We propose to assess access 
charges primarily on loads, but not on generators, because the economic 
choices of loads (such as where to locate) are less likely to be 
affected by access charges than are the choices of generators.\105\ 
Moreover, even if access charges were imposed on generators or other 
market participants, it is likely that they would pass along most or 
all of their access charges to their customers, so that loads would 
ultimately bear most or all of the transmission fixed costs.
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    \105\ Point-to-Point customers wanting to receive a direct 
allocation of Congestion Revenue Rights would also pay the access 
charge, as discussed below.
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    170. Second, we propose to eliminate all ``rate pancaking,'' which 
involves charging separate embedded cost charges for moving power over 
separate Independent Transmission Provider service areas. We propose to 
eliminate rate pancaking both within an Independent Transmission 
Provider's service area and between service areas. Rate pancaking 
impedes the ability of distant generators to compete with nearby 
generators by imposing charges to transmit energy from distant 
generators that are unrelated to actual variable transmission costs. 
Assessing the access charge primarily to load-serving entities based on 
their load ratio share rather than on the number of service areas over 
which energy is transmitted increases generation competition by 
allowing distant generators to compete more easily with nearby 
generators.
    171. As discussed further below, we propose that customers paying 
access charges would receive Congestion Revenue Rights (or 
alternatively, revenues from the auction of Congestion Revenue Rights). 
Thus, in exchange for paying the fixed costs of the transmission 
system, those paying access charges would receive the financial 
benefits--the stream of congestion revenues--resulting from usage of 
the transmission system. In addition, we seek to minimize cost shifts 
that could result from our proposal, and we propose to maintain as much 
as possible the explicit and implicit transmission rights currently 
held by customers. Thus, customers currently receiving Network 
Integration Transmission Service and firm Point-to-Point Transmission 
Service under the existing pro forma tariff would receive Congestion 
Revenue Rights based on their existing service levels. However, there 
are two issues regarding access charges and the allocation of 
Congestion Revenue Rights on which we specifically seek comment.
    172. First, we seek comment on the treatment of existing customers 
taking long-term firm Point-to-Point Transmission Service that are not 
load-serving entities. Such customers currently pay an embedded cost 
charge in order to receive firm Point-to-Point Transmission Service 
under the Order No. 888 pro forma tariff. We believe that it would be 
inequitable for customers to receive an initial allocation of 
Congestion Revenue Rights unless they also pay a share of transmission 
embedded costs. We also believe that it would be inequitable for 
customers to pay a share of transmission embedded costs without 
receiving an initial allocation of Congestion Revenue Rights. Thus, we 
seek comment on two options. One option is for these customers to 
continue paying their embedded cost charges in exchange for receiving 
Congestion Revenue Rights that reflect their current levels of Point-
to-Point Transmission Service. This option would help minimize cost 
shifts, while maintaining the transmission rights currently held by 
these customers. On the other hand, this option would recover a portion 
of embedded transmission costs from customers that are not loads. The 
second option is to eliminate the access charges for these customers 
while also allocating no Congestion Revenue Rights to them. This option 
avoids recovering embedded costs from entities that are not loads. 
However, it would result in some shifting of the responsibility for 
recovering embedded costs, and it would fail to maintain the 
transmission rights currently held by these customers. We seek comment 
on the merits of these two options, as well as whether the Final Rule 
should select one option or, alternatively, allow customers to choose 
between them.\106\
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    \106\ We propose that Congestion Revenue Rights be directly 
assigned only to long-term firm customers, consistent with the 
existing pro forma tariff's right of first refusal. Thus, short-term 
and non-firm point-to-point customers would not receive Congestion 
Revenue Rights under direct assignment. These customers, therefore, 
may wish to structure their contracts such that they expire at the 
time Standard Market Design is implemented. This way, while they 
would not receive Congestion Revenue Rights, they also would no 
longer be paying an access charge.

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[[Page 55477]]

    173. The second issue concerns the treatment of load-serving 
entities in retail open access states that attract loads away from 
their traditional utility suppliers. Under our proposal, a new load-
serving entity that attracts load from other suppliers would be 
assigned a share of embedded costs--costs previously assigned to other 
suppliers. In areas where there is no Available Transfer Capability for 
additional Congestion Revenue Rights, we seek comment on how such new 
load-serving entities should receive an allocation of the customer's 
former load-serving entity's Congestion Revenue Rights. We propose that 
Congestion Revenue Rights ``follow the load.'' Thus, Congestion Revenue 
Rights previously allocated to other suppliers whose loads (and access 
charges) have been reduced would be reallocated to the new load-serving 
entities.
    174. We propose to permit the use of license plate rates such as 
those that are currently in effect within ISOs. We seek comment, 
however, on whether we should retain license plate ratemaking only for 
a transitional period and at some later date, require that all regions 
have postage stamp rates. Should the Commission upon the recommendation 
of a Regional State Advisory Committee accept an embedded cost recovery 
mechanism for the region which may vary from neighboring regions?
    175. To better illustrate the pricing proposals we have included 
Appendix F which identifies by customer types whether and under what 
circumstances they will pay the access charge and/or receive Congestion 
Revenue Rights under Network Access Service.
2. Rates for Bundled Retail Customers
    176. When a vertically integrated utility joins a regional 
organization such as an ISO or RTO, the Commission has required that 
the utility execute a service agreement under the regional transmission 
provider's transmission tariff. For instance, the Commission required 
the vertically integrated utilities in GridSouth to execute a service 
agreement under the GridSouth transmission tariff, thus ensuring that 
these utilities would take service for their bundled retail load under 
the same terms and conditions as all other users of the grid.
    177. With respect to whether the GridSouth transmission charge 
should be applied to the bundled retail load, the Commission permitted 
the utilities to pay the transmission portion of the bundled retail 
rate, but required that the service agreement explicitly state the rate 
to be charged.\107\ The Commission added that having vertically 
integrated utilities pay GridSouth for transmission to serve their 
bundled retail customers does not make those utilities' retail rates 
subject to our jurisdiction. Rather, the Commission stated its 
willingness to accommodate the utilities paying GridSouth a 
transmission rate equal to the transmission component of their bundled 
retail rates, as long as the price is clearly stated, reduced to 
writing in contracts with GridSouth, and is not accomplished by 
omission.\108\
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    \107\ Carolina Power & Light Co., et al., 94 FERC [para]61,273 
at 61,999, order on reh'g, 95 FERC [para]61,282 (2001).
    \108\ 95 FERC [para]61,282 at 61,991.
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    178. Now that the Commission is asserting jurisdiction over all 
transmission service in interstate commerce, including that for bundled 
retail service, the question arises as to whether different charges for 
transmission service for wholesale and bundled retail customers should 
be permitted. Allowing different rates for wholesale and bundled retail 
customers could lead to undue discrimination if the rate setting 
policies of the state and the Commission differ significantly. The 
Commission seeks comment on whether all customers should be charged the 
same transmission rate either upon implementation of Standard Market 
Design or after a reasonable transition period of four years.
3. Inter-Regional Transfers
    179. Under current rate designs, a user that transmits power from 
one region to another would pay two transmission charges to recover the 
embedded costs of the transmission provider from which power was 
exported as well as the embedded costs of the transmission provider 
where power is delivered to load. As long as transmission owners have 
an opportunity to recover their embedded costs, to increase 
competition, we propose to prevent customers from being assessed 
multiple transmission charges.
    180. We have concluded that rate treatment for inter- and intra-
regional transactions should be consistent to avoid creating artificial 
incentives or disincentives for trade across regions. Thus, the design 
of rates for Network Access Service should eliminate the payment of 
multiple access charges, such that only one access charge is paid for 
power to reach load. Accordingly, an export and through-and-out 
transaction originating in an Independent Transmission Provider's 
system and terminating at a load in another Independent Transmission 
Provider's system would pay only the access charge for the transmission 
system where power is ultimately delivered to load.\109\ This will 
encourage broader areas of competition by eliminating multiple access 
charges, and in particular would reduce the harsh inequities of 
regional boundary definition on those customers near such boundaries.
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    \109\ However, the transaction would still be responsible for 
applicable congestion charges and transmission losses in the 
originating and any intermediate transmission systems.
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    181. It has become apparent that transmission pricing across RTO 
borders can have a significant impact both on power purchasing 
decisions and on RTO formation. A customer's choice as to whether to 
purchase power from a generator located within the same RTO or a 
neighboring RTO is directly affected by the fact that one generator 
faces an additional access charge to reach the RTO in which the load is 
located. This additional access charge may cause the sale to become 
uneconomic.\110\
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    \101\ E.g., a load and Generator 1 with a cost of $25 are 
located in RTO A, and a competing Generator 2 with a cost of $24 is 
located just across the border in RTO B. On its face (and absent 
congestion), it appears that the load should choose Generator 2 in 
RTO B. However, because Generator 2 faces a $2 transmission charge 
from RTO B, it is unable to compete with Generator 1 even though it 
is a more efficient unit simply because of the additional access 
charge.
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    182. In addition, decisions on which RTO/ISO to join may be 
affected by inter-regional pricing. Choices driven by the economics of 
transmission owner's merchant function's trading patterns, rather than 
by the most rational and efficient aggregation of transmission assets 
for a particular region, could result in oddly configured RTOs.
    183. Rate pancaking across the numerous transmission owning 
utilities that comprise the RTO has been eliminated by the 
implementation of license plate rates, while continuing to provide an 
opportunity for the transmission owners to recover their full revenue 
requirements. We propose that the same or a similar rate structure 
should be applied to inter-regional transfers. In a competitive market 
environment, reliability and the supplier's cost of generation, rather 
than sunk transmission costs, should be the primary drivers for a 
customer's choice of power suppliers. To the extent rate design 
facilitates that result, transmission owners would have a greater 
incentive to join an RTO based on where their transmission facilities 
most benefit customers and markets, not on where their generators have 
better opportunities to make off-system sales

[[Page 55478]]

(i.e., an access charge for exporting power from one region to a 
neighboring region should not be the deciding factor).
    184. However, absent other adjustment mechanisms, if customers 
going through and out of an RTO are no longer charged access fees by 
that RTO for transmission service, these costs would instead be borne 
by the load served by the RTO through the existing load ratio share 
methodology.\111\ Under the commonly used license plate rate design, 
load within a particular RTO zone would pay that transmission owner's 
full embedded costs, including the portion that is currently 
contributed by through-and-out customers. This may create problematic 
cost shifts for certain transmission providers that currently receive a 
significant amount of revenue from exports and wheel-throughs (e.g., 
AEP and Cinergy). While simply eliminating the transmission charge for 
through-and-out service may avoid the skewing of purchase and sale 
decisions by inter-regional transaction charges, it will result in 
cost-shifting and may stifle new transmission investment since state 
regulators will not generally favor having their customers pay for 
facilities that may primarily benefit other states.
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    \111\ This would also be true for a non-RTO Independent 
Transmission Provider.
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    185. Therefore, we propose to create a mechanism that recognizes 
the import/export quantities in establishing the revenue requirement to 
be recovered through the access charge. We seek comment on two 
approaches that could be used.
    186. One method would be to have the ``source'' Independent 
Transmission Provider allocate a portion of its revenue requirement to 
the ``sink'' Independent Transmission Provider's transmission 
customers. An Independent Transmission Provider's revenue requirement 
could be reduced by the amount of revenues associated with through-and-
out service and that portion of the revenue requirement would then be 
included as uplift in the scheduling charge paid by all customers of 
the sink Independent Transmission Provider in whose service area the 
power sinks. Under this approach, costs would not be shifted from the 
beneficiaries of the inter-regional transaction to the load on the 
source side of the transaction. At the same time, embedded cost 
recovery would not interfere with short-run efficiency, since embedded 
costs would not be recovered in individual inter-regional transactions, 
but would instead be recovered through uplift from all customers in the 
zone of the sink Independent Transmission Provider. This method would 
require a projection of inter-regional transfers and a rate filing to 
accomplish the re-allocation of costs between Independent Transmission 
Providers. It would also require a decision as to how narrowly to focus 
the cost allocation (e.g., RTO to RTO, export zone to import zone).
    187. Alternatively, under a revenue crediting approach, inter-
regional transfers could be priced at the load ratio share charge (or a 
similar transmission charge)\112\ and the inter-regional transaction 
charges would be netted out over some time period (e.g., one month or 
one year). This method would assign the inter-regional charges to all 
customers within the sink Independent Transmission Provider. The cost 
of transmission on a neighboring Independent Transmission Provider 
associated with net imported power could be charged to all of the net 
importing Independent Transmission Provider's customers through the 
Independent Transmission Provider's scheduling charge. The revenues 
would be returned to all transmission customers within the net 
exporting Independent Transmission Provider.
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    \112\ An explanation of how this charge may be calculated is 
contained in Appendix F.
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    188. We seek comment on whether there should be a uniform cost 
allocation of inter-regional costs among all zones within an 
Independent Transmission Provider's system. For instance, there will 
likely be opposition to a region-wide charge by customers who do not 
import power. To address this concern, the inter-regional transfers 
could instead be netted out between zones within neighboring 
Independent Transmission Providers. This way the costs would be 
assigned to all customers within the import zone and the revenues would 
be returned to the export zone. These transmission costs could be 
assigned to the zone where the power was imported as if the neighboring 
Independent Transmission Provider's facilities were part of that zone. 
Likewise, the zone where exports leave an Independent Transmission 
Provider would receive the transmission payments associated with the 
exports. It is possible that the revenue sharing plan used by ISOs with 
license plate rates to resolve intra-ISO, interzone transactions could 
be broadened to encompass inter-RTO transactions.
    189. As noted above, the proposed rule advocates treating inter- 
and intra-regional transmission pricing the same. As explained 
elsewhere, customers within the region who pay the access charge will 
be entitled to Congestion Revenue Rights or the revenues from the 
auction of those rights. We propose a similar result for inter-regional 
transactions when customers in one region are paying a portion of the 
embedded costs of another region. We seek comment on how to assign 
Congestion Revenue Rights to the customers of the importing region. For 
example, if Midwest ISO is a net exporter to PJM, customers on PJM's 
system will be obligated to pay a portion of Midwest ISO's embedded 
costs. PJM's customers could receive a proportionate share of Midwest 
ISO's Congestion Revenue Rights.
4. Application of Inter-Regional Pricing to Parallel Path Flows
    190. To the extent the Commission adopts a true-up methodology for 
recovering the costs of through-and-out services, should a similar 
pricing methodology be applied to parallel path flows? Parallel path 
flows are comparable in that one region benefits by the use of a 
neighboring region's transmission facilities. Parallel path flows are 
currently resolved through cooperation. An alternative method would be 
to price all uses of the grid. We seek comment as to how cost impacts 
of parallel path flows across regional borders should be addressed.
5. Pricing of New Transmission Capacity
    191. The existing transmission grid has fallen far behind the 
demands that have been placed on it. Over the last ten years, we have 
seen a strong increase in the amount of new generation, which has been 
built largely in locations that make the most economic sense for the 
builder of the generation (i.e., where land is affordable and economic 
sources of fuel, water and labor are near). However, we have yet to see 
a parallel jump in construction of transmission infrastructure. The 
absence of needed new transmission facilities has led to more and more 
congestion, which hinders customers from seeking and depending on more 
distant and competitive supply choices.
    192. The sluggishness of transmission construction is largely 
because: (1) Siting transmission is a long and contentious process; and 
(2) mismatches between those who benefit from the new facilities and 
those who pay for them, particularly when the two affected sets of 
customers are served by different transmission providers, are often 
more than enough to make sure the new facilities do not get built. The 
Department of Energy's 2002 National Transmission Study points to 
state-by-state siting approval, a lack of regional

[[Page 55479]]

institutions and a lack of clarity in regulatory pricing policy as 
several of the barriers to transmission investment.\113\
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    \113\ See DOE National Transmission Grid Study.
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    193. The Commission's pricing policy for network upgrades, whether 
for reliability or economic reasons, has traditionally favored ``rolled 
in'' pricing, where all users pay an administratively determined share 
of new facilities. This policy was based on the rationale that the 
transmission grid is a single piece of equipment such that system 
expansions are used by and benefit all users due to the integrated 
nature of the grid. This method forms the basis of the pricing proposal 
in the Generation Interconnection proposed rule.
    194. If the expansion is for region-wide reliability, there is 
little disagreement as to who should pay for the necessary facilities--
all ratepayers. Likewise, interconnection facilities are non-
controversial; there is general agreement that these facilities should 
be directly assigned to the interconnecting generator.
    195. What we see, however, is that economic expansions that would 
remove congestion and allow customers to reach more distant power 
supplies are the most difficult to get sited. This is at least in part 
because state siting authorities have no interest in siting a line that 
benefits a particular generator or a distant load in another state 
because to do so would require the load on the constructing public 
utility's system to pay for the new facilities. The state authorities, 
at a minimum, need assurance that the costs of that expansion will be 
paid for by those who benefit from the expansion in order to have 
sufficient incentive to site the new facilities.
    196. Our goal is to remove any cost recovery impediments to 
transmission expansion so that needed upgrades get built now. 
Traditional means of expansion pricing may not be the most effective 
way of encouraging new transmission infrastructure, in part perhaps 
because they do not take into account the wide regional benefits of 
higher voltage upgrades that can accrue beyond a single transmission 
owner's system.
    197. We believe that a more precise matching of beneficiaries and 
cost recovery responsibility would encourage greater regional 
cooperation to get needed facilities sited and built. Our preference is 
to allow recovery of the costs of expansion through participant 
funding, i.e., those who benefit from a particular project (such as a 
generator building to export power or load building to reduce 
congestion) pay for it.
    198. The Generator Interconnection proposed rule introduced the 
idea that participant funding may be an acceptable pricing policy where 
an independent entity determines: (1) The cost of and responsibility 
for needed upgrades; (2) congestion price signals to which the customer 
responds (along with Congestion Revenue Rights); and (3) the 
assumptions underlying the power flow analysis.\114\
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    \114\ The Commission is currently reviewing extensive comments 
on this topic in that proceeding.
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    199. The Commission envisions that, under Standard Market Design, 
the Independent Transmission Provider will perform all of these 
functions, which will allow the Commission to consider the use of 
participant funding. However, full compliance with Standard Market 
Design will take some time. We are eager to see new infrastructure in 
place as soon as possible and believe that participant funding will be 
a useful tool to make that happen. Accordingly, we propose that, for 
proposed transmission facilities that are included in a regional 
planning process which is conducted by an entity, whether an RTO, ISO, 
or other independent entity, that is independent, we will consider 
participant funding for that project.
    200. In the absence of independence, we would apply a default 
pricing policy that would recognize the regional benefits of 
transmission expansions. Under this default policy, we propose to roll-
in on a region-wide basis all high voltage network upgrades of 138 kV 
and above. Since lower voltage, sub-regional transmission needs are 
less likely to benefit the whole region, the cost of network facilities 
below 138 kV could be more appropriately allocated to a sub-region 
(e.g., a single transmission owner or a ``license plate'' zone) where 
the expansion facilities will be located. Consistent with our proposal 
for interregional transmission service pricing, costs would be 
allocated to the region that benefits from the expansion, which may not 
be the same as the region in which the expansion facilities are 
located. This proposal recognizes that high voltage expansions can have 
benefits beyond the borders of the local transmitting utility and, 
therefore, assigns a portion of these costs to more distant 
beneficiaries.
    201. Further, as we explain in Section IV.G.3, Regional Planning 
Process, we encourage the formation of Regional State Advisory 
Committees, which, in addition to facilitating the siting of regional 
expansions, can enable states to work together to identify 
beneficiaries of expansion projects and make recommendations on pricing 
proposals. To the extent there is agreement within the Regional State 
Advisory Committee, the Commission would look favorably on a pricing 
proposal by the Regional State Advisory Committee if it is consistent 
with the FPA. Such a proposal might take the form of roll-in, an 
assignment to beneficiaries, or some combination of the two.
    202. We seek comment whether these pricing proposals are 
appropriate to meet our goal of expediting needed infrastructure 
investment or whether another method would be more effective.

E. The New Congestion Management System

    203. Under Network Access Service, all transmission customers may 
request transmission service. The Independent Transmission Provider 
must honor all valid transmission requests where there is sufficient 
capability, i.e., when there is no transmission congestion. However, 
when there is transmission congestion we propose to require that all 
Independent Transmission Providers allocate scarce transmission 
capability using a price system. Specifically, we propose to require 
that all Independent Transmission Providers manage congestion using a 
system of LMP and Congestion Revenue Rights. Under LMP, the price to 
transmit energy between any receipt point and delivery point reflects 
the marginal cost (including the marginal opportunity cost) of such 
transmission service, and the price of energy at each location reflects 
the marginal cost (as reflected in participants' bids) of producing 
energy and delivering it to that location.
1. Locational Marginal Pricing
    204. LMP is the method that is currently used for managing 
congestion in the regional markets run by both PJM and New York ISO. It 
is also proposed to be adopted as the congestion management system for 
ISO-New England in 2003 and for the California ISO in its proposed 
market redesign.\115\ Marginal pricing, a fundamental concept in 
economics, is the basis for LMP.\116\ Marginal pricing is the idea

[[Page 55480]]

that the market price should be the cost of bringing the last unit to 
market (the one that balances supply and demand). LMP in electricity 
recognizes that the marginal price may differ at different locations 
and times. Differences result from transmission congestion which limits 
the transfer of electricity between the different locations.\117\ The 
marginal price of energy at a particular location and time--that is, 
the energy LMP--is the additional cost of procuring the last unit of 
energy supply that buyers and sellers at that location willingly agree 
on to meet the demand for energy. That is, it is the price that 
``clears the market'' for energy.\118\
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    \115\ See California ISO's Comprehensive Market Design Proposal, 
Docket No. ER02-1656-000 (May 1, 2002); see also California 
Independent System Operator Corp., 100 FERC [para] 61,060 (2002).
    \116\ It is a widely accepted principle of economics that 
markets work efficiently when prices reflect marginal costs. See 
Alfred E. Kahn, The Economics of Regulation: Principles and 
Institutions, The MIT Press, Cambridge, Massachusetts, reprinted 
1988, pp. 63-70. The economic rationale for applying marginal cost 
pricing to an electricity network using the concepts of LMP was 
presented in Schweppe, F.C., et al., Spot Pricing of Electricity, 
1988, Norwell, MA, Kluwer Academic Publishers; and Hogan, William 
W., ``Contract Networks for Electric Power Transmission,'' Journal 
of Regulatory Economics, 1992, vol. 4, pp. 211-242.
    \117\ Prices may also vary based on transmission losses. For 
purposes of simplification this discussion focuses on the 
differences due to energy prices alone.
    \118\ Under LMP, all suppliers selling at a location receive the 
market clearing price, including those who offer in their bids to 
sell for less. Similarly, all buyers purchasing at the location pay 
the market clearing price, including those who offer in their bids 
to purchase at a higher price. An alternative policy would be to pay 
each seller its bid price (and perhaps, to charge each buyer its bid 
price). We propose a single market clearing price for several 
reasons. First, it encourages sellers to submit bids that reflect 
their marginal costs (and thus, the sellers selected in the energy 
auction are more likely to be the sellers with the lowest actual 
costs). Sellers without market power could not increase the market 
price by increasing their bids, so bidding above their marginal 
costs would have no benefit to them. Bidding above marginal cost 
would merely create the risk that the seller would lose in the 
auction when the market price was higher than the seller's marginal 
costs, and thus, the seller could have earned a profit. Moreover, by 
paying all sellers the market clearing price, sellers with marginal 
costs below the market clearing price would receive revenues to help 
recover their fixed costs. A policy of paying each seller its bid 
would encourage sellers to bid above their marginal costs, since 
doing so would be the only way for them to earn a profit. As a 
result, the sellers selected in the auction would not necessarily be 
the sellers with the lowest actual costs. Moreover, if the pay-as-
bid policy were applied only to sellers (and not to buyers), so that 
buyers were charged the average payment made to sellers, buyers 
would face a price that was lower than the highest accepted seller's 
bid. This result would encourage inefficient purchases and poor 
demand response. For example, on a hot day when the highest accepted 
seller's bid is $1000/MWh but the average payment to sellers is 
$400/MWh, charging buyers $400/MWh under pay-as-bid would encourage 
less demand response than a market clearing price policy of charging 
$1000/MWh. If the pay-as-bid policy were applied to both sellers and 
buyers, then the revenue collected from buyers would usually differ 
from the revenue paid to sellers.
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    205. LMP is a market-based method for congestion management. 
Congestion is managed through energy prices and transmission usage 
charges (congestion and loss charges) determined in a bid-based market. 
When there is no congestion anywhere on the system (when there is 
enough transmission capacity to get power from the cheapest available 
generators to all potential buyers) there will be only one energy price 
in the transmission system, the price bid by the last, or marginal, 
generator that provides energy or load that offers to reduce its 
demand.\119\ When there is congestion, the cheapest generators may be 
unable to reach all their potential buyers. Consequently, when there is 
congestion there may be many different energy prices across the 
transmission system.\120\ Under LMP, the Independent Transmission 
Provider will establish separate energy prices at each node on the 
transmission grid and separate prices to transmit energy between any 
two nodes (receipt and delivery points) on the grid. These prices 
reflect the cost of congestion. LMP relies on economic redispatch in 
managing congestion. Redispatching means decreasing the energy the 
Independent Transmission Provider obtains in front of the constraint 
(where the power is flowing from) and increasing the energy the 
Independent Transmission Provider obtains behind the constraint (where 
the power is flowing to). The cost of redispatch is the basis for the 
congestion charges under LMP. If a customer is willing to pay the 
marginal cost of redispatch, which it signals through its bids, the 
Independent Transmission Provider will schedule the transmission 
service.
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    \119\ The operation of the bid-based auction for energy is 
described further in Section IV.
    \120\ Because the transmission grid is a network, reducing 
transmission service between one receipt point--delivery point pair 
(e.g., from A to B) may free up transmission capability for 
transmission service between a different receipt point--delivery 
point pair (e.g., from C to D), albeit not necessarily on a MW-for-
MW basis. For example, reducing service from A to B by 2 MW may 
allow an additional 1 MW of transmission service from C to D. If so, 
the price to transmit 1 MWh of energy from C to D must reflect at 
least what a customer denied 2 MW of service from A to B would have 
been willing to pay.
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    206. For example, assume there is congestion or a constraint on one 
transmission interface. Some low-cost generators may not be able to 
deliver energy to load on the other (import) side of the constraint. 
So, they will need to reduce their production because of the 
constraint. To signal these generators to reduce their production, the 
energy price that these generators would receive would be lowered. To 
replace the low-cost generation, more expensive generators on the other 
side of the constraint (export) must be dispatched. To signal to these 
higher cost generators that they should increase their production, the 
energy price they would receive would increase. As a result the energy 
price on each side of the transmission constraint would be different. 
The energy price would be lower on the side where more suppliers are 
trying to sell out of the region than can be accommodated by the 
transmission capacity. The energy price would be higher on the side 
where more expensive local generation must be used because of the 
transmission constraint. As discussed further in Section IV.F., for 
purchasers of energy in the Independent Transmission Provider-run spot 
markets, the LMP at the node closest to them is their delivered power 
cost (energy charge plus transmission charge). The generators are then 
paid the LMP at the nodes closest to them.
    207. For customers buying energy through bilateral contracts rather 
than in spot markets, the transmission usage charge would reflect the 
marginal cost of transmission between a receipt point and a delivery 
point.\121\ In the above example, the difference would be the marginal 
cost of moving energy from the import to the export side of the 
constraint which should equal the difference in the energy price on the 
import and the export side of the constraint. In other words, the 
transmission usage charge for bilateral transactions would be the 
difference between the LMP at the receipt point and the delivery point. 
When congestion exists, the difference in energy prices to transmission 
users is a price signal that reflects the marginal cost of economic 
dispatch of resources necessary to accommodate the transmission 
service. Those who place a higher value on the transmission capacity 
and the value of the ultimate delivered electricity, will be willing to 
pay higher transmission usage charges. Also, because transmission usage 
charges for bilateral transactions are based on the differences in spot 
market energy prices, the proposed congestion management system would 
not bias a customer's choice between purchasing energy through the spot 
market versus a bilateral transaction.
---------------------------------------------------------------------------

    \121\ Transmission losses will also be recovered through the 
transmission usage charge and included in the energy prices under 
LMP.
---------------------------------------------------------------------------

    208. LMP uses a financial instrument called a Congestion Revenue 
Right to provide customers with price certainty for transmission 
service.\122\ A Congestion Revenue Right is a financial tool that 
allows a customer to protect itself against the costs of congestion. A 
Congestion Revenue Right ensures that the holder of that right will be 
protected

[[Page 55481]]

against congestion costs for the transmission service covered by that 
right in the day-ahead market.\123\ Once the day-ahead market closes, 
all customers pay for the service requested and, if they hold 
Congestion Revenue Rights, are paid congestion costs associated with 
those rights. Thus, the customer has bought and paid for a quantity of 
transmission at a specified price.
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    \122\ As discussed above, we also propose that Congestion 
Revenue Rights would provide a scheduling priority in certain 
circumstances.
    \123\ For example, a customer holding Congestion Revenue Rights 
could be charged the congestion costs (e.g., $10 MWh) and then 
receive a credit on the same bill for congestion revenues (e.g., $10 
MWh). So, the net congestion costs paid by the customer is $0. The 
customer, however, would have to pay for transmission losses.
---------------------------------------------------------------------------

    209. Any changes a customer wants to make to the transmission 
service it has scheduled in the day-ahead market must be accomplished 
in the real-time market at real-time prices, which may be different 
from the day-ahead prices. A customer wanting less transmission service 
than it requested and received in the day-ahead market would 
effectively sell back to the market the amount of unused service. 
Conversely, a customer needing an additional amount of transmission 
service could buy the additional amount of service in the real-time 
market. No congestion revenues are paid to Congestion Revenue Rights 
holders for transactions made in real-time market.\124\
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    \124\ For example, a customer schedules and receives 100 MW of 
transmission service the day ahead at a congestion cost of $2/MW. 
The customer pays the $2/MW of congestion charges to the Congestion 
Revenue Rights holder (which could be itself). The customer may 
later decide it only needs 90 MW. It could then sell in the real-
time market the unneeded 10 MW. If congestion in the real-time 
market is $3, the seller would receive $3/MW (or $30) for the sale 
of the 10 MW of transmission service from the buyer of the 
transmission service.
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    210. The LMP system for congestion management is better suited to 
manage congestion in a competitive market than the congestion 
management system under the Order No. 888 pro forma tariff (pro rata 
curtailment) because LMP allocates scarce transmission capacity to 
those who value it most and it relies on an incentive system (i.e., it 
assigns congestion costs to the transactions that cause the congestion) 
that encourages market participants to buy and sell power in a manner 
that is consistent with the reliable operation of the system. Under an 
LMP system, market participants have greater commercial flexibility in 
arranging transactions. Market participants have the ability to signal 
whether they are willing to buy their way through transmission 
constraints. Under the current system they do not have the ability to 
do that, in part because transmission providers do not have a mechanism 
for recovering the cost of economic redispatch. Currently, these types 
of transactions would not be scheduled because of the existence of 
congestion. Also, Network Access Service customers would have the 
ability to voluntarily resell their Congestion Revenue Rights when 
others value them more highly. Because market participants will see and 
be responsible for the full effect of their decisions on congestion 
costs, each have an incentive to manage its own transactions in a way 
that is consistent with a least-cost dispatch consistent with reliable 
system operations.
    211. The proposed SMD Tariff lays out the general framework and the 
basic rules for LMP. It is based on the best practices we have seen. We 
recognize that in certain regions there may need to be additional rules 
or changes to accommodate specific regional requirements. We also 
recognize that over time there likely will be a need to update the 
tariff provisions to offer new service options or to further refine the 
market rules. The pro forma tariff is not intended to be a static 
document, but rather one that will evolve over time and meet the needs 
of the marketplace. We seek comment on how best to recognize this need 
for regional variation and the need for continued refinement in the 
rules.
    212. One concern that has been expressed in the Standard Market 
Design conferences and in comments on the Working Paper is that while 
LMP may work well with systems that are dominated by thermal plants, it 
may not work in systems that primarily rely on hydroelectric resources. 
In particular, the Pacific Northwest is concerned that an hourly bid-
based system with LMP may be in conflict with Northwest resource uses, 
practices and obligations, which are dominated by hydroelectric 
generation. Much of this is from ``run-of-river''\125\ facilities that 
cannot store water, and at which energy is lost if a generator does not 
run when water is available. Because the decision to run is virtually 
automatic, many Northwest parties see no need for a bidding system. 
Also, many of the hydroelectric facilities of the Columbia River System 
must coordinate their operations; whether a downstream facility runs 
depends on whether an upstream dam runs and releases water. Some of 
this coordination is among facilities in the United States and Canada 
and is subject to international treaties. There is a concern that a 
bid-based system with LMP, which requires individual generators to bid 
independently against one another, ignores this cooperation or even 
would view such cooperation as collusion in a market system. Some 
coordination agreements assure that low-cost transmission will be made 
available to implement the coordination, and there is a concern that 
LMP congestion pricing may be incompatible with these agreements.
---------------------------------------------------------------------------

    \125\ Run-of-river facilities use the natural flow of the river 
to generate electricity. They typically divert water from a nautral 
channel, run the water through a turbine to produce energy and then 
return the water to the natural channel downstream of the turbine.
---------------------------------------------------------------------------

    213. Northwest parties note that while annual costs in a thermal 
system are minimized simply by minimizing the costs in every individual 
hour the same does not hold true in a hydropower system. A 
hydroelectric dam with stored water has a marginal running cost close 
to zero, however, this does not mean that it should be dispatched first 
every hour. Rather, the value of hydropower over time depends on when 
that stored energy system can best be released to minimize costs over a 
season, a year, or even a multi-year period. Thus, there is a concern 
that in a hydropower system, a congestion management and energy spot 
market designed to minimize hourly costs will not minimize costs over a 
longer period.
    214. Moreover, commenters have noted that decisions about water use 
in the Northwest are based on more than electric power cost 
minimization. Decisions about use of hydropower facilities involve 
coordinated trade-offs among power needs, the needs of fish and 
wildlife, irrigation, flood control, recreation and other factors, 
which may be difficult to reflect in the bids of individual units. Some 
parties in the Northwest acknowledge that a bid-based LMP system could 
be adapted to meet the objections above but are concerned either that 
such a system may be imposed without adaptation or that the adaption 
will be done poorly. There is also concern that adaptation to a bid-
based security-constrained system may reopen such issues as 
transmission priorities and preference power allocations that have been 
settled over many years of negotiation based on factors other than 
market efficiency. Finally, Northwest parties worry about obtaining 
sufficient Congestion Revenue Rights to protect against congestion 
charges.
    215. We believe that the proposed Standard Market Design would work 
well in every region and for all types of fuel sources; we believe that 
the concerns expressed by participants in the Pacific Northwest can be 
accommodated within the LMP system we propose. First, use of the 
Independent Transmission Provider's bid-based spot energy markets would 
be

[[Page 55482]]

optional. No one would be required to bid into these markets (except 
when market power mitigation is imposed).\126\ Hydropower generators 
could choose to self-schedule without submitting a price bid. As a 
result, the bilateral contractual energy arrangements of the Northwest 
would be unaffected. Thus, for example, hydropower facilities along a 
common waterway that wish to develop a coordinated schedule without 
submitting energy price bids would be free to do so. Also, hydropower 
facilities that must consider non-price factors such as the needs for 
irrigation, flood control, and fish and wildlife in their scheduling 
decisions could do so through the self-scheduling feature.
---------------------------------------------------------------------------

    \126\ The market power mitigation measures would be developed on 
a regional basis and would take into account the special 
characteristics of hydropower.
---------------------------------------------------------------------------

    216. For hydropower generators that wish to participate in the 
Independent Transmission Provider's spot energy markets, the Standard 
Market Design that we propose can accommodate the special features of 
hydropower facilities. Suppliers would be allowed to reflect their 
opportunity costs in their bids; bids need not be limited to marginal 
running costs. Also, generators such as hydropower facilities would 
have the option (but not the requirement) of requesting the Independent 
Transmission Provider to schedule the generator's designated MWhs over 
the highest priced hours of the day, to economically optimize 
hydropower production over the day. LMP is a result of a least-cost 
dispatch of the resources available to the transmission system in a 
manner that recognizes both the operational limits of those resources 
and the operational limitations of the transmission system. As a 
result, customers' loads can be met at the lowest total cost (as 
reflected in the submitted bids) consistent with the reliable operation 
of the system, which should be the objective on any system regardless 
of the resource base of the transmission system.
    217. In short, we see no reason why the proposed Standard Market 
Design would prevent hydropower generators from operating in a way that 
accommodates their special features. Indeed, we believe that the LMP 
system would aid hydropower generators in optimizing the economic value 
of their resources within their legitimate operational constraints, 
because the prices for energy and transmission would signal the 
economic costs of providing energy and transmission service at 
different locations and time periods.
    218. Finally, our proposal here would not abrogate existing pre-
Order No. 888 transmission contracts, so customers holding these rights 
could continue their existing services under the existing contractual 
provisions. In addition, this proposal would allocate Congestion 
Revenue Rights or auction revenues to parties based on their recent 
historical usage of transmission. Thus, customers receiving 
transmission service under the Order No. 888 pro forma tariff, as well 
as entities previously serving bundled retail load outside the pro 
forma tariff, would receive Congestion Revenue Rights to protect 
against congestion charges.
    219. We agree that the operational limits of both the resources and 
the transmission systems need to be fully considered in the design of 
the specific market rules. For example, there is likely a need to 
calculate opportunity costs for hydroelectric resources differently 
from thermal plants. These differences can affect market mitigation 
measures. However, we are concerned about whether different market 
designs can be in place in the Northwest and the rest of the West, and 
ask for comment on whether the entire West must have a common set of 
market rules to eliminate seams and prevent manipulation.
    220. In the SMD Tariff we propose to include several different 
types of Congestion Revenue Rights to allow customers to protect 
against congestion costs. For example, one concern that we have heard 
from customers and suppliers in the Northwest is that a receipt point-
to-delivery point Congestion Revenue Right may not work to effectively 
manage congestion on a system that utilizes several different 
hydroelectric facilities on a contingent basis to serve the same 
delivery points. A Congestion Revenue Right that recognized the 
contingent nature of the supply sources would be more valuable to 
customers in this instance. We believe that developing these types of 
Congestion Revenue Rights is possible and we propose to work with the 
regions to develop variations to meet regional needs. The congestion 
management system that we propose is flexible enough to accommodate 
these types of regional variations. Such variation and flexibility 
should not impinge on the development of a seamless electric grid.
2. LMP and Energy Markets
    221. To implement LMP, the Independent Transmission Provider must 
operate an energy market to determine the marginal cost of redispatch. 
We propose to require that the Independent Transmission Provider 
operate both a day-ahead and a real-time energy market to manage 
congestion.
    222. The Commission proposes to use real-time markets for energy to 
resolve energy imbalances. Under the proposal, the transmission 
customer would be charged the real-time price of energy for any 
imbalance, i.e., the difference between the energy the transmission 
customer schedules a day ahead on the system and the amount that it 
takes off the system in real time. The real-time price of energy is 
determined through a security-constrained, bid-based energy market run 
by the Independent Transmission Provider. The Independent Transmission 
Provider uses the bids to select the lowest-cost energy within the 
operational limitations of the transmission system. These same 
procedures will be used to resolve imbalances for all users of the 
transmission system.
    223. The Commission also proposes that the Independent Transmission 
Provider operate a security-constrained, financially binding day-ahead 
energy market that is operated together with a day-ahead scheduling 
process for transmission service.\127\ The day-ahead market for energy 
will allow the Independent Transmission Provider to manage congestion 
that arises in the day-ahead scheduling process.\128\
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    \127\ The operation of both a financially binding day-ahead 
market in conjunction with a financially binding real-time market is 
also known as a multi-settlement system.
    \128\ Such markets are currently operated by the New York ISO 
and PJM. California ISO and ISO-New England are planning on adding 
this feature to their market design.
---------------------------------------------------------------------------

    224. The day-ahead energy market is a bid-based market. Sellers 
submit bids that indicate the quantities of power they will offer for 
sale in each hour of the next day and the price for that power at each 
location (node).\129\ The price for the power may vary based on the 
quantities that are offered for sale. The differences in bid prices 
recognize that a generator's marginal cost of producing power can vary 
at different quantity levels because it operates more efficiently at 
certain output levels than others. Also, at the highest output levels, 
there may be additional opportunity costs because of an increased risk 
of a unit outage. Buyers also submit bids indicating the quantities 
they desire to purchase in each hour of the day. Buyers may also

[[Page 55483]]

indicate the maximum price they are willing to pay for those 
quantities.
---------------------------------------------------------------------------

    \129\ The bids usually take the form of a bid curve that shows 
the bid price and quantity between the unit's minimum output and its 
maximum output. Usually the prices are relatively flat over the 
normal operating range of the unit. As quantities approach the 
maximum output the prices usually increase very rapidly.
---------------------------------------------------------------------------

    225. Under the Commission's proposal, buyers are not required to 
procure energy through the day-ahead energy market. A load-serving 
entity may procure all of its power through bilateral transactions, in 
the transmission provider's spot markets, or by generating its own 
power.\130\ However, a load-serving entity may use the day-ahead market 
if it needs to acquire additional power or the price of power through 
the day-ahead energy market is lower than the price of power under an 
existing bilateral contract or the cost of generating its own power. A 
generator may also buy power through the day-ahead market. It would do 
this if it could buy the power more cheaply than generating to satisfy 
a bilateral contract obligation or if a forced outage requires it to 
procure power to satisfy a contract obligation.
---------------------------------------------------------------------------

    \130\ These transactions must still be scheduled through the 
day-ahead market and are subject to congestion costs if they do not 
have Congestion Revenue Rights.
---------------------------------------------------------------------------

    226. The Commission proposes to require Independent Transmission 
Providers to allow buyers and sellers to submit purely financial bids, 
a feature that currently exists in the day-ahead markets run by PJM and 
New York ISO. These financial bids to buy or sell power are not backed 
by actual generation resources nor are they backed by actual load. 
Rather, these transactions are used to bring the prices in the day-
ahead market and in the real-time market closer together. For example, 
suppose that the day-ahead price is consistently lower than the 
corresponding real-time price. Entities may therefore want to submit 
financial bids to buy energy in the day-ahead market at the lower 
price, and submit a corresponding bid to sell in the real-time market 
at the higher price, thereby making a net profit on the two 
transactions. The additional buyer bids in the day-ahead market would 
tend to increase day-ahead prices, while the additional supply bids in 
the real-time market would tend to reduce the real-time prices. The 
result is that the price differences in the two markets would shrink, 
as would the profits of sale. This process benefits the market. It 
helps market participants make better decisions in advance--in the day-
ahead time frame--that will affect how much electricity they will sell 
or buy, because the day-ahead price becomes a more accurate gauge of 
what the real-time price will be.
    227. The day-ahead energy market is operated together with the 
congestion management system and the day-ahead scheduling process for 
transmission service. The Independent Transmission Provider will 
determine market clearing prices for each hour in the day-ahead energy 
market based on the sale and purchase bids that are submitted. The 
market clearing price is the bid of the last unit of supply needed to 
satisfy the demand, i.e., the highest bid that is accepted. The market 
clearing price at a location is paid to all suppliers at that location 
that are selected in the auction and is paid by all buyers at that 
location that purchase through the auction.
    228. We believe there are important differences between Standard 
Market Design and the market design that was in effect in the 
California ISO when it experienced problems in the energy markets in 
2000 and 2001. First, Standard Market Design is premised on the use of 
bilateral contracts. While LSEs may purchase energy in the spot 
markets, these purchases should constitute a small percentage of their 
actual purchases. In contrast, the California market design required 
the LSEs to purchase the bulk of their energy needs through the spot 
markets. Second, Standard Market Design includes a forward-looking 
long-term resource adequacy requirement to avoid the types of supply 
shortages that adversely affected California. Third, as discussed in 
more detail in Appendix E, Standard Market Design includes trading 
rules, a congestion management system, market power mitigation 
measures, and market power monitoring to address the manipulation 
strategies encountered in the California markets.
    229. In determining market clearing prices, the Independent 
Transmission Provider factors in the operational limitations of the 
transmission capacity, such as congestion and reactive power needs, to 
ensure that the units that set the market clearing prices are 
consistent with the transmission system operations (i.e., a security-
constrained dispatch).\131\ Because LMP is used as the congestion 
management system, the market clearing prices are the prices for energy 
delivered to each location or node on the system. If there is no 
congestion on the transmission system, the same market clearing price 
for energy will apply throughout the system.
---------------------------------------------------------------------------

    \131\ It is important that the schedule developed through the 
day-ahead market be physically feasible, i.e., consistent with 
reliable transmission limitations. If it were not, then it would be 
necessary to make separate congestion payments to suppliers in real 
time to change their output so that the real-time schedule was 
consistent with reliable transmission limitations. This would 
provide an incentive for suppliers to create congestion in the day-
ahead market so that they could receive payments in real time to 
relieve congestion.
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    230. The day-ahead market would be financially binding. This means 
that a seller that is selected in the day-ahead market is obligated to 
actually provide the power in real time or in real time it will be 
charged the cost of procuring the shortfall through the real-time 
market.\132\ The day-ahead market is also financially binding on 
buyers.\133\ This reduces certain opportunities for strategic bidding 
and thus, market manipulation.
---------------------------------------------------------------------------

    \132\ For example, assume in the day-ahead market a generator 
agreed to sell 50 MW for the hour running from 9 a.m. to 10 a.m. at 
a price of $30 Mwh. In the day-ahead market the generator would 
receive $1,500 ($30 times 50) for that sale. In real time, the 
generator only delivered 20 MW during that hour. The real-time price 
of energy in that hour was $40 MWh. The generator would be charged 
$1200 for its 30 MW shortfall in real time (30 times 40). Thus, the 
generator would receive a total net payment of $300.
    \133\ For example, assume that a load-serving entity buys 40 MW 
in the day-ahead market for the hour 10 a.m. to 11 a.m. at a price 
of $30 Mwh. In the day-ahead market the load-serving entity would 
pay $1200 (40 times 30) for that purchase. In real time the load-
serving entity only took 35 MW in that hour. The real-time price of 
energy for that hour was $25. The load-serving entity would 
effectively sell back the excess power (5 MW) at the real-time price 
($25), $125. Thus, the load-serving entity would pay a net total of 
$1075.
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    231. Years of experience with organized markets makes it clear that 
a day-ahead market is a best practice that must be included in the 
Standard Market Design. The development of a day-ahead schedule for 
energy and transmission service, including certain ancillary services, 
provides reliability benefits. It allows the Independent Transmission 
Provider to have advance warning to ensure that sufficient units are 
committed to serve the projected load. For example, if the Independent 
Transmission Provider believes that load has not scheduled sufficient 
transmission service or energy purchases in the day-ahead markets, it 
can commit additional units to be available in real time. Because of 
their operating characteristics, different types of generation units 
have differing levels of start-up costs as well as different lead times 
to be available in real time. The day-ahead market gives the 
Independent Transmission Provider information on unit availability, 
costs and system needs well before real time so the Independent 
Transmission Provider has more options available to ensure reliability 
and reduce costs in the real-time market.
    232. Finally, the day-ahead market provides an important platform 
for market power mitigation. We propose several mitigation measures to 
ensure that there is a well-functioning spot market for wholesale 
power. These spot

[[Page 55484]]

markets will result in price transparency, so buyers and sellers can 
see that market clearing prices are set in a fair and predictable 
manner. While the real-time market will be a transparent market, real-
time prices may not be known until after the fact or at most five to 
ten minutes before real time. This gives buyers and sellers little 
chance to react to prices. In contrast, a day-ahead market provides a 
transparent spot market that allows buyers and sellers to engage in 
additional commercial transactions before real time. Thus, a day-ahead 
market helps liquidity and is likely to be less volatile than the real-
time market.
    233. The Independent Transmission Provider will also establish 
hourly prices for certain ancillary services, which may differ by 
location to the extent that ancillary service requirements differ by 
location. Since the same supply resources can often be used to provide 
either energy or ancillary services, energy and ancillary services 
should have compatible market designs. Otherwise, there would be an 
incentive to sell one type of product over another. Since both are 
needed, a compatible system allows the supplier to sell energy or 
ancillary services, whichever is the most efficient use of the supply 
resources. This yields the lowest total costs to customers.
    234. As explained further below, the Independent Transmission 
Provider will need to manage congestion in two time frames: (1) During 
the day-ahead scheduling process, and (2) during real-time operations. 
The Independent Transmission Provider will conduct separate auctions to 
manage congestion in each time frame. In the day-ahead auction, for 
each hour of the following day the Independent Transmission Provider 
will take bids to buy and sell energy, to provide certain ancillary 
services, and to purchase transmission service between identified 
receipt and delivery points. The Independent Transmission Provider will 
consider the bids for energy, transmission service and ancillary 
services simultaneously. Based on those bids, the Independent 
Transmission Provider will develop a schedule that maximizes the 
economic value (as reflected in the bids) of the transactions over the 
entire day-ahead period, in light of the amount of Available Transfer 
Capability and any resulting transmission congestion and losses. The 
Independent Transmission Provider will also establish prices for 
transmission service, energy and ancillary services that clear the 
markets.
3. Congestion Revenue Rights
    235. Under LMP, transmission usage prices will vary based on the 
price of relieving transmission congestion and losses. Rather than 
using a system of physical reservations, a system of financial rights 
called Congestion Revenue Rights will be used to give customers the 
ability to protect themselves against congestion costs.
    236. The initial allocation process for Congestion Revenue Rights 
will be done through compliance filings that allow for different 
treatment within each region. Since this must occur before Standard 
Market Design is implemented, we have not addressed initial allocation 
in the SMD Tariff, but it is discussed in Section IV.E.3.e below. This 
section describes allocation processes that would be used after the 
initial allocation has been done.

a. General Features

    237. We propose to require that Independent Transmission Providers 
offer Congestion Revenue Rights of several types (one that we will 
mandate now and others that should be offered upon customer request 
when technically feasible) that allow transmission customers to obtain 
protection against uncertain future congestion charges. We have added a 
new section to the SMD Tariff that describes the types of Congestion 
Revenue Rights that would be available, how one acquires Congestion 
Revenue Rights after the initial allocation and how Congestion Revenue 
Rights provide protection against congestion costs (Part II.D., 
Congestion Revenue Rights). The proposed provisions are discussed 
below.
    238. The Independent Transmission Provider would be required to 
offer Congestion Revenue Rights for all of the transmission transfer 
capability on the grid, but it would not be allowed to sell more rights 
than can be accommodated. Congestion Revenue Rights would be available 
over a variety of terms, such as weekly, monthly, yearly and perhaps 
for longer terms. If an entity pays to construct new generation or 
transmission facilities that add transfer capability, and the costs of 
the upgrade are not rolled in, the entity would receive the Congestion 
Revenue Rights associated with the new transfer capability. In the past 
the Commission has allowed credits for upgrades; is there still a role 
for credits under Standard Market Design?
    239. Customers that have not acquired Congestion Revenue Rights in 
advance could schedule transmission service in the day-ahead market, 
but they would not have the Congestion Revenue Rights protection 
against congestion costs.
    240. We propose that Congestion Revenue Rights be made available 
first in the form of receipt point-to-delivery point obligation rights, 
which we propose to mandate now, and later in the form of receipt 
point-to-delivery point option rights and flowgate rights.
    Currently, in PJM and New York ISO only receipt point-to-delivery 
point obligations are offered. However, there has been considerable 
interest expressed by market participants in other types of Congestion 
Revenue Rights. For example, the Midwest ISO is considering offering a 
package of Congestion Revenue Rights that are similar to what we are 
proposing. Also, PJM is considering offering receipt point-to-delivery 
point options. Offering several different types of Congestion Revenue 
Rights would make the system more flexible and better able to adapt to 
the needs of specific customers. Also, certain types of Congestion 
Revenue Rights may be more valued in different regions of the country 
based on the physical configuration of the transmission system and the 
types of resources connected to that system. Various technical papers 
over the last few years have examined offering these alternate rights 
simultaneously and concluded that it is feasible under the conditions 
now specified in the SMD Tariff.\134\ Therefore, we believe the tariff 
should provide this flexibility.
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    \134\ See, e.g., Hogan, William W., Financial Transmission 
Rights Formulations, Center of Business and Government, John F. 
Kennedy School of Government, Harvard University, Cambridge, MA 
(March 31, 2002); Chao, Hung-Po, Peck, Stephen, Oren, Shmuel, and 
Wilson, Robert, Flow-based Transmission Rights and Congestion 
Management, The Electricity Journal, pp. 8, 13 and 38-58 (2000); and 
Chao, Hung-Po and Peck, Stephen, A Market Mechanism for Electric 
Power Transmission, Journal of Regulatory Economics (July 1996).
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b. Types of Congestion Revenue Rights

    241. The SMD Tariff describes the characteristics of each of the 
types of Congestion Revenue Rights. These descriptions are summarized 
below.

(1) Receipt Point-to-Delivery Point Rights.

    242. A receipt point-to-delivery point right is a right that is 
specified by a receipt point (which can be a generator node, an 
aggregation of generator nodes, an interface, a trading hub, or any 
other collection of nodes) and a delivery point (which can be a 
delivery node, an aggregation of delivery nodes, an interface, or a 
trading hub), and the power in MW that is transmitted from the receipt 
point to the delivery point for a period of time (e.g., one hour).

[[Page 55485]]

    243. A receipt point-to-delivery point right entitles the holder to 
the day-ahead congestion revenues associated with transmission service 
from the receipt point to the delivery point.\135\ In addition, during 
any period when the demand for transmission service cannot be met with 
Available Transfer Capability (i.e., because there are too many 
customers who have indicated that they want transmission service at any 
price), holders of receipt point-to-delivery point rights would receive 
priority over other market participants in scheduling transmission 
service between the receipt point and delivery points designated in 
their rights.
---------------------------------------------------------------------------

    \135\ The right is direction-specific. The holder is entitled to 
congestion revenues from the receipt to delivery point, not from the 
delivery point to the receipt point.
---------------------------------------------------------------------------

    244. A receipt point-to-delivery point right would provide the 
holder with the right to schedule transmission service of the specified 
amount of power (MW) in the day-ahead market from the receipt point to 
the delivery point without paying any net charges for congestion 
(although the holder would need to pay a charge for losses). The reason 
is that every customer would be entitled to inform the Independent 
Transmission Provider to schedule its transmission service regardless 
of the congestion charge. In that case, the customer would be charged 
for congestion (as well as for losses). But a self-scheduled customer 
holding a receipt point-to-delivery point right for at least the same 
amount of power between the same receipt and delivery points would 
receive congestion revenues that fully offset the congestion charge.

(2) Obligations and Options.

    245. Receipt point-to-delivery point rights can take the form of 
obligations or options. The difference between obligations and options 
becomes important when congestion occurs in the opposite direction from 
the right, that is, when there is congestion from the delivery point to 
the receipt point. In this case, congestion revenues in the direction 
of the right are negative. Under a receipt point-to-delivery point 
obligation, the Congestion Revenue Rights holder in that case would be 
required to pay the negative congestion revenues to the Independent 
Transmission Provider. Under a receipt point-to-delivery point option, 
the Congestion Revenue Rights holder would not be required to pay the 
negative congestion revenues to the Independent Transmission Provider. 
Existing firm point-to-point transmission contracts under the Order No. 
888 pro forma tariff do not require contract holders to transmit energy 
and, thus, are similar to Congestion Revenue Rights that are options.

(3) Flowgate Rights.

    246. A flowgate is a particular transmission facility or group of 
facilities (e.g., an interface). A flowgate right specifies a portion 
of the transmission capacity over that flowgate in a specified 
direction. A flowgate right entitles the holder to the day-ahead 
congestion revenues associated with the specified power flows over the 
flowgate in the specified direction.
    246a. Consider, for example, a very simplified transmission network 
that connects two points, A and B, with two different but 
interconnected transmission lines, a northern line and a southern line, 
as shown below:
[GRAPHIC] [TIFF OMITTED] TP29AU02.040

Each transmission line could be a separate transmission or flowgate, 
and separate flowgate rights could be issued for each line. The holder 
of a flowgate right on the northern line from west to east would be 
entitled to the congestion revenues associated with that line in the 
west-to-east direction. However, holding a flowgate right on the 
northern line would not entitle the holder to congestion revenues 
associated with the southern line. Hence, if transmission service 
results in energy flows over several flowgates, the buyer must obtain 
sufficient rights on each flowgate to obtain protection from congestion 
charges. By contrast, the holder of a receipt point-to-delivery point 
right from west-to-east (i.e., from A to B) would be entitled to 
congestion revenues in the west-to-east direction regardless of whether 
the northern or the southern lines were congested and thus would have a 
complete hedge for this transaction.
    246b. Unlike a receipt point-to-delivery point obligation, a 
flowgate right would never require the holder to make congestion 
payments. The congestion revenue associated with a flowgate in a 
specified direction would equal the additional net economic value to 
market participants that would result by incrementally increasing the 
flowgate's capacity in the specified direction. That additional net 
economic value may be either positive (i.e., when the flowgate is 
congested) or zero (i.e., when the flowgate is not congested), but it 
would never be negative.
    247. Receipt-point-to-delivery-point rights offer the transmission 
customer with long-term energy contracts the best way to protect itself 
against hourly congestion costs. However, many transmission customers 
may be meeting their loads' needs with a portfolio of generators 
scattered around a regional electricity market. Such customers may be 
seeking a more flexible type of right than the receipt-point-to-
delivery point right (which is typically only reconfigured on a monthly 
basis and which can be traded on the secondary market most easily if 
another customer requires the same points as specified in the right). 
The major market advantage of the flowgate right is that since there 
are fewer congested flowgates than possible under receipt-point-to-
delivery-point rights, transmission customers can focus their rights on 
the key congested flowgates. This allows for coverage of much of the 
congestion charges (in some estimates, between 80 percent to 90 
percent). However, the flowgate rights may not provide a complete 
protection against congestion charges for a receipt point-to-delivery 
point energy transaction, since the congestion revenues may differ from 
the congestion charges.

[[Page 55486]]

c. Requirement for Offering Rights

    248. At the start of Network Access Service, the Independent 
Transmission Provider would be required to offer receipt point-to-
delivery point obligations. These rights are the easiest to implement 
because they are already in wide use. While we want the market to 
develop additional choices for customers, we are concerned about 
requiring implementation of numerous types of rights, including types 
of Congestion Revenue Rights that have not yet been tested by an ISO or 
RTO, when Standard Market Design is first implemented. Because there is 
no experience with the other types of rights, we propose not to require 
the Independent Transmission Provider to offer them initially. However, 
upon the request of market participants, the Independent Transmission 
Provider would be required to offer receipt point-to-delivery point 
options and flowgate rights as soon as technically feasible.
    249. Additionally, Congestion Revenue Rights could be offered for 
various terms, e.g., one month or five years. Some customers may desire 
Congestion Revenue Rights with multi-year terms to correspond to the 
terms of long-term power contracts, including contracts used to satisfy 
the resource adequacy requirement discussed in Section J. At the same 
time, it may be difficult for the market to value long-term Congestion 
Revenue Rights until a region has actual operating experience under an 
LMP congestion management system. This could create problems in an area 
that auctions all Congestion Revenue Rights and allocates the auction 
revenue rights to load. We seek comment on whether the Commission 
should require the Independent Transmission Provider to offer multi-
year Congestion Revenue Rights when Standard Market Design is first 
implemented. Additionally, we seek comment on whether the Independent 
Transmission Provider should be required to offer Congestion Revenue 
Rights with terms tied to the planning horizon used in the region to 
satisfy the resource adequacy requirement.

d. Funding for the Congestion Revenue Rights

    250. As explained above, holders of Congestion Revenue Rights would 
be entitled to receive congestion revenues associated with transmission 
congestion in each hour of the day-ahead market. The aggregate amount 
of Congestion Revenue Rights issued by the Independent Transmission 
Provider would be the amount simultaneously feasible based on Available 
Transfer Capability under normal operating conditions. As a result, 
during normal operating conditions, the Independent Transmission 
Provider would collect enough congestion charge revenue from users of 
transmission service in the day-ahead market to fully pay the day-ahead 
congestion revenues owed to holders of Congestion Revenue Rights. 
Indeed, the Independent Transmission Provider might collect a surplus 
of revenue in some hours during normal operating conditions. However, 
when a significant amount of transmission facilities are out of 
service, so that less transmission service can be provided, the 
Independent Transmission Provider may collect less congestion charge 
revenue from transmission users than the amounts owed to Congestion 
Revenue Rights holders.
    251. There are two ways to handle this revenue shortfall. First, 
the amount of congestion revenues paid to the holders of Congestion 
Revenue Rights may have to be reduced. As a result, the customer may 
only be able to protect against a portion (e.g., 95 percent) of its 
congestion costs in the day-ahead market. Alternatively, the customer 
that has a Congestion Revenue Right could receive full protection 
against congestion costs and the revenue shortfall would be assigned to 
the transmission owner. We propose to use the latter approach. When 
such revenue deficits arise, we propose that such deficits be made up 
by transmission owners whose transmission facilities are out of 
service. We would, however, include an exception for outages due to 
force majeure events, since our intent is to reward transmission owners 
for proactively maintaining their transmission facilities.\138,137\ 
Assigning revenue deficits in this way would encourage transmission 
owners to take steps to minimize forced transmission outages and to 
schedule maintenance outages so as to minimize their effect on 
congestion costs. Assigning congestion revenue surpluses to 
transmission owners may also encourage them to minimize outages. 
However, such a policy may also create an interest on the part of 
transmission owners in maintaining congestion, and thus may discourage 
them from building needed transmission expansions. We propose that any 
revenue surpluses be paid to transmission owners, but we seek comment 
on the potential of this policy to discourage transmission expansions 
and if alternative mechanisms should be used to distribute the revenue 
surpluses.
---------------------------------------------------------------------------

    \136,137\ As a result, in the event of force majeure the 
Congestion Revenue Rights would not be fully funded.
---------------------------------------------------------------------------

e. Auctions and Resales of Congestion Revenue Rights

    252. We believe it is important that there be an active secondary 
market for Congestion Revenue Rights. This will allow a market 
mechanism for customers that have Congestion Revenue Rights to acquire 
new ones or to sell Congestion Revenue Rights they no longer need. 
Additionally, this provides a way for market participants that do not 
have Congestion Revenue Rights to acquire them. Market participants 
would be allowed to resell any Congestion Revenue Rights that they have 
been awarded for the full term of the rights or for a part of the term. 
Resales could be transacted bilaterally between willing buyers and 
sellers. In addition, we propose to require that the Independent 
Transmission Provider conduct periodic auctions of Congestion Revenue 
Rights. The Independent Transmission Provider's auction would allow 
holders of rights to resell their Congestion Revenue Rights in an 
organized market. This would provide greater price transparency for 
these rights than if all sales were conducted through bilateral 
transactions. Moreover, the auctions would provide the ability to 
reconfigure Congestion Revenue Rights into different receipt and 
delivery points, or into different types of rights (e.g., receipt 
point-to-delivery point options, obligations, or flowgate rights). This 
would allow Congestion Revenue Rights holders to change their 
Congestion Revenue Rights if for example they decided to switch 
suppliers. The auctions would also allow Congestion Revenue Rights 
associated with other transmission capacity that becomes available 
(such as through the expiration of previously issued Congestion Revenue 
Rights) to be sold.
    253. In the auctions, buyers and sellers would submit bids that 
specify the type of Congestion Revenue Rights desired to be bought or 
sold, the location, term and price. The Independent Transmission 
Provider would select the combination of bids that maximizes the 
economic value of the transactions for the participants. In so doing, 
the Independent Transmission Provider must reconfigure the Congestion 
Revenue Rights offered for sale in a way that maintains the 
simultaneous feasibility of the Congestion Revenue Rights. That is, the 
types and/or locations of the Congestion Revenue Rights offered for 
sale may differ from those that are purchased. The Independent 
Transmission Provider

[[Page 55487]]

would establish market-clearing prices for each Congestion Revenue 
Right bought or sold. Each seller would receive the market-clearing 
price for the rights that it sold, and each buyer would pay the market-
clearing price for the rights that it purchased.

f. Including Energy and Ancillary Services in the Congestion Revenue 
Rights Auctions

    254. The time period covered by the Congestion Revenue Rights sold 
in auctions would be a month or longer. We propose that an Independent 
Transmission Provider would be permitted, but not required, to conduct 
pre-day-ahead auctions for energy and ancillary services. Under such 
auctions, market participants could offer to buy and sell energy and 
ancillary services at specific locations on a forward basis for a 
specified time period, such as for a month or a year. Participation in 
these pre-day ahead markets, as in all markets, would be on a voluntary 
basis. Such purchases and sales of energy and ancillary service would 
require use of the transmission system, just as sales of Congestion 
Revenue Rights would. Thus, in conducting pre-day-ahead auctions, the 
Independent Transmission Provider would allocate transmission capacity 
among competing demands for Congestion Revenue Rights, forward energy 
and forward ancillary services so as to maximize the economic value of 
the winning bids. The Independent Transmission Provider would establish 
market-clearing prices for forward energy and ancillary services at 
each location, as well as market-clearing prices for Congestion Revenue 
Rights.
    255. A potential benefit of pre-day-ahead auctions is that they 
could more easily maximize the economic benefits of transmission 
capability by considering a greater array of competing uses of the 
transmission grid. They could also provide a convenient, central market 
forum for buyers and sellers to arrange forward trades of energy and 
ancillary services. They could provide transparency and liquidity (and 
thus protection against manipulation) in long-term markets where 
liquidity has recently been reduced.

F. Day-Ahead and Real-Time Market Services

    256. This section sets forth the bidding, scheduling, price 
determination, and settlement provisions necessary to implement LMP in 
the day-ahead and real-time markets for energy, regulation and both 
operating reserves. In this section, we lay out the basic elements that 
would be used for congestion management and operation of the spot 
markets.\138\
---------------------------------------------------------------------------

    \138\ Part I of the SMD Tariff includes a definition of the 
terms related to market services. In addition, as we use the term 
``supplier'' or ``seller'' in this Section, the definition we are 
using includes both generators and demand-side resources that 
satisfy the Independent Transmission Provider's applicable 
requirements.
---------------------------------------------------------------------------

1. Design of the Day-Ahead Markets
    257. We propose that the Independent Transmission Provider operate 
day-ahead and real-time markets for energy and certain ancillary 
services in conjunction with its scheduling of transmission service day 
ahead and in real time. These markets would allocate transmission and 
generation capacity among competing uses in different markets through 
LMP pricing. For example, the markets would determine how much 
transmission capacity would be allocated for transmission service to 
market participants completing bilateral energy transactions, for use 
by the Independent Transmission Provider in completing energy sales and 
purchases through its bid-based energy markets, and for providing 
ancillary services. The markets should be operated jointly to ensure 
that transmission and generation capacity is allocated where it is most 
valuable, and to ensure that the prices for the products and services 
are internally consistent.

a. Scheduling Transmission Service Day Ahead

(1) General Features.

    258. Each day the Independent Transmission Provider would accept 
requests to schedule transmission service to support bilateral energy 
transactions or customer-owned generation for each hour of the 
following day. A customer desiring transmission service would be 
required to submit a scheduling request in a standardized form 
specified by the Independent Transmission Provider. For each requested 
transmission service, the scheduling request would indicate the receipt 
point and the delivery point of the bilateral energy transaction or 
customer-owned generation, the amount of power (MW) to be transmitted 
and the time period. To facilitate the ability of demand to respond to 
price signals, transmission customers will be given several ways of 
indicating their willingness to change their consumption based on 
congestion costs and marginal losses: (1) Customers (whether or not 
they hold Congestion Revenue Rights) would be allowed to specify in 
their scheduling requests the maximum transmission usage charge 
(reflecting the costs of congestion and marginal losses) at which the 
customer desires service; \139\ (2) customers would be allowed to 
specify the maximum congestion charge component of the transmission 
usage charge at which they desire transmission service, or above which 
they are unwilling to pay any congestion costs; or (3) customers 
(whether or not they hold Congestion Revenue Rights) could submit a bid 
that states a desire for transmission service to be scheduled 
regardless of the transmission usage charge. This option may be useful 
for a holder of a Congestion Revenue Right that desires to schedule 
transmission service that uses the receipt point-to-delivery point 
combination covered by that Congestion Revenue Right.
---------------------------------------------------------------------------

    \139\ For example, when transmission usage prices become 
sufficiently high, customers holding receipt point-to-delivery point 
Congestion Revenue Rights may prefer not to schedule transmission 
service between their designated receipt and delivery points. 
Instead, the customers may prefer to receive the applicable 
congestion revenues. Customers could communicate these preferences 
through price-bids.
---------------------------------------------------------------------------

    259. Another way that transmission customers will be able to 
respond to price signals is by submitting multi-hour block bids, 
requesting transmission service for a block of consecutive hours and 
indicating the maximum price for the entire multi-hour period. For 
example, a multi-hour block bid might specify that the customer desires 
10 MW of transmission service from receipt point A to delivery point B 
in each hour from 1 p.m. to 6 p.m. as long as the price per MW for the 
entire 5-hour period does not exceed $10. Such a bid would be accepted 
if the sum of the hourly transmission usage prices for each of the 5 
hours did not exceed $10. Otherwise, the entire bid would be rejected. 
This option allows a customer, for example an industrial customer in a 
state with retail access, to indicate that it is willing to reduce its 
transmission usage if the prices for a multi-hour period are above a 
specified level. This feature has not been put in practice in any of 
the bid-based markets operated by ISOs. We seek comments on its merit 
and any implementation difficulties.
    260. The Independent Transmission Provider would consider these 
transmission scheduling requests in conjunction with bids submitted in 
its day-ahead energy and ancillary service markets. Based on all of 
these, the Independent Transmission Provider would accept the set of 
energy bids and scheduling requests and develop a day-ahead schedule 
that maximizes the economic value for all market participants. The 
Independent Transmission Provider would also

[[Page 55488]]

establish transmission usage prices for each hour of the next day that 
are the same as the implicit transmission usage price included in the 
set of locational energy prices (i.e., the difference in the price of 
energy at the receipt point and at the delivery point, which reflects 
both congestion and losses).
    261. The Independent Transmission Provider would schedule all 
requests for transmission service since these users have agreed to pay 
any applicable congestion charges. The Independent Transmission 
Provider would also schedule all requested transactions where the 
transmission usage charge was below the amount the customer indicated 
it was willing to pay.
    262. Customers with Congestion Revenue Rights would receive 
congestion revenues that help offset any congestion charges paid as 
part of the transmission usage charge. The amount of the congestion 
revenues received (and the associated protection against congestion 
charges) would depend on the specific Congestion Revenue Rights held. A 
customer holding receipt point-to-delivery point Congestion Revenue 
Rights for a certain amount of power between a delivery and receipt 
point that matches its day-ahead transmission schedule would receive 
congestion revenues that exactly offset its congestion charges, so that 
its net bill would reflect no congestion charges (although it would be 
charged for losses).
    263. The above process would be used for scheduling transmission 
service on a daily basis. Some customers, particularly those with 
Congestion Revenue Rights, may desire to schedule the same exact 
service over a longer period to save on administrative costs. The 
Commission seeks comments on whether a customer should be allowed to 
provide a schedule for multiple days or have a standing scheduling 
request that would remain in effect until changed by the customer. Any 
schedule request, once scheduled by the Independent Transmission 
Provider would become financially binding on the customer at the close 
of each day's day-ahead market.

(2) Transmission Service Across Borders.

    264. Transmission service across the border of adjoining 
Independent Transmission Providers' service areas--from a point of 
receipt in one service area to a point of delivery in another--requires 
coordination between the affected Independent Transmission Providers. 
When transmission congestion exists between a point of receipt and a 
point of delivery in different service areas, managing the congestion 
becomes more difficult because more than one Independent Transmission 
Provider is involved.
    265. There are at least two methods for arranging for transmission 
service across borders--physical reservations (i.e., continuing firm 
point-to-point reservations of transfer capability), and scheduling of 
service consistent with internal transactions under Network Access 
Service (scheduling of transmission and financial bidding). We propose 
to treat transmission service across borders in the same way as 
internal transactions. Thus, like internal transactions, an importing 
or exporting customer could either schedule transmission service and 
agree to pay the transmission usage charge regardless of the level or 
submit a bid that limits its congestion exposure. Under the first 
method, the transmission customer would submit to each Independent 
Transmission Provider a request to be scheduled for transmission 
service to and from the border, regardless of the applicable 
transmission usage charges that it will be assessed. The customer would 
be scheduled unless congestion arose that could not be relieved through 
redispatch or some other means. Under the second method, financial 
bidding, the customer would submit a price bid to each Independent 
Transmission Provider indicating the maximum transmission usage charge 
that it is willing to pay for transmission service on each side of the 
border. The customer would be scheduled if its price bid on each side 
of the border was at or above the applicable transmission usage charge. 
Under either method, if the customer's transaction is scheduled, the 
customer would pay the applicable transmission usage charges to and 
from the border. We propose to make both options available to 
transmission customers, because each option may provide benefits to 
customers. We would prefer ``one-stop shopping'' with Independent 
Transmission Provider coordination; we seek comment on whether this can 
be done?
    266. Recently we accepted a prescheduling option for service across 
borders that was proposed by the New York ISO.\140\ A prescheduling 
option would give a customer certainty prior to the day-ahead market 
that it could transmit power across a border. Under the New York ISO's 
prescheduling option a customer may schedule such a transaction up to 
eighteen months in advance of the dispatch day. A customer that 
requests a prescheduled transaction agrees to pay the applicable market 
clearing transmission usage charge. Once submitted, the transaction 
would be financially binding unless the New York ISO permits the 
customer to withdraw the prescheduled transaction. We seek comment on 
whether a similar prescheduling option should be included in Standard 
Market Design.
---------------------------------------------------------------------------

    \140\ New York Independent System Operator, Inc., 99 FERC [para] 
61,292 (2002).
---------------------------------------------------------------------------

b. Transmission Losses

    267. When energy is transmitted from a point of receipt to a point 
of delivery, some of the energy is lost due to resistance on the wires. 
These transmission losses are a cost of transmission and commonly are 
recovered on an average cost basis from all transmission customers. As 
noted earlier, we are proposing that energy prices and the associated 
transmission usage charges be based on marginal costs, in order to 
promote economic efficiency. We seek comment on whether transmission 
losses should be recovered on the basis of the marginal cost of losses 
or if they should be recovered on the average cost of losses. There are 
advantages and disadvantages to each approach. Using marginal losses 
would promote a more efficient use of the transmission system. However, 
as discussed below, charging marginal losses will collect surplus 
revenues that must then be returned to transmission customers. On the 
other hand, the advantage of charging average losses is simplicity. If 
average losses are charged, the losses collected from customers would 
equal actual losses. There would be no need to create a mechanism to 
return surplus losses.
    268. For customers purchasing transmission service to complete 
bilateral transactions, we see value in allowing transmission customers 
to pay for their assigned losses either in cash or in kind. To pay in 
cash, the customer would pay the market price for its assigned MWhs of 
losses, which would be included in the applicable transmission usage 
charge. Thus, the MWh of energy injected at the point of receipt would 
equal the MWh withdrawn at the point of delivery. The transmission 
provider would procure the energy used for losses from its energy 
market. To pay in kind, the customer would supply energy at the point 
of receipt in the amount of its assigned losses. Thus, the MWhs 
injected at the point of receipt would exceed the MWhs at the point of 
delivery by the amount of the assigned losses, and the customer would 
pay in cash only the congestion component of

[[Page 55489]]

the transmission usage charge.\141\ We note, however, that some 
commenters in our outreach process expressed concern that allowing 
customers to provide losses in kind may unduly complicate the 
scheduling process, especially for transactions that involve multiple 
Independent Transmission Providers. We seek comment on whether 
transmission customers should have the choice of paying for losses in 
cash or in kind, or alternatively, whether all transmission customers 
should be required to pay for losses in cash.
---------------------------------------------------------------------------

    \141\ The amount of energy needed for losses would not be known 
until the close of the market. For transactions in the day-ahead 
market, the Transmission Provider would inform each customer that 
wishes to supply losses in kind (after the close of the day-ahead 
market) of the amount of its assigned losses (in MWh), and that 
amount would be included in the customer's day-ahead schedule. For 
transactions in the real-time market, the Transmission Provider 
could provide an estimate in advance of the amount of each 
customer's assigned losses. However, since actual marginal losses 
would not be known until after the fact, the customer would be 
charged or credited at the applicable LMP for any under- or over-
provision of losses.
---------------------------------------------------------------------------

c. Day-Ahead Energy Market

(1) General Features.

    269. We propose that the Independent Transmission Provider be 
required to run a voluntary, bid-based, security-constrained day-ahead 
energy market. ``Voluntary'' means that market participants do not have 
to buy or sell in the day-ahead energy market. The day-ahead market we 
are proposing provides customers with additional supply choices. It is 
not intended to substitute for other longer-term arrangements that 
customers may use to purchase supplies such as bilateral transactions 
or use of a customer's own generation. Thus, market participants would 
be able to schedule bilateral transactions and/or their own generation 
rather than bid into the day-ahead energy market. ``Bid-based'' means 
that participants may submit offers to buy or sell quantities of energy 
into the market and may specify the prices at which they are willing to 
transact. This provides an organized and transparent system for the 
Independent Transmission Provider to determine the marginal cost of 
relieving transmission congestion. ``Security-constrained'' means that 
the Independent Transmission Provider, in the energy auction process, 
takes account of all system constraints, such as contingency limits, 
needed for reliable system operations and develops a schedule that does 
not violate such constraints. This is necessary to ensure that the day-
ahead schedule is physically feasible. Otherwise, the Independent 
Transmission Provider might be required to make additional payments in 
real time to relieve congestion, which could provide an incentive for 
market participants to create congestion in the day-ahead market to 
receive these payments in the real-time market.\142\ The market should 
allow full participation by both the supply side and the demand side of 
the market.
---------------------------------------------------------------------------

    \142\ See the discussion of this issue in Appendix E.
---------------------------------------------------------------------------

(2) Bidding and Scheduling Rules.

    270. Each day, the Independent Transmission Provider would accept 
bids to sell and buy energy for each hour of the following day. 
Participants desiring to sell or buy energy would submit a bid in a 
standardized form.
    271. Each seller's bid would indicate the amount of power (MW) 
offered to be sold, the receipt point, and the time period. In 
addition, each seller would be allowed to submit multi-part bids that 
separately specify bid prices for start-up, no-load, and energy, as 
well as technical characteristics such as ramp rates, minimum run times 
and minimum down times. Allowing suppliers' bids to include these items 
yields more detailed information that can improve the ability of the 
grid operator to dispatch suppliers with the lowest total cost. For 
example, if the supplier were required to submit a one-part bid it 
would need to include start-up costs in its energy bid, resulting in a 
higher energy price bid. However, a supplier submitting a bid that 
separately specified the energy bid and the start-up costs would not 
have to make these estimates and the grid operator would use the bids 
to dispatch the supplier with the lowest total cost. Suppliers would 
also be allowed to submit bids that are self-schedules, that is, that 
would indicate an amount to be supplied at a location regardless of the 
applicable energy price. The supplier would receive the applicable 
market clearing price for its energy. This option may be useful for 
suppliers with very high start-up costs such as nuclear facilities. 
Intermittent resources would be able to participate in the day-ahead 
market on the same basis as other resources.
    272. Similarly, each buyer's bid would indicate the desired amount 
of power (MW) to be bought, the delivery point, and the time period. In 
addition, each buyer would be allowed to specify bid prices that 
indicate the quantities it is willing to purchase at alternative 
prices. Buyers would also be allowed to submit multi-part bids that 
indicate the time and price constraints under which they are willing to 
purchase energy. These options would facilitate demand response 
programs because they allow the buyer to indicate the price at which it 
will voluntarily reduce its consumption. Buyers would also be allowed 
to schedule an amount to be purchased regardless of the applicable 
energy price.\143\ Bids would not need to be tied to a physical 
generator or load resource. However, for reliability purposes, bids 
would need to indicate whether they were purely financial bids or 
whether they were tied to a physical resource. This would permit market 
participants to bring day-ahead and real-time prices closer together, 
increasing the stability of both markets. This option should reduce 
price differences between these two markets.
---------------------------------------------------------------------------

    \143\ Since energy prices have the potential to rise to very 
high levels, it may be necessary to require buyers that request 
energy without submitting a price bid to demonstrate to the 
Independent Transmission Provider in advance that they are 
financially capable of paying very high prices for such quantities. 
Alternatively, the Independent Transmission Provider could limit the 
amounts based on a buyer's creditworthiness.
---------------------------------------------------------------------------

    273. Buyers and sellers would be able to submit different price 
bids for different hours of the day, and bids could vary from day to 
day. However, if market participants can exercise market power, limits 
may be imposed on bidding to mitigate market power, as discussed below 
in the section addressing market power monitoring and mitigation.
    274. We propose a scheduling option to address the special 
conditions facing energy-limited resources such as hydroelectric and 
environmentally constrained thermal resources. These resources are 
limited in the amount of energy or the number of hours that they can 
produce energy over a period of time. As a result, production in one 
hour may reduce the amount of energy that the resource can produce (and 
the associated revenue) in other hours. Energy-limited suppliers could 
submit bids in the day-ahead market that specify the amount of energy, 
or the number of hours, available for production over the next day. The 
supplier could then request the Independent Transmission Provider to 
schedule its energy in those hours of the next day when the energy 
price is highest. Such a scheduling feature would promote efficient 
scheduling because it would allow the energy-limited resource to be 
scheduled where its energy would have the greatest value, with maximum 
profit to the resource owner.\144\ We recognize that the

[[Page 55490]]

resource mix varies significantly from region to region and that some 
regions, such as the Northwest, have a greater amount of energy limited 
resources. We seek comment on whether other scheduling options or 
regional variations should be included for energy-limited resources in 
the tariff.
---------------------------------------------------------------------------

    \144\ While this scheduling feature is intended mainly for 
energy-limited resources, it would be available to all generators 
and would not be restricted to energy-limited resources, unless such 
restrictions are necessary to mitigate market power.
---------------------------------------------------------------------------

    275. We recognize that intermittent resources such as wind power 
may also benefit from scheduling rules that recognize their inability 
to precisely control output. We recently approved a special mechanism 
for intermittent resources selling into the energy market run by the 
California ISO.\145\ Under that mechanism, the intermittent resource 
and the California ISO work together to develop a schedule and 
procedures for accurately forecasting the output of the resources. 
However, California ISO currently runs only a real-time market for 
energy and not both a day-ahead market and real-time market as proposed 
here. Also, the amount of power produced by intermittent resources 
within California is much larger than in many parts of the country. We 
propose to include the California ISO's scheduling option for 
intermittent resources as part of Standard Market Design. However, we 
seek comment on whether there is a better way to schedule intermittent 
resources.
---------------------------------------------------------------------------

    \145\ See California Independent Operator Corp., 98 FERC [para] 
61,327, order accepting compliance filing, 99 FERC [para] 61,309 
(2002).
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    276. Finally, in drafting the bidding and scheduling rules we have 
included several ways for demand to respond to prices. We recognize 
that several ISOs currently have demand response programs that operate 
differently. Under these demand response programs, the ISO pays end-
users to reduce their demand if market clearing prices reach a certain 
level. We believe the direct approach of letting demand bid in the 
market will be less costly than a program where an end-user receives 
payments greater than the market clearing price to reduce its demand. 
We have not proposed to include these types of programs in the pro 
forma tariff although they could be included if the Independent 
Transmission Provider, in consultation with the state advisory 
committee and stakeholders, determined that they were necessary. Since 
the participation of demand in the market is critical for an effective 
wholesale market, we seek comment on whether the measures proposed are 
sufficient or if other measures should be included.

(3) Price Determination and Settlement.

    277. Based on the accepted bids included in the day-ahead schedule, 
the Independent Transmission Provider would establish day-ahead 
locational energy prices for each hour. The hourly energy price at each 
location would reflect the marginal cost (as reflected in bids) of 
producing and delivering energy to that location in that hour. Energy 
prices would be consistent with the transmission usage charges, so the 
difference in energy prices between two locations in an hour would 
reflect the cost of transmitting energy from one location to the other.
    278. The Independent Transmission Provider would establish a single 
market-clearing energy price for each hour for each node on its 
transmission system. We believe it is important that energy prices be 
calculated for each node to avoid socialization of congestion costs and 
to reduce the possibility of manipulating the congestion management 
system.\146\ The Independent Transmission Provider could also establish 
nodal prices for time intervals shorter than an hour. Nodal pricing 
would be used for both buyers and sellers in the day-ahead market.
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    \146\ See discussion in Appendix E of manipulation strategies 
involving congestion management.
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    279. Upon request of market participants, the Independent 
Transmission Provider would establish trading hubs. A trading hub is a 
virtual location where financial transactions may be arranged, whose 
hub price is the weighted average of energy prices at a specified set 
of nodes on the transmission system. A trading hub facilitates 
financial trading and aggregation of supplies from multiple sources. 
Creation of trading hubs should not lead to socialization of congestion 
costs, because the price for service at the trading hub is the weighted 
average of prices at the various nodes that are included in the trading 
hub. Energy may not be injected or withdrawn from the grid at a trading 
hub, since a hub does not exist at a physical location. But a hub may 
be named as an intermediate point between physical points of injection 
and withdrawal where financial energy trades may occur.\147\ Also, at 
the request of market participants, the Independent Transmission 
Provider would establish zones that are the weighted average of energy 
prices at selected delivery nodes on the transmission system. This 
option would permit a load-serving entity to aggregate prices for 
deliveries to its various delivery nodes.
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    \147\ A good example of a trading hub is PJM's Western hub, 
where there are active spot energy and transmission rights markets, 
as well as bilateral markets.
---------------------------------------------------------------------------

    280. Each buyer and seller would transact at the applicable 
clearing price for the hour and time period. A seller that submits 
separate bids for start-up and no-load costs and is dispatched by the 
Independent Transmission Provider for any period during the day, will 
be assured that it will recover the start-up and no-load costs that it 
bid. If a seller's total bid costs (including start-up and no-load 
costs, as well as energy running costs) over the entire day are not 
fully covered by its revenues from selling at the hourly clearing 
prices, it would receive an additional payment (i.e., an ``uplift'' 
payment) for the net revenue shortfall for the day. Hourly energy 
prices would be based only on energy bids; start-up cost bids and no-
load bids would not be used in calculating hourly energy prices. Thus, 
a generator may have legitimate start-up costs that are not fully 
covered by selling at the hourly energy price over the day; paying 
uplift may be necessary to ensure that generators selected in the 
auction will receive revenues that fully cover their bid-costs.\148\ 
Since the additional payments are a cost of providing supplies of 
energy and ancillary services in the Independent Transmission 
Provider's day-ahead market, we propose to recover the additional 
payments from entities that purchase energy and/or ancillary services 
in the Independent Transmission's Provider's day-ahead market. Any 
entity that does not buy any energy from the Independent Transmission 
Provider's day-ahead market on a given day, and that self-supplies all 
of its ancillary service obligations on that day, would

[[Page 55491]]

not be assigned a share of the additional payment for that day.
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    \148\ For example, suppose that the Independent Transmission 
Provider needs to supply an additional 100 MW load in each of 20 
hours over the next day. Two generators, A and B, are available. 
Generator A has energy costs of $35/MWh, but must incur $15,000 in 
start-up costs before beginning production. Generator B has energy 
costs of $40/MWh, and has no start-up costs. Generator A's total 
cost of meeting the load would be $85,000 (i.e., total energy costs 
of $70,000 [$35/MWh x 100 MWh x 20 hrs] PLUS start-up costs of 
$15,000). Generator B's total cost would be $80,000, comprised 
exclusively of energy costs (i.e., $40/MWh x 100 MWh x 20 hrs). 
Generator B should be chosen because its total costs ($80,000) would 
be less than Generator A's total costs ($85,000). Suppose that the 
hourly clearing price in each hour is $42/MWh. By selling 100 MWh in 
each of 20 hours, Generator B would receive total revenues of 
$64,000 (i.e., $32/MWh x 100 MWh x 20 hrs), which is $6,000 less 
than its total bid-in costs of $70,000. Generator A would thus need 
to receive a $6,000 uplift payment in addition to its energy 
revenues. Paying $6,000 in uplift is still cheaper for customers 
than the alternative of dispatching Generator B.
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    281. The results of the day-ahead market would be financially 
binding on buyers and sellers. That is, sellers would be paid the 
applicable locational day-ahead price for energy scheduled to be sold 
in the day-ahead market, and buyers would pay the applicable locational 
day-ahead price for energy scheduled to be bought in the day-ahead 
market. In addition, to the extent sellers and buyers fail to actually 
produce or take energy according to their respective schedules in real 
time, such imbalances would be settled at the applicable real-time 
energy price. Thus, a seller would pay the real-time LMP nodal price 
for any scheduled energy that it fails to deliver in real time to its 
bid delivery point. Similarly, a buyer would be paid the applicable LMP 
nodal real-time price for any scheduled energy that it does not take at 
its bid receipt point in real time.
    282. The Independent Transmission Provider would post prices and 
other market information and settle the markets promptly to provide 
market participants with reliable information regarding their market 
transactions.
    283. In certain instances, a generator may alleviate a voltage or 
stability constraint by producing real power and/or reactive power at 
its location. By alleviating the constraint, the transfer capability of 
the grid may be increased, thereby allowing a greater amount of lower-
cost energy to be transmitted to an area with higher energy prices. For 
example, the transmission capability to import power into a load pocket 
may initially be limited to 1000 MW due to a voltage or stability 
constraint, even though the thermal limit is 1500 MW. However, 
production of an additional 100 MW of real power and/or an additional 
amount of reactive power within the load pocket could increase import 
capability into the load pocket by 50 MW, to 1050 MW. We seek comment 
on whether generators who provide such real or reactive power should 
receive additional compensation (in addition to the locational market 
price for energy and the applicable compensation for reactive power) 
for the additional transfer capability that they create, to provide 
incentives to produce energy that increases transfer capability. For 
example, should such generators be given the Congestion Revenue Rights 
with the additional transfer capability that they create? In certain 
circumstances, a generator must reduce its production of real power in 
order to increase its production of reactive power. In these 
circumstances, should the generator be compensated for the opportunity 
cost of its reduced profits from selling real power? Should the 
generator be paid the higher of its opportunity costs or the market 
congestion value of the additional transfer capability created? How 
should locational market power concerns be addressed in these 
circumstances?

d. Day-Ahead Ancillary Service Markets

    (1) General Features.
    284. Order No. 888 identified six ancillary services. Under this 
proposed rule, all six ancillary services must be provided by the 
Independent Transmission Provider, but the three listed below need not 
be obtained from the Independent Transmission Provider:\149\
    (1) Regulation and frequency response
    (2) Operating reserve--spinning
    (3) Operating reserve--supplemental
    Transmission customers may meet their responsibility through self-
supply, by procuring these ancillary services from a third party, or by 
acquiring them from the Independent Transmission Provider.
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    \149\ The remaining ancillary services that must be obtained 
from the Independent Transmission Provider are (1) Scheduling, 
System Control and Dispatch Services, (2) Reactive Supply and 
Voltage Control Service, and (3) Energy Imbalance Service. We seek 
comment on treating Scheduling, System Control and Dispatch Services 
as a basic cost of providing transmission service instead of as an 
ancillary service.
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    285. As discussed earlier, imbalance energy would be provided 
through the day-ahead and real-time energy markets. For the remaining 
three ancillary services (regulation and both operating reserves), we 
propose to require that the Independent Transmission Providers operate 
bid-based markets open to all potential suppliers so that Independent 
Transmission Providers can procure these ancillary services from the 
lowest cost suppliers. Different regional reliability authorities may 
establish different requirements for operating reserve--supplemental. 
For example, the four jurisdictional operating ISOs procure resources 
for the ancillary service operating reserve--supplemental (which are 
usually generation resources that are not synchronized with the grid or 
demand-side resources that can curtail use), with varying response 
times. Each ISO procures a portion of their necessary operating 
reserve--supplemental requirement with reserves that can respond within 
10 minutes of a dispatch request, as well as slower-responding reserves 
at 30 minutes (New York ISO and ISO-New England) and 60 minutes 
(California). Since different regional reliability authorities have 
established different response times for operating reserve--
supplemental, we do not propose a standard set of markets for operating 
reserve--supplemental. However, we propose to require that each 
Independent Transmission Provider operate separate markets for each 
type of operating reserve--supplemental that it procures.
    286. Location-specific reserve targets may be required in some 
areas due to persistent and significant congestion. The Independent 
Transmission Provider would identify and establish these targets 
consistent with any reliability rules.
    (2) Bidding and Scheduling Rules.
    287. Each day, the Independent Transmission Provider would 
determine the total amount of each of the ancillary services that will 
be required for each hour of the following day. Customers that wish to 
meet their ancillary service requirement through self-supply or 
procurement through a third party would be required to provide the 
Independent Transmission Provider with the necessary information about 
the generation capacity or demand-side resource that would be providing 
the ancillary services (as is currently required under the existing pro 
forma tariff).
    288. To procure the remaining amount of ancillary services, the 
Independent Transmission Provider would accept bids for regulation and 
the types of operating reserves for each hour of the following day. A 
participant desiring to sell regulation or operating reserves would 
submit a bid in a standardized form specified by the Independent 
Transmission Provider. Bids could be offered to provide ancillary 
services from generation capacity or any demand-side resource that 
meets the technical requirements of the ancillary service. Participants 
could offer the same capacity in more than one ancillary service 
market, as well as in the energy market.
    289. Each bid would indicate the type of ancillary service, the 
amount of generating capacity (MW) offered for sale, the receipt point 
of the resource and the time period. The bid would also include an 
availability bid indicating the minimum price per MW (which could be 
either a positive amount or zero) required to provide the ancillary 
service. The availability bid would allow the bidder to ensure that it 
would not be selected to provide the ancillary service unless the 
ancillary service price is high enough to cover out-of-pocket costs, 
such as the costs of keeping a crew at its facility for the following 
day. The bid would also include the various components that would be 
submitted to

[[Page 55492]]

provide energy into the energy market. These components include an 
energy bid, indicating the minimum price per MWh required to produce 
energy. Other bid components would include price-bids for start-up and 
no-load, as well as technical constraints, such as minimum load, ramp 
rates, minimum run time and minimum down time. By providing one 
ancillary service, a bidder may forgo profits from sales in other 
markets, and these forgone profits are an opportunity cost of providing 
ancillary services. As explained in the following section, the 
Independent Transmission Provider will consider the opportunity cost 
associated with forgone sales in other markets operated by the 
Independent Transmission Provider. Opportunity costs from forgone sales 
in markets not operated by the Independent Transmission Provider could 
be included in the bidder's availability bid.
    290. The Independent Transmission Provider would consider all bids 
to sell ancillary services, in conjunction with bids submitted in its 
day-ahead markets for energy and transmission service. As noted 
earlier, based on all submitted bids, the Independent Transmission 
Provider would maximize the economic value (as reflected in the bids) 
of the accepted bids, i.e., accept the bids with the overall lowest 
cost. Thus, for generation capacity and demand-side resource that bid 
into more than one market, the Independent Transmission Provider would 
schedule the generation capacity or demand-side resource into the 
market where it is most efficient (unless it is not efficient to 
schedule the generation capacity or demand-side resource in any 
market).\150\ This should yield the overall lowest cost for procuring 
energy, regulation and operating reserves.
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    \150\ Because of the way that prices would be established in 
each market, the market into which each bidder of generation 
capacity or demand-side resource is scheduled would also be the 
market that is the most profitable for the bidder. That is because, 
as discussed in the following section, the prices in each market 
would reflect marginal opportunity costs of the bidders in that 
market. Thus, the price in each market would be high enough to allow 
each accepted bidder in that market to receive at least as much 
profit as it could have received in any other market operated by the 
Independent Transmission Provider that it is technically capable of 
participating in.
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    (3) Price Determination and Settlement.
    291. Based on the accepted bids included in the day-ahead schedule, 
the Independent Transmission Provider would establish day-ahead prices 
for each of the ancillary services procured in the bid-based markets 
for each hour. In regions with separate locational ancillary service 
requirements, the Independent Transmission Provider would establish 
separate hourly locational ancillary services prices.
    292. To promote an efficient market, the price for regulation and 
operating reserves services would equal the marginal cost of each 
service, which would equal the highest accepted total bid cost 
expressed in dollars per MW. The total bid cost of each generator is 
the sum of: (1) The generator's availability bid per MW and (2) the 
opportunity cost of forgoing sales in other markets operated by the 
Independent Transmission Provider, expressed on a per-MW basis.\151\
---------------------------------------------------------------------------

    \151\ Because prices are determined hourly, an opportunity cost 
expressed in dollars per MWh converts to an equivalent dollar-per-MW 
basis.
---------------------------------------------------------------------------

    293. A generator or demand-side resource could be eligible to bid 
into more than one market operated by the Independent Transmission 
Provider. The opportunity costs paid to the supplier would be the 
forgone profit from the most profitable other market. For example, a 
generator that is capable of providing ancillary services could also 
sell into the transmission provider's day-ahead energy market, although 
it would incur additional variable energy costs to do so. Thus, the 
forgone profit from selling into the energy market (as reflected in the 
generator's bid) would be the difference between the energy price and 
the generator's energy bid. The opportunity cost of selling ancillary 
services would include this forgone energy profit.
    294. The hourly price for one of these ancillary services in a 
given location would thus equal the sum of the opportunity cost and the 
availability bid in dollars per MW of the most expensive unit accepted 
to provide that type of ancillary service in that hour to that 
location. As noted above, a generator providing any ancillary service 
is also technically capable of providing a slower response ancillary 
service. For example, a generator providing operating reserve--spinning 
could also provide operating reserve--supplemental. Thus the 
opportunity cost of providing operating reserves--spinning would be at 
least as high as the price of operating reserve--supplemental. As a 
result, the marginal cost (and thus, the price) of operating reserve--
spinning would not be less than the price of operating reserve--
supplemental in the same hour.
    295. Although suppliers bid to provide these ancillary services in 
the day-ahead market, customers pay for them based on real-time load. 
Transmission customers would be assessed a pro rata share of the total 
ancillary service requirements for each of these three ancillary 
services in each hour, based on their real-time, load-ratio share. 
Ancillary service requirements generally depend more on real-time 
transactions than on day-ahead schedules. Assessing ancillary service 
requirements based on day-ahead schedules would provide an incentive 
for customers to understate their day-ahead schedules.
    296. In Order No. 888, exports are not charged for these ancillary 
services. We ask for comments on whether they should be charged here.
    297. Customers that want to self-provide or procure their own 
ancillary services would be required to notify the Independent 
Transmission Provider in the day-ahead scheduling process and identify 
the resources that would be used to provide these services. Customers 
would be given credit for the amount of ancillary services that they 
self-provide or procure from third parties. Customers that self-provide 
or procure from third parties more capacity than their requirements 
would be paid the applicable hourly ancillary service price for the 
excess if needed by the market.\152\
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    \152\ Since the customer's day-ahead schedule was based on its 
projected share of the ancillary service requirement, it may have 
procided more than its actual share in real time. Thus, the customer 
would be comlpensated for the additional amounts it provided.
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2. Scheduling After the Close of the Day-Ahead Market

a. Replacement Reserves

    298. The Independent Transmission Provider will use the day-ahead 
market to develop prices and a schedule for suppliers. The prices and 
schedules will be based on the bids submitted by buyers and sellers. 
However, the day-ahead schedule may be less than the forecasted load in 
real time and, if so, the Independent Transmission Provider would 
commit additional units to ensure that load can be met reliably in real 
time.
    299. After the Independent Transmission Provider has established a 
day-ahead schedule and associated prices for energy, transmission 
service and ancillary services, it would make its own forecast of load 
within its market area for each hour of the following day. To the 
extent that its forecasted load exceeds the amount of energy scheduled 
to be delivered to load in the day-ahead schedule, the Independent 
Transmission Provider may need to procure additional reserves (called 
``replacement'' reserves) from generators to make up the difference, 
but only to

[[Page 55493]]

the extent necessary to ensure that sufficient generation will be 
available to meet load.
    300. To procure replacement reserves, the Independent Transmission 
Provider would accept bids from generators submitted for the day-ahead 
market. The Independent Transmission Provider would select generators 
to provide replacement reserves so as to minimize the costs of 
availability, start-up costs and no-load costs regardless of energy 
costs. This approach to procuring replacement reserves would provide an 
incentive for load to accurately bid its load in the day-ahead market 
since energy prices may be higher in the real-time market.
    301. As discussed further in the next section, generators selected 
to provide replacement reserves would be included in the real-time 
energy bid stack along with other generators that submit bids into the 
real-time market to provide energy. Generators selected to provide 
replacement reserves would be paid the applicable real-time energy 
price for energy that they produce. If a generator's revenues received 
from selling real-time energy are less than its bids for availability, 
start-up, no-load and energy, the Independent Transmission Provider 
would pay the generator an additional payment (i.e., an ``uplift'' 
payment) for the shortfall. The revenue shortfall would be recovered 
pro rata from all loads that buy energy in real time that have not been 
scheduled in the day-ahead market. Thus, the costs would be allocated 
to the customers that benefitted from the replacement reserves--
customers that took power in real time. This provides an incentive for 
load to accurately predict its requirements in the day-ahead market.
    302. We propose to add a new Section G.2 to the pro forma tariff 
that would implement the foregoing procedures for scheduling and paying 
for reserves after the close of the day-ahead market.

b. Changes to Transmission Schedules

    303. A market participant that has not scheduled transmission 
service in the day-ahead market but desires transmission service in 
real time must inform the Independent Transmission Provider within 
specific time deadlines before real time. Market participants may 
change their day-ahead transmission service schedule by informing the 
Independent Transmission Provider consistent with the time deadlines.
    304. Participants that have informed the Independent Transmission 
Provider of their desired changes within the Independent Transmission 
Provider's lead times, and adhere to the requested changes in real 
time, would settle the changes in transmission service at the 
applicable real-time transmission usage prices, described more fully 
below. Participants with new or increased transmission service would be 
charged the applicable real-time transmission usage price between the 
applicable receipt and delivery points for the new or increased 
transmission service in the applicable hour. Conversely, participants 
that reduce transmission service in real time (compared to the day-
ahead schedule) would be paid the applicable hourly real-time 
transmission usage price for the applicable receipt and delivery 
points, to compensate them for the additional transmission capacity 
they have made available in real time.
3. Design of the Real-Time Markets
    305. Under Standard Market Design, the Independent Transmission 
Provider would be required to operate bid-based, security-constrained 
real-time markets for transmission service, energy, and certain 
ancillary services (i.e., regulation, operating reserve--spinning and 
operating reserve--supplemental).

a. Real-time Energy Markets

    (1) General Features.
    306. Under the Standard Market Design, the Independent Transmission 
Provider would accept bids to buy and sell energy in each hour in the 
real-time energy market. The bids would be in the standardized form 
specified by the Independent Transmission Provider. Real-time energy 
markets would be used to provide the energy imbalance service of Order 
No. 888 pro forma tariff. However, loads could voluntarily enter into 
bilateral contracts with suppliers in advance to lock in a fixed price 
for energy.
    (2) Bidding and Scheduling Rules.
    307. In general, bids would indicate an offer to depart in real 
time from the bidder's day-ahead schedule to purchase or sell energy 
(including a day-ahead schedule to purchase or sell 0 MWhs of energy). 
Real-time bids would be accepted from any market participant, including 
generators, load-serving entities, eligible retail buyers, marketers 
and other agents. Bids would indicate the increase or decrease (in 
MWhs) from the day-ahead schedule in the amount of energy to be sold or 
purchased in real time, and the location and the hour of the changed 
purchase or sale. Each participant bidding into the real-time energy 
market would be allowed to include multi-part price bids similar to 
those allowed in the day-ahead energy market (this is a departure from 
the Working Paper).
    308. The transactions in real time vary from those reflected in the 
day-ahead schedule due to a variety of factors, including changes in 
weather conditions and unexpected equipment outages. The Independent 
Transmission Provider may be informed in advance of some of the 
scheduling departures under the procedures described above; other 
departures may occur without warning.
    309. As occurs today, an Independent Transmission Provider will 
have to adjust energy production and/or load at various locations in 
order to balance generation with load and manage congestion. Under 
Standard Market Design, the Independent Transmission Provider would 
make these adjustments by calling upon participants that have submitted 
bids into the real-time energy market, as well as participants that 
have been selected to provide spinning, supplemental, and replacement 
reserves. The Independent Transmission Provider would issue dispatch 
instructions to bidders so as to balance generation and load, and 
efficiently manage congestion of demand and supply.
    (3) Price Determination and Settlement.
    310. The Independent Transmission Provider would determine energy 
prices in the real-time energy market for each node for each 5-minute 
period or other subhourly period where a 5-minute determination is not 
technically achievable. Each price would reflect the marginal cost (as 
reflected in the real-time supply and demand bids) of producing energy 
and delivering it to the node in that period. The Independent 
Transmission Provider would post prices and other market information 
and settle the markets promptly to give market participants reliable 
information regarding their market transactions.
    311. To promote efficient participant decisions regarding real-time 
transactions, we propose that all departures in real time from the day-
ahead schedule be settled through the real-time market at the 
applicable price (as is done today in many markets). Nodal pricing 
would be used for both buyers and sellers in the real-time market.
    312. There are several aspects of the design of the real-time 
energy market where we seek additional comments.
Ex Post Versus Ex Ante Prices
    313. This Section discusses how to determine real-time energy 
prices. The options are to set the prices using near

[[Page 55494]]

real-time estimates (ex ante), or base the price on the price of the 
actual marginal resource clearing the market in real time (ex post). 
Immediately in advance of each upcoming 5-minute period, the 
Independent Transmission Provider would announce the real-time energy 
prices that it estimates will clear the market and match generation 
with load during that upcoming period (based on the real-time bids 
submitted by market participants). The Independent Transmission 
Provider could settle all departures in real-time from the day-ahead 
schedule using these prices announced in advance. Such an ex ante 
pricing policy would provide price certainty and thereby encourage 
buyers and sellers that have not submitted bids to adjust their 
transactions in response to the announced price.
    314. Alternatively, an ex post pricing policy could be used as an 
incentive for suppliers to follow dispatch instructions. Some bidders 
may not respond to the announced prices in the way suggested in their 
bids. For example, a supplier stating in its bid that it would increase 
its output by 50 MWh for each price increase of $5/MWh may in fact 
increase its output by less than 50 MWh in response to such a price 
increase. By settling at the ex ante price, the generator would be paid 
the higher price despite the fact that it did not increase its output 
as it had promised in its bid. An ex post pricing rule might help to 
encourage bidders to respond in real time in a way consistent with 
their bids. Specifically, the price used to settle real-time deviations 
from day-ahead schedules could be the price-bid associated with the 
energy observed ex post to be produced by the marginal supplier in the 
5-minute period (but not higher than the advisory price announced ex 
ante). Such an ex post price rule would encourage suppliers to supply 
the full amount of energy promised in their bids.
    315. We propose to adopt the ex post rule because it creates 
incentives for bidders to act consistent with their bids. We seek 
comment on the choice between ex post and ex ante pricing.
Other Charges for Uninstructed Deviations From Schedules
    316. We seek comment on whether market participants should face 
additional charges for ``uninstructed'' deviations in real time from 
their schedules, i.e., for producing or taking a different amount of 
energy in real time than was scheduled without permission or direction 
from the Independent Transmission Provider. Uninstructed deviations 
from schedules may increase the amount of regulation service or other 
ancillary services that the Independent Transmission Provider must 
procure, in order to reliably balance load and generation. If so, it 
would be appropriate to recover the costs of these services through a 
charge. We seek comment on whether the increased costs of regulation 
service or ancillary services should be allocated to the entities 
(buyers and sellers) that had uninstructed deviations from their 
schedules since the costs were incurred to serve these entities. 
Uninstructed deviations may also require the use of scarce ramping 
capability within the Independent Transmission Provider's market area. 
If ramping capability were used, it may be appropriate to charge for 
that use. We seek comment on whether and how to establish market prices 
for ramping capability. Finally, in extreme cases large uninstructed 
deviations can threaten reliability of service. To discourage this type 
of conduct a penalty provision may be appropriate.\153\ We seek comment 
on whether the SMD Tariff should include penalty provisions for 
uninstructed deviations that threaten system reliability and how such 
penalty provisions should be structured.
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    \153\ This penalty would be in addition to any penalties 
incurred for violating curtailment orders.
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What Bids Should Be Eligible To Set the Energy Price
    317. Strictly speaking, the marginal cost of meeting a small 
increment of load would be based on the bids of suppliers whose output 
can be increased, or buyers whose load can be decreased, from their 
scheduled level in the hour by as little as 1 MW. Thus, for example, 
the marginal cost of supplying load in an hour would not be based on 
the bid of any generator that is operating in the hour solely because 
of a minimum run constraint, because changes in load would not change 
the output of the generator.\154\
    318. However, we are concerned that by excluding generators whose 
output is adjustable in increments greater than 1 MW, on an hourly 
basis, from setting the energy price may not promote efficient 
results.\155\ These potential inefficient results are more likely to 
occur in the real-time market than in the day-ahead market.\156\ 
Therefore, we propose to allow generators whose output is adjustable on 
an hourly basis, but only in increments greater that 1 MW, to be 
eligible to set the energy price in the Real-Time Market if two 
conditions are met. First, the generator's output must be needed to 
meet load in the hour. That is, in the absence of the generator's 
output, either load could not be fully met or a more expensive 
generator would be needed to fully meet load. Second, the reason that 
the generator is operating must not be a minimum run time constraint. 
We also propose that any cheaper generators that are directed to reduce 
their output would be paid their opportunity costs (i.e., the 
difference between the applicable energy price and their energy bids) 
for the amount of the output reduction. With this payment, the 
generator is compensated for the legitimate opportunity cost of 
following the Independent Transmission Provider's instructions.\157\
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    \154\ Also, a generator that is operating at its low operating 
limit would not be able to set the market-clearing price.
    \155\ When such ``lumpy'' generators are needed to meet 
incremental load, it may be necessary to reduce the output of 
cheaper but more flexible generators (i.e., generators whose output 
can be adjusted in 1 MW increments.) For example, to meet a 30 MW 
increase in load, the cheapest available generator (with a bid of 
$80/MWh) may be a combustion turbine with a capacity of 50 MW that 
can produce only at its maximum capacity. By operating the 
combustion turbine at 50 MW, the output of a cheaper flexible 
generator (with a bid of $60/MWh) would need to be reduced by 20 MW 
in order to match the 30 MW increase in load with the net increase 
in generated output. Once the flexible $60 generator is backed down, 
incremental load would be met with output from the flexible 
generator, so the marginal cost of meeting load would be $60. 
However, it would not be efficient to meet the additional load 
unless the load valued electricity at more than $80, the cost of the 
combustion turbine.
    \156\ In the real-time market, some market participants that 
have not submitted bids may nevertheless adjust their production or 
consumption. Thus, the rules for setting energy prices in the real-
time market should consider these possible effects on market 
participants that have not submitted bids. By contrast, day-ahead 
schedules are based only on bids and self-schedules submitted to the 
Independent Transmission Provider, so day-ahead prices cannot result 
in any unexpected changes in the day-ahead schedule.
    \157\ These payments would be recovered through an uplift charge 
to loads that purchase from the Independent Transmission Provider's 
markets.
---------------------------------------------------------------------------

    319. We seek comment on whether such lumpy generators should also 
be eligible to set the energy price in the day-ahead market. Although 
allowing these lumpy generators to set the energy price may have more 
direct benefit in the real-time market, we are concerned about 
potential negative ramifications from establishing different pricing 
rules for the day-ahead and real-time markets.

b. Real-Time Ancillary Services Markets

    320. As discussed earlier, Order No. 888 requires transmission 
providers to offer to provide to transmission customers energy 
imbalance service, regulation and frequency response, operating 
reserve--spinning and operating reserve--supplemental. Under Standard 
Market Design, energy

[[Page 55495]]

imbalance service would be provided through the transmission provider's 
real-time energy market. The Independent Transmission Provider would 
procure its expected requirements for the remaining three ancillary 
services through day-ahead ancillary service markets discussed above.
    321. We propose that the Independent Transmission Provider operate 
a real-time ancillary services market to accommodate adjustments in the 
supply of ancillary services from the day-ahead schedule. In real time, 
there may be entities that can provide ancillary services more 
efficiently than those that were scheduled in the day-ahead market. The 
real-time market would permit such efficient substitutions. Higher-cost 
suppliers scheduled in the day-ahead market would buy back their offer 
to provide ancillary services at the applicable real-time price, and 
other, lower-cost entities would be paid the real-time price to take 
over the supply of ancillary services. In addition, the Independent 
Transmission Provider may need an amount of ancillary services that 
differs from the amounts procured in the day-ahead market, for several 
reasons. For example, the requirements expected in the day-ahead market 
may differ from actual, real-time requirements, or participants 
scheduled to provide ancillary services may experience outages in real 
time. Under Standard Market Design, the Independent Transmission 
Provider would procure any additional ancillary services needed in real 
time through the real-time ancillary service markets that it operates.
    322. In the real-time market, the Independent Transmission Provider 
would accept bids for each ancillary service. As in the day-ahead 
market, a participant could offer the same capacity in more than one 
ancillary service market. The real-time bids would contain the same 
types of information as those submitted into the day-ahead ancillary 
service markets, with one exception--we propose to exclude availability 
bids for spinning reserves and supplemental reserves in real time. The 
types of costs reflected in the availability bid to ensure that the 
supplier will be available to provide these reserves are incurred in 
the day-ahead time frame, not in real time.\158\ There do not appear to 
be any incremental costs associated with providing these ancillary 
services in real time, other than the opportunity costs of forgoing 
sales in another market operated by the Independent Transmission 
Provider, and these opportunity costs would be reflected in the way 
that ancillary service prices are determined.\159\
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    \158\ For example, the supplier may need to commit in advance to 
pay workers to staff its facility. However, the supplier would be 
able to offer to supply spinning reserves and supplemental reserves 
in real time if its workers were already staffing its facility, so 
in real time the supplier would not incur increment costs to provide 
ancillary services.
    \159\ Providing regulation service, however, would typically 
impose incremental out-of-pocket costs on the supplier, due to the 
additional wear and tear on equipment associated with frequent 
adjustments in output that regulation suppliers must make.
---------------------------------------------------------------------------

    323. The Independent Transmission Provider would consider all bids 
to sell ancillary services in real time and select those bids that 
minimize the overall cost of procuring additional ancillary services 
required in real time.
    324. Based on the bids accepted in the real-time market, the 
Independent Transmission Provider would establish real-time ancillary 
service prices for each hour that reflect the marginal cost of each 
service. All participants supplying a given type of ancillary service 
in a given hour in real time (and to a given location, if there are 
locational ancillary service requirements) would be paid the applicable 
market clearing price.
    325. Transmission customers that have not self-supplied or procured 
through third parties their full assigned ancillary service requirement 
would be assessed a pro rata share of the costs incurred by the 
Independent Transmission Provider for procuring ancillary services in 
real time.
4. Market Rules for Shortages or Emergencies
    326. We believe the market rules discussed above in combination 
with the market mitigation measures and the resource adequacy 
requirement will result in an efficient system for matching supply and 
demand under most operating conditions. However, we recognize that when 
emergency situations do occur, changes may be needed to the market 
rules to comply with reliability requirements. In the event of a 
capacity shortage or emergency, local reliability rules and procedures 
(which typically combine NERC, regional reliability council and system 
operator guidelines) prescribe a series of actions that the system 
operator takes to maintain reliability. For example, procurement of 
reserves is reduced, typically in order of reserve quality (that is, 
supplemental reserve quantities are reduced before spinning reserve 
quantities). The system may be re-dispatched to adjust the location and 
responsiveness of remaining reserves. System operators have also 
traditionally called on emergency supplies from neighboring systems (in 
the past, these emergency purchases have taken place at pre-defined 
prices; increasingly, they are being made at market prices). Finally, 
steps are taken for voluntary and involuntary load-shedding. States 
typically approve in advance the retail curtailment plans of utilities.
    327. In the markets proposed in the SMD Tariff, we envision that 
with more extensive demand-side participation, the potential for these 
types of capacity shortage or emergency situations will substantially 
diminish. However, system emergencies may occur. The existing pro forma 
tariff gives transmission providers the authority to curtail 
transmission service and take any other preventive action necessary to 
preserve system reliability. The SMD Tariff would continue to grant the 
Independent Transmission Provider this same authority. However, the 
actions taken to ensure system reliability can affect prices in the 
energy and ancillary service markets. Market participants should be 
aware of how these actions will affect pricing in the markets operated 
by the Independent Transmission Provider. To that end, the SMD Tariff 
requires Independent Transmission Providers to file proposals with the 
Commission regarding the implications for market pricing of each 
reliability procedure. These proposals would need to be consistent with 
the resource adequacy mechanisms discussed below, but could vary to 
reflect regional differences in reliability requirements. We seek 
comments on what, if any, more specific requirements should be included 
in the Final Rule.

G. Other Changes To Remove Undue Discrimination and Improve the 
Efficiency of the Markets Under Standard Market Design

    328. The existing pro forma tariff was constructed primarily to 
apply to vertically integrated public utilities. It was the first step 
toward competitive electric power markets since it allowed alternate 
suppliers to access loads through an open access transmission tariff. 
It sought to replicate the terms and conditions under which the host 
public utility served its own loads. It also was the first step in 
separating the generation and transmission arms of a public utility.
    329. But more changes are needed to further the development of 
regional competitive wholesale electric markets and assure comparable 
and non-discriminatory treatment of all market participants. 
Accordingly, the following revisions must be made to the pro forma

[[Page 55496]]

tariff to change the market rules in ways that will improve the 
efficiency of wholesale electric markets.
1. Capacity Benefit Margin
    330. Capacity Benefit Margin is the set-aside of transmission 
capability by a transmission provider to ensure the ability to import 
external resources to meet generation reliability requirements or in 
case of a generation capacity deficiency. During the Commission's 
outreach process, many commenters asserted that Capacity Benefit Margin 
ties up valuable transfer capability without a specific reservation and 
payment by the customers who receive the benefit of the set-aside. The 
subsidy occurs because, while part of the transfer capability is 
withheld from the market as Capacity Benefit Margin, the wholesale 
transmission customers using the system pay the entire transmission 
cost (including that of the Capacity Benefit Margin) through their 
transmission charges, thus subsidizing the Capacity Benefit Margin 
beneficiaries. The use of a Capacity Benefit Margin has also been 
regularly challenged on the grounds that the host transmission provider 
is withholding transfer capability under the guise of Capacity Benefit 
Margin in order to thwart competition.
    331. We propose to standardize the treatment of Capacity Benefit 
Margin to ensure that (1) only customers benefitting from it pay for 
it, and (2) transfer capability needed to access resources on a 
neighboring system is treated consistent with all other portions of the 
transmission grid. Thus, an Independent Transmission Provider itself 
would not be permitted to set aside transfer capability for generation 
reliability reasons. Rather, a load-serving entity wanting access to 
resources on a neighboring transmission system to meet its resource 
adequacy requirement should instead acquire Congestion Revenue Rights 
from the interface to its load to ensure that access. This will free up 
transfer capability now unavailable to wholesale transmission customers 
and prevent cross-subsidization of transmission customers that serve 
load within the Independent Transmission Provider's service area by 
point-to-point transmission system users.\160\
---------------------------------------------------------------------------

    \160\ To the extent that an Independent Transmission Provider's 
load ratio share access charge calculation does not pick up this 
reservation, the amount of interface capability can be imputed and 
added to the customer's peak day amount.
---------------------------------------------------------------------------

    332. This prohibition of the generic set-aside of transfer 
capability by the Independent Transmission Provider for generation 
reliability reasons does not apply to an Independent Transmission 
Provider's responsibility to set aside transfer capability to ensure 
transmission reliability (e.g., to ensure that a line can take up the 
power flows it must absorb if a parallel line should go out of service 
or other uncertainties in system conditions arise). Such a set-aside is 
called Transmission Reliability Margin and must be consistent with good 
utility practice and should not be implemented in a way that favors 
particular transmission customers (e.g., by release of the set-aside 
capability for use by native load).
2. Regional and Independent Calculation of Available Transfer 
Capability, Performance of Facilities Studies and OASIS
    333. The Commission has found specific instances of abuse by 
transmission providers regarding the Available Transfer Capability 
calculation process and delays in the completion of transmission 
facilities studies.\161\ There are obvious incentives for a vertically 
integrated transmission provider to favor its own generation by 
delaying facilities studies or manipulating the Available Transfer 
Capability calculations or postings on its OASIS. Under Standard Market 
Design, calculations of transmission capability and the performance of 
facilities studies for transmission expansions must be performed by an 
independent entity to reduce the opportunity for preferential treatment 
by the transmission provider.
---------------------------------------------------------------------------

    \161\ See Section III and Appendix C.
---------------------------------------------------------------------------

    334. More broadly, the SMD Tariff must recognize the regional 
nature of today's energy markets. Transmission capabilities must be 
calculated not for a single utility's service territory, but regionally 
to encompass existing trading patterns and power flows, particularly 
parallel path flows on neighboring systems. All transmission providers 
that are not part of a Commission-approved RTO must contract with an 
independent entity to perform transmission capability calculations on a 
regional basis. Likewise, we propose to require a common OASIS for the 
region.
3. Regional Planning Process
    335. Competitive and reliable regional power markets require 
adequate transmission infrastructure to allow geographically broad 
supply choices and minimize the complications created by loop flow. The 
recent DOE National Grid Study documented the problems resulting from 
recent under-investment in transmission infrastructure and identified a 
number of causes. Among the causes were the lack of regional planning 
and coordination of transmission needs and siting issues.
    336. Transmission planning and expansion have generally been 
performed for a single control area rather than on a regional basis. 
This yields sub-optimal solutions, as individual transmission providers 
consider power flows across a limited area and do not adequately 
consider entire markets. Parallel path flows that occur on neighboring 
systems may make the construction of specific facilities less cost-
effective than a regional solution. This effect can be properly 
considered by performing transmission planning and expansion on a 
regional basis. Moreover, facilities that, if constructed in one system 
would be the optimal solution for a neighboring system, might never be 
considered under a single control area-based planning model.
    337. Implementation of Standard Market Design will only increase 
the importance of examining these issues on a regional basis. More open 
and transparent markets will enable customers to purchase from distant 
suppliers, increasing use of the grid. Locational marginal prices that 
result from the spot markets operated by an Independent Transmission 
Provider would signal to all market participants the value of 
additional supply and demand response at particular locations. Based on 
these prices over time, market participants will be able to decide 
whether additional investment--in transmission or generation facilities 
or demand response--is warranted. The ability of individual market 
participants to see the economics of possible solutions and make 
market-driven decisions concerning the addition of infrastructure is 
the fundamental mechanism that induces efficient investment under 
Standard Market Design. The policy relies primarily on a ``ground-up'' 
planning process that encourages construction by private companies yet 
also recognizes the need for a regional evaluation process for loop 
flow effects and cost-effectiveness. It is neutral with respect to the 
type of investment market participants may make in response to these 
price signals. However, due to loop flow, all system modifications 
would need to be coordinated through a regional process and would have 
to meet any criteria needed to maintain reliability and stability, and 
assure that existing customer rights are not impaired.
    338. Given the need for transmission investment in much of the 
country and the time it will take to implement Standard Market Design 
and for

[[Page 55497]]

investors to observe and respond to price signals, we propose that a 
regional planning process be instituted within six months of the 
effective date of the Final Rule. This process should be designed to 
identify beneficial transmission needed for both reliability and 
economic reasons to support regional markets and reduce the effects of 
generation concentration. The regional planning process should allow 
the market to respond to those identified needs.
    339. A critical piece of the transmission planning process is 
state-level siting decisions. We note a recent National Governors' 
Association report that recommends Multi-State Entities to facilitate 
regional transmission planning decisions.\162\ Multi-State Entities, 
along with an open regional planning process, would preserve the 
states' role in siting decisions, while promoting regional solutions. A 
Multi-State Entity could be an important component of the regional 
planning process.
---------------------------------------------------------------------------

    \162\ See Interstate Strategies for Transmission Planning and 
Expansion, National Governors' Association, posted on July 18, 2002, 
available in .
---------------------------------------------------------------------------

    340. Certain areas of the country and organizations already have 
proposals or processes to consider regional planning or development of 
regional markets. Building off of these existing efforts will help 
facilitate the development of a regional planning process in the near 
term. We emphasize that a planning area need not coincide with the 
geographic area of a Commission-approved RTO or Independent 
Transmission Provider required by this rule. Also, because of the 
interrelationships between Canadian and U.S. energy markets, we 
encourage participation by Canadian entities and provincial authorities 
in the regional planning process.
    341. Current processes such as the Committee on Regional Electric 
Power Cooperation in the West provide for state and provincial advice 
in the planning across the entire Western grid. Therefore, we propose 
to use the area covered by Western Electricity Coordinating Council 
(WECC) that encompasses the geographic area covered by the Western Grid 
for regional planning purposes.
    342. In the Eastern Interconnection there have been several efforts 
at developing regional wholesale electricity markets that we propose to 
build on for the regional planning process. PJM and MISO developed a 
Memorandum of Cooperation dated May 9, 2002 that commits to develop a 
joint and common wholesale electric market for PJM, MISO, and SPP. 
Consequently, we propose that the area covered by these organizations 
would also be a regional planning area.
    343. Similarly, New York ISO and ISO-New England are currently 
pursuing discussions on the merger of these two organizations into a 
Northeast RTO. Both are also members of the Northeast Power 
Coordinating Council which has recently conducted studies of 
transmission needs in the region.\163\ We propose to build on these 
efforts and use the area covered by these organizations as a planning 
area.
---------------------------------------------------------------------------

    \163\ Northeast Power Coordinating Council Collaborative 
Planning Initiative Phase I issued March 13, 2002.
---------------------------------------------------------------------------

    344. Finally, we recognize that there has been ongoing discussion 
development of regional markets in the Southeast. SETrans Regional 
Transmission Organization proposes to encompass a broad area in the 
Southeast. The Tennessee Valley Authority (TVA) has signed a Memorandum 
of Understanding with Southern Companies and Entergy, two sponsors of 
SETrans, to work together to develop coordination agreements. 
Additionally, the SETrans and GridSouth Transco, LLC parties signed a 
Memorandum of Understanding in January 2002 calling for similar 
regional coordination. Thus we propose to build on these efforts and 
propose a Southeast planning area composed of the Southeastern Electric 
Reliability Council and the Florida Reliability Coordinating Council.
    345. We propose that all public utilities that own, control, or 
operate transmission facilities must participate in a regional planning 
process for the planning areas discussed above. We propose that this 
process start within six months after the effective date of the Final 
Rule and that the first regional transmission plan be completed within 
twelve months after the effective date of the Final Rule. Reliance on 
these existing regional efforts should facilitate the start-up of the 
regional planning process before Standard Market Design is implemented 
and all areas have Independent Transmission Providers operating 
transmission facilities.
    346. After Standard Market Design is fully implemented, we believe 
the regional planning process will change as Independent Transmission 
Providers play a greater role in that process. There will still remain 
a significant need for a regional planning process to supplement 
private ``ground up'' investment decisions. The regional planning 
process is intended to supplement these private investment decisions, 
not supplant them. The regional planning process must provide a review 
of all proposed projects to assess whether the project would create 
loop flow issues that must be resolved on a regional basis. In 
addition, because of the externalities involved, there may be no 
private investment sponsor for some projects that would benefit the 
region. Private investment decisions in response to prices may not 
result in adequate expansions for two reasons. First, private parties 
may not be eligible to ask the state to exercise its eminent domain 
rights. Second, some needed and beneficial expansions may not create 
enough identifiable financial benefits to compensate private investors 
adequately, so those projects will not be built under a system that 
relies solely on private investment to expand the grid. A regional 
planning process can identify both the projects that would benefit the 
planning area and potential alternatives in a fair and unbiased manner. 
Additionally, a regional planning process, would evaluate the benefits 
of alternative proposals and provide an independent assessment of which 
projects are the most cost effective and/or have the least 
environmental impact.
    347. To complement private investment initiatives, we propose that 
Independent Transmission Providers establish a mechanism for regional 
transmission planning and expansion guided by the following principles. 
First, the planning process should identify all expansion needs on the 
system, including both reliability and economic needs (e.g., to reduce 
congestion). The planning process should leave open the question of how 
and by whom those needs should be met, without favoring one solution 
(whether it is transmission, generation or demand response) over 
another. The planning process should be open to all industry segments. 
Additionally, all entities could propose projects. As long as the 
project did not make existing Congestion Revenue Rights infeasible due 
to loop flow problems, the entity would be free to complete the project 
as long as it is willing to assume any market or regulatory risk. 
However, to the extent the entity sought to roll-in the costs of the 
facilities, the rate treatment should be reviewed through the planning 
process.
    348. Second, an Independent Transmission Provider should have the 
responsibility to issue requests for proposals when the planning 
process determines that additional resources are needed to serve the 
regional market. Parties may respond with proposals to expand the grid, 
add generation (including distributed generation), or

[[Page 55498]]

implement demand response.\164\ The Independent Transmission Provider 
would approve transmission expansions that would be paid for by all 
customers only when planned private investments are judged to be 
inadequate to meet the reliability and market needs of the region. If 
the bidding process fails to produce a satisfactory outcome, such that 
the Independent Transmission Provider determines that additional 
facilities are needed, the affected transmission owner(s) would be 
required to expand or upgrade the transmission system.\165\
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    \164\ We recognize that the states have the ultimate authority 
over siting.
    \165\ See existing pro forma tariff Secs. 13.5 and 15.4 
(transmission provider required to expand its transmission system if 
transmission customer agrees to compensate the transmission 
provider). This requirement extends to the transmission owners.
---------------------------------------------------------------------------

    349. Finally, the Independent Transmission Provider would act as a 
clearinghouse for proposed projects. It could identify separate 
projects that could be constructed at a lower cost if the projects were 
combined. Also, if there are alternative projects that have been 
proposed, the Independent Transmission Provider could evaluate the 
relative advantages of the alternative projects.
    350. This approach to regional planning and expansion is fully 
consistent with Standard Market Design's goal of inducing efficient 
investment by relying primarily on price signals and independently 
administered Congestion Revenue Rights. At the same time, it recognizes 
that private investment decisions may not be fully adequate in all 
cases because of eminent domain and the possibility that private 
benefits of investment could be significantly less than social 
benefits. The planning process would have a regional scope, permit 
direct competition among all types of investment, include all market 
participants equally, and minimize the need to rely on eminent domain 
and the support of captive customers. Because existing transmission 
owners are the transmission builder of last resort, it also respects 
the reality that not all states allow non-traditional utilities to 
build in their state or to obtain eminent domain, thus creating a legal 
barrier to entry.
4. Modular Software Design
    351. Software and data issues have become an important part of the 
market design and changes to market design. On many occasions over the 
past several years, market designs and improvements have been delayed 
or even abandoned due to software constraints or software development 
costs. Software and data systems inherited from the old structure are 
often idiosyncratic, making changes and seams issues more difficult 
than they should be. Market participants often find software to be 
impenetrable ``black boxes.'' Software development and modifications 
have become expensive and software ``wheels'' are being reinvented. 
Consequently, the software used to implement the Standard Market 
Design's real-time and day-ahead markets will be a critical element in 
the feasibility and success of Standard Market Design.
    352. The Standard Market Design software should have the following 
characteristics: transparency (the ability to understand what the 
software does), testability (the ability to understand and compare 
performance) and modularity (the ability to change software modules 
without changing other software). Transparency, modularity and 
testability help break down entry barriers and allow for competition in 
software development. Modularity requires standard interfaces (well-
defined data inputs and outputs and ease of access). Since we expect 
Standard Market Design to evolve over time and wholesale markets to 
grow, the underlying software must be able to accommodate change. 
Scalability, security and robustness are desirable design features.
    353. All market and operations software approximates the actual 
operation of the system. However, computational and feasibility issues 
are not well understood. Issues include performance, AC vs. DC models 
and consistency if both are used. Unit commitment models use different 
heuristics that were not important in the old vertical structure, but 
can be very important for new demand and supply entrants in a 
decentralized market. To instill confidence in the software, testing, 
validation and evaluation should be a part of an open process.
    354. We propose to require that the software meet the 
characteristics set forth above and that the input and output data 
systems and other Electronic Data Interchange be standardized in a 
common data model including a data dictionary (glossary and/or data 
definitions) and common network description. We seek comment on the 
following questions.
    355. The Commission held a conference on July 18, 2002, to discuss 
the operational data and software needed to implement Standard Market 
Design and large regional wholesale markets, following an earlier 
conference on software issues. Among the topics discussed were market 
operational software capabilities, software standardization, ISO 
experiences with implementing software, cyber-security and the need to 
achieve some standardization within the electric market and grid 
operations software modules across vendors.
    356. The conference established that for most applications, 
software does not appear to be a binding constraint on the size of RTOs 
or the implementation of Standard Market Design. Participants noted 
that the computational algorithms inside the models are continually 
improving, as is the speed of the processors used to solve the models, 
so it is reasonable to expect that software and associated hardware 
needs should keep pace with market span.
    357. The Commission's goal is to assure that the best software is 
available for use in the nation's wholesale markets. This can best be 
attained by promoting competition among vendors, in a way that assures 
that no vendor comes to ``own'' a market niche or impose barriers to 
entry by new software companies with innovative analytical approaches.
    358. Many vendors have particular areas of expertise and their 
software is often integrated with other software in complete software 
systems. We propose to encourage the development of ``plug-and-play'' 
software designs so that the best modules can be integrated into 
complete market operational systems for Independent Transmission 
Providers. To accomplish this we need to standardize data transfer 
between modules. Participants at the conference proposed two ways of 
accomplishing this--open systems and standardization. The open systems 
approach would leave it to each vendor to develop and publish the 
interface to the next module in the system. The standardization 
approach would define a set of minimum specific standard functions for 
each software module and specify the interfaces to be used between 
modules. We believe that the standardization approach is best suited to 
the close time frame needed for Standard Market Design implementation, 
and invite comment on the best process to develop these standards--
should we use the evolving NAESB process or forums set up by the 
Electric Power Research Institute for this purpose, or use another 
approach?
    359. The discussion of a suite of benchmark problems to test 
software illustrated the importance of benchmarking to facilitate 
testing and comparison of candidate software with respect to solution 
outcomes and processing time. We therefore encourage

[[Page 55499]]

the industry to develop such a suite of benchmark or test problems.
    360. As a follow-up to the July 18, 2002 Standard Market Design 
software conference, the Commission will hold another conference on 
these topics on October 3, 2002. This conference will focus 
particularly and in detail on what process or body should be used to 
set standards for data standardization for inputs and outputs to 
software modules; whether the standards already developed by the 
Ontario Independent Market Operator for this purpose might be 
applicable for United States markets;\166\ and how to proceed with the 
development of test problems for evaluating and comparing software 
modules.
---------------------------------------------------------------------------

    \166\ See http://www.oeb.gov.on.ca/english/electronic_business_standards.htm last visited July 30, 2002.
---------------------------------------------------------------------------

5. Transmission Facilities That Must Be Under the Control of an 
Independent Transmission Provider
    361. In a variety of public forums, including RTO conferences and 
comments to RTO proceedings, much uncertainty has been expressed 
concerning two questions: which facilities belong under the control of 
the RTO; and which customer-owned transmission facilities that are 
turned over to RTO control are entitled to a credit? \167\ In some 
instances, the dispute centers on whether the facilities are 
integrated. Other disputes involve the voltage level at which a 
facility is determined to be transmission. Under this proposed rule, 
the question becomes which transmission facilities must be under the 
control or an Independent Transmission Provider, be it an RTO or not.
---------------------------------------------------------------------------

    \167\ See, e.g., City of Vernon, California, 93 FERC [para] 
61,103 (2000), 94 FERC [para] 61,344 and 61,148 (2001); 95 FERC 
[para] 61,274 (2001); and 96 FERC [para] 61,312 (2001).
---------------------------------------------------------------------------

a. Before Order No. 888

    362. Before Order No. 888, much of the industry consisted of 
vertically integrated investor-owned utilities (IOUs) that, for the 
most part, provided a single service--bundled requirements power--to 
retail and wholesale customers alike. The classification of delivery 
facilities between transmission and distribution came up only in a 
ratemaking context. Because wholesale requirements customers purchased 
bulk power, they often did not require service over distribution 
facilities. Often, only a stepdown substation or a feeder line was 
involved. For those few stand-alone transmission services that an IOU 
might provide, the cost allocation issue was the same. The Commission 
approached this allocation issue by defining an integrated transmission 
grid as those facilities that operate in a single cohesive fashion to 
deliver bulk power and allocating wholesale (and stand-alone 
transmission customers) a proportional share of the embedded costs of 
those facilities on a rolled-in basis with postage stamp pricing.
    363. Infrequently, the Commission would consider rate treatments 
premised on the distinction between transmission and subtransmission 
(high and low voltage transmission). If there were delivery facilities 
(transmission or distribution) that were not part of the integrated 
grid, but were used by a specific wholesale customer (e.g., radial tap 
line or stepdown substation), the Commission would allow the direct 
assignment of those facility costs in wholesale rates.
    364. These issues were discussed at length in Commission cases in 
the 1970s when IOUs attempted to bifurcate the pricing (effectively 
pancaking) and thereby increase their wholesale revenues. Customers, on 
the other hand, wanted to classify facilities as transmission and 
thereby decrease their delivered energy charges by only paying one 
charge for these facilities. While the issue was often framed as a 
transmission/distribution issue, it was mostly a battle over utilities 
trying to pancake rates (through charging a rolled-in rate plus a 
direct assignment charge) for transmission facilities or facilities 
that provided both transmission and distribution functions (dual-
function facilities).

b. Order No. 888

    365. Order No. 888 did not require a change in traditional rate 
treatments. However, since the Commission issued its open access rules, 
a number of utilities have proposed subclassifications of transmission, 
e.g., transmission and subtransmission. Protestors (generally 
transmission-dependent utilities) have argued that this rate treatment 
favors transmission users that are connected to the transmission system 
at higher voltages (i.e., the transmission owners' own generation) by 
reducing their rates for open access transmission service (because they 
pay only the high-voltage charge) and that reclassification is just 
another way to pancake rates and increase charges to low-voltage users. 
During the Commission's public outreach, commenters pointed to such 
splits as the pool transmission facilities (PTF)/non-pool transmission 
facilities in ISO New England as an example. This is not a consistent 
classification of pool transmission facilities and non-pool 
transmission facilities among transmission owners in New England. A 
generator located on a lower voltage portion of the ISO's grid must pay 
an additional non-PTF charge to access the New England market, but 
other, generators do not, putting the first generator at a competitive 
disadvantage.
    366. The issue of transmission/distribution classification in Order 
No. 888 was in the context of unbundled retail transmission service and 
the Federal Power Act's legal jurisdiction distinction between 
``transmission'' facilities (subject to Commission jurisdiction) and 
``local distribution'' facilities (subject to state or local 
jurisdiction). To determine what facilities would be under Commission 
jurisdiction for purposes of the Order No. 888 open access requirements 
and what facilities would remain subject to state jurisdiction for 
purposes of retail stranded cost adders or other retail regulatory 
purposes, the Commission developed a seven factor test to determine 
what facilities are transmission facilities and what facilities are 
local distribution facilities.\168\ With respect to the seven factor 
test, the Commission also stated that it would defer to the state 
commission's findings as to what facilities constitute local 
distribution facilities if the state's determination was consistent 
with our comparability principles. In addition, dual purpose 
facilities, i.e., those used both for transmission or wholesale sales 
and for local distribution, would fall under the Commission's 
jurisdiction. To the extent use of particular facilities changed over 
time, the Commission would revisit these determinations. The Supreme 
Court upheld these determinations upon appellate review.\169\

c. Test for Transmission Facilities
---------------------------------------------------------------------------

    \168\ Order 888 at 31,771.
    \169\ New York v. FERC, 122 S. Ct. 1012.
---------------------------------------------------------------------------

    367. Order No. 888's seven factor test was designed to determine 
the local distribution component of an unbundled retail sale. The test 
did not exist prior to Order No. 888 and in fact was created to do 
something the Commission had never done before--identify local (retail) 
distribution facilities. Thus, the test identifies all facilities that 
are not local distribution facilities. We propose that this is the 
appropriate starting point for determining which facilities belong 
under the control of an Independent Transmission Provider. To the 
extent that a transmission owner or Independent Transmission Provider

[[Page 55500]]

believes that certain facilities should not be under the Independent 
Transmission Provider's control, the Independent Transmission Provider 
may request an exception to this presumptive determination.
    368. This proposed test focuses on the presumption that, if a 
facility is transmission, it belongs under the control of the 
Independent Transmission Provider. Thus, once a determination is made 
with the seven factor test, there would be no need for an additional 
review under the Commission's previous integrated facilities test. In 
MidAmerican Energy Company,\170\ the Commission explained that the 
Commission's determination of which facilities are transmission is 
fluid and dependent on actual use of the facilities:
---------------------------------------------------------------------------

    \170\ 90 FERC [para] 61,105 (2000).

    Although we are accepting the state commissions' classification, 
we reiterate our finding in Order No. 888 that to the extent that 
any facilities, regardless of their original nominal classification, 
in fact, prove to be used by public utilities to provide 
transmission service in interstate commerce in order to deliver 
power and energy to wholesale purchasers, such facilities become 
subject to this Commission's jurisdiction and review.\171\ In 
addition, the rates, terms and conditions of all wholesale and 
unbundled retail transmission service provided by public utilities 
in interstate commerce are subject to this Commission's jurisdiction 
and review.\172\
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    \171\ In Order No. 888, the Commission explained that ``a public 
utility's facilities used to deliver electric energy to a wholesale 
purchaser, whether labeled ``transmission,'' ``distribution,'' or 
``local distribution,'' are subject to the Commission's exclusive 
jurisdiction under sections 205 and 206 of the FPA.'' Order No. 888 
at 31,969; accord Nevada Power Company, 88 FERC [para] 61,234 at 
61,768 (1999).
    \172\ Transmission service in interstate commerce by public 
utilities, including the rates, terms and conditions for such 
service, remains within this Commission's exclusive jurisdiction. 16 
U.S.C. 824, 824d, 824e (1994). See generally Order No. 888-A at 
30,339-41.
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    Further, our deference in this proceeding does not affect the 
Commission's separate determination of what facilities must be under 
the operational control of RTOs, including ISOs and Transcos.\173\ 
The Commission will make this latter determination, taking into 
account the seven factors formulated for purposes of determining 
jurisdiction as set forth in Order No. 888,\174\ the ISO principles 
set forth in Order No. 888,\175\ and the principles set forth in the 
RTO Final Rule.\176\
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    \173\ Which facilities will or will not be under an RTO's 
operational control also does not predetermine transmission pricing, 
cost allocation, or rate design determinations at either a state 
commission or at this Commission.
    \174\ Order No. 888 at 31,771.
    \175\ Order No. 888 at 31,730-32.
    \176\ Regional Transmission Organizations, Order No. 2000, FERC 
Stats. & Regs. [para] (1999) (RTO Final Rule).
---------------------------------------------------------------------------

We note that the determination of which facilities are under the 
operational control of the Independent Transmission Provider does not 
dictate transmission pricing.\177\
---------------------------------------------------------------------------

    \177\ As noted in MidAmerican, present ISO agreements obligate 
transmission owners to provide access over facilities that are not 
under the control of the ISO if those facilities are needed to 
provide wholesale transmission service regardless of ownership or 
whether those facilities are labeled transmission, distribution 
(i.e., distribution facilities other than local distribution), or 
local distribution. The same holds for Independent Transmission 
Providers.
---------------------------------------------------------------------------

    369. We request comment whether, either in addition to or in lieu 
of the seven factor test, the Commission should use a bright line 
voltage test (e.g., 69 kV) to determine which facilities are placed 
under the control of the Independent Transmission Provider. If so, we 
seek comment on the bright line, whether we should allow regional 
variation, and how transmission facilities that are not placed under 
the control of the Independent Transmission Provider's tariff are 
treated with respect to open access and rates.

H. Transition to Single Transmission Tariff

    370. This section discusses the transition process that will be 
used to move from the existing pro forma tariff to the SMD Tariff. 
First, we discuss the provisions of the revised tariff that remain the 
same as those in the existing pro forma tariff, but may change based on 
the comments received in response to our questions. Second, we discuss 
the provisions we propose to change. When Standard Market Design is 
implemented, the revised tariff would apply to nearly all transmission 
services on the system. All customers would receive the same quality 
and quantity of service they currently receive. Customers currently 
taking transmission service under an open access transmission tariff 
would continue to do so, but now would be served under the new Network 
Access Service under a revised open access transmission tariff. Bundled 
retail customers would continue to receive service from their existing 
load-serving entity; however, the load-serving entity would be required 
to take service under the new Network Access Service pro forma tariff 
in order to serve those retail customers. Similarly, while wholesale 
customers with pre-Order No. 888 contracts would be given the 
opportunity to convert to the new transmission service under a revised 
open access transmission tariff, if they choose not to do so, the 
transmission owner that provides service under the pre-888 contract 
would be required to take service under the new Network Access Service 
pro forma tariff in order to meet its contractual obligations to serve 
those customers.
    371. Standard Market Design is intended to cure undue 
discrimination, more efficiently use the transmission grid and give 
customers additional options. To help ensure that the transition 
process satisfies these objectives, the proposed rule would allow 
certain regional flexibility in the implementation process to the SMD 
Tariff. In particular, the regions would have flexibility in converting 
the rights of existing customers to Congestion Revenue Rights or 
auction revenues under the new tariff. Also, the regions would have 
flexibility in establishing the rate design for the new Independent 
Transmission Providers. It is anticipated that the state 
representatives, through the Regional State Advisory Committees 
discussed in Section IV.K., will play an active role in these regional 
decisions.
1. Treatment of Customers Under Existing Wholesale Contracts
    372. When the Commission issued Order No. 888 it faced the issue of 
what to do with existing contracts. The Commission decided that it 
would not generically abrogate existing requirements and transmission 
contracts, but that under all post-Order No. 888 contracts were to 
conform to the Order No. 888 pro forma tariff.
    373. Similarly, we propose not to abrogate existing pre-Order No. 
888 contracts. On a nationwide basis, these contracts should represent 
a relatively small portion of the total load and should be able to be 
accommodated within the Standard Market Design.\178\ The customers with 
these contracts will be able to convert these existing contracts, 
consistent with their contract terms, to the new Network Access Service 
upon implementation of Standard Market Design. However, as discussed 
below, if customers choose not to convert to the new service, the 
transmission owner would be required to take service under the new 
tariff in order to meet its contractual obligations to serve the pre-
Order No. 888 contract customers.
---------------------------------------------------------------------------

    \178\ It appears that these contracts would be less than 10 
percent of total load on a nationwide basis based on data from Form 
No. 1 filings by public utilities for calendar year 2000.
---------------------------------------------------------------------------

    374. If pre-Order No. 888 contracts remain in effect, the 
contracting transmission owner would be required to take service from 
the Independent Transmission Provider in order to serve its existing 
wholesale power or

[[Page 55501]]

transmission contract. The Independent Transmission Provider will 
assess the transmission owner for all charges and payments for 
providing the transmission service. The transmission owner will receive 
the allocation of initial Congestion Revenue Rights (or auction 
revenues associated with Congestion Revenue Rights) to provide 
protection against congestion costs for these existing contracts. If 
the ultimate transmission customer prefers having a direct allocation 
of these rights, it can convert the contract, subject to any 
contractual limitations, so that the customer directly receives service 
through a service agreement under the SMD Tariff and would take service 
directly from the Independent Transmission Provider.\179\ We expect 
that the Congestion Revenue Rights or auction revenues for Congestion 
Revenue Rights that the transmission owner will receive in association 
with these contracts will be sufficient to cover increased congestion 
costs that would result from having the transmission owner take service 
under the new tariff in order to serve its wholesale requirements 
customers. However, the transmission owner would have the right to make 
a filing pursuant to section 205 of the Federal Power Act to 
demonstrate that its revenue requirement should be adjusted to recover 
additional costs caused by implementation of this provision.
---------------------------------------------------------------------------

    \179\ To the extent that there are contractual limitations, the 
customer could seek modification of the contract through a filing 
with the Commission.
---------------------------------------------------------------------------

    375. The Commission is concerned that pre-Order No. 888 contracts 
could permit the parties to extend a contract indefinitely through the 
use of roll-over or evergreen provisions in the contracts. The 
Commission seeks comment on whether it should limit the ability of the 
parties to extend these contracts past their initial term, or if that 
has passed the end of the next roll-over period and, if so, what 
limitations are appropriate.
2. Allocation of Congestion Revenue Rights
    376. The initial allocation of Congestion Revenue Rights is 
important to ensure that the implementation of Standard Market Design 
preserves the service rights of existing customers, provides access to 
all available capacity and minimizes cost shifts. We offer a process 
for this transition. First, the Independent Transmission Provider would 
compile a catalogue of all the existing long-term firm obligations for 
its transmission system that would still be in effect when Standard 
Market Design is implemented.\180\ This would include firm Point-to-
Point Transmission Service under an open access transmission 
tariff,\181\ firm transmission under pre-Order No. 888 contracts, 
designated resources for network transmission service pursuant to an 
open access transmission tariff, and bundled retail load (which is 
served under an implicit contract with the transmission owner). For 
firm Point-to-Point Transmission Service, the existing rights would be 
those specified in existing service agreements. For network 
transmission service and bundled retail transmission service, the 
existing rights would be limited to the designated resources in effect 
at the time, up to an amount equal to the customer's current peak load 
since this would replicate the service the customer is currently 
receiving. The Congestion Revenue Rights would go to the entity taking 
service under the Independent Transmission Provider's tariff. In 
general, these customers would not be granted an initial allocation 
based on additions for future load growth, but would have to secure 
those rights. However, there are instances where the vertically 
integrated transmission provider has identified load growth and limited 
the term (and rollover rights) of point-to-point transmission 
contracts. We seek comment as to whether and under what circumstances 
load growth should be accommodated in the direct allocation of 
Congestion Revenue Rights. The initial Congestion Revenue Rights would 
be receipt point-to-delivery point obligations.
---------------------------------------------------------------------------

    \180\ Network transmission contracts are not currently 
assignable because they do not consist of reservations from 
particular receipt points to delivery points in specific stated 
amounts. Therefore, some measure of historical usage on a point-to-
point basis will have to be imputed to each network customer in 
order to assign Congestion Revenue Rights.
    \181\ Short-term firm contracts would expire before the 
implementation of Standard Market Design and would thus not be 
included in the catalogue.
---------------------------------------------------------------------------

    377. Next, the catalogue of firm obligations would be subject to a 
simultaneous feasibility test.\182\ On some systems, it may not be 
possible to award Congestion Revenue Rights that are simultaneously 
feasible to all of the existing firm transmission customers on the 
system, because the system may be leveraging load diversity--different 
customers using the grid at different times--to meet the peak needs of 
all users. If those needs cannot all be met simultaneously, then not 
all customers can have annual Congestion Revenue Rights equal to their 
peak usage,\183\ then the initial allocation of Congestion Revenue 
Rights would be limited to the amount that is simultaneously feasible. 
The Congestion Revenue Rights could be allocated between customers on a 
pro rata basis or customers could be given the opportunity to change 
receipt points to achieve a simultaneously feasible result, or the 
Congestion Revenue Rights could be restricted to certain periods.\184\
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    \182\ Simultaneously feasibility means that power can be 
simultaneously transmitted from the receipt points to the delivery 
points specified in the Congestion Revenue Rights in a contingency-
constrained dispatch. If this power flow does not cause overloads on 
the system (either pre- or post-contingency), then the power flow is 
simultaneously feasible.
    \183\ Congestion Revenue Rights that give a holder different 
seasonal quantities could be an option in such a case.
    \184\ If the simultaneous feasibility tests indicate there are 
additional Congestion Revenue Rights that could be offered, these 
Congestion Revenue Rights will be offered through an auction open to 
all customers.
---------------------------------------------------------------------------

    378. Either of two methods could ensure that current customers 
receive the value of their current contracts (actual or implicit)--
direct assignment and an auction with a revenue assignment.\185\ First, 
Congestion Revenue Rights could be directly assigned to the customers 
that currently have the receipt points and delivery points identified 
in their existing contracts (actual or implicit). Under this approach, 
a customer that currently has a firm point-to-point transmission 
contract for 100 MW from point A to point B would receive 100 MW of 
Congestion Revenue Rights from point A to point B for the length of its 
contract. A network customer or a load-serving entity serving retail 
load that has identified a network resource for 100 MW of capacity 
would receive a Congestion Revenue Right for 100 MW from that receipt 
point to the customer's load.\186\ The delivery points would be defined 
as the customer's interface points with the Transmission Provider. For 
network contracts and implicit contract, it is likely that customers 
would continue service for the foreseeable future (without a contract 
termination date). Thus, we seek comment on what type of term should be 
used for purposes of the Congestion Revenue Rights allocation for these 
contracts.
---------------------------------------------------------------------------

    \185\ For the sake of simplification, this discussion assumes 
that simultaneously feasible Congestion Revenue Rights could be 
issued to replicate current rights. If adjustments need to be made 
to ensure a simultaneously feasible result, the numbers may change, 
but the same basic methodology would be used for the conversion 
process.
    \186\ In states that have retail competition, provisions would 
also be needed to ensure that the Congestion Revenue Rights stay 
with the load. So if a new retail marketer starts serving load 
previously served by the local utility, the retail marketer would 
get a proportionate share of the Congestion Revenue Rights.

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[[Page 55502]]

    379. Alternatively, current firm customers could be given the 
auction revenues from the sale of Congestion Revenue Rights. Thus, the 
existing customers would receive the market value of those rights. 
Under this approach, all of the Congestion Revenue Rights available on 
the system would be sold through an auction. At a minimum, the 
Congestion Revenue Rights sold in the initial auction would have to 
include point-to-point obligations. If there is interest from market 
participants and it is technically feasible, the auction could also 
include point-to-point options and flowgate rights.
    380. The terms of the Congestion Revenue Rights would vary. 
Initially, a set percentage would be auctioned on a monthly basis, 
another set percentage would be auctioned for six months and another 
for one year. This rulemaking proposes that the regions be given 
flexibility in setting the initial terms for the Congestion Revenue 
Rights sold in auctions. Since congestion patterns can change 
significantly after the implementation of LMP, there may be a benefit 
to delaying the auction of multi-year Congestion Revenue Rights until 
after a start-up period. On the other hand, customers may desire long-
term Congestion Revenue Rights to correspond to the term of the long-
term contracts used to satisfy the long-term resource adequacy 
requirement. We seek comment on whether we should require long-term 
Congestion Revenue Rights in such cases. The Congestion Revenue Rights 
that would be sold during the initial auction would be the set of 
Congestion Revenue Rights that maximizes the value of the awarded 
Congestion Revenue Rights based on buyers' bids that is simultaneously 
feasible. The revenues from the auction would be given to the customers 
that are paying for the embedded costs of the system through an access 
charge.
    381. In the long-term, the auction methodology has a number of 
advantages over the allocation methodology in a competitive wholesale 
market. First, the auction methodology makes it easier for load-serving 
entities to change receipt points (and thus supply sources) and obtain 
protection against congestion costs because of the more frequent 
auctions for Congestion Revenue Rights. The same would also apply to 
sellers seeking to sell to different buyers. In contrast, if Congestion 
Revenue Rights are directly assigned, holders of the Congestion Revenue 
Rights on congested paths may be reluctant to offer these in the 
secondary market. This could limit the ability of new suppliers to 
enter the market. This could be problematic particularly with 
Congestion Revenue Rights held by vertically-integrated utilities. 
Second, experience to date has been that there is a more vibrant 
secondary market where Congestion Revenue Rights are auctioned rather 
than directly assigned.\187\
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    \187\ New York ISO auctions Congestion Revenue Rights and PJM 
directly assigns Congestion Revenue Rights. MISO has also proposed 
to initially directly assign Congestion Revenue Rights but to 
transition to an auction of Congestion Revenue Rights with an 
allocation of auction revenues to the customers that pay the 
embedded costs of the system.
---------------------------------------------------------------------------

    382. This proposed rule establishes a preference for the auction of 
Congestion Revenue Rights. After a transition period, all Independent 
Transmission Providers would be required to auction their Congestion 
Revenue Rights. However, for an initial transition period of four 
years, this rulemaking proposes to allow regional flexibility on this 
issue. During a transition period, the Independent Transmission 
Provider after consultation with the Regional State Advisory Committee 
and stakeholders in a region, could decide to directly assign 
Congestion Revenue Rights. At the end of the transition period, the 
Independent Transmission Provider would be required to submit a filing 
to move to an auction for Congestion Revenue Rights with the auction 
revenues allocated to those that pay the access charge, or justify why 
a longer transition period is necessary. The customer that previously 
had been allocated the Congestion Revenue Rights would now receive the 
auction revenues. The customer could participate in the auction if it 
wished to retain the Congestion Revenue Rights. We seek comment on 
whether to allow a transition period before the start of Congestion 
Revenue Rights auction allocations and, if so, what the length of such 
a transition should be.
3. Reciprocity Provision
    383. In Order No. 888, the Commission included a reciprocity 
provision in the pro forma tariff. Under this provision, all customers 
(and their affiliates), including non-public utility entities, that 
own, control or operate interstate transmission facilities and that 
take service under a public utility's open access transmission tariff, 
must offer comparable (not unduly discriminatory) services in 
return.\188\ The Commission also recognized that a public utility may 
deny service simply on a claim that the open access offered by a non-
public utility was not satisfactory. Thus, the Commission developed a 
voluntary safe harbor procedure under which non-public utilities could 
submit to the Commission a transmission tariff and a request for 
declaratory order that the tariff meets the Commission's comparability 
(non-discrimination) standards. If the Commission found it to be an 
acceptable reciprocity tariff, the Commission would require the public 
utility to provide open access service to that particular non-public 
utility.\189\
---------------------------------------------------------------------------

    \188\ See Order No. 888 at 31,760; Order No. 888-A at 30,285.
    \189\ Id. at 31,761.
---------------------------------------------------------------------------

    384. We propose to continue this approach to reciprocity. Further, 
we propose to grandfather all reciprocity tariffs that the Commission 
previously found met the comparability standards of Order No. 888. We 
request comment on this proposal.
4. Force Majeure and Indemnification Provisions
    385. In Order No. 888, the Commission recognized that the risk 
allocations regarding liability and indemnification ``must be carefully 
drafted so that transmission providers and customers can accurately 
assess and account for their respective risks.'' \190\ The Order No. 
888 pro forma tariff contains a force majeure provision and an 
indemnification provision.\191\ The force majeure provision provides 
that neither the transmission provider nor the transmission customer 
will be liable to the other when they behave properly, but 
unpredictable and uncontrollable force majeure events prevent 
compliance with the tariff.
---------------------------------------------------------------------------

    \190\ Order No. 888 at 31,765.
    \191\ See Sections 10.1 and 10.2 of the pro forma tariff.
---------------------------------------------------------------------------

    386. Under the indemnification provision, the transmission customer 
indemnifies the transmission provider against third-party claims that 
arise from the performance of obligations under the tariff. The 
Commission explained that the purpose of the indemnification provision 
was to allocate the risks of a transaction, and costs of the risks, to 
the party on whose behalf the transaction was conducted.\192\ Further, 
as the tariff did not obligate the customer to perform services on 
behalf of the transmission provider there was no comparable basis for 
imposing an indemnification obligation on the transmission provider. 
The Commission found it inappropriate to require the customer to 
indemnify the transmission provider from damages arising from the 
transmission provider's own negligence. Thus, a transmission customer 
is not required to indemnify the transmission provider in the case of 
negligence or

[[Page 55503]]

intentional wrongdoing by the transmission provider.\193\ The 
Commission further explained that while it was appropriate to protect 
the transmission provider when it provides service without negligence, 
the determination of liability in other instances should be left to 
other proceedings.
---------------------------------------------------------------------------

    \192\ See Order No. 888-A at 30,301.
    \193\ See Order No. 888-A at 30,299-300; Order No. 888-B at 
62,080.
---------------------------------------------------------------------------

    387. Since Order No. 888, several entities have sought to revise 
their open access transmission tariffs to include liability provisions 
arguing, among other things, that no current federal forum exists for 
entities that are now subject to Commission jurisdiction only and can 
no longer seek relief at the state level.
    388. We recognize that there may be a need to include liability 
provisions in the Commission's pro forma tariff in circumstances in 
which there are no liability provisions available in a state tariff; 
however at this time, we are not prepared to propose a specific 
provision.\194\
---------------------------------------------------------------------------

    \194\ We have included the indemnification and liability 
provisions from the existing pro forma tariff in the SMD Tariff 
pending review of the comments in this proceeding.
---------------------------------------------------------------------------

    389. We seek comment on the following issues: Is there a need to 
include liability provisions in the Commission's pro forma tariff? 
Under what circumstances should liability protection be provided in a 
Commission open access transmission tariff (e.g., should we provide 
such protection only where it is not available through state tariffs)? 
If we adopt liability provisions, should they be generic or do they 
need to be adopted on a regional basis? Should the standards adopted in 
a Commission pro forma tariff reflect what was previously provided 
under state law? How do we resolve the issue in the multi-state context 
of an ISO or RTO? The Commission will review the comments filed and 
then hold a staff technical conference in the fall to further discuss 
this issue.

I. Market Power Mitigation and Monitoring in Markets Operated by the 
Independent Transmission Provider

1. Principles and Objectives
    390. In a structurally competitive market, one with many buyers and 
sellers who cannot influence price, the market can assure an overall 
efficient outcome where prices indicate the value of additional 
supplies and conservation. The development of structurally competitive 
markets is the Commission's long-term goal. However, at this stage of 
the industry's evolution, wholesale electric markets are not yet 
structurally competitive in all respects. The two significant 
structural flaws are the lack of price-responsive demand and generation 
concentration in transmission-constrained load pockets. Given these 
structural defects, the Commission cannot rely on the interaction of 
supply and demand in all instances to ensure that prices are 
competitive and thus just and reasonable.
    391. Cost-of-service regulation is not effective for spot market 
pricing of commodities such as electricity. In the past, customers were 
served by a monopoly supplier under cost-of-service rates, in which the 
fixed and variable costs of a company's generation portfolio were 
allocated over the expected hours of service to determine a cost per 
kWh. But today, the power needs of load-serving entities are met 
through a mix of sources, including the companies' generation 
portfolios, and long-term and spot market purchases from a variety of 
sellers, including independent producers and marketers. These do not 
match the long-term arrangements needed for cost-of-service regulation. 
In this competitive context, cost-of-service regulation designed for 
long-term cost recovery is not well suited for determining appropriate 
spot market prices. When applied to spot markets, cost-of-service 
regulation blunts price signals and leads to inefficient investment and 
consumption decisions which over the long run increase costs for all 
customers.
    392. When markets do not produce competitive outcomes, the 
Commission must use new regulatory tools to produce just and reasonable 
results. We propose new market power mitigation measures to deal with 
the consequences of major structural defects in wholesale electric 
markets, by approximating the outcomes that a competitive market would 
produce. These measures should function in markets that are not 
workably competitive, but not inhibit market operation in more 
competitive markets. Effective market monitoring and market power 
mitigation are critical elements of the Commission's plan to create and 
sustain competitive regional bulk power markets. Therefore, the 
Commission proposes rules for the spot markets to be operated by the 
Independent Transmission Provider to mitigate market power.
    393. Market power is the ability to raise price above the 
competitive level.\195\ This can be accomplished if the generator can 
withhold physical power (physical withholding) or cause physical power 
to be withheld through inflated bids (economic withholding).\196\ 
Competitive prices over the long run should recover both the fixed and 
variable costs of efficient generating units. The challenge for market 
power mitigation on the supply side is to assure that it allows long-
term competitive prices, which allows the opportunity to recover the 
fixed costs of the investment as well as the short-term variable costs 
of producing electricity. If some degree of scarcity pricing is not 
allowed, and generation only recovers short-term marginal costs, then 
some generators needed for reliability could fail to recover their full 
costs and may be retired. Worse yet, prices could be held so low that 
investors decline to invest in needed generation, transmission and 
demand-side projects because they do not see a reasonable expectation 
of recovering their costs.
---------------------------------------------------------------------------

    \195\ The Commission's natural gas pipeline cases have used a 
definition of market power that examines the company's ability to 
raise prices significantly above a competitive level for a sustained 
period. Alternatives to Traditional Cost-of-Service Ratemaking for 
Natural Gas Pipelines, 74 FERC [para] 61,076 at p. 61,230 (1996); 
and cases cited id at n. 52. See also, Alternatives to Traditional 
Cost-of-Service Ratemaking for Natural Gas Pipelines, 70 FERC [para] 
61,139 at p. 61,403 (1995) (concerning transportation and storage 
services). These factors recognize that it is difficult to identify 
market power with precision, both because it is difficult to 
precisely identify the competitive price (which should recover both 
fixed and variable costs over the long run) and because it can be 
difficult to isolate the impact of one entity on the competitive 
price. These factors also recognize that there is an implicit cost/
benefit assessment to decisions to intervene in the exercise of 
market power. The cost of intervention in transient price increases 
could be greater than the public benefit gained by the intervention. 
Commission decisions about when to intervene in an exercise of 
market power are important, but need to be tailored to the 
circumstances of the product and the industry. In the electric 
industry, electricity prices can spike for one hour or a few hours 
in ways that are less likely for natural gas pipeline transportation 
and storage rates, and the consequences can be quite different. 
Since the definition of market power and the decision when to 
intervene in its exercise are analytically distinct issues, in this 
rulemaking the Commission incorporates the concept of when to 
intervene in an exercise of market power into the choice of triggers 
for the market power mitigation mechanisms, rather than in the 
definition of what constitutes market power.
    \196\ Market power can also be exercised by creating barriers to 
entry so other suppliers cannot reach the market or by causing other 
supplier's production costs to increase.
---------------------------------------------------------------------------

    394. The market power mitigation measures proposed here are 
designed to address the major structural defects in wholesale electric 
markets. The major structural defect on the demand side is the lack of 
price-responsive demand; when customers cannot respond to high prices 
by lowering their consumption, they cannot discipline price increases 
from suppliers. Absent demand response, market prices will reflect

[[Page 55504]]

suppliers' bids alone, so we cannot rely on market prices to ration 
scarce supplies in all situations. Therefore, the market power 
mitigation needs to compensate for the lack of price-responsive demand 
in the market.
    395. On the supply-side, structural problems tend to be more 
location-specific and time-dependent. For example, binding and 
sometimes unpredictable transmission constraints may restrict 
competitive alternatives and create opportunities for some sellers to 
increase prices above a competitive level, at least for any seller that 
knows some of its output will be required to meet load reliably. This 
problem is often described as a load pocket problem. In some load 
pockets, a specific generator may be identified as needed for 
reliability, which gives it a local monopoly.\197\ In other situations 
without severe constraints, the geographic market may be broader but if 
little generation divestiture or entry by non-affiliated generators has 
occurred, concentration of ownership may remain high. Market power 
mitigation needs to mitigate local market power, whether it arises 
because of a load pocket, transmission constraints, or ownership 
concentration.
---------------------------------------------------------------------------

    \197\ This is also true for certain types of ancillary services 
(e.g., reactive power) where specific generators may have the 
ability to exercise market power because of their location.
---------------------------------------------------------------------------

    396. To be effective, market power mitigation measures must be 
applied before the fact, since remedies after the withholding has 
occurred are disruptive to the market and increase regulatory risk to 
its participants, which increases costs to customers.
    397. In sum, the challenge in developing an effective market power 
mitigation plan is to design a plan that allows markets to function 
where they are competitive and, where they are not, uses market 
mechanisms to facilitate the transition to competitive markets. Market 
mechanisms can be used to approximate the outcomes that a competitive 
market would produce to provide the price signals for efficient 
investment and demand response. Because of the characteristics of 
electricity (it can be stored only in limited instances--pumped 
storage, compressed air, batteries) and the electric grid (flows follow 
the path of least resistance), even in regions where markets are 
generally competitive, transmission constraints may create non-
competitive conditions during certain hours. In addition, when market 
power exists, the market power mitigation plan should be calibrated so 
that it does not inefficiently suppress prices, or mask scarcity 
prices, providing the wrong economic signals for efficient investment 
or demand response.
2. Overview of the Market Power Mitigation Measures
    398. The Commission proposes a market power mitigation plan 
composed of three mandatory components that are specifically tailored 
to the structural flaws in the wholesale electric markets and a 
voluntary fourth measure that could apply in unusual market conditions 
to assure that the high prices are not the result of market power.
    399. The first measure addresses the local market power problem and 
is similar in concept to the reliability must run agreements that exist 
in the ISOs today. The market monitor will identify certain conditions 
in which certain generators are in concentrated geographic markets 
created by transmission congestion or reliability needs of the grid. 
These would include units needed to run to support the reliable 
operation of the grid or a set of units owned by a small number of 
companies. At those times, those units will have localized market power 
so that when they are required to provide their energy or ancillary 
services to the grid their bids into the market should be capped.\198\ 
The conditions when their power must be supplied to the grid (a must-
offer obligation) and the bid cap to apply would be specified in their 
participating generator agreement with the Independent Transmission 
Provider.
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    \198\ This would include a broader group of units than what are 
often referred to as reliability must run units.
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    400. The second component, a safety-net bid cap such as the $1000 
per megawatt-hour cap currently used in Northeast markets and Texas, 
addresses the lack of price-responsive demand. Sellers could freely 
offer any amount of energy to the spot markets constrained only by the 
safety-net bid cap. The safety-net bid cap should allow markets to 
produce prices that reflect some (and perhaps a significant) amount of 
scarcity when shortages of reserves or power exist. But absent demand 
response, it sets an outer bound on suppliers' ability to exercise 
economic withholding.
    401. The third component of the market power mitigation plan is the 
resource adequacy requirement discussed in Section J. The resource 
adequacy requirement does not directly prevent withholding, but by 
expanding the resource alternatives it diminishes the incentive and the 
ability of suppliers to practice and profit from either physical or 
economic withholding.
    402. While it is clear that the first three measures must be part 
of the Standard Market Design market power mitigation plan, there may 
be market conditions in which a fourth measure is needed. The fourth 
mitigation measure would deal with situations when non-competitive 
conditions may exist, by examining and possibly limiting bids from 
individual suppliers into the day-ahead and real-time spot markets if 
those bids are high due to withholding rather than scarcity. Exercise 
of this mitigation could be triggered by predetermined conditions or 
triggers (such as a sustained period of prices significantly above 
competitive levels), or by significant infrastructure problems in the 
market (e.g., sustained tight reserve conditions, as might be due to 
drought). This mechanism is like the Automatic Mitigation Procedure 
(AMP) used by the New York ISO, and adopted recently for the California 
ISO. This mechanism would not be required for every region but may be 
adopted if the market monitor's analysis determines this measure is 
needed.
    403. The implementation of the market power mitigation plan 
summarized above and described in more detail below will rely on the 
results of an initial competitive market analysis by the Independent 
Transmission Provider's market monitor in each region. This will 
identify at the outset the persistent load pockets or other conditions 
that create local market power. This analysis will be filed with the 
Commission as part of the implementation process for Standard Market 
Design and subject to comment from all interested parties. After 
Commission review, it will form the basis for the mitigation measures 
that are applied by the Independent Transmission Provider. It then will 
be updated annually to review the continuing effectiveness of the 
market power mitigation.
    404. The market power mitigation measures proposed rely principally 
on mitigating market power in spot markets. Mitigation would only apply 
to products traded in the spot markets operated by the Independent 
Transmission Provider, not to products traded under bilateral contracts 
outside the Independent Transmission Provider's spot markets. This is 
the least intrusive framework for market power mitigation but at the 
same time provides very effective protection against market power.
    405. Although power and operating reserves purchased in the 
organized spot market are only a small percentage of total purchases, 
mitigating the organized spot market is an effective

[[Page 55505]]

way of mitigating market power generally.\199\ Bilateral contracts 
generally reflect buyer and seller expectations of prices in spot 
markets. Therefore, market power mitigation in the organized spot 
market will effectively discipline market power in bilateral markets as 
well.\200\ However, if spot market prices are over-mitigated, it may 
weaken incentives for buyers to contract in bilateral markets and 
expose spot market prices to greater price volatility. Regular 
reassessment of the market power mitigation practices can prevent this 
outcome, and, as discussed infra, the market monitor will be required 
to annually reassess the effectiveness of the market power mitigation.
---------------------------------------------------------------------------

    \199\ Stoft, Steven. Power System Economics. New York, NY: 
Wiley-IEEE Press, 2002, Section 2-4.5, ``How Real-Time Price-Setting 
Caps the Forward Markets,'' p. 150.
    \200\ Relying on mitigating market power in the spot market has 
been an effective mitigation method in the New York ISO under its 
AMP, and the California ISO since May, 2001.
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3. Market Power Mitigation for Local Market Power
    406. Local market power principally arises either from the 
concentration of generator ownership within a load pocket, or the need 
for local units to operate to assure system reliability and stability 
within the load pocket. Local market power can arise from both 
persistent and foreseeable congestion, or from sporadic transmission 
congestion. Although local market power can arise from these different 
conditions, the mitigation method proposed here can be effective at 
mitigating the local market power regardless of how it arises.
    407. In the existing ISOs in California and the Northeast, 
participating generator agreements are used to set out the operating 
terms, conditions and obligations concerning the dispatch of a 
generating unit, serving principally a reliability purpose. Under the 
Standard Market Design pro forma tariff all generators dispatched by 
the Independent Transmission Provider would enter into a participating 
generator agreement.\201\ Standard Market Design will require these 
participating generator agreements to include provisions to mitigate 
local market power.
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    \201\ SMD Tariff Section A.9.2.
---------------------------------------------------------------------------

    408. The participating generator agreements, which would be filed 
with the Commission, would identify the non-competitive conditions when 
the generator with local market power would be required to offer its 
energy either by scheduling a bilateral transaction or by offering all 
available energy to the spot markets. This would be a must-offer 
requirement. The requirement would apply when the generator's power is 
needed to maintain the reliable operation of the grid, and also when 
there are insufficient competitive alternatives. The participating 
generator agreement would specify the conditions that would give rise 
to a generator's must-offer requirement, and would also specify bid 
caps that would apply when the generator was required to bid into the 
day-ahead and real-time markets. In non-competitive conditions, the 
generator's bids could not exceed the capped values. Although the 
participating generator agreement may restrict a generator's energy and 
operating reserves bids, the generator would still receive a market-
clearing price and additional revenue to cover start-up and no-load 
costs.\202\ The capped bid could also set the market clearing price.
---------------------------------------------------------------------------

    \202\ SMD Tariff section F.1.11. The generator's legitimate 
minimum run times would also be honored under the provisions of SMD 
Tariff section F.1.5.
---------------------------------------------------------------------------

    409. In addition to the bid caps specified in the participating 
generator agreements, local market power also will be limited through 
bilateral contracts between load-serving entities and the generators. 
Under the resource adequacy requirement, load-serving entities must 
have enough resources to meet their demand to ensure the reliability of 
the grid. It can be expected that some of those resource requirements 
will need to be fulfilled with contracts with generators within their 
load pocket to ensure that the resource is deliverable during peak or 
congested periods. Bilateral contracts are an effective way for a buyer 
to mitigate the market power of a seller.\203\ The load-serving 
entities can be expected to include provisions in these contracts 
specifying when a generator must run to meet any reliability needs in 
that location and the price to be paid. Whenever a generator is 
scheduled to run under a bilateral contract, this will fulfill its 
must-offer obligation in the participating generator agreement with the 
Independent Transmission Provider.
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    \203\ See Comment of the Staff of the Bureau of Economics and 
the Office of the General Counsel of the Federal Trade Commission, 
Docket No. RM01-12-000 (July 23, 2002).
---------------------------------------------------------------------------

    410. Under the participating generator agreements, when conditions 
are not competitive, that is, when there are insufficient alternatives 
available to meet load in that location, a generator must run to 
provide all its available capacity to the grid, either by scheduling a 
bilateral transaction or bidding into the spot market. The need for the 
generator to be producing could be identified either in the day-ahead 
market based on projected system conditions or in real time. In the 
day-ahead market, all available capacity would include all capacity not 
sold bilaterally and scheduled or on an outage. In the real-time 
market, all available capacity would include all non-producing capacity 
(not delivered to the market) i.e., capacity not on a planned or forced 
outage.\204\
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    \204\ Under the Standard Market Design tariff, all units 
scheduled day ahead under a must-offer obligation, but not needed in 
real time would get paid their start-up and no-load costs.
---------------------------------------------------------------------------

    411. The Commission invites comment on how to structure the local 
market power mitigation, particularly on how to define the 
noncompetitive conditions which should trigger the mitigation, and on 
how bid caps should be structured for generators operating under a 
participating generator agreement.
    412. There are some options for dealing with the risk of a forced 
outage inside a load pocket. One is for a portion of available day-
ahead capacity to be exempt from the bid-in requirement to reflect 
forced outage risk in real time. Another possibility is to allow 
generators to provide all available capacity in real time at a capped 
bid in lieu of bidding in the day-ahead market to accommodate 
generators that have significant risk or opportunity costs. A third 
option would vary depending on whether the generator receives a reserve 
capacity payment. If the generator receives a capacity payment, that 
payment compensates for the outage risk so the generator should be 
obligated to deliver energy or to pay for substitute supply from some 
other source. If the generator does not receive a capacity payment, 
then it should not have to bear the risk for a legitimate outage. Units 
declaring a forced outage would be subject to audit by the market 
monitor. If the outage is found to be unjustified, then the generator 
should be subject to a penalty. The Commission requests comment on the 
penalty that would be appropriate to deter unjustified forced outages.
4. The Safety-Net Bid Cap
    413. If bid-in capacity is generally insufficient to meet both 
operating reserve requirements and load, capacity rights associated 
with the resource adequacy requirement may be exercised by load-serving 
entities that have secured sufficient capacity so that they will not be 
interrupted. However, in this situation, lack of demand response can

[[Page 55506]]

result in dramatic increases in market-clearing prices, even with 
comprehensive mitigation on the supply-side, if imports can bid in at 
unrestrained levels. In this case, imported power from adjacent markets 
could set a market-clearing price above the marginal cost of the 
highest cost unit dispatched within the market.\205\
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    \205\ Generators outside the region would not have participating 
generator agreements with the Independent Transmission Provider, 
with provisions for addressing local market power, and neither would 
marketers.
---------------------------------------------------------------------------

    Current markets in the Northeast and Texas rely on a $1000 per 
megawatt-hour bid cap, regardless of market conditions, as a safety-net 
that may be binding in this situation. The Commission proposes to adopt 
a safety-net bid cap as part of the market power mitigation plan here. 
Under this proposal, no bid to supply can exceed this level, regardless 
of cost or risk or location, even if the market is confronted with a 
genuine operating reserve shortage. However, if the monitor establishes 
that some units may provide power at a cost that exceeds the safety-
net, a higher price for those units would be justified. In California, 
for example, imports are not allowed to set the market clearing price. 
However, in the market power mitigation framework proposed here imports 
would be allowed to set the market clearing price in order to get a 
proxy for a scarcity price, up to a capped value. If requirements 
cannot be satisfied with bid-in imports that would be subject to the 
safety-net bid cap, then load that has not met its resource adequacy 
requirement should be penalized as described in the Resource Adequacy 
section. A safety-net bid cap, such as the $1000 per megawatt-hour cap 
in the Northeast and Texas, can serve as a proxy scarcity price under 
Standard Market Design. The Commission requests comment whether the 
safety-net bid cap should be uniform across an interconnection, so that 
there would be one cap applicable in the East and another applicable in 
the West.
    414. Comment is requested on how to determine an appropriate value 
for such a cap. It is important to examine the implicit trade-off 
between bilateral capacity payments, the safety-net bid cap and local 
market power mitigation. That is, a bid cap that constrains scarcity 
prices would be expected to translate into higher bilateral capacity 
payments under a contract to fulfill the long-term resource adequacy 
requirement. With a higher safety-net bid cap, perhaps one based on the 
value of lost load, smaller bilateral capacity payments would be 
required to maintain the same level of resource adequacy in the absence 
of price.
5. Mitigation Triggered by Market Conditions
    415. The Commission proposes a fourth voluntary market power 
mitigation measure which may be recommended by the market monitor 
during the Standard Market Design implementation process, or any time 
thereafter. This measure, if needed, would apply to unanticipated and 
sustained market conditions that would give the ability and the 
incentive to exercise market power. For example, extreme supply or 
demand conditions to which the market cannot quickly adapt, such as the 
loss of significant hydropower capacity because of drought, or force 
majeure events such as a major transmission line outage. These kinds of 
events, which are not transitory, can provide opportunities to exercise 
market power even in a market that is normally workably competitive. It 
may be appropriate for other conditions to trigger this mechanism. We 
seek comment on what these triggers should be. Although market-clearing 
prices would be expected to rise in these situations, and perhaps 
sharply and significantly, it may be important for the market to have 
the assurance that the price increases are attributable to the extreme 
circumstances and not to the exercise of market power. An AMP mechanism 
such as those approved by the Commission in New York ISO and California 
could provide this kind of assurance.\206\
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    \206\ See California Independent System Operator Corp., 100 FERC 
[para] 61,060 (2002). See New York Independent System Operator, Inc. 
et al., 99 FERC [para] 61,246 (2002). Although AMP was in effect in 
all of New York, it was only triggered on four occasions, reflecting 
conditions in eastern New York.
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    416. This kind of mechanism may not be necessary in every region. 
If a market monitor proposes such a mechanism, the proposal must 
include the specific triggers that would be used to initiate this form 
of market power mitigation along with the details of the mitigation 
method. Since this form of market power mitigation is for temporary 
market conditions, it will be equally important for the market monitor 
to indicate the criteria to determine when the market has returned to 
normal competitive conditions and this market power mitigation method 
will be suspended.
    417. The details of this market power mitigation method, including 
the triggers, would be set out in the Independent Transmission 
Provider's tariff. If market conditions developed that satisfied the 
pre-determined triggers for the mechanism, it would be the market 
monitor's responsibility to give notice to the public and the 
Commission that the tariff mechanism had been triggered. The mechanism 
would then automatically take effect until the conditions developed 
that satisfied the pre-determined triggers for the suspension of this 
market power mitigation mechanism. If a market monitor proposes to use 
this form of market power mitigation, the details of the mechanism and 
the triggers would be subject to comment by all interested parties, and 
review by the Commission.
6. Establishing Bid Caps or Competitive Reference Bids
    418. The mitigation for local market power, through the 
participating generator agreements, relies on must-offer obligations to 
mitigate physical withholding and bid caps to mitigate economic 
withholding. Mitigating economic withholding entails determining 
appropriate bid caps for all bid-in parameters.\207\ The unit-specific 
bid caps in the participating generator agreements serve as proxy 
competitive bids for energy, regulation service, and operating 
reserves, and for other unit-specific operating parameters such as 
minimum run times and high and low operating levels. Bid caps should 
reflect the marginal cost--including opportunity cost--of offering all 
capacity, including power that may be supplied only under limited 
conditions. Other bid-in parameters should reasonably reflect operating 
conditions consistent with good engineering practice under competition.
---------------------------------------------------------------------------

    \207\ These same considerations would apply if the Commission 
adopted an AMP-like mechanism with bid caps or competitive reference 
bids.
---------------------------------------------------------------------------

    419. The development of bid caps, especially for generators with 
significant opportunity costs such as hydropower and energy-limited 
units, is difficult and can be controversial. Nevertheless, this 
mitigation plan would require that each generator, including hydropower 
and energy-limited units, that may have local market power would need 
to have an agreement establishing bid caps for all bid-in parameters if 
its power is needed for the grid or local market power mitigation is 
necessary.
    420. The Commission has approved several options for setting 
default energy bids that in some circumstances serve as energy bid 
caps. They include: (1) Default bids based on various averages of 
previously selected in-merit bids; (2) default bids based on various 
cost measures, usually a measure of operating cost adjusted for fuel 
costs;

[[Page 55507]]

and (3) default bids agreed through contract or negotiation. For many 
fossil-fired units, an estimate of operating costs plus a margin, such 
as ten percent, could provide a reasonable bid cap for a unit's energy 
bid when competitive forces cannot be relied on, similar to PJM's 
approach for mitigating reliability must run units.\208\ Although 
fossil-fired units may have opportunity costs not fully reflected by 
operating costs, an adder, such as that used by PJM, is one way to 
allow flexibility to respond to these uncertain costs. The Commission 
requests comment on whether the level of the adder should be reviewed 
on a region-by-region basis or if the Commission should establish a 
uniform adder, and if so, at what level.
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    \208\ This method may not work for fossil-fired units that are 
only permitted to run a limited number of hours due to environmental 
restrictions. These energy-limited resources are discussed below.
---------------------------------------------------------------------------

    421. For peaking units that are likely to set market clearing 
prices when they are dispatched, the must-offer requirement coupled 
with mitigation that sets bid caps at marginal cost could result in 
revenues that fail to recover fixed costs over a reasonable period of 
time. Although such units may recover additional revenue in capacity 
and reserves markets, bid caps for these units could also reflect a 
``scarcity'' premium or adder to compensate for the lack of price-
responsive demand that would otherwise set the price when these units 
were dispatched. The average cost of a new peaking unit at a given 
location operated over a given number of hours could form the basis for 
setting such a premium. This kind of adjustment to bid caps for peaking 
units could help support reliability until demand-side measures for 
responding to price were more fully incorporated in markets. The 
Commission requests comments on whether this approach or other 
adjustments to bid caps for peaking units might usefully substitute for 
demand response in the near term.
    422. For hydropower and other energy-limited resources much of the 
difficulty in determining an appropriate energy bid cap for these units 
comes from the difficulty of assigning a value to their temporal 
opportunity costs. However, the times when it would be necessary for 
the transmission provider to call on power from these sources are 
likely to be times when prices are high and these units would want to 
be scheduled in any event. At all other times, hydropower units, in 
particular, should be offering all available capacity as operating 
reserves since their marginal operating costs are close to zero, but 
they may have high temporal opportunity costs. In other words, there 
appears to be no economic reason why such units should not always be 
fully committed either to the bilateral market or spot markets for 
operating reserves. Consequently, it appears unnecessary to cap energy 
bids from such resources below the safety-net bid cap as long as their 
bids to provide operating reserves were always in-merit. Alternatively, 
other energy-limited resources might be allowed to submit a bid that 
states a total megawatt-hour availability over the day and allow the 
market operator to schedule the power from the unit in the hours when 
the price is highest. Comment is requested on these and other 
approaches to establishing reasonable caps for energy bids.
    423. Another alternative for hydropower, and other energy-limited 
resources, would be for the unit operator to submit a seasonal or 
monthly schedule for when the unit would not be expected to operate. 
This would enable, for example, hydropower units to specify the periods 
when they would expect to need to preserve water or flow water to 
satisfy environmental conditions. While these units have many 
legitimate competing needs for the water flow, it is still possible for 
a hydropower generator to engage in physical or economic withholding. 
In the existing ISOs, generators must submit a schedule for planned 
outages, which is coordinated by the ISO to ensure that outages occur 
when they are the least disruptive to the markets. The Independent 
Transmission Provider is expected to continue to perform this outage 
coordination function under Standard Market Design. Scheduling outages 
in advance, coupled with auditing by the market monitor, would provide 
a way to evaluate whether failures to run were from withholding or 
legitimate limitations. For hydropower units, for which the marginal 
costs are primarily opportunity costs, this method may be a sufficient 
check against withholding so that it might be unnecessary to have a bid 
cap for these units. The Commission requests comment on these 
alternatives.
    424. Any parameters that a generator may include in its bid may 
require a cap or other restraint. For example, PJM caps regulation 
service at $100 per megawatt-hour, and New England uses energy prices 
to cap prices for spinning reserves. Standard Market Design would also 
allow availability bids for these products. The participating generator 
agreements should also contain bid caps for these operating reserves 
when they are needed for the operation of the transmission system and 
non-competitive conditions exist. However, the Commission requests 
comment on how to identify the options for determining competitive bid 
caps for regulation service and operating reserves, including 
availability bids, that should be established for day-ahead and real-
time markets.
    425. In the New York and PJM day-ahead markets, the unit-specific 
energy bid cap applies to the day-ahead market where separate bids for 
start-up and no-load costs are also available and would also be 
available under Standard Market Design. Market power mitigation should 
also establish caps for these bids and a variety of bid-in operating 
parameters, such as low and high operating levels and minimum run 
times, if non-competitive circumstances would permit sellers to 
manipulate these parameters to get unjustified higher up-lift payments. 
PJM, for example, does not mitigate the start-up and no-load bids or 
certain operating parameters, but it only allows units to change these 
values once every six months. New York permits greater flexibility and 
uses various screens to assess whether a seller is behaving non-
competitively and should be mitigated.
    426. Several approaches could be used for establishing bid caps for 
these particular parameters. One possibility would be to rely on 
engineering data, such as from the manufacturer about the specific type 
of unit, to establish caps for start-up and no-load bids and certain 
operating parameters, and give generators the flexibility to bid within 
those ranges without mitigation. These ranges would also be included in 
the generators' participating generator agreements. Just as with energy 
bids, a bid above the range could be mitigated if the bid raised 
market-clearing prices or uplift payments above a competitive benchmark 
level by a significant amount. Because factors that might cause 
generators to modify start-up and no-load bids and parameters such as 
minimum run times generally are thought to be less variable than 
factors that may influence energy bids, caps for these variables may be 
quite tight.\209\ In fact, PJM's approach to permit changes to these 
parameters once every six months may be a simpler alternative that does 
not unduly restrict competitive generator behavior. Comment is 
requested on this approach and on other ways to prevent sellers from 
manipulating these bids and operating parameters to increase market-
clearing prices and uplift payments.
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    \209\ For example, energy prices could change frequently because 
of differences in the cost of fuels such as natural gas.

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[[Page 55508]]

    427. In the implementation filing, the market monitor would propose 
tariff language that sets forth the process for setting the bid caps 
for individual units or any formulas that might be used for this 
purpose. The market monitor would be responsible for collecting and 
verifying data from these units to establish appropriate caps for 
energy bid values consistent with the procedures in the Independent 
Transmission Provider's tariff. This could be controversial, especially 
for generators in load pockets that may effectively face ``mitigation'' 
in most situations. The Commission requests comment whether the 
Commission should establish a formula for determining the bid caps or 
whether the Commission should review the proposals developed in each 
region.
7. Exemptions
    428. It is appropriate to exempt certain sellers from the market 
power mitigation. Specifically, sellers who control a small amount of 
capacity in the market, for example no more than fifty megawatts, would 
be exempt from mitigation. Sellers with little capacity would have 
little incentive to exercise market power since a non-competitive bid 
could eliminate their only unit from the dispatch. However, the 
Commission requests comment whether any other sellers should be exempt 
from the mitigation because they have insufficient incentives to 
withhold.
8. Monitoring
    429. Market monitoring should be conducted on an on-going basis by 
a market monitoring unit that is autonomous of the Independent 
Transmission Provider's management and market participants. The market 
monitoring unit may be located within the offices of the Independent 
Transmission Provider, to permit easy access to the market data and 
operations personnel, or it may be physically located elsewhere.
    430. The market monitor will be expected to report directly to the 
Commission, and the independent governing board of the Independent 
Transmission Provider. This will include reporting at regular intervals 
on the general performance of the markets in its region and reporting, 
on a timely basis, observed attempts at market manipulation or factors 
that impair the efficiency of the market. Although the market monitor 
will be accountable only to the Commission and the governing board, it 
should share its analyses and reports with the management of the 
Independent Transmission Provider and the Regional State Advisory 
Committee. This will enable the committee to carry out its advisory 
functions in an informed manner.
    431. The market monitor must focus both on the functioning of the 
markets run by the Independent Transmission Provider as well as the 
conduct of individual market participants. The market monitor should 
focus on identifying factors that might contribute to economic 
inefficiency. Such factors include market design flaws, inefficient 
market rules, entry barriers to new generation, including distributed 
generation, barriers to demand-side resources, transmission constraints 
and market power. In monitoring for exercises of market power, the 
market monitor should focus principally on detecting economic and 
physical withholding (as distinct from the normal operation of supply, 
demand, and true scarcity). For entities that own both transmission and 
generation assets, withholding behavior could include both generator 
and transmission outages. For example, instead of directly withholding 
a generator's power, a market participant with transmission assets 
could effect the same end by derating a transmission line needed to 
deliver the generator's power to the market. Monitoring should be 
designed to detect this kind of behavior.
    432. The Commission requests comment on whether the market monitor 
should also be responsible for monitoring the Independent Transmission 
Provider's operations, in addition to the markets and the market 
participants. Specifically, should the market monitor evaluate whether 
the Independent Transmission Provider treats market participants 
neutrally, without undue discrimination?
    433. To meet its responsibilities, the market monitor must have the 
ability to collect and evaluate necessary data provided by the 
Independent Transmission Provider and market participants. The market 
monitor would have the responsibility to propose to the Commission, and 
the Independent Transmission Provider's board changes to market rules, 
if they provide inefficient incentives to market participants, and to 
promptly identify circumstances that may require additional market 
power mitigation so that remedies can be put in place 
prospectively.\210\ The market monitor would also be required to 
provide a comprehensive analysis and report of market structure and 
individual generator conduct in the spot markets, at least annually, to 
evaluate the overall efficiency of spot market operations, the market 
for Congestion Revenue Rights, and how the balance between resources 
and demand in the region affects the market's ability to efficiently 
serve load at least cost. In addition, the market monitor must also 
annually assess the effectiveness of any mitigation actions taken and 
review the terms, conditions, and bid caps in the participating 
generator agreements. Finally, the market monitor must engage in 
surveillance to insure that market participants comply with the rules 
in the Independent Transmission Provider's tariff.
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    \210\ The changes would only go into effect after Commission 
approval.
---------------------------------------------------------------------------

    434. The work and findings of the market monitor must be integrated 
into the regional planning process. The market monitor's analysis of 
the markets will identify load pockets and can help provide direction 
for needed investment in generation, including distributed generation, 
demand response capability, and transmission infrastructure to improve 
the competitive structure of the markets.
    435. The Commission proposes here the basic elements of a market 
monitoring plan to be used by each market monitor. The Commission staff 
will convene a conference in the Fall to discuss and further develop 
the essential elements that should be required in a standard market 
monitoring plan. After getting additional public input at the 
conference, Staff may propose additional detail for the market 
monitoring plan, which the Commission may adopt, after an opportunity 
for public comment.

a. Framework for Analyzing Market Structure and Market Conduct

    436. The Commission intends to require the use of a core set of 
questions and analytical techniques to be used by each market monitor 
to assess market structure, participant behavior, market design, and 
market power mitigation. This will facilitate inter-regional 
comparisons. Examining this core set of issues using techniques 
reflecting ``best practices'' would be an essential part of the 
monitor's responsibilities that allows inter-regional comparisons. 
However, specifying these core requirements here should not prohibit or 
discourage monitors from expanding their analyses where regional 
differences or unanticipated events warrant it. In fact, because 
markets and monitoring are in a formative stage, the Commission would 
need to continue to facilitate communication between market monitors to 
share insights and develop common approaches.
    437. An important focus of market monitoring will be structural 
market

[[Page 55509]]

conditions since the Commission's ultimate goal is to foster 
structurally competitive regional bulk power markets. Academic analysts 
and market monitors have examined the competitiveness of current spot 
markets using various approaches and data. Some have focused on 
developing a simulated competitive benchmark that can serve as a 
reasonable measure of the market's overall efficiency.\211\ Others have 
examined whether specific generator bidding behavior has been 
consistent with profit maximization under competitive conditions.\212\
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    \211\ See, e.g., Borenstein, S., J.B. Bushnell, and F. Wolak 
(1999). ``Diagnosing Market Power in California's Deregulated 
Wholesale Electricity Market.'' POWER Working Paper PWP-064, 
University of California Energy Institute, available in http://www.ucei.berkeley.edu/ucei/pwrpubs/pwp064.html.
    \212\ Joskow, P.J., and E.P. Kahn (2001). ``A Quantitative 
Analysis of Pricing Behavior in California's Wholesale Electricity 
Market During Summer 2000.'' NBER Working Paper No. W8157. National 
Bureau of Economic Research.
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    438. Some monitors have estimated whether average generator 
profitability would cover costs of a gas-fired peaking unit and provide 
sufficient inducement for entry.\213\ Most monitors also track bidding 
patterns so that sudden, inexplicable changes can be investigated 
promptly to evaluate whether market power is a cause of the 
change.\214\ Monitors also track changes in concentration, unplanned 
generator and transmission outages, and changes in various operating 
parameters that may signify market power problems.\215\ Although the 
reports have been very useful in enhancing our understanding of a wide 
range of issues, the approaches have been varied, key questions have 
been framed differently and, importantly, the markets have not had the 
same design. As a consequence, results have not been comparable across 
markets. With the widely varying market designs of the past, greater 
comparability across regions was not feasible. However, these analyses 
have served as a useful starting point for developing a standard 
analytical framework.
---------------------------------------------------------------------------

    \213\ See, e.g., PJM Interconnection State of the Market Report 
2000.
    \214\ See, e.g., New York Market Advisor Annual Report on The 
New York Electricity Market for Calendar Year 2000, by David B. 
Patton, Ph.D., Capital Economics, April, 2001.
    \215\ See, e.g., Annual Market Report, May 2000-April 2001, ISO 
New England, August 1, 2000.
---------------------------------------------------------------------------

    439. The Commission proposes to require each monitor to perform a 
structural analysis of the region that would include: (1) Market 
concentration including by type of generation, (2) conditions for entry 
of new supply, (3) demand response, and (4) transmission constraints 
and load pockets that give sellers the ability and incentive to 
exercise market power. This analysis would be performed prior to the 
implementation of the Standard Market Design, in order to implement the 
market power mitigation. It also would be performed annually to 
reassess and adjust the market power mitigation, and to evaluate the 
conditions of the market.\216\
---------------------------------------------------------------------------

    \216\ The monitor should particularly pay attention to 
concentration in the regulation and operating reserves markets, and 
consider the amount of supply relative to demand, and propose 
specific market power mitigation measures for these markets if 
necessary.
---------------------------------------------------------------------------

    440. In addition, the Commission proposes to require an annual 
assessment of the performance of the markets operated by the 
Independent Transmission Provider. This assessment would use a 
competitive benchmark to assess market performance as an additional 
means of assessing the effectiveness of the market power mitigation.
    441. Comment is requested on how the monitor should address these 
and other topics, to develop useful measures that permit inter-regional 
comparisons. For example, concentration measures stratified by 
generator type might better identify competitive alternatives under 
various demand conditions. Estimates of generator profitability, such 
as PJM and ISO-New England have used in the past, might be a useful 
measure of incentives for generator entry. These estimate the degree to 
which a hypothetical unit operating in all profitable hours would have 
recovered its costs. Although it is not a definitive profit estimate 
for any particular generator, it may be a useful measure for comparing 
incentives for generator entry across market or regions.
    442. A core set of questions and analytical techniques must also be 
developed for monitors to use to evaluate conduct of market 
participants in the transmission and spot markets operated by the 
Independent Transmission Provider. Analysis of generation and 
transmission outages is central because these can be forms of 
withholding. Because some owners of generation also own transmission, 
monitors must review any planned transmission outages, for example, to 
make sure that scheduling outages could not be used to enhance or 
create opportunities to exercise generator market power. Analysis of 
generator conduct might also include a review of bidding behavior in 
the spot markets operated by the Independent Transmission Provider to 
identify any auction design flaws that may give market participants an 
unanticipated incentive and ability to manipulate market-clearing 
prices or up-lift payments. The monitor should also evaluate the 
effectiveness of the participating generator agreements in mitigating 
market power where market structure is not sufficiently competitive.
    443. Finally, the monitor must analyze the operation of the 
congestion management system and the market for the resale of 
Congestion Revenue Rights for evidence of market power or manipulation. 
The monitor must also assess whether those who collect congestion 
revenues are in a position to influence transmission expansion plans 
that can affect congestion revenues and report on the incentive 
structure of those arrangements.
    444. Any flaws in the market rules that may be identified by the 
monitor and any market participant conduct that indicates the ability 
to exercise market power under the market rules in effect would be 
remedied prospectively after Commission authorization of changes to the 
market rules. However, if the conduct violates existing rules, the 
market monitor must have the necessary tools to investigate the conduct 
and to penalize it. These will be discussed in the sections below.
    445. An important adjunct to the market power mitigation and 
monitoring plan will be a clear set of rules governing market 
participant conduct with the penalties for violations clearly spelled 
out. The Commission proposes to require the Independent Transmission 
Provider to include in its tariff certain minimum behavioral rules, 
which will be monitored by the market monitor. These will include, at a 
minimum, the following rules:
    (1) Physical Withholding: Entities may not physically withhold the 
output of an Electric Facility (Generating unit or Transmission 
Facility) by (a) falsely declaring that an Electric Facility has been 
forced out of service or otherwise become unavailable, or (b) failing 
to comply with the must-offer conditions of a participating generator 
agreement.
    (2) Economic Withholding: Entities may not economically withhold by 
submitting high bids that are not consistent with the caps specified in 
the tariff or the participating generator agreements.
    (3) Availability Reporting: Entities must comply with all reporting 
requirements governing the availability and maintenance of a Generating 
Unit or Transmission Facility, including proper Outage scheduling 
requirements. Entities must immediately notify the Independent 
Transmission Provider when capacity changes or resource limitations 
occur that affect the

[[Page 55510]]

availability of the unit or facility or the ability to comply with 
dispatch instructions.
    (4) Factual Accuracy: All applications, schedules, reports, or 
other communications to the Independent Transmission Provider or the 
Market Monitor must be submitted by a responsible company official who 
is knowledgeable of the facts submitted. All information submitted must 
be true to the best knowledge of the person submitting the information.
    (5) Information Obligation: Entities must comply with requests for 
information or data by the Market Monitor or the Independent 
Transmission Provider that are consistent with the tariff.
    (6) Cooperation: Entities must assist and cooperate in 
investigations or audits conducted by the Market Monitor.
    (7) Physical Feasibility: All bids or schedules that designate 
resources must be physically feasible within the limits of the 
resource, i.e., the resource is physically capable of supplying the 
energy, ancillary service, or demand response needed to fulfill a 
schedule or bid according to the physical limitations of the resource.
    446. These rules must be accompanied by predetermined penalties, as 
discussed below in the Enforcement section.

b. Data Requirements and Data Collection

    447. Data collection should be targeted to providing monitors with 
information necessary to answer the required questions covering 
critical issues regarding market structure, participant behavior, and 
market design. These data would be acquired from various public sources 
and in the normal course of operating the markets. They would include: 
(1) Market statistics and indices, such as market-clearing prices and 
system-wide congestion costs; (2) data on system conditions, such as 
transfer capability and planned and forced outages; (3) information on 
other prices, such as fuel prices and prices in adjacent markets; (4) 
information on load served from the spot market; (5) data relating to 
generator bidding patterns; and (6) information on Congestion Revenue 
Rights.
    448. In addition, monitors must have the ability to obtain data on 
generator production and opportunity costs and information on the 
operating status of transmission and generation facilities that relate 
to claimed outages or deratings. Generator-specific data on all 
relevant costs and operating parameters--e.g., start-up, no-load, 
environmental, fuel, maintenance, ramp rates, low and high operating 
levels, and heat rates--may also be relevant to establishing 
appropriate bid caps for participating generator agreements. These data 
when combined with information acquired in the normal course of 
business operations and schedules for planned outages should give 
monitors the information they need to fully analyze the competitiveness 
of the markets operated by the Independent Transmission Provider.
    449. As a condition for participating in the spot markets, and 
using the transmission grid, market participants must agree to provide 
the market monitor with any information requested. Since the ability of 
the market monitor to perform his or her monitoring role is dependent 
upon the ability to acquire the necessary information, the monitor must 
have the ability to require market participants to provide information. 
This is an important enforcement tool. The Independent Transmission 
Provider's tariff should specify the penalties that would apply to 
market participants who fail to comply with an information request from 
the market monitor. Market participant objections to market monitor 
information requests will be resolved by the Commission on an expedited 
basis because delays in providing information could result in 
continuing harm to the market. In any such dispute the Commission will 
give substantial deference to the market monitor's stated need for the 
information.
    450. All information obtained by the monitor that is specific to a 
market participant would be treated confidentially. Any disputes 
concerning how the confidential information could be used would be 
resolved by the Commission, before the data are released to the public. 
Since the Commission has oversight responsibility for wholesale 
electric markets, any data collected by the market monitor would be 
available to the Commission and the confidentiality of the data would 
be protected by the Commission under its regulations.

c. Reporting Requirements

    451. At a minimum, the monitor would be required to submit an 
annual report to the Commission and the Independent Transmission 
Provider's governing board, and share that report with the Regional 
State Advisory Committee. The report would include: (1) A general 
description of the market operations, supply and demand, and market 
prices; (2) an analysis of market structure and participant behavior 
following guidelines described above; (3) an evaluation of the 
effectiveness of mitigation measures taken; (4) an overall assessment 
of market efficiency perhaps using a simulated competitive benchmark as 
some have developed; (5) an evaluation of barriers to entry for 
generating, demand-side, and transmission resources; and (6) any 
recommended changes to market design or market power mitigation 
measures to improve market performance. The report would also include a 
discussion and analysis of any region-specific issues that the monitor 
judges important to achieving a competitive outcome. This could also be 
particularly useful to the planning process in determining where 
expanded transmission capacity might reduce market power problems in 
load pockets. The annual report would be made public, with appropriate 
protections to maintain confidentiality, if necessary.
    452. In addition, the market monitor will be required to report to 
the Commission, through the Office of Market Oversight and 
Investigation, any instances of conduct by market participants that 
appear to be inconsistent with the Independent Transmission Provider's 
tariff. Early reporting of questionable conduct will permit 
coordination between the market monitor and the Commission's 
investigative staff to determine the best methods for developing the 
facts and addressing conduct that could be harmful to the market.
    453. The Commission requests comment whether additional reporting 
requirements are needed.

d. Enforcement of the Tariff Rules

    454. The market monitor must play an important role in the 
enforcement of the market rules contained in the Independent 
Transmission Provider's tariff. In this role the market monitor will 
need to coordinate closely with the Commission's investigative and 
enforcement staff. However, to ensure effective enforcement, the market 
monitor must have adequate authority to investigate market participant 
conduct and the Independent Transmission Provider must have a set of 
predetermined penalties to apply to conduct that is in violation of the 
rules of the Independent Transmission Provider's tariff.
    455. As a condition of participating in the markets operated by the 
Independent Transmission Provider and using the transmission grid 
operated by the Independent Transmission Provider, the Commission 
proposes to require market participants and transmission customers to 
agree to predetermined penalties that would apply to violations

[[Page 55511]]

of the tariff rules. Since the tariff rules are intended to ensure the 
fair and efficient operation of the markets, the penalties should be 
designed to deter conduct that is inconsistent with the fair and 
efficient operation of the markets. Specifically, the penalties should 
deter conduct that results in an economic benefit derived from a 
violation of the rules. The penalties should, at a minimum, require 
payment of the economic benefit derived by the violator from violating 
the rules. Where the violation could result in conduct that could be 
harmful to the reliability of the grid, it would be appropriate for the 
penalty to be significantly higher to serve as a deterrent for the 
conduct. The Independent Transmission Provider's tariff must specify 
the conditions that would apply for each level of penalty.
    456. It may be appropriate to build into the tariff standards for 
mitigating the penalty. Some standards that could be used are: the 
impact on the operation of the grid, the financial impact on the 
violator, and any good faith efforts to maintain compliance. The 
Commission requests comment on the conditions that would justify 
mitigation of the penalty.

J. Long-Term Resource Adequacy

    457. To operate the transmission system reliably, the transmission 
operator must be able to balance generation and load at all times. This 
requires adequate electric generating, transmission, and demand 
response infrastructure. Some lead time is needed to develop adequate 
infrastructure for the future through self supply or bilateral 
contracting.
    458. Resource adequacy today must be assessed at the regional 
level. Because all customers in an interconnected region are 
interdependent, a shortage of resources for some customers in the 
region can lead to a shortage for the entire region, which threatens 
reliable grid operations and risks sustained shortages with attendant 
high prices for the region.
    459. We propose a resource adequacy requirement to provide for 
sufficient supply and demand resources to avert such shortages. Under 
these procedures, we believe that involuntary curtailment will rarely 
if ever be employed. However, consistent with current policies, the 
proposal must include procedures for such emergency conditions.
1. The Reason for the Requirement
    460. The Commission proposes to adopt a resource adequacy 
requirement to help ensure development of the infrastructure needed for 
reliable transmission system operation. Because electricity cannot be 
generated and easily stored for future delivery, extra generating and 
demand response resources are needed to serve a function similar to 
storage in the natural gas industry; other commodity markets would call 
these a supply inventory. The cost of necessary reserves is analogous 
to the necessary cost of storage or inventory.
    461. A requirement to assure adequate long-term resources is 
currently needed because spot market prices do not consistently signal 
the need for new infrastructure in the electric power industry. Most 
resources take years to develop and spot market prices alone may not 
signal the need to begin development of new resources in time to avert 
a shortage. Moreover, spot market prices that are subject to mitigation 
measures may not produce an adequate level of infrastructure investment 
even after a shortage occurs. Further, as long as regional resources 
are made available to all regional load-serving entities and their 
customers during a shortage, such entities have the incentive to lower 
their supply costs by depending on the resource development investments 
of others, a strategy that leads to systematic under-investment in 
infrastructure by all load-serving entities in the region.\217\
---------------------------------------------------------------------------

    \117\ For further discussion of these topics, see e.g., Steven 
Stoft, Power System Economics (IEEE Press, Wiley-Interscience, 2002) 
especially ``Fallacy: The `Market' Will Provide Adequate 
Reliability.''
---------------------------------------------------------------------------

a. Spot Market Prices Alone Will Not Signal the Need To Begin 
Development of New Resources in Time to Avert a Shortage
    462. The spot market price does not yet work well to produce long-
term reliability investment, even without price mitigation, for several 
reasons. Extra resources need to be planned in advance for electricity 
because, when prices rise, demand is not reduced quickly and new 
generation cannot be added quickly. Both the demand for electricity and 
the supply of new generating capacity generally respond very slowly to 
price.
    463. Regarding demand response, most retail customers buy power at 
a regulated fixed price. Even in states that have approved retail 
competition, customers are often shielded for years from price changes 
by a rate freeze. They are unaware of hourly changes in the cost of 
producing electricity. Electric meters are read monthly, and customers 
see only the imperfect price signal of a monthly bill rendered after 
electricity is used. Although larger commercial and industrial 
customers can be more price responsive, for many of them electricity is 
a small fraction of their cost of doing business and may receive little 
managerial attention. It takes time to develop the administrative rules 
and the technical capability to reduce consumption. As a result, most 
demand today is unable to respond to real-time prices because of 
insufficient price information, inflexible rate designs, and metering 
limitations.
    464. The response of new generating capacity to price is slow 
because it takes time to plan, site and construct new electric power 
generating facilities. Development of a new power plant takes two to 
five years or more, depending on the type of plant and its location. It 
can take even longer to site the transmission lines needed to transmit 
the power to customers.
    465. These factors together can lead to sustained periods of 
inadequate supplies, threatening the reliable operation of the bulk 
power system. Insufficient demand response to price and the slow supply 
response to price can combine to produce electricity shortages that not 
only threaten reliability but also can raise day-ahead and real-time 
market prices significantly.
    466. Further, rushing to relieve inadequate regional supplies and 
reduce high regional spot prices may bias construction choices toward 
supply resources that can be constructed quickly, perhaps sacrificing 
long-term cost minimization, environmental concerns and fuel diversity 
goals. Most customers prefer spreading out resource capital costs over 
time to concentrating them into a peak period. A resource adequacy 
requirement accomplishes this.
b. Spot Market Prices That Are Subject to Mitigation Measures May Not 
Produce an Adequate Level of Investment When a Shortage Occurs
    467. Customers object strongly to inadequate supplies--and high 
prices when supplies are inadequate--because electricity is essential 
for many uses and customers cannot turn to substitutes to reduce 
electricity demand. Electric power drives modern life, and there is 
significant societal disruption from even short supply interruptions.
    468. For these reasons, customers want protection from the exercise 
of market power that may occur when supplies are short, and some form 
of market power mitigation is needed under these circumstances, as 
discussed in the market power mitigation section. However, market power 
mitigation may tend to suppress the scarcity price that

[[Page 55512]]

would otherwise stimulate new resource development. As a result, 
investors may not develop adequate infrastructure--making the problem 
worse--unless there is a provision for resource adequacy. Such a 
provision helps customers by assuring adequate supplies and helps 
generation developers by creating a demand for resources in advance of 
electricity prices doing so alone.
c. Load-serving Entities Will Underinvest in Resources Needed for 
Reliability if They Can Depend on the Resource Development Investments 
of Others
    469. In an interconnected region, the failure of some market 
participants to secure sufficient long-term electricity resources can 
contribute to a shortage that affects reliability and spot market 
prices for all participants in the wholesale power market.
    470. Under retail competition, load-serving entities competing for 
customers may compete on the basis of cutting the cost of forward 
contracting for resources unless they all are held to the same resource 
adequacy requirement. Without such a uniform requirement, those 
suppliers that contract for reserves may lose market share, and those 
who do not may gain a market share--at least for a short period of 
time. For this reason, a load-serving entity has an incentive to 
minimize its own costs by procuring few or no reserves and relying on 
others to develop reserves. If the rules allow it, some load-serving 
entities will try to have the reliability benefit of adequate regional 
resources that other load-serving entities pay for or that 
uncontracted-for generation must offer pursuant to market power 
mitigation.
    471. Severe power shortages lead to public insistence on government 
intervention. Both historical practice and recent events indicate that 
during a shortage those load-serving entities that have reserves are 
required by government to share them with those that do not have 
reserves. There are at times state regulatory and gubernatorial 
requirements to protect customers from blackouts or high prices, a U.S. 
Department of Energy requirement for utilities to share power reserves 
in an emergency, or a Commission requirement to bid all available power 
into an organized spot market.
    472. Some market participants depend on government intervention 
during severe shortages as an alternative to paying their share of the 
cost of developing adequate regional resources. As long as regional 
reserves are made available to all, a load-serving entity can reduce 
its own reserve resource costs and rely on the resources of others. The 
result is that all load-serving entities will tend to follow this 
strategy, leading to a systematic underinvestment in resources needed 
for reliability.\218\ The current physical configuration of the 
transmission grid often exacerbates this problem because it is often 
difficult to impose the results of one party's resource shortfall 
solely on that party. For example, if several competing load-serving 
entities serve customers in the same electrical neighborhood, it may 
not be technically feasible to curtail some of these customers and not 
others during a shortage.
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    \218\ This is the well-known ``free rider'' problem for public 
goods, those for which consumption cannot be limited to those who 
paid for them (such as parks and national defense) and that are 
available to all users even if only some users pay for them. See, 
e.g., Lee S. Friedman, The Microeconomic of Public Policy Analysis, 
Princeton University Press (Princeton, NJ 2002), which states at 
pages 597-598:
    If their provision were left to the marketplace, public goods 
would be underallocated. The reason is that individuals would have 
incentives to understate their own preferences in order to avoid 
paying and free-ride on the demands of others. Thus, public goods 
provide one of the strongest arguments for government intervention 
in the marketplace: not only does the market fail, but it can fail 
miserably.
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    473. These arguments persuade us to propose a long-term resource 
adequacy requirement in the Standard Market Design rule. A resource 
adequacy requirement provides for timely development of supply and 
demand response resources to assure regional resource adequacy. It 
helps smooths out the price swings of the electricity business cycle. A 
well-designed resource adequacy requirement supports competitive 
markets if it allows suppliers to compete to provide infrastructure and 
buyers to choose the infrastructure with the best combination of 
features such as cost, reliability, environmental effects, and service 
life.
2. Basic Features of the Requirement
    474. We propose to require, as set out in the proposed regulations, 
that an Independent Transmission Provider must forecast the future 
demand for its area, facilitate determination of an adequate level of 
future regional resources by a Regional State Advisory Committee, and 
assign each load-serving entity in its area a share of the needed 
future resources based on the ratio of its load to the regional load.
    475. The Independent Transmission Provider must assure that each 
load-serving entity in its area acts to meet its share of the future 
regional needs--through self-supply, contracts to purchase generation, 
biddable demand or other demand response program. The Independent 
Transmission Provider must apply standards, discussed below, to audit 
the adequacy of the plans of load-serving entities to meet the future 
resource needs of its area. Moreover, the Independent Transmission 
Provider must check that resources are not double-counted by different 
load-serving entities. In a region with more than one Independent 
Transmission Provider, each Independent Transmission Provider must 
coordinate this checking responsibility with all the Independent 
Transmission Providers in the region.
    476. If a power shortage occurs during which the Independent 
Transmission Provider is unable to satisfy demand in the spot market 
and also meet its reliability requirement for a minimum level of 
operating reserves, the Independent Transmission Provider must add a 
per-megawatt-hour penalty during the shortage to the price of energy 
taken from the spot market by a load-serving entity that did not meet 
its share of the regional needs for that year.
    477. Further, if the operating reserve level decreases to the point 
that the Independent Transmission Provider must curtail load, the 
Independent Transmission Provider must, to the extent possible, curtail 
the spot energy purchases of the load-serving entity that did not meet 
its resource adequacy requirement before curtailing the spot energy 
purchases of load-serving entities that did. The load-serving entity is 
subject to such first curtailment during a shortage only in the amount 
by which it falls short of meeting its share of the resource adequacy 
requirement for the year in which the shortage occurs.\219\
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    \219\ A load-serving entity that continues to take spot market 
energy despite the curtailment order of the Independent Transmission 
Provider would be subject to a very high penalty under the tariff.
---------------------------------------------------------------------------

    478. If a shortage remains after all such first curtailments are 
completed and additional curtailment is necessary, the remaining loads 
of the first-curtailed load-serving entities and the loads of other 
load-serving entities that have satisfied their resource adequacy 
requirement would be curtailed under the same protocol. In this case 
the shortage may be attributable to certain load-serving entities of 
either type that, whether or not they may have met their resource 
adequacy requirement. We expect that those load-serving entities that 
are short of their own reserves would lose service ahead of those that 
are not short.
    479. The approach to resource adequacy proposed here is intended to 
assure the development of both new supply and demand response 
resources.

[[Page 55513]]

This approach focuses on encouraging payment to fund construction of 
future resources instead of avoiding payment of a penalty for 
inadequate current resources as in some current programs. The forward-
looking planning horizon provides time for market entry by new 
suppliers, which will help to check any market power among existing 
suppliers.\220\
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    \220\ A regional resource adequacy requirement should also 
provide substantial evidence of need for infrastructure to investors 
as well as to siting authorities. This should aid suppliers in 
acquiring financing and should facilitate siting decisions. An added 
benefit may be the ability to better predict, plan, and finance new 
transmission system facilities associated with these resource 
requirements.
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    480. This proposal is designed to complement, not replace, existing 
state resource adequacy programs. A vertically integrated utility 
satisfying a current state resource requirement that equals or exceeds 
its share of the resource adequacy requirement would not have to do 
anything more. For those states that have retail choice programs in 
which retail customers or their suppliers buy power from a multistate 
region, we intend this approach to provide for regional adequacy in a 
way that no one state alone may be able to accomplish.
    481. The proposed approach is like the traditional reserve margin 
requirement imposed by states on monopoly utilities. It worked well 
during most of the last century to ensure adequate supplies, and is 
still in use in most states, especially states that have no retail 
choice program. However, because the traditional approach relies on 
individual utility plans and resources, it might not continue to work 
well in a region where utilities now rely on independent power 
producers in several states for new resources instead of their own new 
generation. The traditional reserve margin requirement may also not 
work well in a region where some states have traditional monopoly 
utilities and others have retail choice because a shortages in one 
state can affect all states in the region.
    482. To continue to rely on the traditional reserve margin 
requirement, it has to be adapted to have a regional focus and to fit 
with competitive procurement. We propose a resource adequacy 
requirement of this type.
    483. The resource adequacy requirement proposed here is unlike that 
of the three Northeast ISOs. ISO-New England, the New York ISO and PJM 
each impose an obligation on load-serving entities known as an 
Installed Capacity (ICAP) requirement. The three requirements differ, 
but share some basic characteristics. We are reluctant to impose a 
national ICAP requirement, in part because of our concern about the 
effectiveness of the existing ICAP programs and in part because they 
were based on former voluntary tight power pools. The three ISOs play a 
strong role in administering the program, a role that may not suit 
regions without a history of tightly coordinated reserve sharing.
    484. The basic features of the proposed requirement are set out 
next, including discussion of the demand forecast, the level of 
resource adequacy, the role of the load-serving entity, the load-
serving entity's share of the regional resource adequacy requirement, 
the types of resources that can satisfy the resource requirement, the 
standards that each type of resource must meet, the planning horizon, 
enforcement of the requirement, and regional flexibility.

a. Demand Forecast

    485. An Independent Transmission Provider would be required to do 
an annual demand forecast for its area. The forecast would look ahead 
for the time period needed to add new supply and demand response 
resources. We will refer to this time period as the planning horizon, a 
topic discussed further below.
    486. Demand forecasts have long been used in the utility industry 
to determine the need for future resources and to plan new 
infrastructure investments. The Independent Transmission Provider may 
undertake a ``bottom up'' method of demand forecasting by adding up the 
demand forecasts of its component areas where they can be relied 
on.\221\ This may be accomplished through a collaborative process with 
all stakeholders.
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    \221\ A load-serving entity has an incentive to underestimate 
its future load if doing so would reduce its share of the resource 
adequacy requirement. For an analysis of bias in demand forecasts, 
see Mark Bock, ``Analysts hunt for bias in NERC forecasts,'' 
Electric Light & Power, July 2002.
---------------------------------------------------------------------------

b. Level of Resource Adequacy

    487. After the area's demand is forecast, the Independent 
Transmission Provider must assess whether the collective resource plans 
of load-serving entities in this area are adequate to meet the 
projected future peak need with allowance for adequate reserves. In 
today's more competitive environment, the effectiveness of single-
utility supply forecasts may be reduced. Under open wholesale 
transmission access, regional patterns of energy flow can change 
quickly, making single-utility transmission planning difficult. 
Generators sited in a utility's service territory, if not under 
contract, may export power to another area or region. Single-utility 
forecasting is also more difficult today because power market 
information is considered very sensitive. Competitive suppliers are 
reluctant to share this information with a utility that is a potential 
competitor. A regional assessment of regional supply adequacy by one or 
more independent entities in the region would help overcome these 
difficulties.
    488. Further, close coordination is needed between those planning 
generation and transmission because the location of planned generation 
affects the location of planned transmission and vice versa, and an 
Independent Transmission Provider (or a group of Independent 
Transmission Providers acting collectively in a region with more than 
one Independent Transmission Provider) is in the best position to 
coordinate these planning functions.
    489. Once the future level of supply and demand resources is 
determined, the region must assess whether this level is adequate. This 
requires a regional determination of the appropriate level of resource 
reserves, for example, whether the reserve margin (if reserve margin is 
the region's measure of resource adequacy) should be 12, 15, 18 
percent, or another level. We seek comment on and encourage regional 
discussion of appropriate planning targets in energy-limited areas, 
specifically on how to incorporate volatility of annual hydropower 
supply.
    490. Each region should take its own characteristics into account 
when determining the appropriate level, subject to a minimum level of 
resource adequacy for all regions discussed below. This determination 
has been made by load-serving entities under the oversight of the 
states, and we want this state oversight to continue. We propose that 
the level should be set by a Regional State Advisory Committee.\222\ 
States in the region should have this strong role in determining the 
level of resource adequacy because a higher level provides greater 
reliability and also incurs higher costs that affect most retail 
customers. State representatives are in the best position to determine 
on behalf of retail customers the trade-off between the cost to the 
customers of extra generation and demand response reserves and the 
difficult-to-quantify benefits to the customers of increased 
reliability and reduced exposure of the region to the effects of a 
power shortage.
---------------------------------------------------------------------------

    \222\ See the following section, State Participation in RTO 
Operations, for a discussion of the composition of the advisory 
committee.
---------------------------------------------------------------------------

    491. We will require the Independent Transmission Provider (or the 
several

[[Page 55514]]

Independent Transmission Providers in a region with more than one such 
Provider) to provide a forum and assistance to the Regional State 
Advisory Committee to establish the appropriate level of resource 
adequacy for the region. Because many Independent Transmission 
Providers encompass more than one state (or province), the Independent 
Transmission Provider's role as a facilitator will be helpful in 
establishing the regional reserve level.
    492. However, we ask for comment on what fallback provision should 
be employed if the Regional State Advisory Committee does not reach 
agreement on the appropriate level of resource adequacy. We believe 
that having different reserve levels in different states in the same 
region maintains the problem of some customers relying on the reserves 
of others.
    493. We are concerned that the requirement be set so that the 
Independent Transmission Provider can operate the interstate 
transmission system reliably with real-time operational resource 
adequacy. We are also concerned that inadequate resources could lead to 
poor market liquidity and even shortages with sustained high wholesale 
power prices. For these reasons, we propose to adopt a 12 percent 
reserve margin \223\ as a minimum regional reserve margin for all 
regions with the understanding that this is low by traditional 
generation adequacy standards and that the Regional State Advisory 
Committee in each region may set this number higher for the region to 
achieve greater reliability. We selected a 12 percent reserve margin as 
a minimum in that it is two-thirds of the typical historical reserve 
margin target of 18 percent for large utilities.\224\ We emphasize that 
most utilities historically used a reserve margin well above 12 
percent. This 12 percent reserve margin is intended to be a safety-net 
level in planning for reliable future transmission and market 
operations and not to be the target reserve level for the region that 
should be established by the Regional State Advisory Committee.
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    \223\ The reserve for a period is the amount of resources 
expected to be available during the period less the forecast peak 
load during the period. The reserve margin is the ratio of the 
reserves to the forecast peak load during the period, expressed as a 
percentage. A region may use another measure of adequacy as long as 
the minimum level is the arithmetic equivalent of a 12 percent 
reserve margin. For example, many use capacity margin, which is the 
ratio of the reserves to the amount of resources expected to be 
available during the period, expressed as a percentage. A capacity 
margin of 10.7 percent is the same as a reserve margin of 12 
percent. Some may measure adequacy with a loss-of-load probability, 
called LOLP, which is a statistical measure of the expected total 
time during a period that generation will be unable to meet load. 
The common U.S. standard is one day in ten years, which means that 
the sum of the hours (or fractions of hours) during a ten-year 
period when generation is expected to be short is 24 hours. Reserve 
margin cannot be translated directly into LOLP without studying a 
particular system. For example, an area served by a few large 
generators is more vulnerable to a shortage caused by an outage of 
one or two large generators than a similar area served by many 
smaller generators. The area with a few large generators may need a 
larger reserve margin to achieve the same LOLP. A general rule-of-
thumb for a large U.S. utility system is that an LOLP of one-day-in-
ten-years is achieved with a reserve margin of about 18 percent.
    \224\ The target level of these reserves, often called planning 
reserves, is not the same as the operating reserve level, a subject 
treated further below.
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c. Load-serving Entities

    494. Each load-serving entity must satisfy a portion of the 
regional resource adequacy requirement. Load-serving entity here means 
any entity that uses transmission in interstate commerce to provide 
power to load, whether a traditional distribution utility or an energy 
service supplier that aggregates retail loads under a retail access 
program.
    495. A large retail industrial or commercial customer that has 
retail access rights and buys power directly from suppliers is also 
considered a load-serving entity. If it does not buy power from another 
load-serving entity but uses the interstate grid to buy power directly 
from a supplier, it too would be required to meet its share of the 
resource adequacy requirement. As for other load-serving entities, 
their reserves may include the ability to reduce their own demand on 
the grid.
    496. A load-serving entity may choose a higher level of reliability 
by developing more supply or demand response resources than required. 
Further, a load-serving entity may choose greater reliability and price 
assurance by procuring additional reserves for its own use. In 
particular, customers in a load pocket that is served by a few large 
generating units may need a higher reserve margin to have the same 
level of reliability as customers outside a load pocket.

d. Load-Serving Entity's Share of the Regional Resource Requirement

    497. Once the future regional requirement is determined, each load-
serving entity's share of the regional requirement must be determined. 
Meeting a regional resource adequacy level does not assure that every 
part of the region has adequate resources if there are internal 
transmission constraints or if resources are counted that may be sold 
outside the region, retired before needed, or otherwise made 
unavailable. For these reasons, it is important that resources not be 
considered merely regional but be associated with and committed to 
particular load-serving entities.
    498. We request comment on two methods for determining each load-
serving entity's share of the regional requirement. One is to allocate 
the future resource adequacy needs to loads based on each load's 
forecasted future demand. For example, if the load forecast is for 
three years ahead and a particular load is growing faster than the 
regional average, its share of the adequacy requirement could be based 
on its forecast load ratio share for three years ahead, not on the 
present load ratio share. This method assigns more adequacy 
responsibility--and cost--to faster growing loads. However, if the 
Independent Transmission Provider's forecast is made through a ``bottom 
up'' method that adds up individual load forecasts, it must rely on 
each load to report its growth rate accurately. This approach creates 
an incentive for loads to understate their growth to lower their 
resource costs.
    499. The other method is to allocate the future adequacy 
requirement to loads based on each load's most recently documented load 
ratio share. This method is less subject to manipulation. However, an 
area with a slow load growth located within a region of generally high 
load growth may subsidize the high reserve needs of its neighbors.
    500. We ask for comment on which of these two methods the 
Commission should choose in the Final Rule. Alternatively, we ask 
whether this issue should be left to regional determination.
    501. Once each load-serving entity's share of the regional adequacy 
requirement is determined, the Independent Transmission Provider must 
inform each load-serving entity of its share. It must require each 
load-serving entity to report and document how it plans to meet its 
adequacy requirement.
    502. The time available to the load-serving entity from being 
informed of its resource share to having to report to the Independent 
Transmission Provider must be adequate to allow it to develop 
arrangements for meeting future resource needs. We ask for comment on 
how much time is needed for these purposes.

e. Resources That Can Satisfy the Resource Needs

    503. Each region's resource adequacy requirement could be satisfied 
by a combination of generation,

[[Page 55515]]

transmission, and demand response infrastructure.
(1) Generation and Transmission
    504. The supply requirement could be satisfied by self-owned 
generation, local distributed generation, or firm bilateral contracts 
for power that are backed by specific generating units (or a portfolio 
of designated generation units). The firm bilateral contract could be 
either a forward contract for the purchase of power or an option to 
purchase energy under specified shortage or price conditions, as long 
as the firm contract is backed by specified generating units.
    505. In any of these cases, the generator must be committed to 
supply power to the load-serving entity, at least under certain 
conditions. Self-owned generation that is committed to another load-
serving entity, unless it can be recalled during a shortage, would 
contribute to the other load-serving entity's requirement, not the 
requirement of the load-serving entity that owns it. Generation under 
contract must specify that the generator will be available to the load-
serving entity--or at least to the market that the load-serving entity 
participates in--under conditions set out in the contract. These 
conditions, discussed further below under generation standards, must be 
adequate to meet the region's need for reserve resources.
    506. The firm contract would be for a forward-looking period that 
would at least cover the planning horizon, which (as discussed further 
below) would be selected regionally and should be based on the time 
needed to develop new resources in the region. The load-serving 
entities must also demonstrate that future use of the designated 
resources is physically feasible and, in particular, that transmission 
is or will be available to deliver energy from a generator to the load-
serving entity that claims it in its resource plan.
(2) Demand Response
    507. Allowing demand response infrastructure to satisfy the 
requirement removes bias toward exclusive reliance on new generation to 
meet regional needs. Better demand response to high prices when a 
shortage condition approaches will lower demand and reduce the use of 
high-cost power resources. Demand response will help ensure 
reliability, prevent a shortage that could produce a curtailment, act 
as a check against market power, and provide a yardstick for the value 
that buyers place on supply.
    508. Biddable and interruptible load can satisfy the resource 
adequacy requirement as well as generation.\225\ A load-serving entity 
that does not want to pay for generating reserves can substitute a 
demand response alternative to meet its resource adequacy requirement. 
Under some state programs, the larger retail customer may be rewarded 
for reducing its electric use in addition to enjoying a reduced bill 
for reduced consumption. Several states have this type of biddable load 
reduction; it is one way to allow the customer to determine how much it 
is willing to pay for power. Further, competitive energy service 
suppliers can compete for load by offering lower rates to customers who 
agree to participate in demand response programs such as remote air 
conditioner cycling, aggregate building load management, and other 
proven demand response and load management options.
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    \225\ The traditional reliability reserve margin allows 
interruptible load to be counted equally with generation resources, 
with some exceptions.
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3. Resource Standards
    509. The Independent Transmission Provider must determine if each 
load-serving entity's planned resources meet certain standards. The 
resources must meet the standards to count toward satisfying the 
entity's share of the regional resource requirement. Both generation 
and interruptible or biddable load must meet standards to satisfy the 
requirement.
    510. We propose here certain minimum standards for comment. We also 
are considering in the Final Rule to ask the North American Energy 
Standards Board (NAESB) to develop more detailed standards for 
determining whether resources satisfy the resource adequacy 
requirement, and we seek comments on this approach.

a. Generation Standards

    511. Generation must be owned by or under contract to the load-
serving entity and committed to meet the resource needs of the load-
serving entity at least during certain conditions such as an operating 
reserve shortage. The Independent Transmission Provider must be 
satisfied that the generation is physically feasible; that is, the 
generating units are capable of generating the power planned, and 
enough transmission is available to deliver the power from the 
generating station to the particular load. The generating units under 
contract must be real and specific generators. This is so that only 
real generation that can avert a supply shortage is counted and so that 
its transmission over the grid can be assured. For example, it does no 
good for a load on Long Island to claim a generator in western New York 
as a resource if the power cannot be delivered to Long Island during a 
Long Island shortage.
    512. Because the purpose of this requirement is to encourage the 
development of new resources including new generation, generation under 
contract for development within the planning horizon should satisfy the 
requirement. Should the Commission specify the contract content needed 
to rely on generation under development? If so, should we refer this 
matter to NAESB to determine the content?
    513. For these reasons also, a contract with a marketer to deliver 
power at a future time from unspecified sources cannot satisfy the 
requirement. The purpose here is not to transfer financial risk for 
nonperformance to a marketer but to ensure performance, that is, to 
ensure that enough actual, deliverable generating capacity is available 
or developed at satisfactory locations to avert a future shortage. 
However, a forward contract with a marketer that is linked to specific 
generation and demonstrates transmission adequacy would satisfy the 
requirement. We ask for comment on whether we should allow a liquidated 
damages contract for power from unspecified sources to be included in 
the resource adequacy plan, and also on whether we should allow a load-
serving entity that initially fails to satisfy the resource adequacy 
contract, but later brings in new resources under a liquidated damages 
contract for the amount of its resource deficiency, to avoid the 
penalty price and first curtailment in the spot market during a 
shortage.

b. Transmission Standards

    514. Generation must be deliverable to satisfy the requirement. A 
Congestion Revenue Right for the appropriate year is one way to satisfy 
this requirement. We propose to adopt a practice (used in PJM) that 
allows a resource owner to pay for the development of adequate 
transmission to deliver its energy to a load and then to sell its 
Congestion Revenue Rights while still satisfying the requirement that 
its generation be deliverable. Should a commitment by any load-serving 
entity to pay congestion costs no matter how high also satisfy the 
requirement? If so, how should the Independent Transmission Provider 
respond if the sum total of all such commitments exceeds the available 
capacity of a bottleneck interface?
    515. A robust transmission system with few constraints may allow a 
load to rely on generation and demand

[[Page 55516]]

response reserves that are farther away than if the transmission system 
is weak. Supply reserves that are not deliverable to the load claiming 
them when needed cannot be counted as satisfying that load's reserve 
requirement.
    516. For transmission as well as for generation and demand 
response, the purpose of this requirement is to encourage the 
development of least-cost resources, which may include new transmission 
needed to access existing or new generation. We believe therefore that 
planned transmission with full siting approval and completion expected 
within the planning horizon should satisfy the adequacy requirement.

c. Demand Response Standards

    517. Demand response must also be verifiable to satisfy the 
adequacy requirement. The Independent Transmission Provider must have 
confidence that the demand response resource will be able to contribute 
when called on during a shortage. Demand response may be obtained 
through biddable demand reduction, interruptible load, or other 
dependable load management program. Distributed generation that is 
interconnected with a customer, a load-serving entity, or an energy 
services company, although it is technically generation and not demand 
response, can also be used by a local distributor to reduce the demand 
that the distribution system places on the grid. With biddable demand 
reduction, certain loads will be assured of dropping off the system at 
known price levels; the amount of load dropped should increase with the 
price.
    518. With interruptible load, a customer pays a lower power price 
year round but will be interrupted under defined shortage conditions; 
the load is subject to a simple on-off criterion. An important feature 
of this proposal is that the load-serving entity plan that depends on 
interruptible load to meet its resource adequacy requirement must be 
capable of being implemented. The Independent Transmission Provider may 
require, for example, that the load-serving entity install equipment 
that gives it direct control over the loads of the customers that are 
subject to the interruption. We recognize, however, that installation 
of such equipment may be too costly or otherwise impractical in some 
situations. In that case, the load-serving entity must have a 
satisfactory arrangement for implementing its interruptible load 
program under the instructions of the Independent Transmission 
Provider.
    519. If load in an area ``buys'' demand reduction from another area 
(in effect buying some of that other area's freed-up generation), the 
transmission needed to deliver the freed-up generation to the load that 
relies on it must be available.
4. Planning Horizon
    520. The purpose of a forward-looking resource adequacy requirement 
is to create a demand for new resource entry in advance of a shortage 
so that enough supply construction and demand response infrastructure 
installation are begun in time to avert the shortage. The planning 
horizon for each region is the number of years ahead for which the 
Independent Transmission Provider must forecast annually its area's 
load, as well as the number of years ahead for which load-serving 
entities must show that they have adequate resources. For example, the 
Independent Transmission Provider could forecast its area's peak load 
three years from the present and require that each load-serving entity 
in its area have acceptable plans today to have enough resources three 
years from now to meet the forecast peak with a reserve margin of 12 
percent. In this example, the planning horizon is three years and the 
reserve level is the minimum 12 percent.
    521. The choice of the planning horizon affects the lead time for 
construction and the duration of forward contracts that can satisfy a 
resource adequacy requirement.\226\ The traditional state-required 
electric company planning horizon was 10 to 20 years. The horizons were 
established when the industry relied on new large hydroelectric, coal, 
or nuclear facilities to meet growing load, and these facilities could 
take 10 or more years to site and construct. Today, most new resources 
are planned and developed over a much shorter time frame, in part 
because of the reliance on low cost natural gas. However, this planning 
horizon could change again if natural gas were no longer the main fuel 
of choice.
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    \226\ For example, forward-contracting for supply with one-year 
contracts that begin today and end after one year would not satisfy 
an adequacy requirement with a three-year planning horizon. A one-
year contract for the third year forward would satisfy the goal for 
that year.
---------------------------------------------------------------------------

    522. Because the planning horizon should be no less than the time 
frame for developing new resources and development times vary from 
region to region, the planning horizon can depend on that region's 
reliance on coal, gas, wind, hydropower or new demand-response 
technology for new supply. This argues for allowing each region to 
determine its own appropriate planning horizon.
    523. We propose to make the planning horizon a matter for regional 
choice. Regions should consider several factors in selecting the 
planning horizon. Most important, the planning horizon chosen should 
not be so short that it fails to motivate and achieve construction of 
generation and demand response resources in time to avert a shortage. 
Greater fuel diversity may be achieved with a longer planning horizon. 
If the horizon is short, two years for example, load-serving entities 
may have an incentive to select resources that can be developed in two 
years or less, such as peaking units and some other gas-fired 
generators. A longer planning horizon allows time for development of 
other resources such as coal-fired generation, hydroelectric resources, 
and some advanced demand response programs. Load-serving entities in 
retail choice states would benefit from a shorter planning horizon 
because it would reduce their business risk associated with demand 
forecast error. Also, they may not want to enter into bilateral 
contracts for supplies for a time period that is longer than the 
duration of their contracts with their customers.
    524. We propose to have the Regional State Advisory Committee 
determine the planning horizon for the region. The Independent 
Transmission Provider (including each Independent Transmission Provider 
in a region with more than one Independent Transmission Provider) must 
provide information and support to the Committee, as requested, to help 
it to determine the region's planning horizon. We request comment on 
how to resolve any lack of consensus within the Committee regarding the 
appropriate planning horizon. We also ask for comment on whether the 
Commission should establish limits on the region's choice of planning 
horizon, such as at least three years and no more than five years.
    525. We also ask for comment on whether to have a resource adequacy 
requirement before the end of the first planning horizon period. For 
example, if the horizon is three years, should there be a requirement 
for resource adequacy in the first two years?
5. Enforcement
    526. Here we explain in more detail our proposal to enforce the 
resource adequacy requirement, along with some alternative enforcement 
procedures, and ask for comment on the most effective enforcement 
method.
    527. Unlike some ICAP requirements, the approach adopted here does 
not require a load-serving entity to pay a penalty in the near term for 
failure to

[[Page 55517]]

have adequate future resources. Our proposed approach relies primarily 
on two enforcement mechanisms: (1) a Commission-set tariff penalty 
imposed on a load-serving entity that threatens reliable transmission 
operation by taking energy from the spot market during a shortage in a 
year for which it fails to meet its resource adequacy requirement, and 
(2) a Commission requirement that the spot market electric service of 
such a load-serving entity must be curtailed first when the shortage 
that is severe enough to require that some customers be curtailed. Each 
of these mechanisms, the penalty rate and the load curtailment, would 
occur at the end of the planning horizon, not the beginning.\227\
---------------------------------------------------------------------------

    \227\ For example, if the planning horizon is three years, a 
demand forecast would be made in 2004 for the year 2007. The 
Independent Transmission Provider would assess the adequacy of 
resources for 2007 and allocate the resource adequacy requirement 
for 2007 among the load serving entities. The entities would submit 
to the Independent Transmission Provider in 2004 their plans to meet 
their share of the 2007 resource adequacy requirement. An entity 
fails to submit in 2004 a satisfactory resource plan for 2007 would 
not be subject to the penalty rate or be among the first curtailed 
during a shortage in 2004 but would be subject to the penalty rate 
and be among the first curtailed during a shortage in 2007. Next 
year, in 2005, the same process repeats: the Independent 
Transmission Provider would forecast demand in 2008, and so on.
---------------------------------------------------------------------------

    528. The first mechanism applies during a power shortage in which 
the Independent Transmission Provider is unable to satisfy demand in 
the spot market and also meet its reliability requirement for a minimum 
level of operating reserves.\228\ As a shortage develops, price is 
expected to increase in the spot energy market. A load-serving entity 
that is short on self-generation, bilateral contracts (including 
affiliate generation and call contracts), and demand response resources 
will be dependent on the spot markets to meet its resource needs. The 
rising price in the spot market is, of course, a principal incentive 
for the load-serving entity to develop adequate supply and demand 
resources. If shortage conditions develop to the point where the 
Independent Transmission Provider cannot serve all load and maintain 
the minimum level of operating reserves, it must take some action to 
maintain reliable operation. Some load must be given either an economic 
incentive to exit the spot market or an order to stop taking power from 
the spot market. We propose that these measures be applied first to the 
load of the load-serving entities that did not meet their share of the 
resource adequacy requirement. However, the load-serving entity is 
subject to a penalty and first curtailment during a shortage only for 
spot energy purchases \229\ and only in the amount by which it falls 
short of meeting its resource adequacy requirement.
---------------------------------------------------------------------------

    \228\ Operating reserves are generation and demand response 
resources needed to keep the system in balance, follow changes in 
load, and make up for a ``contingency'' such as the loss of the 
largest generating unit or of a major transmission line that 
delivers more power than any one generating unit. The North American 
Electric Reliability Council and the regional reliability councils 
set rules regarding the minimum operating reserves that must be 
maintained by the system operator for reliable operation. The rules 
are expressed in a formula so that the value of the minimum 
operating reserves changes during the day with load conditions and 
with the sources of supply. Typically, for a large utility, the 
minimum operating reserves are in the range of 5 to 8 percent of 
load, but this can vary significant with changing conditions. An 
operator that operates with less than minimum operating reserves 
threatens not only its own reliable operation but the reliability of 
its electrical neighbors.
    \229\ These actions apply to spot energy purchases onluy. In the 
event that the load-serving entity that failed to meet its share of 
the resource adequacy requirement has adequate supply and demand 
resources outside the spot market available to it at the time of the 
shortage, the Independent Transmission Provider would continue to 
provide transmission to support delivery of these resources. This 
proposal gives deference to the ownership and contractual right to 
use self-generation, bilateral contracts, and demend response 
resources, and it encourages the development of such resources 
during the planning horizon period by those entities that failed to 
plan adequately at the beginning. It also discourages contracting 
with unreliable resources to meet the resource adequacy requirement 
because each load-serving entity must actually rely on its resources 
to meet its resource needs.
---------------------------------------------------------------------------

    529. Specifically, we propose that during such a shortage the 
Independent Transmission Provider must add a per-megawatt-hour penalty 
price to the price of energy taken from the spot market by a load-
serving entity that did not meet its share of the regional needs for 
that year. This rate would apply only to spot energy purchases, not to 
power received from the load-serving entity's self-generation or 
bilaterally contracted energy. However, it would apply to spot market 
energy sales needed to correct for imbalances associated with energy 
from these sources. We would set the penalty price high enough that we 
do not suggest that failing to meet a resource adequacy requirement and 
paying a penalty rate is an acceptable alternative to developing new 
resources, which would be the case if the paying the penalty appears to 
be less costly over time.
    530. The penalty price would increase in stages as the shortage 
becomes more severe. For example, the penalty price could be $500 (in 
addition to the spot market energy price) when operating reserves are 
just below the minimum level, $600 when operating reserves are more 
than below 1 percent below the minimum level, $700 when operating 
reserves are more than 2 percent below the minimum level, and so on. We 
ask for comment on having such a graduated penalty and the appropriate 
penalty rates.
    531. This first enforcement mechanism provides a price-based 
mechanism to enforce a resource adequacy requirement and to restore the 
transmission system to a reliable condition. Most system operators--and 
their regulators--treat load curtailment (voltage reductions and 
blackouts) as a last resort measure, and operators may violate the 
reliability rule for minimum operating reserves rather than implement a 
load curtailment to satisfy the minimum operating reserve 
criterion.\230\ We believe that the penalty price should be set high 
enough to bring about voluntary load reduction by a load-serving entity 
and thus restore the system to a reliable condition.
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    \230\ We will not overturn this practice by requiring 
curtailment of load immediately to restore the minimum operating 
reserve level. Some regions have a regional policy of taking action 
to reduce voltage or shed load only when operating reserves fall to 
some fraction, such as three-fourths or three-fifths, of the minimum 
operating reserve requirements of the reliability organizations.
---------------------------------------------------------------------------

    532. The second enforcement mechanism is applied when the operating 
reserve level decreases to the point that some load must be 
curtailed.\231\ The spot energy purchases of that load-serving entity 
load would be reduced by the amount of its resource deficiency and 
consequently some of its customers would be curtailed before the loads 
of other load-serving entities.\232\
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    \231\ Regional practice will determine when load must be 
curtailed to maintain reliable operation. Operators may continue to 
follow their existing reliability practices: those that do not 
curtail service immediately when the operating reserve level goes 
below the minimum must impose the penalty price on resource-
deficient load-serving entities. However, it is not our intent to 
require an operator to violate a reliability rule by providing 
service with a penalty price instead of enforcing its reliability 
rule through load curtailment. We believe that a high penalty price 
may result in the needed load reduction. Whenever the operator must 
curtail load to maintain reliability, it should do so. Our 
requirement goes to which load must be curtailed first when 
curtailment of load is necessary, not to when curtailment becomes 
necessary.
    \232\ An individual load-serving entity may run short of 
planned-for resources when its region is not experiencing a 
regionwide shortage, for example, because of a combination of high 
demand on its own system and unplanned outages of its own resources. 
In this case it is not required to be curtailed because that load-
serving entity may procure additional supplies from the short-term 
or long-term bilateral market or from the spot market. Since the 
region is not short, others are likely to sell power, including 
perhaps a portion of their reserves on the basis that the reserves 
can be recalled if a regionwide shortage occurs.
---------------------------------------------------------------------------

    533. In support of this second mechanism, we will require the 
Independent Transmission Provider to

[[Page 55518]]

inform the load-serving entity's state regulatory authority \233\ if 
the load-serving entity fails to submit a satisfactory plan for 
adequate future resources, thereby exposing its customers to possible 
penalties and future first curtailment during a shortage. Our intent is 
to rely on the traditional state role of enforcing a load-serving 
entity's reserve obligation. We believe that in most cases the state 
regulatory authority would prefer to have the load-serving entity meet 
the adequacy requirement as a condition of doing business in the state, 
rather than expose its retail customers to first curtailment. The state 
regulatory authority may wish to consider any decision of a load-
serving entity not meet its resource adequacy requirement. It may want 
to ask the load-serving entity to identify which of its customers will 
be subject to first curtailment if the region is short of power.\234\
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    \233\ In this section, the term ``state regulatory authority'' 
includes the retail rate regulating authority for load-serving 
entities not regulated by a state utility commission.
    \234\ Any necessary curtailment action, whether a first 
curtailment or any subsequent curtailment action may have to satisfy 
applicable state or local rules for ensuring that essential retail 
services (such as police, hospitals, fire stations) are maintained.
---------------------------------------------------------------------------

    534. If the Independent Transmission Provider does not have direct 
control of the circuit equipment needed to implement a curtailment and 
relies on the load-serving entity to follow its instructions to 
implement a curtailment, the load-serving entity would be subject to a 
severe penalty for the unauthorized taking of power from the spot 
energy market because this jeopardizes grid reliability. We propose to 
charge the applicable Locational Marginal Price plus $1000/MWh for all 
unauthorized energy taken following an instruction to implement 
curtailment.\235\ We also seek comment on whether the $1000/MWh penalty 
would be sufficient to deter unauthorized taking of energy and, if 
these penalties are paid, who should receive these revenues.
---------------------------------------------------------------------------

    \235\ See SMD Tariff, Appendix B, Section I.5.
---------------------------------------------------------------------------

    535. We believe that load-serving entities, under these enforcement 
provisions and under the oversight of state regulatory authorities, 
will meet their resource adequacy requirement and not be subject to 
these curtailment penalty and first curtailment provisions at all. If 
most meet the requirement as we expect, shortages and first curtailment 
of any that do not should occur infrequently.
    536. Having presented our enforcement proposal, we suggest 
variations of this proposal and ask for comments on these alternatives. 
As mentioned, under our proposal the penalty rate or load curtailment 
would occur at the end of the planning horizon, not the beginning. 
However, we ask for comment on this approach compared to an alternative 
approach that may provide a more immediate and effective incentive to a 
load-serving entity to take action to provide for future resources well 
in advance of facing a penalty or first curtailment. This is to impose 
a penalty on the load-serving entity immediately (that is, in year 2004 
to continue the example in an earlier footnote) if it fails to submit a 
satisfactory plan to meet its 2007 resource adequacy requirement. We 
did not propose this option as our first choice because it has some of 
the unfavorable features of some ICAP programs that focus more on 
avoiding immediate penalties than on motivating long term resource 
development. However, we ask for comments on the merits of this 
alternative approach.
    537. As presented, the Independent Transmission Provider audits the 
plan of each load-serving entity only at the beginning of the planning 
period (in 2004 in the example above). We are concerned that a load-
serving entity may submit a satisfactory plan but fail to fully 
implement the plan. The proposal permits but does not require the 
Independent Transmission Provider to audit each year the progress of 
the load-serving entity in implementing its plan, and we ask whether we 
should explicitly require this. If the load-serving entity's progress 
is unsatisfactory, should the Independent Transmission Provider find 
that it fails to satisfy its resource adequacy requirement? If the 
load-serving entity implements its plan but some of its resources fail 
to perform when needed during a shortage, should that load-serving 
entity, in addition to having a greater need for spot market energy at 
a presumably higher spot market price, also be subject to either of the 
enforcement mechanisms set out above?
    538. Another feature of our proposal is that it would not affect 
electric service from the self-generation and bilateral contracts of a 
load-serving entity that fails to meet its resource adequacy 
requirement (except that it would be subject to a penalty price during 
a shortage for balancing energy in the spot energy market). We ask for 
comment on whether this proposal unduly weakens the incentive to 
develop regional resources and whether, in the alternative, the 
Independent Transmission Provider should first curtail service to the 
load serving entities that failed to meet their share of the resource 
adequacy requirement, including transmission service from resources 
acquired outside the spot market, freeing up those resources for the 
use of those that planned adequately.
    539. Finally, our proposed enforcement mechanisms are designed to 
create an incentive to avoid a future penalty or first curtailment. 
During the public outreach process for developing this proposed rule, 
some commenters recommended a stronger Independent Transmission 
Provider role in compliance with a mandatory resource adequacy 
requirement. One proposal is for the Commission to require the 
Independent Transmission Provider to procure resources on behalf of 
load-serving entities that fail to meet fully their requirement and 
charge them for the cost of the resources.\236\ Another is for us to 
require the Independent Transmission Provider to either (1) calculate 
an expected capacity deficiency and purchase the call options necessary 
to meet the adequacy requirement on behalf of the load-serving 
entities, allocating costs pro rata, or (2) require load-serving 
entities to purchase reserves at the price produced by an Independent 
Transmission Provider-run auction.\237\
---------------------------------------------------------------------------

    \236\ See, e.g., Electricity Market Design and Structure, Docket 
No. RM01-12-000, comments of Reliant Resources, Inc., filed May 3, 
2002, at pages 11-12, in Docket No. RM01-12-000.
    \237\ See, e.g., Electricity Market Design and Structure, Docket 
No. RM01-12-000, comments of Mirant Americas, Inc. and Mirant 
Americas Energy Marketing, L.P. filed May 2, 2002.
---------------------------------------------------------------------------

    540. These approaches have advantages as well as disadvantages. 
Among the advantages are that they provide a greater assurance of 
achieving adequate resources and avoid the possible pitfalls of 
applying penalty rates or first curtailment. Among the disadvantages 
are that they take away one demand response option, namely curtailment, 
from the range of policy choices. Also, the latter approaches appear to 
require the Independent Transmission Provider to take a position in the 
capacity market, which places the Independent Transmission Provider in 
a role that may be incompatible with its independence.\238\
---------------------------------------------------------------------------

    \238\ They also raises difficult jurisdictional questions, in 
that Commission has regulated the seller's side of wholesale 
transactions and the states have regulated the buyer's side. Under 
some of these proposals, we would have to distinguish a transmission 
penalty levied by the Independent Transmission Provider for a load-
serving entity's failure to procure the resources needed to maintain 
transmission security from a Commission-enforced mandatory purchase 
of reserves by the load-serving entity.
---------------------------------------------------------------------------

    541. What is the effect of these alternate enforcement mechanisms 
on the incentives and business risks of the

[[Page 55519]]

load serving entities in the region? Is there another enforcement 
mechanism that is both appropriate and effective?
6. Regional Flexibility
    542. We propose to apply the requirement set out above to all 
regions, including regions that already have an ICAP requirement that 
has been previously approved by the Commission. This requirement would 
replace the current ICAP program.
    543. Some regulators, customers, and market participants have 
expressed dissatisfaction with the ICAP models presently in place. Some 
customers view ICAP as an added cost with no tangible benefits; they 
assert that the commodity being traded has little value because 
customers are paying for installed capacity but not receiving any 
greater assurance that generation adequacy is maintained. Some 
commenters say that, in some ICAP programs, a generator can receive an 
ICAP payment and later be released from the ICAP obligation for a 
relatively small penalty to sell its capacity in another market with a 
high wholesale price.
    544. Existing local generators are said to have preferential 
ability to participate in the ICAP market. The ICAP payment goes to the 
existing generators and does not necessarily lead others to enter the 
market to increase capacity. Depending on how the ICAP rules are 
designed, existing generators may be able to exercise market power, 
forcing up ICAP prices. In some markets, trading has been so thin at 
times that there is a question about whether there is a competitive 
market price.
    545. In some such cases, the ISO has intervened to set the price 
administratively, and market participants are concerned that the price 
does not reflect the forward value of generating capacity. Some contend 
that prices in the spot markets and bilateral markets, including long-
term forward contract markets, appear to be not well correlated with 
ICAP market prices.
    546. The generators object to ICAP price controls. Some power 
generators see short-term ICAP payments as providing inadequate 
assurance of capital cost recovery to motivate new investment. They 
prefer longer-term contracts to ensure that their investment costs will 
be recovered.
    547. Finally, many parties object that ICAP focuses on power 
generation, ignoring the potential of demand response.
    548. Although we propose that every region must adopt our approach, 
this approach offers significant regional flexibility. Our approach 
allows each region to set its own level of resource adequacy, set its 
own planning horizon, and select from a combination of supply and 
demand response resources for meeting its needs.
    549. Our proposal permits but does not require a region to have its 
Independent Transmission Provider establish a market for acquiring and 
trading adequate resources. We believe that the bilateral market and 
other means can be adequate for acquiring and trading resources. 
Nevertheless, we ask for comment on whether, under the approach to 
resource adequacy proposed here, we should require an Independent 
Transmission Provider to create a market to facilitate load-serving 
entities meeting their resource adequacy requirement efficiently.
    550. Despite the flexibility of our proposed approach, regions with 
a historical reliance on a tight pool for sharing reserve may argue for 
a continuation of some form of ICAP program. We ask for comment on how 
existing Commission-approved ICAP mechanisms can be transitioned and 
modified so as to be made consistent with our resource adequacy 
proposal here without disrupting financial commitments made under 
existing rules. What are the disadvantages of particular elements of 
the ICAP approach that should be avoided in the approach proposed here? 
Do any of the enforcement proposals or alternatives discussed above re-
introduce any such disadvantageous elements?

K. State Participation in RTO Operations

    551. States have an important role in the process of creating and 
sustaining an efficient competitive wholesale market for electricity. 
The Commission has already established state-federal RTO panels as a 
forum for the Commission and state commissioners to discuss issues 
related to RTO development. However, there currently is not a formal 
process for state representatives to engage in a similar dialogue with 
the independent entity that will operate the electric grid under 
Standard Market Design. Therefore, the Commission is proposing to 
establish a formal role for state representatives to participate on an 
ongoing basis in the decision-making process of these organizations.
    552. We envision that the Independent Transmission Provider that 
operates the grid would have a Regional State Advisory Committee. The 
Regional State Advisory Committee should be formed and should have 
direct contact with the governing board, in a manner which recognizes 
its public interest responsibilities, and be designed to provide the 
board as well as market participants and the Commission with a 
consensus view from states in the area. The specifics of how this 
advisory committee would be formed and operate would be decided on a 
regional basis. This coordinated oversight will ensure fulfillment of 
federal public interest responsibilities in a manner that includes the 
views of states throughout the region. In this regard, we also 
encourage the participation of Canadian provincial authorities in this 
process.
    553. We take note of the recent report by the National Governors' 
Association entitled ``Interstate Strategies for Transmission 
Planning,'' which recommends establishing ``Multi-State Entities'' to 
facilitate state coordination on transmission planning, certification, 
and siting at a regional level.\239\ The report recognizes the critical 
role states currently play in siting as well as the need to address 
regional needs. The institution we propose here appears complementary 
to the National Governors Association's recommendation. In fact, it may 
be useful to have a single Regional State Advisory Committee rather 
than separate committees for siting and other issues. We seek comment 
on whether there should be a single Regional State Advisory Committee, 
or separate committees for siting and other issues. We also seek 
comment on how the state representatives should be selected (e.g., 
whether the governor should select them or some other process should be 
used).
---------------------------------------------------------------------------

    \239\ Available in http://www.ng.org/center/divisions/1,1188,C--
ISSUE--BRIEF[caret]D--4110,00.html.
---------------------------------------------------------------------------

    554. The Regional State Advisory Committee may work with the 
regional transmission organization to seek regional solutions to issues 
that may fall under federal, state, or shared jurisdiction, which may 
include but are not limited to:

a. Resource adequacy standards;
b. Transmission planning, expansion;
c. Rate design and revenue requirements;
d. Market power and market monitoring;
e. Demand response and load management;
f. Distributed generation and interconnection policies;
g. Energy efficiency and environmental issues;
h. RTO management and budget review.

    Further duties may evolve with the development and operation of the 
regional councils.
    555. As discussed, the Commission is proposing to require that the 
independent entity that operates the

[[Page 55520]]

markets under Standard Market Design will have a Market Monitoring Unit 
(MMU). The MMU will be required to report directly to the Commission 
and the independent governing board of the Independent Transmission 
Provider. The MMU should also provide its reports directly to the 
Regional State Advisory Committee. Finally, because of the regional 
nature of these organizations, there are many new issues involving rate 
design and revenue requirements. We believe that the Regional State 
Advisory Committees can bring a valuable regional perspective to these 
issues and should play a role in deciding these issues in partnership 
with the Commission. Once the advisory committees are established, we 
intend to work with them to establish protocols for deciding these 
regional rate issues. Additionally, the Independent Transmission 
Provider will be required to develop regional plans for transmission 
planning and expansion. We believe this is also an area where the 
Regional State Advisory Committee can bring a valuable regional 
perspective and should be consulted in developing these regional plans.

L. Governance for Independent Transmission Providers

    556. The Commission has previously recognized the importance of 
independent governance of regional organizations in both Order No. 888 
and Order No. 2000. In Order No. 888, the Commission required that ISO 
governance be structured in a fair and non-discriminatory manner and 
that the ISO be independent of any individual market participant or any 
one class of participants. The Commission also required that the ISO's 
rules of governance should prevent control, and appearance of control, 
of decision-making by any class of participants. Order No. 2000 built 
upon and extended this independence requirement to RTOs. In Order No. 
2000, we reaffirmed our commitment to independence as a bedrock 
principle for regional organizations, and in this rulemaking we find 
that our commitment to independence also is critical to the successful 
implementation of Standard Market Design. Compliance with the 
independence requirement of Order No. 2000 is based on the independence 
of the Board of Directors and all employees of the RTO. The governance 
requirements for the Board of Directors is critical to ensuring that 
the RTO is independent and that the RTO's interests are aligned with 
the interests of the market as a whole rather than with particular 
market participants of classes or market participants. While we did not 
mandate detailed governance requirements for RTO boards in Order No. 
2000, we stated that we would review on a case-by-case basis the RTO 
governance proposals and judge them against the overarching standard 
that the RTO's decisionmaking process must be independent of individual 
market participants and classes of market participants. We also 
required an audit of the independence of an ISO's governance process 
two years after its approval as an RTO.\240\
---------------------------------------------------------------------------

    \240\ See California Operational Audit of the California 
Independent System Operator issued January 25, 2002 in PA02-1-000 
and Order Concerning Governance of the California Independent System 
Operator 100 FERC [para]61,059 (2002).
---------------------------------------------------------------------------

    557. The Commission has considered on a case-by-case basis whether 
individual RTO proposals satisfy the Commission's requirements for 
independence.\241\ We have required changes where they did not.\242\ 
However, we are concerned that the lack of more definitive guidance 
from the Commission on governance may be hindering the development of 
larger RTOs. Also, we are concerned that the existing stakeholder 
process may not provide adequate representation for all market 
participants and interested parties. The lack of adequate 
representation may hinder development of alternative energy resources, 
such as distributed generation, renewable energy, or demand response 
programs, since these programs may be contrary to the business 
interests of certain market participants. Therefore, we are proposing 
to require that all Independent Transmission Providers satisfy specific 
governance requirements. Specifically, we are proposing to more clearly 
define the responsibilities of the Board of Directors, more clearly 
define the role of stakeholders in selection of the board and in the 
management of the Independent Transmission Provider, and to establish a 
process that would be used for selecting the Board of Directors by 
Independent Transmission Providers.
---------------------------------------------------------------------------

    \241\ See Avista Corporation, et al.., 95 FERC [para]61,114 
(2001).
    \242\ See Carolina Power & Light Company, 94 FERC [para]61,273 
(2001).
---------------------------------------------------------------------------

1. Responsibilities of the Board of Directors
    558. As we have previously stated in both Order No. 888 and Order 
No. 2000, it is critical that the board be independent. The board's 
primary responsibility is to ensure that the markets operated by the 
Independent Transmission Provider are operated in a fair, efficient and 
non-discriminatory manner. The board's focus should be on the interests 
of the wholesale market, not the interests of particular market 
participants or classes of market participants. The board should not be 
regarded as a partner or a contractor of the market participants. 
Further, the board should be composed of members that are not part of 
the management of the Independent Transmission Provider. This 
Commission has the overall responsibility for the function of the 
wholesale electric market, including setting overall policy for the 
market. Independent Transmission Providers are public utilities subject 
to the Commission's jurisdiction under the Federal Power Act because 
they own, control or operate jurisdictional transmission facilities and 
will administer jurisdictional wholesale energy markets. In order to 
carry out the functions required by Standard Market Design, the board 
must be fully independent of any market participants. The board is 
responsible for overseeing the Independent Transmission Provider's 
administration of the tariff and market rules that have been approved 
by the Commission. It also must monitor the operation of the markets 
within its region to identify problems, e.g., the ability to exercise 
market power, and to propose solutions. In both of these areas, the 
board is accountable to the Commission, not the market participants and 
should ensure the following: system reliability and operating 
efficiency, efficiently functioning markets, and short- and long-term 
planning objectives. Indeed, the board should ensure that any instance 
of perceived or real market power or market dysfunction is reported 
directly and immediately by the MMU to the Commission.
    559. An important implication of these principles is that the board 
must not be a stakeholder board with industry segments given specific 
seats on the board. The interest of all board members should be a well-
functioning market, not representation of a specific industry segment. 
Similarly, board members must have no financial interests in market 
participants so that there is no appearance of bias or benefit.
2. Stakeholder Participation
    560. Stakeholders have an important role in advising the boards of 
Independent Transmission Providers. Most current regional organizations 
have established stakeholder committees that act either as advisors or 
in some cases vote on proposals that go

[[Page 55521]]

before the board.\243\ We continue to believe that an active 
stakeholder process is needed and that to fully satisfy the 
independence principles of Standard Market Design, these stakeholder 
committees must be used to advise the Board of Directors rather than 
function as a decision making body.
---------------------------------------------------------------------------

    \243\ In Order No. 2000, 23 required that these types of stake 
holder committees be advisory in RTOs. This meant that the board 
would have the ability to propose changes to market rules to the 
commission whether those changes we approved by the stakeholder 
committees. We propose to continue this policy for Independent 
Transmission Providers.
---------------------------------------------------------------------------

    561. We are concerned that the current composition of these 
advisory committees may not adequately represent all segments of the 
industry. The current structure of many ISO stakeholder committees 
tends to replicate the functions of vertically integrated utilities. 
For example, PJM currently has five classes, Generation Owners, 
Transmission Owners, Other Suppliers, Electric Distributors, and End-
Use Customers. Four of these classes represent interests that would 
benefit from higher levels of demand. Only one represents customers or 
end-users, and none represents demand-side technologies or alternative 
load control services such as demand resource management. This sector 
structure could discourage the introduction of changes that implement 
new demand management technologies and services, one of the biggest 
potential outgrowths of the move towards a competitive market. 
Financial entities, which are usually financial trading firms such as 
banks or other financial institutions that provide the needed capital 
to the industry, are also poorly represented, if at all. Therefore, we 
propose to require that an Independent Transmission Provider approved 
by the Commission must have at a minimum committees that reflect six 
stakeholder classes: (1) Generators and marketers, (2) transmission 
owners (this sector would include vertically integrated utilities), (3) 
transmission-dependent utilities,\244\ (4) public interest groups 
(e.g., consumer advocates, environmental groups, citizen 
participation), (5) alternative energy providers (e.g., distributed 
generation, demand response technologies, renewable energy), and (6) 
end-users and retail energy providers (i.e., load-serving entities that 
do not own transmission or distribution assets). In addition, we 
propose to require that there be a separate Regional State Advisory 
Committee that would advise the board. We believe that six stakeholder 
classes provides better representation for certain market participants, 
e.g., transmission-dependent utilities and new technologies that have 
not been adequately represented in the past. Also, we propose that a 
company (including all of its affiliates) may have a representative in 
only one stakeholder sector. For example, a vertically integrated 
utility that has a marketing affiliate would have to choose whether it 
would be represented in the transmission owner sector or the generator/
marketer sector. This will prevent large corporations from dominating 
sector representation by placing their affiliates and subsidiaries in 
several sectors. Initially, the company would be allowed to choose 
which sector it wished to join. However, requests to change sectors may 
be subject to limitations to avoid frequent changes that could be used 
to affect sector voting results for advisory actions recommended to the 
board. For example, the corporation may be required to decide which 
sector it will join on an annual basis. This would allow corporations 
to change sectors to reflect changes in corporate business models, but 
not allow frequent changes that could be used to change voting results 
on particular proposals. We also seek comment on whether or under what 
circumstances, a stakeholder class should be able to take an issue 
directly to the board outside the stakeholder process.
---------------------------------------------------------------------------

    \244\ These are utilities that must take transmission service 
from public utilities to provide retail service to their customers.
---------------------------------------------------------------------------

3. Initial Selection Process for Board of Directors
    562. The initial selection process for the Board of directors must 
be structured to ensure that board members are independent and have 
expertise in a variety of transmission and electric market areas. We 
propose that the following process be used.\245\
---------------------------------------------------------------------------

    \245\ We are not proposing any specific requirements on the 
number of board members. We anticipate that the board will have 
between five and nine members, which is consistent with the current 
size of the Board of Directors for ISOs and proposed for RTOs.
---------------------------------------------------------------------------

    563. First, the qualifications of the board members should be 
established. We believe it is important that the qualifications be more 
widely focused than just experience with electric transmission systems. 
Experience in additional areas such as risk management, generation 
planning and operation, or technology and innovation would provide the 
board with a wider background of knowledge in areas crucial to market 
development. We propose that board candidates be required to have 
experience in one or more of these fields: senior corporate leadership 
of a major publicly traded company; professional disciplines of 
finance, accounting, or law; electrical engineering; regulation of 
utilities; transmission system operation or planning; trading or risk 
management; information technology; and generation planning or 
operation. The candidate could have experience in the electric industry 
in either an Investor-Owned Utility or public power entity. The 
objective is to have a board that collectively possesses experience in 
many, if not all, of these areas.
    564. Board members or their immediate families should not have 
current or recent ties (within the last two years) as a director, 
officer or employee of a market participant in the region or its 
affiliates. Board members or their immediate families should also not 
have direct business relationships with market participants or their 
affiliates. Finally, to the extent that the board member owns stocks or 
bonds of companies that are market participants, these must be divested 
within six months of being elected to the board. Prior to divestiture, 
the board member would not be able to participate in any decisions 
affecting that market participant or its affiliates. These requirements 
are necessary to ensure that the board member does not have any 
financial interest in a market participant that could influence the 
board member's decision. We propose that board members, their immediate 
families and senior management be required to fill out annual financial 
disclosure statements to ensure that there is no conflict of interest. 
The financial disclosure statements would be available for audit by the 
Commission.
    565. Second, a nationally recognized search firm should be retained 
by the nominating committee to identify candidates that satisfy these 
criteria. The search firm should supply at least two names for each 
available board seat. The use of a nationally recognized search firm to 
develop the list of potential board members helps ensure the integrity 
of the process since the search firm would not have a financial 
interest in proposing candidates that represent specific market 
participants or classes of market participants. The search firm should 
not have a significant ongoing business relationship with the market 
participants in the region. The search firm must disclose to the 
nominating committee any ongoing business relationships it has with 
market participants in the region.

[[Page 55522]]

    566. A nominating committee composed of two members from each of 
the stakeholder classes would be formed to review the list of 
candidates presented by the search firm. The nominating committee would 
vote for the individual board candidates as follows. Each nominating 
committee member would have the right to cast votes equal to the number 
of open board seats. A member shall not cast more than one vote for any 
one candidate and is not required to cast all of its votes.
    567. Board seats are filled by a simple majority. Candidates with 
the highest vote totals are elected to open board seats. Ties for the 
last open board seats will have a runoff subject to the same rules as 
the initial selection process. The elected board members would vote to 
designate one of the members as Chairman of the Board. We seek comment 
on whether the Chief Executive Officer of the Independent Transmission 
Provider should be a non-voting member of the board.
    568. We recognize that allowing a vote on candidates by 
stakeholders could be perceived as allowing a sector to dominate the 
board selection process or result in less than a fully independent 
board. While we recognize the concern, we believe that it is important 
that stakeholders have a voice in the selection process. We do not 
believe that it is the Commission's role to be the primary decision-
maker in determining the candidates that are selected for the board. We 
seek comment on what protections should be built into the selection 
process to ensure that a class of market participants does not dominate 
the stakeholder voting process. Nevertheless, we solicit comment on 
whether to require the nominating committee to vote on an entire slate 
of candidates rather than on individual candidates.
4. Succession of Board Members
    569. The governance process also needs to include ongoing 
procedures for the selection of new board members. We believe that the 
process should seek to maintain a degree of continuity of board 
membership to ensure stability and consistency in decisionmaking, while 
at the same time ensuring that the board does change membership over 
time to allow the introduction of new viewpoints and encourage 
innovation.
    570. To accomplish these two objectives, we propose that the board 
members have staggered terms. Approximately half of the first board 
should have initial terms of four years. The remaining board members 
should have initial terms of three years. All subsequent board members' 
terms will be for four years. The staggered terms will provide a degree 
of continuity to the board in its decision making process. We seek 
comment on whether the proposed staggered terms would lead to too rapid 
a turnover in the composition of the board. Board members would be 
permitted to serve no more than two consecutive terms. This limitation 
will ensure that there will be a change in board membership over time 
to allow for the introduction of board members with different 
experience.
    571. The same process that was used to select the initial Board of 
Directors would be used in the selection process for subsequent board 
members in the case of resignation, death or removal for cause. Namely 
a nationally recognized search firm would be retained to identify board 
candidates. A nominating committee would be formed to review the list 
of candidates and propose new board members.
    572. When the first set of board members terms start expiring a two 
stage process would be used for electing board members. First, existing 
board members whose terms are expiring would indicate whether they 
wished to remain on the board for a second term. The stakeholders would 
vote on whether these existing board members would remain on the Board 
of Directors. Second, if there were any remaining vacancies, then a 
search firm would be retained to provide candidates for the vacant 
seats on the Board of Directors. The same process that was used for 
filling the initial Board of Directors would be used for filling these 
vacancies.
5. Mergers of Independent Transmission Providers
    573. We propose the following initial governance structure in the 
event of a merger of ISOs, RTOs or Independent Transmission Providers. 
Initially, the board members of the newly formed entity will be 
comprised of a number of board members from each of the respective 
organizations in addition to new members. We propose that there should 
be equal representation from each former organization plus an equal 
number of new board members.\246\ This type of composition will provide 
the new merged Independent Transmission Provider with the expertise, 
knowledge and experience during start-up while new board members would 
bring fresh ideas and perspective. The members from the existing boards 
will be chosen by their respective boards, after consultation with 
stakeholders on the expertise and experience needed by the new 
organization.
---------------------------------------------------------------------------

    \246\ For example, a nine member board for a merger of two RTOs 
would reflect 3 members from each of the former RTOs plus three new 
members.
---------------------------------------------------------------------------

    574. A nominating committee will nominate all candidates (except 
the initial members that originate from the original boards of ISOs, 
RTOs or Independent Transmission Providers) for the initial election of 
new board members. The initial nominating committee will be composed of 
two board members from each of the respective merging organizations and 
the Chairs of two committees representing market operations, 
reliability and/or management.

M. System Security

    575. System security is critical to the reliable operation of the 
interstate transmission grid. Wholesale electric grid operations are 
highly interdependent, and a failure of one part of the generation, 
transmission, or grid management system can compromise the reliable 
operation of a major portion of the regional grid. The wholesale 
electric market relies on the continuing reliable operation of not only 
physical grid resources, but also the operational infrastructure of 
monitoring, dispatch and market software and systems. Because of this 
mutual vulnerability and interdependence, it is necessary to safeguard 
the electric grid and market resources and systems by establishing 
minimum standards for public utilities that own, control or operate 
facilities used for transmitting electric energy in interstate commerce 
as well as entities that use these facilities.
    576. NERC's Critical Infrastructure Protection Advisory Group has 
recently developed a set of recommended minimum requirements 
(standards) for securing information assets that support grid 
reliability and market operations and the physical environments in 
which these information assets operate. These standards are designed to 
ensure that the entity has a basic security program protecting the 
electric grid and market from the impact of acts, either accidental or 
malicious, that could cause wide-ranging harmful impacts on grid 
operations. These standards would be administered through an annual 
self-certification due January 31, 2004, and every January 31 
thereafter. The proposed form for the self-certification is attached as 
Appendix G.
    577. We propose to require that all public utilities that have 
tariffs on file with the Commission must file the self-certification by 
January 31, 2004, and every January 31 thereafter. Additionally, on and 
after February 1, 2004, as a condition of receiving

[[Page 55523]]

transmission service provided by a public utility that owns, controls 
or operates transmission facilities, a customer must demonstrate that 
it has a basic security program in place. The customer can satisfy this 
requirement by supplying the public utility with a copy of the executed 
self-certification form. In the case of entities seeking transmission 
service that are not public utilities subject to the Commission's 
regulations, the entity would still be required to demonstrate that it 
has a basic security program in place to receive transmission services. 
This could be done by supplying the transmission provider with an 
executed self-certification using the Commission's form. Alternatively, 
the transmission provider and the customer could develop an alternative 
arrangement for ensuring that the customer has a basic security program 
in place.
    578. Finally, when the SMD Tariff is implemented, we propose to 
extend the requirement to cover the additional services being provided 
by the Independent Transmission Provider. At that time, any customer 
seeking to buy or sell through the markets operated by the Independent 
Transmission Provider or take transmission service under the Network 
Access Service would be required to demonstrate that it has a basic 
security program in place.
    579. We expect that these standards will be revised and refined 
over time in light of changes in technology and operational experience 
with the standards. Therefore, the regulations will also identify the 
specific version number of the system security standards. When NERC 
revises the standards, the revisions will be filed with the Commission. 
The Commission will issue a Notice that it is considering revising the 
updated system security standards, and we will seek comments on the 
proposed changes. These security standards for electric market 
participants can be found in Appendix G, along with the proposed self-
certification form, discussed above.

V. Implementation

    580. The Commission proposes to find in the Final Rule that rates, 
terms and conditions of transmission service and wholesale electric 
sales that do not comport with the regulations adopted by the Final 
Rule are unjust, unreasonable or unduly discriminatory. Many of the 
elements included in Standard Market Design will require computer 
software development and changes that public utilities may not be able 
to fully implement for a couple of years. The Commission's objective is 
to have Standard Market Design implemented on all jurisdictional 
transmission systems no later than September 30, 2004, or such time as 
the Commission may establish. The Commission does not believe it is in 
the public interest to delay implementation of the remedial action to 
cure undue discrimination or to develop necessary infrastructure until 
the time when all of the software changes necessary for standard market 
design are completed. Consequently, the Commission proposes a multi-
step process that will be used to bring these rates, terms and 
conditions of service into conformity with the regulations.

30 Days After Effective Date of Final Rule

    581. The Commission will require all public utilities that own, 
control or operate interstate transmission facilities to begin 
discussions with stakeholders and state representatives within 30 days 
after the effective date of the Final Rule about how they will 
implement the transition process and comply with the requirements of 
the Final Rule. These discussions should address selection of an 
Independent Transmission Provider that will manage the transmission 
facilities, establishment of a regional state advisory committee, 
development of a regional transmission planning and expansion program, 
development of a long-term resource adequacy requirement and 
identification of areas such as load pockets where mitigation or 
appropriate infrastructure will be necessary.

July 31, 2003

    582. The Commission recognizes that it has accepted many changes to 
the pro forma tariffs of individual transmission providers that deviate 
from the pro forma tariff contained in Order No. 888. To the extent 
these changes involve bundled retail load or give preference to either 
native load customers or the transmission provider's use of its system, 
we propose to direct the transmission provider to eliminate them. We 
have revised the Order No. 888 pro forma tariff to place bundled retail 
load under the open access transmission tariff, and to eliminate undue 
preferences for native load customers and the transmission owner's use 
of its own system.\247\ The revised Order No. 888 pro forma tariff, 
which is referred to as the Interim Tariff in this proposed rule, is 
attached as Appendix A. Pursuant to section 206 of the FPA, we propose 
to require all public utilities that own, control or operate facilities 
used for the transmission of electric energy in interstate commerce to 
file the Interim Tariff, no later than July 31, 2003. The Interim 
Tariff will become effective on September 30, 2003, after the peak 
summer season.
---------------------------------------------------------------------------

    \247\ The public utility would make the revisions to its 
currently effective Open Access Transmission Tariff. The changes to 
the Order No. 888 tariff are intended to identify the changes that 
must be made.
---------------------------------------------------------------------------

    583. Although a transmission tariff rate is already in effect for 
all public utilities that own, operate or control facilities used for 
the transmission of electric energy in interstate commerce, we 
acknowledge that changes to individual utility rates may be necessary 
as a result of the changes to non-rate terms and conditions that the 
Interim Tariff requires. Should a public utility determine that such 
rate changes are warranted by the new non-rate terms and conditions, it 
may file a new rate proposal pursuant to FPA section 205, no later than 
July 31, 2003. We will impose a blanket suspension on any such filings 
that we receive and make them effective, subject to refund, 61 days 
after they are filed.
    584. We also propose a new tariff (SMD Tariff), attached as 
Appendix B, to supersede the Interim Tariff and implement Standard 
Market Design. The new SMD Tariff includes many areas in which the 
Independent Transmission Provider would propose provisions consistent 
with the policy framework set forth in the Final Rule, but designed to 
meet the specific circumstances of the region. We propose to give 
regions discretion in developing a transition program for existing 
contracts that is consistent with the guidelines set forth in the Final 
Rule.
    585. The Commission recognizes that public utilities will need time 
to ensure that transmission facilities are operated by an Independent 
Transmission Provider, implement Network Access Service, establish day-
ahead and real-time markets, adopt LMP for congestion management, 
incorporate market power mitigation measures customized for the region, 
develop a market monitoring program and develop a resource adequacy 
requirement for the region. Thus, for these requirements the Commission 
proposes a process for implementation that provides an opportunity for 
active participation by state representatives and market participants 
and that gives the Commission opportunities to review progress and 
require changes if sufficient progress is not being made.
    586. To implement the requirements of Standard Market Design, we 
propose to require every public utility that owns, controls or operates 
facilities used for the transmission of electric energy in

[[Page 55524]]

interstate commerce to select an Independent Transmission Provider to 
operate its transmission facilities. A public utility may meet this 
requirement by: (1) Itself satisfying the definition of Independent 
Transmission Provider; (2) turning over its transmission facilities to 
a Commission-approved RTO that meets the definition of Independent 
Transmission Provider; or (3) contracting with an entity that meets the 
definition of Independent Transmission Provider to operate its 
transmission facilities.
    587. The Commission will require all public utilities that own, 
operate or control interstate transmission facilities to file an 
Implementation Plan for compliance with the regulations no later than 
July 31, 2003. In the Implementation Plan, the public utility must 
identify the independent entity that will serve as the Independent 
Transmission Provider for the transmission facilities that the public 
utility owns, controls or operates. (A public utility that is already a 
member of an entity that satisfies the definition of Independent 
Transmission Provider may request a waiver from this requirement in its 
Implementation Plan filing.) Additionally, the Implementation Plan must 
include time lines and a proposal for compliance with the long-term 
resource adequacy requirements of the Final Rule. Further, the 
Implementation Plan must identify the software vendor(s) that the 
public utility will use for implementation of Standard Market Design 
and a time line that identifies implementation milestones and indicates 
the projected timing of their completion. The Commission wants to 
ensure that the cost of implementation of Standard Market Design is 
reasonable, and intends to closely monitor the expenditures incurred to 
implement the Final Rule. Therefore, we propose to require that all 
public utilities include in their Implementation Plan a detailed 
estimate of their projected cost of implementing the Final Rule. The 
estimate should include projected software costs as well as other costs 
that the public utility may incur. The public utility will also be 
required to file status reports on the Implementation Plan on a 
quarterly basis. The Commission will review the Implementation Plans 
and quarterly reports to ensure compliance with the regulations. Also, 
the Commission will establish appropriate procedures, if needed, for 
resolving concerns of state representatives and market participants.
    588. The Commission recognizes that some public utilities will be 
able to implement Standard Market Design more quickly than others. The 
dates proposed in the Implementation Plan should reflect the level of 
changes that are required. The Commission intends to be flexible in 
setting compliance dates for Standard Market Design. The Commission 
expects that those public utilities that do not require significant 
changes could implement Standard Market Design much sooner than others. 
While the Commission's objective is to have Standard Market Design in 
place everywhere by September 30, 2004, it will consider requests to 
extend this date if the public utility can document that additional 
time is necessary.
    589. Finally, the public utility must cooperate with others in its 
region to have a Regional State Advisory Committee in place by July 31, 
2003.

Six Months After Effective Date of Final Rule

    590. The Commission proposes to require all public utilities that 
own, control or operate facilities used for the transmission of 
electric energy in interstate commerce to begin a regional transmission 
planning process within six months and produce a plan within one year 
of the effective date of the Final Rule. This will be an intermediate 
step in the process of satisfying the planning and expansion 
requirements contained in section 35.34(k)(7) of the Commission's 
regulations.\248\ The Independent Transmission Provider will take over 
this process when it becomes operational.
---------------------------------------------------------------------------

    \248\ 18 CFR 35.34(k)(7) (2002).
---------------------------------------------------------------------------

December 1, 2003 and September 30, 2004

    591. Pursuant to section 206 of the FPA, by December 1, 2003 all 
Independent Transmission Providers will be required to file the SMD 
Tariff, including language that explains the Independent Transmission 
Provider's proposals for market monitoring, market power mitigation, 
long-term resource adequacy, transmission planning and expansion, 
transmission pricing and any changes to the SMD Tariff necessary to 
accommodate regional needs. The filing must also indicate the date, 
which must be no later than September 30, 2004, or such date as the 
Commission may establish, when the Independent Transmission Provider 
will be able to fully implement Standard Market Design. The Commission 
must approve the tariff filing before the Independent Transmission 
Provider will be able to implement Standard Market Design. We 
anticipate acting on these filings on a timely basis so that the 
Independent Transmission Providers will know several months before the 
planned implementation date any changes that are required in these 
filings.
    592. As a result of the changes required by the Final Rule, the 
Independent Transmission Provider or transmission owners may believe 
that other changes are needed in their transmission rates for 
jurisdictional service. Transmission owners and Independent 
Transmission Providers should file these types of changes under section 
205 of the FPA at least 60 days prior to the date on which they propose 
to implement Standard Market Design. The Commission intends the 
implementation process to be a collaborative one. The Commission 
directs public utilities to meet with stakeholders and state 
commissions on a regular basis to discuss the changes that are 
necessary to comply with the Final Rule. Based on the filings that are 
received, the Commission may also establish technical conferences, 
mediation efforts or other procedures as necessary to ensure that all 
public utilities that own, control or operate interstate transmission 
facilities will be operating under Standard Market Design no later than 
September 30, 2004, or such time as the Commission may establish.
    593. Further, the Commission intends this phased compliance process 
to encourage joint compliance filings. Public utilities may submit a 
single, joint application to meet the requirements of Standard Market 
Design, and Independent Transmission Providers may make necessary 
filings on behalf of their public utility members. Such joint filings 
may streamline the compliance process and reduce its costs.

January 31, 2004

    594. The Commission proposes to require all public utilities to 
provide assurances to the Independent Transmission Provider with which 
they are affiliated that the public utilities comply with minimum 
security standards. We propose to require public utilities that have 
transmission tariffs on file with the Commission to file the self-
certification of compliance with security standards that is attached as 
Appendix G. The self-certification must be submitted by January 31, 
2004, and every January 31 thereafter. On and after February 1, 2004, 
any transmission customer (including a non-jurisdictional entity) that 
seeks to receive transmission service from a public utility that owns, 
controls or operates facilities used for the transmission of electric 
energy in interstate commerce must provide assurances to the 
transmission provider that it has a basic security system in

[[Page 55525]]

place. This may be done by providing the transmission provider with a 
copy of the executed self-certification form, or the transmission 
provider and customer may make alternate arrangements. Following the 
implementation of Standard Market Design, we propose to extend this 
self-certification requirement to apply to any customer seeking to buy 
or sell through the Independent Transmission Provider's markets or take 
Network Access Service.

VI. Public Comment Procedures

    595. The Commission invites interested persons to submit comments, 
data, views and other information concerning matters set out in this 
proposed rule. To facilitate the Commission's review of the comments, 
the Commission requests commenters to provide an executive summary (not 
to exceed ten pages) of their positions. To the greatest degree 
possible, commenters should use the topic headings that the proposed 
rule uses and arrange their comments in the order of topics presented 
in this proposed rule, and cite the specific referenced paragraph 
numbers. Commenters should identify separately any additional issues 
that they may wish to address. Commenters should double-space their 
comments. Comments must refer to Docket No. RM01-12-000, and may be 
filed on paper or electronically via the Internet. The Commission must 
receive all comments no later than October 15, 2002. Comments should 
include an executive summary that should not exceed ten pages. Those 
filing electronically do not need to make a paper filing. Reply 
comments will not be entertained.
    596. Those making paper filings should submit the original and 14 
copies of their comments to the Office of the Secretary, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426.
    597. The Commission strongly encourages electronic filings. 
Commenters filing their comments via the Internet must prepare their 
comments in WordPerfect, MS Word, Portable Document Format, or ASCII 
format (see http://www.ferc.gov/documents/electronicfilinginitiative/efi/efi.htm, in particular ``User Guide''). To file the document, 
access the Commission's Web site at www.ferc.gov and click on ``e-
Filing'' and then follow the instructions for each screen. First time 
users will have to establish a user name and password. The Commission 
will send an automatic acknowledgment to the sender's e-mail address 
upon receipt of comments. User assistance for electronic filing is 
available at 202-208-0258 or by e-mail to [email protected]. Do not 
submit comments to the e-mail address.
    598. The Commission will place all comments in the Commission's 
public files and they will be available for inspection in the 
Commission's Public Reference Room at 888 First Street, NE., 
Washington, DC 20426, during regular business hours. Additionally, all 
comments may be viewed, printed, or downloaded remotely via the 
Internet through FERC's home page using the FERRIS link.

VII. Regulatory Flexibility Act

    599. The Regulatory Flexibility Act \249\ requires rulemakings to 
contain either a description and analysis of the effect that the 
proposed rule will have on small entities or a certification that the 
rule will not have a significant economic impact on a substantial 
number of small entities.
---------------------------------------------------------------------------

    \249\ 5 U.S.C. 601-612 (1994).
---------------------------------------------------------------------------

    600. This rule applies to public utilities that own, control or 
operate interstate transmission facilities, not to electric utilities 
per se. The total number of public utilities that, absent waiver, would 
have to modify their current open access transmission tariffs by filing 
the Interim Tariff is 176.\250\ Of these only 6 public utilities, or 
less than two percent, dispose of 4 million MWh or less per year.\251\ 
We do not consider this a substantial number, and in any event, these 
small entities may seek waiver of the Standard Market Design Final Rule 
requirements.\252\
---------------------------------------------------------------------------

    \250\ The sources for this figure are FERC Form No. 1 and FERC 
Form No. 1-F data.
    \251\ Id.
    \252\ The Regulatory Flexibility Act defines a ``small entity'' 
as ``one which is independently owned and operated and which is not 
dominant in its field of operation.'' See 5 U.S.C. 601(3) and 601(6) 
(1994); 15 U.S.C. 632(a)(1) (1994). In Mid-Tex Elec. Coop. v. FERC, 
773 F.2d 327, 340-343 (D.C. Cir. 1985), the court accepted the 
Commission's conclusion that, since virtually all of the public 
utilities that it regulates do not fall within the meaning of the 
term ``small entities'' as defined in the Regulatory Flexibility 
Act, the Commission did not need to prepare a regulatory flexibility 
analysis in connection with its proposed rule governing the 
allocation of costs for construction work in progress (CWIP). The 
CWIP rules applied to all public utilities. The Standard Market 
Design rules will apply only to those public utilities that own, 
control or operate interstate transmission facilities. These 
entities are a subset of the group of public utilities found not to 
require preparation of a regulatory flexibility analysis for the 
CWIP rule.
---------------------------------------------------------------------------

    601. With respect to the Interim Tariff, the Commission will 
specify precisely the terms and conditions that public utilities will 
have to incorporate into their existing tariffs, and this will 
considerably reduce the burden of modifying transmission tariffs. In 
order to implement the SMD Tariff, every public utility that owns, 
controls or operates facilities used for the transmission of electric 
energy in interstate commerce must (a) meet the definition of 
Independent Transmission Provider, (b) turn over the operation of its 
transmission facilities to a regional transmission organization that 
meets the definition of Independent Transmission Provider, or (c) 
contract with an entity that meets the definition of Independent 
Transmission Provider to operate its transmission facilities. We do not 
expect that any entity that must file an SMD Tariff would be a small 
entity as defined by the Regulatory Flexibility Act.
    602. We do not, therefore, believe that the requirement of filing 
the Interim Tariff and SMD Tariff will impose a significant economic 
impact on small entities. Consequently, the Commission certifies that 
this proposed rule will not have a significant economic impact upon a 
substantial number of small entities.

VIII. Environmental Statement

    603. In furtherance of the National Environmental Policy Act of 
1969, the Commission will prepare an environmental assessment (EA) that 
will consider the environmental impacts of the proposed rule. A notice 
of intent to prepare the EA, including a request for comments on the 
scope of the EA and notice of a public scoping meeting was issued on 
July 26, 2002.\253\
---------------------------------------------------------------------------

    \253\ Notice of Intent to Prepare an Environmental Assessment 
and Request for Comments on the Scope of Issues to be Addressed for 
the Proposed Rulemaking on Electricity Market Design and Structure, 
Docket No. RM01-12-000 (July 26, 2002).
---------------------------------------------------------------------------

IX. Public Reporting Burden and Information Collection Statement

    604. The Commission is submitting the following collections of 
information contained in this proposed rule to the Office of Management 
and Budget (OMB) for review under section 3507(d) of the Paperwork 
Reduction Act of 1995. The Commission identifies the information 
provided under Part 35 as FERC-516.
    605. The Commission solicits comments 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 that the Commission 
will collect, and any suggested methods for minimizing respondent's 
burden, including the use of automated information techniques.

[[Page 55526]]

 The burden estimates for complying with this proposed rule are as 
follows:

 
----------------------------------------------------------------------------------------------------------------
                                                           Number of     Number of    Hours per    Total annual
                    Data collection                       respondents    responses     response        hours
----------------------------------------------------------------------------------------------------------------
FERC-516..............................................             176            1       *1,199         211,024
                                                                   176            4            3           2,112
                                                                    12            1          164           1,968
                                                       ---------------------------------------------------------
    Totals............................................                                     1,366        215,104
----------------------------------------------------------------------------------------------------------------
*Rounded off.


----------------------------------------------------------------------------------------------------------------
                                                                                                   Hours per
           Respondent                 Document          Recipient         Required content          response
----------------------------------------------------------------------------------------------------------------
All public utilities that own,   (no document       Stakeholders and   Public utilities must   430 hours
 operate or control               required).         state              discuss with
 transmission facilities.                            representatives.   stakeholders and
                                                                        state representatives
                                                                        how they will
                                                                        implement the
                                                                        transition process
                                                                        and comply with the
                                                                        Final Rule:
                                                                       1. Selection of
                                                                        Independent
                                                                        Transmission Provider.
                                                                        2. Establishment
                                                                        regional state
                                                                        advisory committee.
                                                                        3. Development of
                                                                        regional transmission
                                                                        planning /expansion
                                                                        program.
                                                                       4. Development of a
                                                                        long-term resource
                                                                        adequacy requirement.
                                                                       5. Identification of
                                                                        areas where
                                                                        mitigation or
                                                                        appropriate
                                                                        infrastructure will
                                                                        be needed.
----------------------------------------------------------------------------------------------------------------
All public utilities that own,   Revisions to       FERC.............  Tariff language to      182 hours
 operate or control               Order No. 888                         place service to
 transmission facilities.         tariff (Interim                       bundled retail
                                  Tariff) or                            customers under OATT,
                                  request for                           eliminate preferences
                                  waiver of this                        for native load and
                                  requirement.                          for a transmission
                                                                        provider's own use of
                                                                        its system.
----------------------------------------------------------------------------------------------------------------
All public utilities that own,   Implementation     FERC.............  1. Identify             193 hours
 operate or control               plan for                              Independent
 transmission facilities.         compliance with                       Transmission Provider
                                  proposed                              (or request waiver of
                                  regulations.                          this requirement).
                                                                       2. Time lines and
                                                                        proposed procedures
                                                                        for regional
                                                                        transmission planning
                                                                        process.
                                                                       3. Time line and
                                                                        proposal for
                                                                        compliance with long-
                                                                        term resource
                                                                        adequacy
                                                                        requirements.
                                                                       4. Identify software
                                                                        vendor(s) to be used
                                                                        for implementation of
                                                                        SMD.
                                                                       5. Implementation time
                                                                        line showing
                                                                        projected timing and
                                                                        completion of
                                                                        milestones for
                                                                        software development.
                                                                       6. Detailed estimate
                                                                        of costs of
                                                                        implementing SMD.
----------------------------------------------------------------------------------------------------------------
Public utilities...............  Quarterly Reports  FERC.............  Implementation Plan     3 hours
                                                                        Status.
----------------------------------------------------------------------------------------------------------------
Transmission Provider..........  Proposed tariff    FERC.............  1. SMD Tariff,          124 hours
                                  language.                             including proposed
                                                                        language for market
                                                                        monitoring and market
                                                                        power mitigation;
                                                                        long-term resource
                                                                        adequacy;
                                                                        transmission planning
                                                                        and expansion;
                                                                        changes to SMD Tariff
                                                                        needed to accommodate
                                                                        regional needs.
                                                                       2. Date by which
                                                                        transmission provider
                                                                        will fully implement
                                                                        SMD.
----------------------------------------------------------------------------------------------------------------
Transmission Provider..........  Section 205        FERC.............  Section 205 filing      *If respondent
                                  filing                                demonstrating that      decides to
                                  requesting                            transmission            submit a Sec.
                                  approval of                           provider's revenue      205 filing, the
                                  adjustment of                         requirement should be   burden is
                                  revenue                               adjusted to recover     already covered
                                  requirement                           additional costs        under existing
                                  (optional).                           associated with         requirements
                                                                        conversion pre-Order
                                                                        No. 888 contracts to
                                                                        service under new
                                                                        tariff and allocation
                                                                        of congestion revenue
                                                                        rights directly to
                                                                        customers.
----------------------------------------------------------------------------------------------------------------

[[Page 55527]]

 
Transmission Provider/           Participator       FERC.............  1. Identify             34 hours
 participating generators.        Generator                             noncompetitive
                                  agreements.                           conditions in which
                                                                        generator would have
                                                                        to selfschedule or
                                                                        supply all capacity
                                                                        to spot markets.
                                                                       2. Specify bid caps
                                                                        that would apply to
                                                                        generator's day-ahead
                                                                        and real-time bids.
----------------------------------------------------------------------------------------------------------------
Transmission Provider..........  Reliability        FERC.............  Proposal regarding      63 hours
                                  proposals.                            implications of each
                                                                        reliability procedure
                                                                        (e.g. curtailment)
                                                                        for market prices in
                                                                        energy and ancillary
                                                                        services markets.
----------------------------------------------------------------------------------------------------------------
Transmission Provider..........  Transmission       FERC.............  Have in place a         120 hours
                                  Expansion Plan.                       regional transmission
                                                                        planning process and
                                                                        complete first
                                                                        transmission
                                                                        expansion plan
                                                                        pursuant to 18 CFR
                                                                        35.34(k)(7).
----------------------------------------------------------------------------------------------------------------
Market Monitoring Unit.........  Initial            FERC.............  1. Identify load        78 hours
                                  competitive                           pockets that require
                                  market analysis.                      different bid
                                                                        mitigation triggers.
                                                                       2. Identify generators
                                                                        that may be required
                                                                        for reliability.
----------------------------------------------------------------------------------------------------------------
Market Monitoring Unit.........  Annual report on   FERC &             1. General description- 86 hours
                                  market             Independent        -market operations,
                                  operations.        Transmission       supply and demand,
                                                     Provider's         market prices.
                                                     Governing Board.
                                                                       2. Analysis of market
                                                                        structure and
                                                                        participant behavior.
                                                                       3. Evaluation of
                                                                        effectiveness of
                                                                        mitigation measures
                                                                        taken.
                                                                       4. Overall assessment
                                                                        of market efficiency.
                                                                       5. Evaluation of
                                                                        barriers to entry for
                                                                        generating, demand-
                                                                        side, and
                                                                        transmission
                                                                        resources.
                                                                       6. Recommended changes
                                                                        to market design or
                                                                        market power
                                                                        mitigation measures
                                                                        to improve market
                                                                        performance.
----------------------------------------------------------------------------------------------------------------
Load serving entities..........  Resource adequacy  RTO..............  Report and document     38 hours
                                  report.                               plan to meet share of
                                                                        regional adequacy
                                                                        requirement.
----------------------------------------------------------------------------------------------------------------
RTOs...........................  Regional Demand    RTO..............  Regional demand         To be determined
                                  Forecast.                             forecast for its
                                                                        region for the
                                                                        planning horizon.
----------------------------------------------------------------------------------------------------------------
All public utilities with a      Self-              FERC.............  Completed and executed  2 hours
 transmission tariff on file      certification of                      form contained in
 with the Commission.             compliance with                       Appendix G to Notice
                                  system security                       of Proposed
                                  standards.                            Rulemaking.
----------------------------------------------------------------------------------------------------------------
All public utilities with a      Annual             FERC.............  Completed and executed  .5 hours
 transmission tariff on file      recertification                       form contained in
 with the Commission.             of compliance                         Appendix G to Notice
                                  with system                           of Proposed
                                  security                              Rulemaking.
                                  standards.
----------------------------------------------------------------------------------------------------------------
Total Annual Hours for Collection (reporting + record keeping (if appropriate) = 215,104 hours.

Information Collection Costs

    606. Because of the regional differences and the various staffing 
levels that will be involved in preparing the documentation (legal, 
technical and support) the Commission is using an hourly rate of $50 to 
estimate the costs for filing and other administrative processes 
(reviewing instructions, adjusting existing ways to comply with 
previously applicable instructions or requirements, training personnel 
to be able to respond to the information collection, searching data 
sources, completing and transmitting the collection of information and 
conducting outreach sessions with all affected entities) associated 
with this proposed rule. The estimated cost is anticipated to be 
$10,755,200 (215,104 hours x $50) for this portion of the rule.
    607. In addition, there is a separate component that must also be 
considered when implementing the requirements of this proposed rule, 
the costs for information technology (IT) needed to implement the SMD 
Tariff. The number of entities to be impacted at this phase of the 
rule's implementation will be fewer than at the Interim Tariff stage, 
but is still unknown at this time. Further, several entities are 
already developing or employing software that may be sufficient to 
implement the SMD Tariff, and the entities' software packages are at 
different stages of development. There are also regional differences to 
consider (as noted above) with respect to labor compensation. For these 
reasons, the Commission seeks comments on the anticipated costs for IT 
development associated with this proposed rule. When preparing their 
estimates, commenters should take into consideration design, 
procurement and operation costs for the following: (1) Data collection 
systems (including monitors, detection systems, control

[[Page 55528]]

systems and other equipment necessary to obtain information or data of 
interest, as well the facilities and equipment necessary to house and 
operate such systems); (2) data management systems necessitated by the 
data collection(s) (including computers and other hardware, programs 
and other software, storage media and facilities); and (3) data 
reporting systems necessitated by the information collection (including 
electronic links, installing and operating the reporting components of 
an information management system and the burden of maximizing public 
accessibility). These investments in information technology are for 
systems whose useful lifetime exceeds the expiration of the data 
collection (which must be reviewed and approved by OMB after three 
years), so the costs for this reporting burden needs to be estimated 
based on the costs of a longer lived investment. OMB regulations 
require OMB to approve certain information collection requirements 
imposed by agency rule.\254\ Accordingly, pursuant to OMB regulations, 
the Commission is providing notice of its proposed information 
collections to OMB.
---------------------------------------------------------------------------

    \254\ See 5 CFR 1320.11 (2002).
---------------------------------------------------------------------------

    Title: FERC-516, Electric Rate Schedule Filings.
    Action: Proposed Data Collections.
    OMB Control No.: 1902-0096.
    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.
    Frequency of Responses: One time.
    Necessity of Information: The proposed rule would revise the 
requirements contained in 18 CFR part 35. The Commission is seeking to 
standardize wholesale electric market design and transmission service. 
The Commission proposes to develop a standardized set of electricity 
market rules that reflects many of the recommendations and suggestions 
elicited from all market participants.
    608. The proposed SMD rules are intended to have a generally 
positive impact on these market participants. For example, the proposed 
SMD rules will facilitate direct dealings between market participants 
who want to secure long-term bilateral power supply arrangements. The 
proposed SMD rules will also facilitate short-term transactions that 
are made in the spot market to make up for imbalances (differences) 
between scheduled electricity supplies that were matched to projected 
load levels, and the load levels that actually develop. Through these 
proposed SMD rules, sellers will be able to more effectively sell into 
the market and buyers will be able to more efficiently buy from the 
market because they will not need to be directly matched up at the last 
minute on a real-time hourly and day-ahead basis. In addition, the 
proposed SMD rules will bolster the ability of many smaller customers, 
as well as larger customers, to profitably participate in programs 
designed to encourage reductions in loads to offset electricity supply 
shortages. Finally, the proposed SMD rules will foster the trading of 
transmission rights among transmission customers that will allow them 
to hedge against transmission congestion surcharges.
    609. Up to 176 public utilities that own, operate or control 
transmission would be required to implement the Commission's SMD Rule. 
The revised open access transmission component of the SMD Rule would be 
incorporated as an interim amendment to the existing transmission 
tariffs of all jurisdictional transmission providers operating in 
interstate commerce. Independent Transmission Providers would also be 
required to file SMD Tariffs contained in the Final Rule to implement 
Network Access Service and Standard Market Design. To the extent an 
affected public utility participates in an RTO, or contracts with an 
Independent Transmission Provider, the RTO or Independent Transmission 
Provider would make the required filing on behalf of the affected 
public utility. Public utilities also will be permitted to file 
Implementation Plans jointly with other utilities. Further, the 
Commission proposes to entertain requests for waivers of the 
requirement to make compliance filings. These features of the proposed 
rule would lessen the incidence of SMD compliance filings. We have 
estimated for purposes of this analysis that RTOs and ITPs may number 
from 5 to 12 entities in the lower 48 states.
    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 Sections 203 and 205 of the Federal Power Act 
to evaluate efforts for the interconnection and coordination of the 
United States electric transmission system and to ensure the orderly 
formation and operation of a standard design in wholesale electric 
transmission markets, 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.
    610. 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, Capital Planning and Policy Group, Phone: (202) 502-
8415, fax: (202) 208-2425, e-mail: [email protected].]
    611. Please send your comments concerning the collection of 
information(s) and the associated burden estimates to the contact 
listed above and 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) 
395-7856, fax: (202) 395-7285].

X. Document Availability

    612. 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 contents of this document via the 
Internet through FERC's home page (http://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m., to 5 
p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 
20426.
    613. From FERC's home page on the Internet, this information is 
available in the Federal Energy Regulatory Records Information System 
(FERRIS). The full text of this document is available on FERRIS in PDF 
and WordPerfect format for viewing, printing, and/or downloading. To 
access this document in FERRIS, type the docket number of this 
document, excluding the last three digits in the docket number 
field.User assistance is available for FERRIS and the FERC's Web site 
during normal business hours from our Help Line at (202) 208-2222 (e-
mail to [email protected]) or the Public Reference at (202) 208-1371 
Press 0, TTY (2020) 208-1659 (e-mail to 
[email protected]).

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Electricity, Reporting 
and recordkeeping requirements.


[[Page 55529]]


    By direction of the Commission. Commissioner Breathitt concurred 
with a separate statement attached.
Magalie R. Salas,
Secretary.
    In consideration of the foregoing, the Commission proposes to amend 
Part 35, Chapter I, Title 18, Code of Federal Regulations, as follows.

Regulatory Text

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 G, Procedures and 
Requirements Regarding Non-Discriminatory Open Access Transmission 
Services and Standard Market Design, including new Secs. 35.35, 35.36, 
35.37 and 35.38 to read as follows:
Subpart G--Procedures and Requirements Regarding Non-Discriminatory 
Open Access Transmission Services and Standard Market Design
35.35  Standard Market Design Tariff.
35.36  Market monitoring and market power mitigation.
35.37  Long-term electric energy resource adequacy.
35.38  Long-term transmission planning and expansion.

Subpart G--Procedures and Requirements Regarding Non-Discriminatory 
Open Access Transmission Services and Standard Market Design


Sec. 35.35  Standard Market Design Tariff.

    (a) Applicability. This section applies to any public utility that 
owns, controls or operates facilities used for the transmission of 
electric energy in interstate commerce and to any Independent 
Transmission Provider.
    (b) Definitions--
    (1) Independent Transmission Provider. As used herein the term 
Independent Transmission Provider shall mean any public utility that 
owns, controls or operates facilities used for the transmission of 
electric energy in interstate commerce, that administers the day-ahead 
and real-time energy and ancillary services markets in connection with 
its provision of transmission services pursuant to the pro forma tariff 
contained in Order No. ----, FERC Stats. & Regs. [para] ---- (Final 
Rule on Electricity Market Design and Structure), and that is 
independent (i.e., has no financial interest, either directly or 
through an affiliate, as defined in section 2(a)(11) of the Public 
Utility Holding Company Act (15 U.S.C. 79b(a)(11)), in any market 
participant in the region in which it provides transmission services or 
in neighboring regions).
    (2) Market Participant. As used herein the term Market Participant 
shall mean:
    (i) Any entity that, either directly or through an affiliate, sells 
or brokers electric energy, or provides ancillary services to the 
Independent Transmission Provider, unless the Commission finds that the 
entity does not have economic or commercial interests that would be 
significantly affected by the Independent Transmission Provider'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 
Independent Transmission Provider's actions or decisions.
    (c) Non-discriminatory open access transmission services and 
standard market design.
    (1) Every public utility that owns, controls or operates facilities 
used for the transmission of electric energy in interstate commerce, 
shall provide non-discriminatory open access services through the 
interim tariff contained in Order No. ----, FERC Stats. & Regs. [para] 
----(Final Rule on Electricity Market Design and Structure) no later 
than September 30, 2003. Such tariff shall remain on file with the 
Commission until it is superseded by the pro forma tariff contained in 
Order No. ----, FERC Stats. & Regs. [para] ---- (Final Rule on 
Electricity Market Design and Structure).
    (2) To implement the requirements of Non-Discriminatory Open Access 
Transmission Services and Standard Market Design, every public utility 
that owns, controls or operates facilities used for the transmission of 
electric energy in interstate commerce must meet the definition of 
Independent Transmission Provider, turn over the operation of its 
transmission facilities to a regional transmission organization, as 
defined in Sec. 35.34(b)(1) of this title, that meets the definition of 
Independent Transmission Provider, or contract with an entity that 
meets the definition of Independent Transmission Provider to operate 
its transmission facilities.
    (i) Every public utility that owns, controls or operates facilities 
used for the transmission of electric energy in interstate commerce as 
of [effective date of Standard Market Design Rule] must comply with 
this requirement by September 30, 2004, or such other date as 
determined by the Commission. Such public utility must inform the 
Commission which Independent Transmission Provider will operate the 
public utility's transmission facilities, and provide further 
information about its plans to implement Standard Market Design as 
specified in Order No. ----, FERC Stats. & Regs. [para] ----, no later 
than July 31, 2003. Every public utility that owns, controls or 
operates facilities used for the transmission of electric energy in 
interstate commerce after the effective date of this rule must comply 
no later than 60 days prior to the time its facilities are used for 
transmission in interstate commerce.
    (ii) A public utility that is a member of an approved regional 
transmission organization or an independent system operator or other 
entity that meets the definition of Independent Transmission Provider 
may file a request for a waiver of the filing requirements of this 
paragraph on the ground that it has already complied with the 
requirement. An application for a waiver must be filed no later than 
July 31, 2003, or no later than 60 days prior to the time the public 
utility's transmission facilities are used for transmission in 
interstate commerce.
    (3) Pursuant to section 206 of the Federal Power Act, any entity 
that meets the definition of Independent Transmission Provider must 
file with the Commission a tariff of general applicability for the 
provision of transmission services, including ancillary services and 
the administration of the day-ahead and real-time energy and ancillary 
services markets. Such tariff must be the pro forma tariff contained in 
Order No. ----, FERC Stats. & Regs. [para]---- (Final Rule on 
Electricity Market Design and Structure) or such other open access 
tariff as may be approved by the Commission consistent with Order No. 
----, FERC Stats. & Regs. [para]---- (Final Rule on Electricity Market 
Design and Structure). Such tariff must include proposed language that 
explains the Independent Transmission Provider's proposals for market 
monitoring, market power mitigation, long-term resource adequacy, 
transmission planning and expansion, transmission pricing, changes to 
the pro forma tariff necessary to accommodate regional needs, and 
further information as specified in the pro forma tariff contained in 
Order No. ----, FERC Stats. & Regs. [para]---- (Final Rule on 
Electricity Market Design and Structure). The filing also shall specify 
the date on which the Independent Transmission Provider proposes to 
implement Standard Market Design.
    (4) The Independent Transmission Provider shall file, pursuant to 
section

[[Page 55530]]

205 of the Federal Power Act, any changes to its transmission rates 
necessary to implement Standard Market Design, no later than 60 days 
prior to the date on which it proposes to implement Standard Market 
Design, or 60 days prior to the time its facilities are used for 
transmission in interstate commerce.
    (5) One or more public utilities may jointly file an application to 
meet the requirements of this paragraph.
    (6) An Independent Transmission Provider may make necessary filings 
on behalf of public utilities required to meet the requirements of this 
paragraph.
    (7) The interim tariff and pro forma tariff contained in Order No. 
----, FERC Stats. & Regs. [para]---- (Final Rule on Electricity Market 
Design and Structure) will not apply to transmission of electric energy 
pursuant to contracts that were executed on or before July 9, 1996 and 
remain in effect as of [effective date of Standard Market Design Rule]. 
Customers under such contracts may elect to convert their contracts, 
consistent with their contract terms, to service under the pro forma 
tariff contained in Order No. ----, FERC Stats. & Regs. [para]---- 
(Final Rule on Electricity Market Design and Structure) at any time 
after [effective date of Standard Market Design Rule].
    (8) Waivers. A public utility subject to the requirements of this 
section may file a request for waiver of all or part of the 
requirements of this section, for good cause shown. An application for 
waiver must be filed no later than [effective date of Standard Market 
Design Rule], or no later than 60 days prior to the time the 
Independent Transmission Provider would otherwise have to comply with 
the requirement.
    (d) Non-public utility procedures for tariff reciprocity 
compliance.
    (1) A non-public utility may submit a transmission tariff and a 
request for declaratory order that its voluntary transmission tariff 
provides transmission service that is comparable to the service that 
the non-public utility provides itself.
    (i) Any submittal and request for declaratory order submitted by a 
non-public utility will be provided an NJ (non-jurisdictional) docket 
designation.
    (ii) If the submittal is found to be an acceptable transmission 
tariff, an applicant in a Federal Power Act (FPA) section 211 case 
against the non-public utility shall have the burden of proof to show 
why service under the open access tariff is not sufficient and why a 
section 211 order should be granted.
    (2) A non-public utility may file a request for waiver of all or 
part of the reciprocity conditions contained in a public utility open 
access tariff, for good cause shown. An application for waiver may be 
filed at any time.
    (3) If a non-public utility has on file with the Commission, as of 
[effective date of Standard Market Design Rule], a reciprocity tariff 
accepted by the Commission, the non-public utility is not required to 
make a filing under paragraph (d) of this section.


Sec. 35.36  Market monitoring and market power mitigation.

    (a) The Independent Transmission Provider must have a market 
monitoring unit that is independent of the Independent Transmission 
Provider's management and that is accountable to the Commission. The 
market monitoring unit will provide information and recommendations to 
the Commission and the governing board of the Independent Transmission 
Provider.
    (b) The market monitoring unit will monitor all markets run by the 
Independent Transmission Provider and the operation of the transmission 
grid for exercises of market power, flaws in the Independent 
Transmission Provider's tariff rules or operations that contribute to 
economic inefficiency, and market participants' compliance with the 
Independent Transmission Provider's tariff. The market monitoring unit 
also shall perform further duties as instructed by the Commission.
    (c) The market monitoring unit will report at least annually on the 
structure and performance of the markets in the Independent 
Transmission Provider's region. The report must include, at a minimum: 
a description of market operations, supply and demand, and market 
prices; an structural analysis of the market, including an evaluation 
of barriers to entry; an assessment of market performance, including an 
assessment of market participant behavior; an evaluation of the 
effectiveness of the existing market power mitigation; and 
recommendations for improving the market design or market power 
mitigation measures to improve the efficiency of the market. The market 
monitoring unit also shall provide further reports as directed by the 
Commission.
    (d) The Independent Transmission Provider must include in its 
tariff provisions requiring market participants, as a condition of 
participating in the markets operated by the Independent Transmission 
Provider and using the interstate transmission facilities operated by 
the Independent Transmission Provider.
    (1) To agree to provide to the market monitoring unit all 
information and data requested by the market monitoring unit to perform 
its functions under these rules and the Independent Transmission 
Provider's tariff, and
    (2) To agree to penalties specified in the Independent Transmission 
Provider's tariff for the violation of any tariff provisions.
    (e) The market monitoring unit is responsible for administering the 
market power mitigation provisions of the Independent Transmission 
Provider's tariff.


Sec. 35.37   Long-term electric energy resource adequacy.

    (a) Each Independent Transmission Provider must ensure that the 
level of planned regional resources for a future year (the last year of 
the planning horizon) is adequate. Annually, each Independent 
Transmission Provider must:
    (1) Perform an electric energy demand forecast for the last year of 
the planning horizon;
    (2) Apportion the regional resource adequacy requirement for the 
last year of the planning horizon among the load serving entities in 
its area on the basis of the ratio of their loads;
    (3) Require each load-serving entity in its area to submit to the 
Independent Transmission Provider a plan (including generation, 
transmission and demand-side options) to meet the load-serving entity's 
share of the regional resource adequacy requirement for the last year 
of the planning horizon; and
    (4) Ensure that each load-serving entity's electric energy resource 
plan meets standards approved by the Commission and is feasible, 
including ensuring that resources are not double counted by different 
load serving entities.
    (b) This requirement shall replace installed capacity requirements 
approved by the Commission prior to [effective date of Standard Market 
Design Rule].


Sec. 35.38  Long-term transmission planning and expansion.

    (a) Each Independent Transmission Provider shall keep on file with 
the Commission a regional transmission expansion plan.
    (b) Each Independent Transmission Provider's regional transmission 
expansion plan shall, at a minimum:
    (1) permit all market participants to participate equally in a 
facilitated process to identify transmission projects that would best 
serve the needs of the region; and
    (2) require the Independent Transmission Provider to issue requests 
for proposals to address transmission planning needs identified through 
such a process.

[[Page 55531]]

    (c) Independent Transmission Providers shall satisfy the provisions 
of Sec. 35.34(k)(7) of this title no later than the date on which 
service commences under Standard Market Design.

    Note: The following Appendices will not be published in the Code 
of Federal Regulations.

APPENDICES

A. INTERIM PRO FORMA TARIFF REVISIONS
B. STANDARD MARKET DESIGN TARIFF (SMD TARIFF)
C. EXAMPLES OF FLAWS IN THE CURRENT REGULATORY ENVIRONMENT
D. CONVERSION OF THE ORDER NO. 888 PRO FORMA TARIFF TO THE REVISED 
STANDARD MARKET DESIGN PRO FORMA TARIFF
E. STANDARD MARKET DESIGN AND TRADING STRATEGIES ENCOUNTERED IN 
INDEPENDENT SYSTEM OPERATORS
F. ACCESS CHARGES AND CONGESTION REVENUE RIGHTS
G. FORM FOR ANNUAL SELF-CERTIFICATION OF COMPLIANCE WITH FERC SECURITY 
STANDARDS

Appendix A--Proposed Revisions to Order No. 888--A Pro Forma Open 
Access Transmission Tariff

    Among the revisions that the Commission proposes to require the 
Transmission Provider to file are revisions to Sections 1.19, 13.5, 
13.6, 14.2, 22.1(a), 28.2, 28.3, 33.2, 33.3, 33.5, and 33.7 to 
recognize that the preferences contained in the tariff for native 
load customers and for the Transmission Provider's use of its system 
have been eliminated. The changes are set forth below:
    1.19  Native Load Customers: The wholesale and retail power 
customers of the Transmission Provider on whose behalf the 
Transmission Provider, by statute, franchise, regulatory 
requirement, or contract, has undertaken an obligation to construct 
and operate the Transmission Provider's system to meet the reliable 
electric needs of such customers. The Transmission Provider will 
take Network Integration Transmission Service under Part III of the 
Tariff on their behalf.
    13.5  Transmission Customer Obligations for Facility Additions 
or Redispatch Costs: In cases where the Transmission Provider 
determines that the Transmission System is not capable of providing 
Firm Point-To-Point Transmission Service without (1) degrading or 
impairing the reliability of service to all customers taking firm 
service, or (2) interfering with the Transmission Provider's ability 
to meet prior firm contractual commitments to others, the 
Transmission Provider will be obligated to expand or upgrade its 
Transmission System pursuant to the terms of Section 15.4. The 
Transmission Customer must agree to compensate the Transmission 
Provider for any necessary transmission facility additions pursuant 
to the terms of Section 27. To the extent the Transmission Provider 
can relieve any system constraint more economically by redispatching 
the Transmission Provider's resources than through constructing 
Network Upgrades, it shall do so, provided that the Eligible 
Customer agrees to compensate the Transmission Provider pursuant to 
the terms of Section 27. Any redispatch, Network Upgrade or Direct 
Assignment Facilities costs to be charged to the Transmission 
Customer on an incremental basis under the Tariff will be specified 
in the Service Agreement prior to initiating service.
    13.6  Curtailment of Firm Transmission Service: In the event 
that a Curtailment on the Transmission Provider's Transmission 
System, or a portion thereof, is required to maintain reliable 
operation of such system, Curtailments will be made on a non-
discriminatory basis to the transaction(s) that effectively relieve 
the constraint. If multiple transactions require Curtailment, to the 
extent practicable and consistent with Good Utility Practice, the 
Transmission Provider will curtail service to Network Customers, 
including transmission service taken by the Transmission Provider 
for native load, and Transmission Customers taking Firm Point-To-
Point Transmission Service on a basis comparable to the curtailment 
of service to the Transmission Provider's Native Load Customers. All 
Curtailments will be made on a non-discriminatory basis, however, 
Non-Firm Point-To-Point Transmission Service shall be subordinate to 
Firm Transmission Service. When the Transmission Provider determines 
that an electrical emergency exists on its Transmission System and 
implements emergency procedures to Curtail Firm Transmission 
Service, the Transmission Customer shall make the required 
reductions upon request of the Transmission Provider. However, the 
Transmission Provider reserves the right to Curtail, in whole or in 
part, any Firm Transmission Service provided under the Tariff when, 
in the Transmission Provider's sole discretion, an emergency or 
other unforeseen condition impairs or degrades the reliability of 
its Transmission System. The Transmission Provider will notify all 
affected Transmission Customers in a timely manner of any scheduled 
Curtailments.
    14.2  Reservation Priority: Non-Firm Point-To-Point Transmission 
Service shall be available from transmission capability in excess of 
that needed for reliable service to Network Customers and other 
Transmission Customers taking Long-Term and Short-Term Firm Point-
To-Point Transmission Service. A higher priority will be assigned to 
reservations with a longer duration of service. In the event the 
Transmission System is constrained, competing requests of equal 
duration will be prioritized based on the highest price offered by 
the Eligible Customer for the Transmission Service. Eligible 
Customers that have already reserved shorter term service have the 
right of first refusal to match any longer term reservation before 
being preempted. A longer term competing request for Non-Firm Point-
To-Point Transmission Service will be granted if the Eligible 
Customer with the right of first refusal does not agree to match the 
competing request: (a) Immediately for hourly Non-Firm Point-To-
Point Transmission Service after notification by the Transmission 
Provider; and, (b) within 24 hours (or earlier if necessary to 
comply with the scheduling deadlines provided in section 14.6) for 
Non-Firm Point-To-Point Transmission Service other than hourly 
transactions after notification by the Transmission Provider. 
Transmission service for Network Customers from resources other than 
designated Network Resources will have a higher priority than any 
Non-Firm Point-To-Point Transmission Service. Non-Firm Point-To-
Point Transmission Service over secondary Point(s) of Receipt and 
Point(s) of Delivery will have the lowest reservation priority under 
the Tariff.
    22.1  Modifications On a Non-Firm Basis: The Transmission 
Customer taking Firm Point-To-Point Transmission Service may request 
the Transmission Provider to provide transmission service on a non-
firm basis over Receipt and Delivery Points other than those 
specified in the Service Agreement (``Secondary Receipt and Delivery 
Points''), in amounts not to exceed its firm capacity reservation, 
without incurring an additional Non-Firm Point-To-Point Transmission 
Service charge or executing a new Service Agreement, subject to the 
following conditions.
    (a) Service provided over Secondary Receipt and Delivery Points 
will be non-firm only, on an as-available basis and will not 
displace any firm or non-firm service reserved or scheduled by 
third-parties under the Tariff.
    28.2  Transmission Provider Responsibilities: The Transmission 
Provider will plan, construct, operate and maintain its Transmission 
System in accordance with Good Utility Practice in order to provide 
the Network Customer with Network Integration Transmission Service 
over the Transmission Provider's Transmission System. The 
Transmission Provider, as a Network Customer, shall be required to 
designate resources and loads on behalf of its Native Load 
Customers, in the same manner as any Network Customer under Part III 
of this Tariff. This information must be consistent with the 
information used by the Transmission Provider to calculate available 
transmission capability. The Transmission Provider shall include the 
Network Customer's Network Load in its Transmission System planning 
and shall, consistent with Good Utility Practice, endeavor to 
construct and place into service sufficient transmission capacity to 
deliver the Network Customer's Network Resources to serve its 
Network Load on a basis comparable to the Transmission Provider's 
delivery of its own generating and purchased resources to its Native 
Load Customers.
    28.3  Network Integration Transmission Service: The Transmission 
Provider will provide firm transmission service over its 
Transmission System to all Network Customers for the delivery of 
capacity and energy from designated Network Resources on a basis 
that is comparable to the Transmission Provider's historical use of 
the Transmission System to reliably serve its Native Load Customers.

[[Page 55532]]

    33.2  Transmission Constraints: During any period when the 
Transmission Provider determines that a transmission constraint 
exists on the Transmission System, and such constraint may impair 
the reliability of the Transmission Provider's system, the 
Transmission Provider will take whatever actions, consistent with 
Good Utility Practice, that are reasonably necessary to maintain the 
reliability of the Transmission Provider's system. To the extent the 
Transmission Provider determines that the reliability of the 
Transmission System can be maintained by redispatching resources, 
the Transmission Provider will initiate procedures pursuant to the 
Network Operating Agreement to redispatch all Network Resources and 
the Transmission Provider's own resources on a least-cost basis 
without regard to the ownership of such resources.
    33.3  Cost Responsibility for Relieving Transmission 
Constraints: Whenever the Transmission Provider implements least-
cost redispatch procedures in response to a transmission constraint, 
all Network Customers, including network service taken by the 
Transmission Provider on behalf of its Native Load Customers, will 
bear a proportionate share of the total redispatch cost based on 
their respective Load Ratio Shares.
    33.5  Allocation of Curtailments: The Transmission Provider 
shall, on a non-discriminatory basis, Curtail the transaction(s) 
that effectively relieve the constraint. However, to the extent 
practicable and consistent with Good Utility Practice, any 
Curtailment will be shared by all Network Customers, including the 
Transmission Provider on behalf of its Native Load Customers in 
proportion to their respective Load Ratio Shares. The Transmission 
Provider shall not direct the Network Customer to Curtail schedules 
to an extent greater than the Transmission Provider would Curtail 
the Transmission Provider's schedules under similar circumstances.
    33.7  System Reliability: Notwithstanding any other provisions 
of this Tariff, the Transmission Provider reserves the right, 
consistent with Good Utility Practice and on a not unduly 
discriminatory basis, to Curtail Network Integration Transmission 
Service without liability on the Transmission Provider's part for 
the purpose of making necessary adjustments to, changes in, or 
repairs on its lines, substations and facilities, and in cases where 
the continuance of Network Integration Transmission Service would 
endanger persons or property. In the event of any adverse 
condition(s) or disturbance(s) on the Transmission Provider's 
Transmission System or on any other system(s) directly or indirectly 
interconnected with the Transmission Provider's Transmission System, 
the Transmission Provider, consistent with Good Utility Practice, 
also may Curtail Network Integration Transmission Service in order 
to (i) limit the extent or damage of the adverse condition(s) or 
disturbance(s), (ii) prevent damage to generating or transmission 
facilities, or (iii) expedite restoration of service. The 
Transmission Provider will give the Network Customer as much advance 
notice as is practicable in the event of such Curtailment. Any 
Curtailment of Network Integration Transmission Service will be not 
unduly discriminatory. The Transmission Provider shall specify the 
rate treatment and all related terms and conditions applicable in 
the event that the Network Customer fails to respond to established 
Load Shedding and Curtailment procedures.
    In addition, the Commission proposes to require Transmission 
Providers to make the following changes to section 2 of the pro 
forma tariff:

2. Reservation Priority for Existing Firm Service Customers

    2.1  Right of First Refusal: Existing firm service customers 
(wholesale requirements and transmission-only, with a contract term 
of one-year or more), have the right to continue to take 
transmission service from the Transmission Provider when the 
contract expires, rolls over or is renewed. This transmission 
reservation priority is independent of whether the existing customer 
continues to purchase capacity and energy from the Transmission 
Provider or elects to purchase capacity and energy from another 
supplier. If at the end of the contract term, the Transmission 
Provider's Transmission System cannot accommodate all of the 
requests for transmission service the existing firm service customer 
must agree to accept a contract term at least equal to a competing 
request by any new Eligible Customer and to pay the current just and 
reasonable rate, as approved by the Commission, for such service. 
This transmission reservation priority for existing firm service 
customers is an ongoing right that may be exercised at the end of 
all firm contract terms of one-year or longer.
    2.2  Notice of Rollover: Consistent with requests for new 
service described in Section 13.2 of Part II of the Tariff, a 
Transmission Customer must submit its request to exercise rollover 
rights no later than sixty (60) days prior to the date the current 
service agreement expires.
    2.3  Future Load Growth: The Transmission Provider may reserve 
existing transmission capacity needed for future load growth 
reasonably forecasted within the Transmission Provider's current 
planning horizon. The Transmission Provider may decline a Customer 
the ability to roll over its firm transmission service with a term 
of one year or longer only if the Transmission Provider includes in 
the original service agreement a specific, reasonably forecasted 
need for the transfer capability to serve load growth at the end of 
the term of the service agreement.
    2.4  Redirects: A Customer receiving firm transmission service 
with a term of one year or longer which requests to use alternate 
point(s) of receipt or delivery retains its right of first refusal 
for service the original point(s) of receipt and delivery at the 
time the current service agreement expires.

Appendix B--SMD Tariff

Standard Market Design Pro Forma Open Access Transmission Tariff Table 
of Contents

Part I. General Terms and Conditions

A. Common Service Provisions
    1. Definitions
    2. Open Access Same Time Information System (OASIS)
    3. Local Furnishing Bonds
    3.1  Transmission Owners That Own Facilities Financed by Local 
Furnishing Bond
    3.2  Alternate Procedures for Requesting Transmission Service
    4. Reciprocity
    5. Billing and Payment
    5.1  Billing Procedure
    5.2  Interest on Unpaid Balances
    5.3  Customer Default
    6. Regulatory Filings
    7. Force Majeure and Indemnification
    7.1  Force Majeure
    7.2  Indemnification
    8. Creditworthiness
    9. Eligibility for Independent Transmission Provider Services
    9.1  Requirements for Network Access Service
    9.2  Requirements for Market Services
    9.3  Participating Generator Agreements
    9.4  Requirements Common to All Customers: Completed Application 
and Minimum Technical Requirements
    9.4.1  Application
    9.4.2  Completed Application
    9.4.3  Approval of Application and/or Notice of Deficient 
Application
    10. Dispute Resolution Procedures
    10.1  Internal Dispute Resolution Procedures
    10.2  External Arbitration Procedures
    10.3  Arbitration Decisions
    10.4  Costs
    10.5  Rights Under the Federal Power Act
    11. Metering
    11.1  Customer Requirements
    11.2  Load-Serving Entities
    11.3  Ancillary Service Providers
    11.4  Third Party Metering Services
    11.5  Estimation of Metering
    12. Data and Confidentiality Provisions
    12.1  Access to Complete and Accurate Data
    12.2  Independent Transmission Provider Procedures
    12.3  Access to Confidential Information
    12.4  Use of Confidential Information
    12.5  Disclosure of Bid Information
    12.6  Survival

Part II. Transmission Services

B. Network Access Service
Preamble
    1. Nature of Network Access Service
    1.1  Scope of Service
    1.2  Independent Transmission Provider Responsibilities
    1.3  Service at Points without Concurrent Congestion Revenue 
Rights
    2. Initiating Service
    2.1  Condition Precedent for Receiving Service
    2.2  Application Procedures

[[Page 55533]]

    2.2.1  Applications That Do Not Require the Integration of 
Resources and Load
    2.2.2  Applications That Require the Integration of Resources 
and Load
    2.3  Technical Arrangements to be Completed Prior to 
Commencement of Service
    2.4   Customer Facilities
    2.5  Filing of Service Agreement
    2.6  Notice of Deficient Application
    2.7  Response to a Completed Application
    2.8  Execution of Service Agreement
    2.9  Initiating Service in the Absence of an Executed Service 
Agreement
    2.10  Scheduling of Network Access Service
    3. Network Resources
    3.1  Designation of Network Resources
    3.2  Designation of New Network Resources
    3.3  Designation of Alternate Resources
    3.4  Substitution of Resources and Congestion Revenue Rights
    3.5  Termination of Network Resources
    3.6  Customer Redispatch Obligation
    3.7  Transmission Arrangements for Network Resources Not 
Physically Connected with the Independent Transmission Provider
    3.8  Limitation on Designation of Network Resources
    3.9  Customer Owned Transmission Facilities
    4. Designation of Network Load
    4.1  Network Load
    4.2  New Network Load Connected with Independent Transmission 
Provider
    4.3  New Interconnection Points
    4.4  Changes in Service Requests
    4.5  Annual Load and Resource Information Updates
    5. Service Availability
    5.1  General Conditions
    5.2  Determination of Available Transfer Capability
    5.3  Notice of Need for System Impact Study
    5.4  System Impact Study Agreement and Cost Reimbursement
    5.5  System Impact Study Procedures
    5.6  Facilities Study Procedures
    5.7  Facilities Study Modifications
    5.8  Due Diligence in Completing New Facilities
    5.9  Obligation to Provide Transmission Service that Requires 
Expansion or Modification of the Transmission System
    5.10  Partial Interim Service
    5.11  Expedited Procedures for New Facilities
    5.12  Compensation for New Facilities and Congestion Costs
    6. Procedures if The Independent Transmission Provider is Unable 
to Complete New Transmission Facilities for Transmission Service
    6.1  Delays in the Construction of New Facilities
    6.2  Alternatives to the Original Facility Additions
    6.3  Refund Obligation for Unfinished Facility Additions
    7. Provisions Relating to Transmission Construction and Services 
on Systems of Other Utilities
    8. Network Access Service Customer Responsibilities
    8.1  Conditions Required of Customers
    8.2  Customer Responsibility for Third-Party Arrangements
    9. Load Shedding and Curtailments
    9.1  Procedures
    9.2  Transmission Constraints
    9.3  Curtailments of Scheduled Deliveries
    9.4  Load Shedding
    9.5  System Reliability
    10.  Rates and Charges
    10.1  Monthly Access Charge
    10.2  Determination of Customer's Monthly Network Load
    10.3  Transmission Usage Charges
    11.  Operating Agreements
    11.1  Operation Under the Network Operating Agreement
    11.2  Network Operating Agreement
    11.3  Network Operating Committee
    12.  Reservation Priority for Existing Firm Service Customers
    12.1  Right of First Refusal
    12.2  Notice of Rollover
C. Ancillary Service
    1. Scheduling, System Control and Dispatch Service
    1.1  Billing Units and Calculation of Rates
    2. Reactive Supply and Voltage Control from Generation Sources 
Service
    3. Regulation Service
    4. Energy Imbalance Service
    5. Operating Reserves
D. Congestion Revenue Rights
Preamble
    1. Types of Congestion Revenue Rights
    1.1  Receipt Point-to-Delivery Point Congestion Revenue Rights
    1.1.1  Obligation Rights
    1.1.2  Option Rights
    1.1.3  Types of Receipt Point and Delivery Points
    1.2 Flowgate Congestion Revenue Rights
    1.2.1  Definition of Flowgates and Flowgate Rights
    2. Term of Congestion Revenue Rights
    3. Scheduling Priority for Holders of Congestion Revenue Rights 
in the Event of Curtailment
    4. Existing Transmission Contracts
    4.1  Conversion of Existing Transmission Contracts
    5. Allocation of Congestion Revenue Rights
    5.1  Allocation of Congestion Revenue Rights
    5.2  Requirement to Conduct Periodic Auctions for Congestion 
Revenue Rights
    6. Resale of Congestion Revenue Rights
    7. Auctions for Congestion Revenue Rights
    7.1  General Description of the Auction Process
    7.2  Frequency of Congestion Revenue Rights Auction
    7.3  Responsibilities of the Independent Transmission Provider 
Prior to Each Auction
    7.3.1  Establish Auction Rules
    7.3.2  Evaluate Creditworthiness
    7.3.3  Information to be Made Available to Bidders
    7.3.4  Other Responsibilities
    7.4  Responsibilities of each Buying Bidder
    7.4.1  Creditworthiness Information
    7.4.2  Bids to Buy Congestion Revenue Rights
    7.5  Responsibilities of each Selling Bidder
    7.5.1  Bids to Sell Congestion Rights
    7.6  Selection of Winning Bids and Determination of Market 
Clearing Price
    7.7  Auction Settlement
    7.8  Simultaneous Feasibility
    7.9  Responsibilities of the Independent Transmission Provider 
upon Completion of the Auction
    8. Exchanging Congestion Revenue Rights
    8.1  Condition for Exchanging Congestion Revenue Rights
    9. Direct Sales of Congestion Revenue Rights over OASIS
    10. Congestion Revenue Rights Associated with Transmission 
Expansion

Part III. Day-Ahead and Real-Time Market Services

E. General Responsibilities and Requirements Preamble
     1. Day-Ahead and Real-Time Market Services
     2. Independent Transmission Provider Authority
     3. Information and Reporting Requirements
     4. Communication Requirements for Market Services
F. Day-Ahead Scheduling and Markets Preamble
    1. Day-Ahead Scheduling Procedures
    1.1  Day-Ahead Trading Deadline
    1.2  Rules for Self Schedules
    1.2.1  Supplier-Committed Self Schedules
    1.2.2  Independent Transmission Provider-Committed Self 
Schedules
    1.2.3  Self Supply of Ancillary Services
    1.3  Rules for Bilateral Transactions Schedules
    1.3.1  Internal Transactions
    1.3.2  External Transactions
    1.4  Rules for Bidding
    1.5  Bid-Based Security Constrained Unit Commitment and 
Determination of the Day-Ahead Schedule
    1.6  Determination of the Day-Ahead Prices
    1.7  Load Forecasts
    1.8  Reliability-Based Security Constrained Unit Commitment
    1.9  Reliability Forecast
    1.10  Posting the Day-Ahead Schedule
    1.11  Day-Ahead Bid Revenue Sufficiency Guarantee
    2. Day-Ahead Market for Energy
    2.1  General
    2.2  Independent Transmission Provider Obligations
    2.3  Purchaser Rules and Obligations
    2.3.1  Specification of Bids
    2.3.2  Specification of Virtual Bids
    2.3.3  Period of Bids
    2.4  Supplier Rules and Obligations
    2.4.1  Eligibility to Supply
    2.4.2  Specification of Bids
    2.4.3  Bids to Supply Virtual Incremental Energy
    2.4.4  Bids to Supply Decremental Energy
    2.4.5  Periods of Bids to Supply Energy
    2.5  Calculation of Day-Ahead Locational Marginal Prices for 
Energy
    2.5.1  Energy LMP Calculation
    2.5.2  Hub Price Calculation
    2.5.3  Zone Price Calculation
    2.6  Calculation of Additional Payments and Charges
    2.6.1  Bid Revenue Sufficiency Guarantee

[[Page 55534]]

    2.6.2  Other Payments and Charges
    2.7  Market Rules for Shortages or Emergencies
    2.8  Settlement
    2.8.1  Payments by Purchasers
    2.8.2  Payments to Suppliers
    2.8.3  Payments by Suppliers
    3. Day-Ahead Scheduling of Transmission and Settlement Functions 
for Congestion Revenue Rights
    3.1  General
    3.2  Day-Ahead Transmission Requests
    3.2.1  Information Provided by the Customer
    3.3  Calculation of the Day-Ahead Transmission Usage Charges
    3.3.1  Marginal Congestion Component
    3.3.2  Marginal Losses Component
    3.4  Flowgate LMP Calculation
    3.5  Settlement of Congestion Revenue Rights
    3.5.1  Settlement of Receipt Point-to-Delivery Point Congestion 
Revenue Rights
    3.5.2  Settlement of Flowgate Right
    3.6  Disposition of Congestion Revenue Surplus or Deficit
    3.6.1  Hourly Congestion Charge Collection
    3.6.2  Hourly Net Congestion Revenue Owed to Congestion Revenue 
Rights Holders
    3.6.3  Determination and Disposition of Congestion Revenue 
Surplus or Deficit
    3.7  Disposition of Marginal Loss Revenue Surplus
    3.7.1  Hourly Marginal Loss Charge Collection
    3.7.2  Determination and of Marginal Loss Revenue
    4. Day-Ahead Market for Regulation and Frequency Response
    4.1  General
    4.2  Independent Transmission Provider Obligations
    4.3  Purchaser Rules and Obligations
    4.4  Supplier Rules and Obligations
    4.4.1  Eligibility to Supply
    4.4.2  Specification of Bids
    4.5  Calculation of Market Clearing Price
    4.6  Calculation of Additional Payments and Charges
    4.6.1  Bid Revenue Sufficiency Guarantee
    4.6.2  Other Payments and Charges
    4.7  Market Rules for Shortages
    4.8  Settlement
    4.8.1  Payments to Suppliers
    5.  Day-Ahead Market for Operating Reserve--Spinning Reserve
    5.1  General
    5.2  Independent Transmission Provider Obligations
    5.3  Purchaser Rules and Obligations
    5.4  Supplier Rules and Obligations
    5.4.1  Eligibility to Supply
    5.4.2  Specification of Bids
    5.5  Calculation of Market Clearing Price
    5.5.1  Methodology for Calculation of Market Clearing Price
    5.5.2  Calculation of Zonal or Locational Prices
    5.5.3  Transmission for Operating Reserves
    5.6  Calculation of Additional Payments and Charges
    5.6.1  Bid Revenue Sufficiency Guarantee
    5.6.2  Other Payments and Charges
    5.7  Market Rules for Shortages
    5.8  Settlement
    5.8.1  Payments to Suppliers
    6. Day-Ahead Markets for Operating Reserve - Supplemental
    6.1  General
    6.2  Independent Transmission Provider Obligations
    6.3  Purchaser Rules and Obligations
    6.4  Supplier Rules and Obligations
    6.4.1  Eligibility to Supply
    6.4.2  Specification of Bids
    6.5  Calculation of Market Clearing Prices for Supplemental 
Reserves
    6.5.1  Methodology for Calculation of Prices
    6.5.2  Calculation of Zonal or Locational Prices
    6.5.3  Transmission for Operating Reserves
    6.6  Calculation of Additional Payments and Charges
    6.6.1  Bid Revenue Sufficiency Guarantee
    6.6.2  Other Payments and Charges
    6.7  Market Rules for Shortages
    6.8  Settlement
    6.8.1  Payment to Suppliers
G. Post Day-Ahead Scheduling and Real-Time Markets Preamble
    1. Post Day-Ahead Bidding and Scheduling Procedures
    1.1  General
    1.2  Rules for Self Schedules
    1.2.1  Supplier-Committed Self-Schedules
    1.3  Rules for Bilateral Transactions
    1.3.1  Internal Transactions
    1.3.2  External Transactions
    1.4  Rules for Bidding
    2. Security Constrained Intra-Day Unit Commitment and Dispatch
    2.1  Intra-Day Security-Constrained Unit Commitment and Dispatch
    2.2  Security Constrained Dispatch
    2.3  Intra-Day Revenue Sufficiency Guarantee
    3. Real-Time Market for Energy
    3.1  General
    3.2  Independent Transmission Provider Obligations
    3.3  Purchaser Rules and Obligations
    3.3.1  Specification of Bids
    3.4  Supplier Rules and Obligations
    3.4.1  Eligibility to Supply
    3.4.2  Specification of Bids
    3.4.3  Period of Bids to Supply Energy
    3.5  Calculation of Real-Time Locational Marginal Prices for 
Energy
    3.5.1  Ex Post LMP Calculation
    3.5.2  Determination of Energy LMPs by Fixed Block Resources
    3.5.3  Five Minute Real-Time LMPs
    3.6  Calculation of Additional Payments and Charges
    3.6.1  Bid Revenue Sufficiency Guarantee
    3.6.2  Undergeneration by Suppliers
    3.6.3  Other Payments and Charges
    3.7  Market Rules for Shortages or Emergencies
    3.8  Settlement
    3.8.1  Settlement when Actual Injections are Less than Scheduled 
Energy Injections
    3.8.2  Settlement when Actual Injections are Greater than 
Scheduled Energy Injections
    3.8.3  Settlement when Actual Energy Withdrawals are Less than 
Scheduled Energy Withdrawals
    3.8.4  Settlement when Actual Energy Withdrawals are Greater 
than Scheduled Energy Withdrawals
    4. Real-Time Scheduling for Transmission
    4.1  General
    4.2  Transmission Bids
    4.3  Real-Time Transmission Usage Charges
    4.3.1  Marginal Congestion Component
    4.3.2  Marginal Losses Component
    4.4  Calculation of Flowgate LMPs
    4.5  Marginal Loss Charge Collection
    4.5.1  Determination and Disposition of Marginal Loss Revenue 
Surplus
    4.6  Disposition of Other Real-Time Revenue Surplus
    5. Real-Time Market for Regulation
    5.1  General
    5.2  Independent Transmission Provider Obligations
    5.3  Purchaser Rules and Obligations
    5.4  Supplier Rules and Obligations
    5.4.1  Eligibility to Supply
    5.4.2  Specifications of Bids
    5.4.3  Bidding and Scheduling Process
    5.5  Calculation of Market Clearing Price
    5.6  Calculation of Additional Payments and Charges
    5.6.1  Bid Revenue Sufficiency Guarantee
    5.6.2  Failure to Provide Regulation in Real-Time
    5.6.3  Other Payments and Charges
    5.7  Market Rules for Shortages or Emergencies
    5.8  Settlement
    5.8.1  Payments by Purchasers
    5.8.2  Payments to Suppliers
    5.9  Monitoring Suppliers and Generators
    6. Real-Time Market for Operating Reserve--Spinning Reserve
    6.1  General
    6.2  Independent Transmission Provider Obligations
    6.3  Purchaser Rules and Obligations
    6.4  Supplier Rules and Obligations
    6.4.1  Eligibility to Supply
    6.4.2  Specification of Bids
    6.5  Calculation of Market Clearing Price
    6.5.1  Methodology for Calculation of Prices
    6.5.2  Calculation of Zonal or Marginal Clearing Prices
    6.5.3  Transmission for Operating Reserves
    6.6  Calculation of Additional Payments and Charges
    6.6.1  Bid Revenue Sufficiency Guarantee
    6.6.2  Failure to Perform in Real-Time
    6.6.3  Other Payments and Charges
    6.7  Market Rules for Shortages or Emergencies
    6.8  Settlement
    6.8.1  Payments by Purchasers
    6.8.2  Payments to Suppliers
    6.8.3  Payments by Suppliers
    6.9  Failure to Provide Operating Reserves
    7. Real-Time Markets for Operating Reserves--Supplement Reserves
    7.1  General
    7.2  Independent Transmission Provider Obligations
    7.3  Purchaser Rules and Obligations
    7.4  Supplier Rules and Obligations

[[Page 55535]]

    7.4.1  Eligibility to Supply
    7.4.2  Specification of Bids
    7.5  Calculation of Market Clearing Price for Supplemental 
Reserve
    7.5.1  Methodology for Calculation of Prices
    7.5.2  Calculation of Zonal or Locational Prices
    7.5.3  Transmission for Operating Reserves
    7.6  Calculation of Additional Charges and Payments
    7.6.1  Bid Revenue Sufficiency Guarantee
    7.6.2  Failure to Perform in Real-Time
    7.6.3  Exceptions
    7.6.4  Other Payments and Charges
    7.7  Market Rules for Shortages or Emergencies
    7.8  Settlement
    7.8.1  Payments by Purchasers
    7.8.2  Payments to Suppliers
    7.8.3  Payments by Suppliers
    8. Other Real-Time Payments and Charges
    8.1  Bid Revenue Sufficiency Guarantee Payments for Replacement 
Reserves
    8.1.1  Payments to Suppliers
    8.1.2  Charges to Customers
    8.1.3  Unrecovered Bid Revenue Sufficiency Guarantee Payments
    8.2  Other Real-Time Bid Revenue Sufficiency Guarantee Payments
    8.2.1  Payments to Customers
    8.2.2  Charges to Customers

Part IV. Market Monitoring

H. Market Power Mitigation and Market Monitoring
    1. Market Power Mitigation
    1.1  Participating Generator Agreements
    1.2  Determination of Bid Caps
    1.2.1  The Safety-Net Bid Cap
    1.2.2  Generator-Specific Bid Caps
    1.3  Determination of Available Capacity
    1.3.1  Adjustments to Capacity to Reflect Risk of Forced Outages 
in Real-Time Market
    1.3.2  Available Capacity Reduced by Forced Outages Subject to 
Audit
    1.4  Determination of Non-Competitive Conduct
    1.4.1  Local Non-Competitive Conditions
    1.4.2  Other Non-Competitive Conditions
    1.5  Triggering Mechanisms
    1.5.1  Market Power Mitigation Independent of Market Conditions
    1.5.2  Market Power Mitigation Triggered by Section H.1.4.1
    1.5.3  Market Power Mitigation Triggered by Section H.1.4.2
    2. Market Monitoring Plan
    2.1  Data Requirements and Data Collection
    2.1.1  Obligations of Market Participants
    2.1.2  Generator-Specific Data
    2.1.3  Data Acquired in the Course of Conducting Market 
Operations
    2.1.4  Other Publically Available Data
    2.1.5  Confidentiality
    2.2  Framework for Analyzing Market Structure and Generator 
Conduct
    2.2.1  Obligations of the Market Monitor
    2.2.2  Structural Analysis
    2.2.3  Conduct Analysis
    2.3  Annual Reports
    2.4  Periodic Reports
    3. Rules for Market Participant Conduct
    3.1  Physical Withholding
    3.2  Economic Withholding
    3.3  Availability Reporting
    3.4  Factual Accuracy
    3.5  Information Obligation
    3.6  Cooperation
    3.7  Physical Feasibility
    3.8  Enforcement
I. Long-Term Resource Adequacy
    1. Data Submission for annual forecast of future regional load
    2. Assignment of Resource Adequacy Requirements
    3. Load-Serving Entity's Submission for Resource Adequacy 
Requirements
    4. Resource Adequacy Requirements Standards
    5. Penalties
    6. Curtailment

Part V. Other

J. Generation Interconnection Procedures (to be provided in separate 
rule)

Part VI. Transmission Planning and Expansion

K. Transmission Planning and Expansion

Part VII. Pro Forma Service Agreements

Form of Service Agreement for Network Access Service
Form of Service Agreement for Market Services
Form of Participating Generator Agreement

Part VIII. Attachments

ATTACHMENT A  Methodology to Assess Transfer Capability
ATTACHMENT B  Methodology for Completing System Impact Study
ATTACHMENT C  Network Operating Agreement
ATTACHMENT D  Index of Network Access Customers
ATTACHMENT E  Index of Market Services Customers
ATTACHMENT F  Rates
ATTACHMENT G  List of Existing Transmission Contracts

Part I. General Term and Conditions

A. Common Service Provisions

1. Definitions

    Access Charge: A charge designed to recover the embedded costs 
of the Transmission System.
    Ancillary Services: Those services that are necessary to support 
the transmission of Energy from Resources to Loads while maintaining 
reliable operation of the Independent Transmission Provider's 
Transmission System in accordance with Good Utility Practice.
    Automatic Generation Control (``AGC''): The automatic regulation 
of the power output of electric generating facilities within a 
prescribed range in response to a change in system frequency, or 
tie-line loading, to maintain system frequency or scheduled 
interchange with other areas within predetermined limits.
    Availability Bid: Bid by a Resource that indicates the minimum 
price at which Regulation or Operating Reserves is offered to be 
supplied.
    Available Transfer Capability (``ATC''): A measure of the 
Transfer Capability remaining in the physical transmission network 
for further commercial activity over and above already committed 
uses. ATC is defined as the Total Transfer Capability, less the sum 
of existing transmission commitments (including transmission which 
is used for reliability purposes).
    Base Point Signal: Signals sent from the Independent 
Transmission Provider and ultimately received by Resources 
specifying the scheduled MW level for the Resource.
    Bid: Offer to purchase and/or sell products or services in an 
Auction, including Energy, Demand Reductions, Transmission Service, 
Congestion Revenue Rights and/or Ancillary Services at a specified 
location, quantity, and time-period that is duly submitted to the 
Independent Transmission Provider pursuant to Independent 
Transmission Provider Procedures. The Bid should indicate either a 
specific price or the Bidder's desire to have the Bid accepted 
regardless of the market clearing price.
    Bid Revenue Sufficiency Guarantee: A guarantee by the 
Independent Transmission Provider that ensures the minimum recovery 
of the Bid prices for Resources scheduled through the Day-Ahead 
Market, in subsequent post Day-Ahead Market commitments for 
reliability, and in the Real-Time Market.
    Bilateral Transaction Schedule: Simultaneous schedules of Load 
and Generation of the same MW level by a Market Participant.
    Boundary Interface: Point(s) used to indicate Point(s) of 
Receipt and Point(s) of Delivery outside of the Service Area.
    Commission (``FERC''): The Federal Energy Regulatory Commission, 
or any successor agency.
    Completed Application: An application for Transmission or Market 
Service that satisfies all of the information and other requirements 
of the Tariff, including any required deposit.
    Congestion: The state of a Transmission System when a binding 
limit (constraint) on the system's Transfer Capability is reached 
that must be addressed.
    Congestion Charges: Charges relating to the Marginal Congestion 
Component of Energy Purchases or Transmission Usage Charges. These 
charges reflect the increased cost that result from dispatching the 
Transmission System to respect Transmission System (or Flowgate) 
constraints.
    Congestion Revenue Deficit: In the Day-Ahead Market, the 
absolute value of the difference between the Hourly Congestion 
Charge Collection and the Hourly Net Congestion Revenue Owed to 
Congestion Revenue Rights Holders when the difference is negative.
    Congestion Revenue Right: A property right held by a Customer 
that entitles and/or obligates the holder of the right to receive 
specified Congestion revenues.
    Congestion Revenue Surplus: In the Day-Ahead Market, the 
difference between the Hourly Congestion Charge Collection and the 
Hourly Net Congestion Revenue Owed to Congestion Revenue Rights 
Holders when the difference is positive.
    Contingency: An actual or potential unexpected failure or outage 
of a system component, such as a Generator,

[[Page 55536]]

transmission line, circuit breaker, switch or other electrical 
element. A Contingency also may include multiple components, which 
are related by situations leading to simultaneous component outages.
    Control Center: The equipment, facilities and personnel used by 
the Independent Transmission Provider to coordinate and direct the 
operation of the Service Area and to administer the Day-Ahead and 
Real-Time Markets, including facilities and equipment used to 
communicate and coordinate with the Market Participants in 
connection with transactions in the Day-Ahead and Real-Time Markets 
or the operation of the Service Area.
    Curtailment: Reduced transmission service or provision of 
electricity to a Customer in response to a transmission capability 
for reliability purposes.
    Customer: An entity which has complied with the requirements 
contained in this Tariff, including having signed a Service 
Agreement, and is eligible to utilize the services provided by the 
Independent Transmission Provider under this Tariff; provided, 
however, that a party taking services under this Tariff pursuant to 
an unsigned Network Access Service Agreement filed with the 
Commission by the Independent Transmission Provider shall be deemed 
a Customer.
    Day-Ahead: Nominally, the twenty-four hour period directly 
preceding the Operating Day, except when this period may be extended 
by the Independent Transmission Provider to accommodate holidays and 
weekends.
    Day-Ahead Market: The market administered by the Independent 
Transmission Provider in which Energy, Ancillary Services, and 
Transmission Services are scheduled and sold Day-Ahead, consistent 
of the Day-Ahead scheduling process, price calculations, and 
settlements.
    Decremental Energy Bid: A Bid Price curve provided by an entity 
engaged in a bilateral Import or Internal Transaction to indicate 
the LMP below which that entity is willing to reduce its Generator's 
output and purchase Energy in the LMP Markets.
    Delivering Party: The entity supplying capacity and Energy to be 
transmitted at Point(s) of Receipt.
    Delivery Point: The location where a transaction terminates. A 
Delivery Point can be a delivery Node, an aggregation of delivery 
Nodes, an Interface, or a Trading Hub. For purposes of this Tariff, 
the Delivery Point does not have to be a location where power is 
consumed.
    Direct Assignment Facilities: Facilities or portions of 
facilities that are constructed for the sole use/benefit of a 
particular Customer requesting service under the Tariff. Direct 
Assignment Facilities shall be specified in the Service Agreement 
that governs service to the Customer and shall be subject to 
Commission approval.
    Dispatch Hour: The sixty (60) minute period commencing at the 
beginning of each hour (0000 hour).
    Dispatch Interval: Length of time between dispatch instructions 
from the Independent Transmission Provider.
    Emergency: Any abnormal system condition that requires immediate 
automatic or manual action to prevent or limit loss of transmission 
facilities or Generators that could adversely affect the reliability 
of the electric system.
    Energy: A quantity of electricity that is Bid, produced, 
purchased, consumed, sold or transmitted over a period of time and 
measured or calculated in megawatt-hours.
    Energy Bid: For an Energy Supplier, a Bid curve that indicates 
an entity's willingness to supply Energy at certain prices to 
markets operated by the Independent Transmission Provider. For an 
Energy Purchaser, Bid curve that indicates an entity's willingness 
to purchase Energy at certain prices in markets operated by the 
Independent Transmission Provider.
    Energy Limited Resource: Capacity Resources that, due to design 
considerations, environmental restrictions on operations, cyclical 
requirements, such as the need to recharge or refill, or other non-
economic reasons, are unable to operate continuously on a daily 
basis.
    Ex Ante Real-Time Energy LMP: The LMP that is produced by the 
Independent Transmission Provider's Security Constrained Dispatch 
and communicated to Resources under dispatch instructions in advance 
of real time. Under SMD, the LMP used for settlement is the Ex Post 
LMP.
    Ex Post Real-Time Energy LMP: The LMP that is produced following 
the evaluation of actual dispatch relative to dispatch instructions. 
It is the LMP used for settlement purposes in the Real-Time Market.
    Existing Transmission Contract: A contract for Transmission 
Service or wholesale requirements service currently in effect 
between two or more Transmission Owners, or between a Transmission 
Owner and another entity, that was executed on or before July 9, 
1996, or earlier.
    Export: Energy that is delivered from the Independent 
Transmission Provider Service Area Interconnection to another 
Service Area.
    External Transaction: A Bilateral Transaction in which either 
the Receipt Point or the Delivery Point must be a point at the 
boundary of the Independent Transmission Provider Service Area. If 
the Receipt Point is a Boundary Interface, then the External 
Transaction is an Import. If the Delivery Point is a Boundary 
Interface, then the External Transaction is an Export.
    Facilities Study: An engineering study conducted by the 
Independent Transmission Provider to determine the required 
modifications to the Independent Transmission Provider's 
Transmission System, including the cost and scheduled completion 
date for such modifications, that will be required to provide the 
requested transmission service.
    Federal Power Act (``FPA''): The Federal Power Act, as may be 
amended from time-to-time (See 16 U.S.C. Sec. 796 et seq.)
    Fixed Block Resource: A unit that, due to operational 
characteristics, can only be in one of two states: either turned 
completely off, or turned on and run at a fixed capacity level.
    Flowgate: A transmission facility (such as a transmission line 
or a transformer or some other component of the electrical network) 
or group of facilities (e.g., an Interface).
    Flowgate Right: A Congestion Revenue Right specified by a 
portion of the total MW capacity over a particular transmission 
Flowgate in a specified direction. Flowgate Rights entitle the 
holder to collect congestion revenues associated with the specified 
MW flow over the identified Flowgate in the specified direction.
    Generation Capacity: The sustained maximum net output of a 
Generator, measured in megawatts, as demonstrated by the performance 
of a test or through actual operation as defined in the Independent 
Transmission Provider Procedures.
    Generator: A facility capable of supplying Energy, capacity and/
or Ancillary Services that is accessible to the Service Area.
    Good Utility Practice: Any of the practices, methods and acts 
engaged in or approved by a significant portion of the electric 
utility industry during the relevant time period, or any of the 
practices, methods and acts which, in the exercise of reasonable 
judgment in light of the facts known at the time the decision was 
made, could have been expected to accomplish the desired result at a 
reasonable cost consistent with good business practices, 
reliability, safety and expedition. Good Utility Practice is not 
intended to be limited to the optimum practice, method, or act to 
the exclusion of all others, but rather to be acceptable practices, 
methods, or acts generally accepted in the region.
    Hourly Economic Maximum Level: The maximum MW level a Resource 
may operate under normal system conditions.
    Hourly Economic Minimum Level: The minimum MW level a Resource 
may operate under normal system conditions.
    Hourly Emergency Maximum Level: The maximum MW level a Resource 
may operate under Emergency system conditions.
    Hourly Emergency Minimum Level: The maximum MW level a Resource 
may operate under Emergency system conditions.
    Hub: A mathematical simplification of a set of buses to emulate 
a single bus for financial and trading purposes. A Hub is defined by 
a set of buses that are each associated with a fixed numerical 
weights such that the sum of weights equal one.
    Hub Price: The weighted average of Energy LMP's at the buses 
that comprise the Hub.
    Import: Energy that is delivered to an Independent Transmission 
Provider Service Area Interconnection from another Service Area.
    Incremental Energy Bid: A Bid Price curve for Energy generated 
above the Hourly Minimum Economic Level.
    Independent Transmission Provider: The entity that operates the 
facilities used for the transmission of Energy in interstate 
commerce and provides transmission service under the Tariff.
    Independent Transmission Provider's Monthly Transmission System 
Peak: The maximum usage of the Independent Transmission Provider's 
Transmission System in a calendar month.
    Interface: A defined set of transmission facilities (see also 
Boundary Interface).
    Internal Transaction: Bilateral Transactions whose Receipt Point 
and Delivery Point are both within the Independent Transmission 
Provider's service territory.

[[Page 55537]]

    Load: A term that refers to either a consumer of Energy or the 
amount of Energy (MWh) or demand (MW) consumed.
    Load Forecast: Independent forecasts by the Independent 
Transmission Provider of Load within the Independent Transmission 
Provider's Service Area used in its scheduling decisions to ensure 
reliable operation of the system.
    Load Ratio Share: The ratio of a Load-Serving Entity's Load to 
total Load within the Service Area during a specified time period.
    Load-Serving Entity: An entity, including a municipal electric 
system and an electric cooperative, authorized by law, regulatory 
authorization or requirement, agreement, or contractual obligation 
to supply Energy, to retail Customers located within the Independent 
Transmission Provider's Service Area, including an entity that takes 
service directly from the Independent Transmission Provider to 
supply its own Load in the Independent Transmission Provider's 
Service Area.
    Load Shedding: The systematic reduction of system demand by 
temporarily decreasing Load in response to Transmission System or 
area capacity shortages, system instability, or voltage control 
considerations.
    Locational Marginal Pricing (``LMP''): A pricing methodology 
under which the price of Energy at each location in the Transmission 
System is equivalent to the cost to supply or the value to purchase 
the next increment of Load at that location taking into account the 
physical aspects of the Transmission System. The term LMP also 
refers to the price of Energy bought or sold at a specific location.
    Lower Regulation Limit: The lowest operating point that the 
Independent Transmission Provider may dispatch a unit for Regulation 
under normal operating conditions.
    Marginal Congestion Component (``MCC''): Component of Locational 
Marginal Price and Transmission Usage Charge reflecting the cost of 
dispatching the Resources available to the Independent Transmission 
Provider such that transmission constraints are respected.
    Marginal Loss Charge Collection: The net amounts charged to 
purchasers associated with the Marginal Loss Component of the hourly 
LMPs at the purchasers' buses less the net amounts paid to sellers 
associated with the Marginal Loss Component of the hourly LMPs at 
the sellers' buses.
    Marginal Losses: The Transmission System Real Power Losses 
associated with each additional MWh of consumption by Load, or each 
additional MWh transmitted under a Bilateral Transaction as measured 
at the Points of Withdrawal.
    Marginal Losses Component (``MLC''): The component of LMP at a 
bus that accounts for the Marginal Losses, as measured between that 
bus and the Reference Bus.
    Market Clearing Price: The price of a product or service 
determined by the Independent Transmission Provider at a given 
location and time at which the total amounts offered for sale and 
purchase are equal.
    Market Monitor(ing Unit): Entity required to report directly to 
the Commission and to the independent governing board of the 
Independent Transmission Provider the results and recommendations 
derived from its study of the markets operated by the Independent 
Transmission Provider.
    Market Services: Services provided by the Independent 
Transmission Provider under the Tariff related to the markets for 
Energy, capacity and Ancillary Services.
    Maximum Curtailment Time: Maximum time (in hours) that a 
supplier of demand response Resources is willing to respond to 
Curtailment dispatch instructions.
    Maximum Run Time: Maximum length of time (in hours) that a 
Generator can be reliably expected to operate.
    Maximum Shut Down Limit: Maximum number of times a Generator is 
able to shut down in a 24 period.
    Maximum Start-up Limit: Maximum number of times a Generator is 
able to start-up in a 24 period.
    Minimum Curtailment Time: Minimum time (in hours) that a 
supplier of demand response Resources is willing to respond to 
Curtailment dispatch instructions.
    Minimum Down Time: Minimum length of time (in hours) required 
for a Generator to begin operations following an outage due to 
operational constraints.
    Minimum Generation Bid: The payment required by a Supplier to 
operate at the unit's Hourly Economic Minimum.
    Minimum Generation Emergency: An Emergency declared by the 
Independent Transmission Provider in which the Independent 
Transmission Provider anticipates requesting one or more generating 
Resources to operate at or below Normal Minimum Generation, in order 
to manage, alleviate, or end the Emergency.
    Minimum Run Time: Minimum length of time (in hours) required for 
a Generator to be in operation due to operational constraints.
    Network Access Service: Transmission service offered by the 
Independent Transmission Provider under this Tariff. It offers use 
of the transmission grid by allowing Customers to: (1) Serve Load 
with any Resource on the system, (2) access any Interface to import 
power from a neighboring system, (3) integrate, economically 
dispatch and regulate its current and planned Resources to serve its 
Load; (4) transmit power through and out of the Independent 
Transmission Provider's system, and (5) aggregate Resources for 
resale and hub-to-hub transfer.
    Network Operating Agreement: Agreement that contains the terms 
and conditions under which the Customer shall operate its facilities 
and the technical and operational matters associated with the 
implementation of the Tariff.
    Network Operating Committee: Committee responsible for 
coordinating operating criteria to determine each Party's 
responsibilities under the Network Operating Agreement.
    No-load Cost: Hourly costs associated with generating at a 
unit's Hourly Economic Minimum.
    Node: A location where Energy can be injected and/or withdrawn 
from the grid.
    Normal Response Rate: The expected response rate of an Energy 
supplying Resource measured in MW/min.
    Obligation Right: A Congestion Revenue Right that requires the 
Customer to receive the Congestion revenues (either positive or 
negative).
    Open Access Same-Time Information System (OASIS): The 
information system and standards of conduct contained in Part 37 of 
the Commission's regulations and all additional requirements 
implemented by subsequent Commission orders dealing with OASIS.
    Operable Capacity: Capacity that is readily converted to Energy 
and is measured in MW.
    Operating Day: The daily 24 hour period beginning at midnight 
for which transactions on the Energy Market are scheduled.
    Operating Reserves: Generator Capacity that is available to 
supply Energy, or Load Resources that are available to Curtail 
Energy usage, in the event of Contingency conditions, which meet the 
requirements of the Independent Transmission Provider. Operating 
Reserves include Spinning Reserves and Supplemental Reserves.
    Opportunity Cost: The cost of giving up the opportunity to sell 
(or consume) a product (or service) at a location and time in order 
to sell a related product (requiring the same inputs), at the same 
location and time or the same product at another location and time.
    Optimal Power Flow (``OPF''): A Power Flow that maximizes the 
value (as expressed in the Bids) of the Congestion Revenue Rights, 
subject to the constraint that the selected set of Bids must be 
simultaneously feasible.
    Option Right: A Congestion Revenue Right that allows the 
Customer to receive the positive Congestion revenues without the 
obligation to pay Congestion revenues when they are negative.
    Planning Horizon: The number of years ahead in each region for 
which the Load-Serving Entities must demonstrate to the Independent 
Transmission Provider that they have procured adequate Energy 
Resources.
    Power Flow: A simulation tool that provides an estimate of 
Energy flows on the Transmission System and adjacent transmission 
systems under a given set of assumed characteristics.
    Primary Holder: The Owner of a Congestion Revenue Right 
recognized as such by the Independent Transmission Provider for 
settlement purposes.
    Real Power Losses: The loss of Energy, resulting from 
transporting power over the Transmission System, between the Point 
of Injection and Point of Withdrawal of that Energy.
    Real Time: Referring to the time period in which transmission 
and generation dispatch instructions are ultimately given.
    Real-Time Market: The market administered by the Independent 
Transmission Provider for Energy, Ancillary Services, and 
Transmission Services in real time, consisting of the real time 
scheduling process, dispatch, price calculations, and settlements.
    Receipt Point: The location where a Transaction originates. A 
Receipt Point can be a Generator Node, an aggregation of Generator 
Nodes, an Interface, or a Trading Hub. For purposes of this Tariff, 
a Receipt Point does not have to be a Generator.

[[Page 55538]]

    Receipt Point-to-Delivery Point Congestion Revenue Right 
Obligation: Congestion Revenue Rights that confer: (i) The right to 
collect revenues equal to the applicable Marginal Congestion 
Component of the hourly Transmission Usage Charge from the Receipt 
Point to the Delivery Point when the Marginal Congestion Component 
is positive, and (ii) the obligation to pay an amount to the 
Independent Transmission Provider equal to the absolute value of the 
applicable Marginal Congestion Component of the hourly Transmission 
Usage Charge when the Marginal Congestion Component is negative.
    Receipt Point-to-Delivery Point Congestion Revenue Right Option: 
Congestion Revenue Rights that confer to the holder the right to 
collect revenues equal to the applicable Congestion Charge component 
of the hourly Transmission Usage Charge from the Receipt Point to 
the Delivery Point when the Marginal Congestion Component is 
positive, but do not obligate the holder to pay the absolute value 
of the applicable Marginal Congestion Component of the hourly 
Transmission Usage Charge when the Marginal Congestion Component is 
negative.
    Receiving Party: The entity receiving the capacity and Energy 
transmitted by the Independent Transmission Provider to Point(s) of 
Delivery.
    Reference Bus: The location on the Transmission System relative 
to which all mathematical quantities, including Shift Factors and 
penalty factors relating to physical operation, will be calculated.
    Regulation: The capability of a specific generating unit with 
appropriate telecommunications, control and response capability to 
increase or decrease its output in response to a regulating control 
signal, in accordance with the specifications in the Manuals. 
Regulation also encompasses regulation and frequency response 
service i.e. the continuous balancing of Resources (generation and 
interchange) with Load variations in order to maintain scheduled 
Interconnection frequency.
    Regulation Capability: The maximum amount of Regulation Service 
in MW a Resource can operationally provide to the Independent 
Transmission Provider.
    Regulation Requirement: Quantity of Regulation identified by the 
local reliability authority to be procured by the Independent 
Transmission Provider to ensure system reliability.
    Reliability Rules: Those rules, standards, procedures and 
protocols, including Local Reliability Rules, developed in 
accordance with NERC, regional reliability councils, FERC, PSC and 
NRC standards, rules and regulations, and other criteria.
    Reserve Location: Geographic area for which there is a specific 
Operating Reserve requirement applies.
    Resource: Either a Generator or a Load that can reliably adjust 
its electricity usage by some specified range and rate at a specific 
Withdrawal Point in response to Day-Ahead or Real-Time prices or by 
instruction by the Independent Transmission Provider.
    Resource Adequacy Requirement: The Resource reserve margin, 
stated as a ratio of the reserves to the forecast peak load during 
the final year of the Planning Horizon, expressed as a percentage.
    Response Rate: The capability (in MW/minute) of a Resource to 
adjust its generation level in response to dispatch signals.
    Scheduled Amount: Megawatt supply or demand obligation as 
indicated by the Independent Transmission Provider's Schedule.
    Scheduled Resource: Resource incurring a supply or demand 
obligation as indicated by the Independent Transmission Provider's 
Schedule.
    Security Constrained Dispatch: The determination of the dispatch 
that incorporates all transmission constraints necessary for 
reliability.
    Security Constrained Unit Commitment: The allocation of Load to 
Generators by the Independent Transmission Provider through the 
operation of a computer algorithm which continuously calculates 
individual Generator loading at minimum Bid cost, balancing Load and 
scheduled interchange with generation while meeting all reliability 
rules and Generator performance constraints.
    Self-Schedule: The Supplier's provision to the Independent 
Transmission Provider with its hourly Energy schedule in the Day-
Ahead Market and Real-Time Market independent of market prices.
    Self-Supply: The provision of certain Ancillary Services, or the 
provision of Energy to replace Marginal Losses, by a Customer using 
either the Customer's own Generators or generation obtained from an 
entity other than the Independent Transmission Provider.
    Seller: Market Participant whose Bid to supply into either the 
Day-Ahead or Real-Time Market has been accepted and who has incurred 
the associated supply obligations.
    Service Agreement: The initial agreement and any amendments or 
supplements thereto entered into by the Customer and the Independent 
Transmission Provider for service under the Tariff.
    Service Area: The geographic region and transmission facilities 
therein that are under the operational control of the Independent 
Transmission Provider.
    Service Commencement Date: The date the Independent Transmission 
Provider begins to provide service pursuant to the terms of an 
executed Service Agreement, or the date the Independent Transmission 
Provider begins to provide service in accordance with the Tariff.
    Settlement: The process of determining the charges to be paid to 
or by a Customer in the markets operated by the Independent 
Transmission Provider under this Tariff.
    Shift Factor: A ratio, calculated by the Independent 
Transmission Provider, that compares (1) the change in power flow 
through a transmission facility resulting from an incremental change 
in injection of power at a Receipt Point and withdrawal of power at 
the Delivery Point to (2) the incremental change in injection of 
power at the Receipt Point.
    Shortage: A situation in which the markets for Energy, 
Regulation or Operating Reserves are not able to clear because of 
insufficient Bid-in capacity.
    Spinning Reserves: Operating Reserves provided by synchronized 
Resources that can respond immediately to dispatch instructions.
    Spinning Reserves Requirement: Quantity of Spinning Reserves 
identified by the local reliability authority to be procured by the 
Independent Transmission Provider to ensure system reliability.
    Start Time: The number of hours required by a generating 
Resource to reach its Hourly Economic Minimum Level.
    Start-up Cost: Payment needed by the Purchaser of Energy to 
cover the fixed costs associated with its Energy Bid or payment 
required by Generator to Start-up and reach its minimum operating 
level.
    Supplemental Commitment: Scheduling of Resources by the 
Independent Transmission Provider following the posting of the Day-
Ahead Schedule to meet the reliability needs.
    Supplemental Reserves: Operating Reserves provided by Resources 
that can be started, synchronized and loaded within a specified time 
period.
    Supplemental Reserves Requirement: Quantity of Supplemental 
Reserves identified by the local reliability authority to be 
procured by the Independent Transmission Provider to ensure system 
reliability.
    Supplier: A Party that is supplying the Demand Reduction, Energy 
and/or associated Ancillary Services to be made available under the 
Tariff, including Generators and demand side Resources that satisfy 
all applicable Independent Transmission Provider requirements.
    System Impact Study: An assessment by the Independent 
Transmission Provider of (i) the adequacy of the Transmission System 
to accommodate a request for Congestion Revenue Rights or (ii) 
whether any additional costs may be incurred in order to provide 
Congestion Revenue Rights.
    System Marginal Price (SMP): The LMP of Energy at the Reference 
Bus.
    Total Transfer Capability: The amount of electric power that can 
be transferred over the interconnected transmission network in a 
reliable manner.
    Transaction: The purchase and/or sale of Energy, Congestion 
Revenue Rights, Ancillary Services, or Transmission Service.
    Transfer Capability: The measure of the ability of 
interconnected electrical systems to reliably move or transfer power 
from a set of Receipt Points to a set of Delivery Points over all 
transmission facilities (or paths) between those areas under 
specified system conditions.
    Transmission Owner: Entity with financial ownership of the 
transmission assets used in the provision of Transmission Service by 
the Independent Transmission Provider.
    Transmission Owner's Monthly Transmission System Peak: The 
maximum hourly firm usage as measured in megawatts (MW) of the 
Transmission Owner's transmission system in a calendar month.
    Transmission Planned Outage: Any transmission outage scheduled 
in advance for a pre-determined duration and which meets the 
notification requirements for such outages specified by the 
Independent Transmission Provider.
    Transmission Service: Services needed to move Energy from a 
Receipt Point to a Delivery Point provided to Customers by the 
Independent Transmission Provider in accordance with this Tariff.
    Transmission System: The facilities controlled and operated by 
the Independent

[[Page 55539]]

Transmission Provider that are used to provide transmission service 
under the Tariff.
    Transmission Usage Charge: A per unit charge for Transmission 
Service to support a Bilateral Transaction. The Transmission Usage 
Charge is equal to the difference of the LMP at the Delivery Point 
and the LMP at the Receipt Point (in $/MWh).
    Unit-Specific Opportunity Cost: The Opportunity Cost calculation 
for specific Resources that are selected to provide Regulation or 
Operating Reserves in either the Day-Ahead or the Real-Time Markets.
    Upper Regulation Limit: The highest operating point that the 
Independent Transmission Provider will dispatch a unit for 
Regulation under normal operating conditions.
    Virtual Demand Bid: A Demand Bid in the Day-Ahead Market without 
a physical Resource capable of withdrawing Energy in the Real-Time 
Market.
    Virtual Energy: Energy purchased or sold in the Day-Ahead Energy 
Market that is not backed by physical Resources.
    Virtual Supply Bid: A Supply Bid in the Day-Ahead Market without 
a physical Resource capable of injecting Energy in the Real-Time 
Market.
    Voltage Support Service: The provision of reactive power support 
necessary to maintain transmission voltage.
    Wheel Through: Transmission Service through the Service Area of 
the Independent Transmission Provider that originates and terminates 
outside the Service Area of the Independent Transmission Provider.
    Zonal-LMP: Load weighted average of Energy LMPs over a set of 
buses and weights defined by a zone.
    Zone: A set of buses in a geographic area.
    Zone Price: Load weighted average price over the defined set of 
buses in a zone.

2. Open Access Same-Time Information System (OASIS)

    Terms and conditions regarding Open Access Same-Time Information 
System and standards of conduct are set forth in 18 CFR Sec. 37 of 
the Commission's regulations (Open Access Same-Time Information 
System and Standards of Conduct for Public Utilities).

3. Local Furnishing Bonds

    3.1  Transmission Owners That Own Facilities Financed by Local 
Furnishing Bonds: This provision is applicable only to Transmission 
Owners that have financed facilities for the local furnishing of 
Energy with tax-exempt bonds, as described in section 142(f) of the 
Internal Revenue Code of 1986, as amended, or corresponding 
provisions of predecessor statutes (``local furnishing bonds''). 
Notwithstanding any other provision of this Tariff, the Independent 
Transmission Provider shall not be required to provide transmission 
service to any Customer pursuant to this Tariff if the provision of 
such transmission service would jeopardize the tax-exempt status of 
any local furnishing bond(s) used, in whole or in part, to finance 
the Transmission Owner's facilities, regardless of whether such 
facilities financed with these bonds are transmission, distribution, 
or generation facilities.
    3.2  Alternative Procedures for Requesting Transmission Service:
    (i) If the Independent Transmission Provider determines that the 
provision of transmission service requested by a Customer would 
jeopardize the tax-exempt status of any outstanding local furnishing 
bond(s) used, in whole or part, to finance any of the Transmission 
Owner's facilities, regardless of whether such facilities financed 
with these bonds are transmission, distribution, or generation 
facilities, or would jeopardize the Transmission Owner's entitlement 
to income tax deductions for interest expense in connection with 
such tax-exempt bonds, it shall advise the Customer within thirty 
(30) days of receipt of the Completed Application of (a) such 
determination and (b) the reasonably expected amount of any costs 
resulting from such loss of tax-exempt status and/or income tax 
deductions (or from the prevention of any such loss). For purposes 
of this section, the costs resulting from such loss of tax exempt 
status and/or income tax deductions (or from the prevention of any 
such loss) due to the provision of such transmission service shall 
include, without limitation, any reasonable transactions costs 
(including any redemption premium) of defeasing and/or redeeming any 
outstanding local furnishing bonds and/or from any such refinancing 
with taxable debt and/or from any disallowance or loss of a 
deduction for tax purposes of the interest in respect of such bonds.
    (ii) If the Customer thereafter renews its request for the same 
transmission service referred to in (i) by tendering an application 
under Section 211 of the Federal Power Act, the Independent 
Transmission Provider, within ten (10) days of receiving a copy of 
the Section 211 application, will waive its rights to a request for 
service under Section 213(a) of the Federal Power Act and to the 
issuance of a proposed order under Section 212(c) of the Federal 
Power Act. The Commission, upon receipt of the Independent 
Transmission Provider's waiver of its rights to a request for 
service under Section 213(a) of the Federal Power Act and to the 
issuance of a proposed order under Section 212(c) of the Federal 
Power Act, shall issue an order under Section 211 of the Federal 
Power Act specifying that such service is provided subject to the 
Customer's payment of all costs deemed by the Commission to be 
eligible for recovery under Section 212(a) of the Federal Power Act. 
Upon issuance of the order under Section 211 of the Federal Power 
Act, the Independent Transmission Provider shall be required to 
provide the requested transmission service in accordance with the 
terms and conditions of this Tariff and such order. Transmission 
service shall not commence until after the Customer complies with 
the creditworthiness provisions of Section 8 of this Tariff.

4. Reciprocity

    A Customer receiving transmission service under this Tariff 
agrees to provide comparable transmission service that it is capable 
of providing on similar terms and conditions over facilities used 
for the transmission of Energy owned, controlled or operated by the 
Customer and over facilities used for the transmission of Energy 
owned, controlled or operated by the Customer's corporate 
affiliates. A Customer that is a member of a power pool or Regional 
Transmission Group also agrees to provide comparable transmission 
service to the members of such power pool and Regional Transmission 
Group on similar terms and conditions over facilities used for the 
transmission of Energy owned, controlled or operated by the Customer 
and over facilities used for the transmission of Energy owned, 
controlled or operated by the Customer's corporate affiliates.
    This reciprocity requirement applies not only to the Customer 
that obtains transmission service under the Tariff, but also to all 
parties to a transaction that involves the use of transmission 
service under the Tariff, including the power seller, buyer and any 
intermediary, such as a power marketer. This reciprocity requirement 
also applies to any Customer that owns, controls or operates 
transmission facilities that uses an intermediary, such as a power 
marketer, to request transmission service under the Tariff. If the 
Customer does not own, control or operate transmission facilities, 
it must include in its Application a sworn statement of one of its 
duly authorized officers or other representatives that the purpose 
of its Application is not to assist a Customer to avoid the 
requirements of this provision.

5. Billing and Payment

    5.1  Billing Procedure: Within a reasonable time after the first 
day of each month, the Independent Transmission Provider shall 
submit an invoice to the Customer for the charges for all services 
furnished under the Tariff during the preceding month. The invoice 
shall be paid by the Customer within twenty (20) days of receipt. 
All payments shall be made in immediately available funds payable to 
the Independent Transmission Provider, or by wire transfer to a bank 
named by the Independent Transmission Provider.
    5.2  Interest on Unpaid Balances: Interest on any unpaid amounts 
(including amounts placed in escrow) shall be calculated in 
accordance with the methodology specified for interest on refunds in 
the Commission's regulations at 18 CFR Sec. 35.19a(a)(2)(iii). 
Interest on delinquent amounts shall be calculated from the due date 
of the bill to the date of payment. When payments are made by mail, 
bills shall be considered as having been paid on the date of receipt 
by the Independent Transmission Provider.
    5.3  Customer Default: In the event the Customer fails, for any 
reason other than a billing dispute as described below, to make 
payment to the Independent Transmission Provider on or before the 
due date as described above, and such failure of payment is not 
corrected within thirty (30) calendar days after the Independent 
Transmission Provider notifies the Customer to cure such failure, a 
default by the Customer shall be deemed to exist. Upon the 
occurrence of a default, the Independent Transmission Provider may 
initiate a proceeding with the Commission to terminate service but 
shall not terminate service until the Commission so approves any 
such request. In the event of a billing dispute between the 
Independent Transmission Provider and the Customer, the Independent 
Transmission Provider will

[[Page 55540]]

continue to provide service under the Service Agreement as long as 
the Customer (i) continues to make all payments not in dispute, and 
(ii) pays into an independent escrow account the portion of the 
invoice in dispute, pending resolution of such dispute. If the 
Customer fails to meet these two requirements for continuation of 
service, then the Independent Transmission Provider may provide 
notice to the Customer of its intention to suspend service in sixty 
(60) days, in accordance with Commission policy.

6. Regulatory Filings

    Nothing contained in the Tariff or any Service Agreement shall 
be construed as affecting in any way the right of the jurisdictional 
Independent Transmission Provider to unilaterally make application 
to the Commission for a change in rates, terms and conditions, 
charges, classification of service, Service Agreement, rule or 
regulation under Section 205 of the Federal Power Act and pursuant 
to the Commission's rules and regulations promulgated thereunder.
    Nothing contained in the Tariff or any Service Agreement shall 
be construed as affecting in any way the ability of any Party 
receiving service under the Tariff to exercise its rights under the 
Federal Power Act and pursuant to the Commission's rules and 
regulations promulgated thereunder.

7. Force Majeure and Indemnification

    7.1  Force Majeure: An event of Force Majeure means any act of 
God, labor disturbance, act of the public enemy, war, insurrection, 
riot, fire, storm or flood, explosion, breakage or accident to 
machinery or equipment, any Curtailment, order, regulation or 
restriction imposed by governmental military or lawfully established 
civilian authorities, or any other cause beyond a Party's control. A 
Force Majeure event does not include an act of negligence or 
intentional wrongdoing. Neither the Independent Transmission 
Provider nor the Customer will be considered in default as to any 
obligation under this Tariff if prevented from fulfilling the 
obligation due to an event of Force Majeure. However, a Party whose 
performance under this Tariff is hindered by an event of Force 
Majeure shall make all reasonable efforts to perform its obligations 
under this Tariff.
    7.2  Indemnification: The Customer shall at all times indemnify, 
defend, and save the Independent Transmission Provider harmless 
from, any and all damages, losses, claims, including claims and 
actions relating to injury to or death of any person or damage to 
property, demands, suits, recoveries, costs and expenses, court 
costs, attorney fees, and all other obligations by or to third 
parties, arising out of or resulting from the Independent 
Transmission Provider's performance of its obligations under this 
Tariff on behalf of the Customer, except in cases of negligence or 
intentional wrongdoing by the Independent Transmission Provider.

8. Creditworthiness

    For the purpose of determining the ability of the Customer to 
meet its obligations related to service hereunder, the Independent 
Transmission Provider may require reasonable credit review 
procedures. This review shall be made in accordance with standard 
commercial practices. In addition, the Independent Transmission 
Provider may require the Customer to provide and maintain in effect 
during the term of the Service Agreement, an unconditional and 
irrevocable letter of credit as security to meet its 
responsibilities and obligations under the Tariff, or an alternative 
form of security proposed by the Customer and acceptable to the 
Independent Transmission Provider and consistent with commercial 
practices established by the Uniform Commercial Code that protects 
the Independent Transmission Provider against the risk of non-
payment.

9. Eligibility for Independent Transmission Provider Services

    In order to purchase Network Access Service, purchase or supply 
Energy, or to supply Ancillary Services in the Independent 
Transmission Provider Administered Markets, Customers must satisfy 
the requirements of this Article.
    9.1  Requirements for Network Access Service: A Customer 
eligible for Network Access Service is: (i) any electric utility 
(including the Load-Serving Entity or any power marketer), Federal 
power marketing agency, or any person generating Energy for sale is 
eligible to be a Customer for Network Access Service under the 
Tariff. Energy sold or produced by such entity may be Energy 
produced in the United States, Canada or Mexico. However, with 
respect to transmission service that the Commission is prohibited 
from ordering by Section 212(h) of the Federal Power Act, such 
entity is eligible only if the service is provided pursuant to a 
state requirement that the Independent Transmission Provider offer 
the unbundled transmission service, or pursuant to a voluntary offer 
of such service by the Independent Transmission Provider. (ii) Any 
retail Customer taking unbundled transmission service pursuant to a 
state requirement that the Independent Transmission Provider offer 
the transmission service, or pursuant to a voluntary offer of such 
service by the Independent Transmission Provider, is eligible to be 
a Customer under the Tariff.
    9.2  Requirements for Market Services: The Independent 
Transmission Provider and each market participant shall execute a 
Service Agreement for Market Services which sets forth the terms and 
conditions under which a market participant shall either supply or 
purchase market services, consistent with the Form of Service 
Agreement for Market Services in Part VII.
    9.3  Participating Generator Agreements: The Independent 
Transmission Provider and the owners of each Generator shall enter 
into a Participating Generator Agreement which shall be filed with 
the Commission. Each Participating Generator Agreement shall set 
forth the operating terms, conditions, and obligations concerning 
the dispatch of a generating unit.
    9.4  Requirements Common to All Customers: Completed Application 
and Minimum Technical Requirements
    A Customer shall submit a Completed Application and shall 
receive Independent Transmission Provider approval prior to 
obtaining any services under the Independent Transmission Provider's 
Tariff. A Customer also shall demonstrate to the Independent 
Transmission Provider's reasonable satisfaction that it is capable 
of performing all functions required by the Independent Transmission 
Provider's Tariff including operational, financial and settlement 
requirements.
    9.4.1  Application: Each Customer requesting to schedule, take 
or provide any services under the Tariff must apply to the 
Independent Transmission Provider in writing at least sixty (60) 
days in advance of the month in which service is to commence. The 
Independent Transmission Provider will consider requests for such 
services on shorter notice when feasible. Service commencement will 
depend on the Independent Transmission Provider's ability to 
accommodate the request. To apply, the Customer shall complete and 
deliver a Service Agreement (in the form of Part VII) and an 
Application to the Independent Transmission Provider.
    9.4.2  Completed Application: A Completed Application shall 
provide all of the information reasonably required by the 
Independent Transmission Provider to permit the Independent 
Transmission Provider to perform its responsibilities under the 
Independent Transmission Provider's Tariff. A Customer taking or 
providing service under the Tariff shall provide the Independent 
Transmission Provider, upon application for service, with a list 
identifying its parent company as well as any affiliate. The 
Customer shall notify the Independent Transmission Provider within 
30 days of the effective date of any change to the original list. 
Any Customer shall notify the Independent Transmission Provider 
within 30 days of the effective date of any change to the original 
list. Any Customer shall respond within 10 days to a request by the 
Independent Transmission Provider to update the list of affiliates 
and/or parent company. The Independent Transmission Provider shall 
treat the information provided in the Application as Confidential 
Information except to the extent that disclosure of the information 
is required by the Independent Transmission Provider's Tariff, by 
regulatory or judicial order or for reliability purposes pursuant to 
Good Utility Practice.
    9.4.3  Approval of Application and/or Notice of Deficient 
Application:
    The Independent Transmission Provider will promptly review the 
Application and may request additional information to determine 
whether the applicant meets the Independent Transmission Provider's 
minimum financial and technical requirements. The Independent 
Transmission Provider will notify the applicant within thirty (30) 
days of receipt of a Completed Application.
    If the Independent Transmission Provider rejects an Application, 
the Independent Transmission Provider shall provide a written 
explanation within fourteen (14) days of the rejection. The 
Independent Transmission Provider will attempt to remedy minor 
deficiencies in the Application through informal communications with 
the

[[Page 55541]]

applicant. If such efforts are unsuccessful, the Independent 
Transmission Provider shall return the Application.

10. Dispute Resolution Procedures

    10.1  Internal Dispute Resolution Procedures: Any dispute 
between a Customer and the Independent Transmission Provider 
involving transmission or Market Services under the Tariff 
(excluding applications for rate changes or other changes to the 
Tariff, or to any Service Agreement entered into under the Tariff, 
which shall be presented directly to the Commission for resolution) 
shall be referred to a designated senior representative of the 
Independent Transmission Provider and a senior representative of the 
Customer for resolution on an informal basis as promptly as 
practicable. In the event the designated representatives are unable 
to resolve the dispute within thirty (30) days [or such other period 
as the Parties may agree upon] by mutual agreement, such dispute may 
be submitted to arbitration and resolved in accordance with the 
arbitration procedures set forth below.
    10.2  External Arbitration Procedures: Any arbitration initiated 
under the Tariff shall be conducted before a single neutral 
arbitrator appointed by the Parties. If the Parties fail to agree 
upon a single arbitrator within ten (10) days of the referral of the 
dispute to arbitration, each Party shall choose one arbitrator who 
shall sit on a three-member arbitration panel. The two arbitrators 
so chosen shall within twenty (20) days select a third arbitrator to 
chair the arbitration panel. In either case, the arbitrators shall 
be knowledgeable in electric utility matters, including electric 
transmission and bulk power issues, and shall not have any current 
or past substantial business or financial relationships with any 
party to the arbitration (except prior arbitration). The 
arbitrator(s) shall provide each of the Parties an opportunity to be 
heard and, except as otherwise provided herein, shall generally 
conduct the arbitration in accordance with the Commercial 
Arbitration Rules of the American Arbitration Association and any 
applicable Commission regulations or Regional Transmission Group 
rules.
    10.3  Arbitration Decisions: Unless otherwise agreed, the 
arbitrator(s) shall render a decision within ninety (90) days of 
appointment and shall notify the Parties in writing of such decision 
and the reasons therefor. The arbitrator(s) shall be authorized only 
to interpret and apply the provisions of the Tariff and any Service 
Agreement entered into under the Tariff and shall have no power to 
modify or change any of the above in any manner. The decision of the 
arbitrator(s) shall be final and binding upon the Parties, and 
judgment on the award may be entered in any court having 
jurisdiction. The decision of the arbitrator(s) may be appealed 
solely on the grounds that the conduct of the arbitrator(s), or the 
decision itself, violated the standards set forth in the Federal 
Arbitration Act and/or the Administrative Dispute Resolution Act. 
The final decision of the arbitrator must also be filed with the 
Commission if it affects jurisdictional rates, terms and conditions 
of service or facilities.
    10.4  Costs: Each Party shall be responsible for its own costs 
incurred during the arbitration process and for the following costs, 
if applicable:
    (A) the cost of the arbitrator chosen by the Party to sit on the 
three member panel and one half of the cost of the third arbitrator 
chosen; or
    (B) one half the cost of the single arbitrator jointly chosen by 
the Parties.
    10.5  Rights Under the Federal Power Act: Nothing in this 
section shall restrict the rights of any party to file a Complaint 
with the Commission under relevant provisions of the Federal Power 
Act.

11. Metering

    11.1  Customer Requirements: The Independent Transmission 
Provider shall establish metering specifications and standards for 
all metering that is used as a data source by the Independent 
Transmission Provider. Customers shall install and maintain such 
metering at their own expense and deliver data to the Independent 
Transmission Provider without charge. A Customer taking service 
under the Independent Transmission Provider's Tariff will make 
available to the Independent Transmission Provider metered data that 
meets Independent Transmission Provider requirements by one of the 
following means: (i) Direct transmission to the Independent 
Transmission Provider; (ii) direct transmission to the Independent 
Transmission Provider through Transmission Owner communications 
equipment, or (iii) indirectly through metering provided by the 
Transmission Owner within whose area its Load is located. The 
Customer also shall provide its metered data to the Transmission 
Owner within whose area its Load is located, to the extent that the 
Transmission Owner determines that the metered data provided to the 
Independent Transmission Provider is required for its system 
operation and planning functions, for the billing of services it 
provides to the Customer, or to perform calculations required by the 
Independent Transmission Provider.
    11.2  Load-Serving Entities: Any Load that is not directly 
metered, as described above, will have its Load determined by the 
Transmission Owner within whose area its Load is located in 
accordance with the Transmission Owner's Retail Access plan on file 
with the (state commission) or otherwise authorized.
    11.3  Ancillary Service Suppliers: Suppliers shall ensure that 
adequate metering data is made available to the Independent 
Transmission Provider as described above.
    11.4  Third Party Metering Services: Customers whose metering 
services are provided by third parties qualified under rules, 
regulations and procedures of applicable state regulatory 
authorities shall be responsible to ensure that all data described 
in this Section are satisfactorily made available to the Independent 
Transmission Provider and applicable Transmission Owner(s) by those 
third parties.
    11.5  Estimation of Metering: In the event of a meter 
malfunction or inadequate metering data, the Independent 
Transmission Provider may use estimates to determine Customer's 
rights and responsibilities under the Independent Transmission 
Provider's Tariff.

12. Data and Confidentiality Provisions

    12.1  Access to Complete and Accurate Data: Customers under the 
Tariff shall provide to the Independent Transmission Provider such 
information and data as the Independent Transmission Provider 
reasonably deems necessary in order to perform its functions and 
fulfill its responsibilities under the Tariff and in accordance with 
the Independent Transmission Provider Market Monitoring Program. 
Such information will be provided on a timely basis and in the 
formats prescribed in the Independent Transmission Provider 
Procedures.
    12.2  Independent Transmission Provider Procedures: The 
Independent Transmission Provider shall develop, and modify as 
appropriate, procedures for the efficient and non-discriminatory 
operation of the Independent Transmission Provider Administered 
Markets and for the safe and reliable operation of the Independent 
Transmission Provider's Service Area in accordance with the terms 
and conditions of the Tariff. All such procedures must be consistent 
with Good Utility Practice. Whenever requested by the Independent 
Transmission Provider, each Load-Serving Entity shall provide the 
Independent Transmission Provider with a forecast of the Loads for 
which it is responsible for the particular time period designated by 
the Independent Transmission Provider. Customers shall inform the 
Independent Transmission Provider of the Availability of Generators 
within the Independent Transmission Provider Service Area subject to 
a Customer's control by Energy contract, ownership or otherwise. 
Additionally, the Transmission Owners will provide megawatt, 
megavar, voltage readings, Transmission System data (facility 
ratings and impedance data), and maintenance schedules for all 
Transmission Facilities under the Independent Transmission 
Provider's Operational Control. For Transmission Facilities 
Requiring Independent Transmission Provider Notification, the 
Transmission Owners shall inform the Independent Transmission 
Provider of all changes in the status of the designated transmission 
facilities. Suppliers will provide data on Generator status and 
output including maintenance schedules, Generator scheduled return 
dates (inclusive of return to service from maintenance, forced 
outages or partial unit outages that resulted in a significant 
reduction in a generating unit's ability to produce Energy in any 
hour), and Generator machine data. These data shall also include 
Generator Incremental/Decremental Bids, operating limits, response 
rates, megawatt, megavar, and voltage readings.
    12.3  Access to Confidential Information: The Independent 
Transmission Provider may request, and the Customer shall provide, 
Confidential Information consistent with the disclosure requirements 
set forth in the Independent Transmission Provider's Tariff. The 
Independent Transmission Provider

[[Page 55542]]

shall prevent the disclosure of Confidential Information and shall 
not publish, disclose or otherwise divulge Confidential Information 
to any person or entity without the prior written consent of the 
party supplying such Confidential Information, except as provided 
for under the Independent Transmission Provider Market Power 
Monitoring Plan. The provisions of this Section shall not apply to 
any Confidential Information: (i) Which was in the public domain at 
the time of disclosure hereunder; (ii) which thereafter passes into 
the public domain by acts other than the acts of the Independent 
Transmission Provider; (iii) that the Independent Transmission 
Provider is required to make publicly available by the Commission, 
the (state commission) or other legal process, or for reliability 
purposes pursuant to Good Utility Practice; or (iv) information 
required to be provided to the Commission, which will be protected 
under the Commission's rules for non-public material. A Customer may 
request that the Independent Transmission Provider keep confidential 
from another entity Confidential Information that the other entity 
does not require to perform its obligations and duties hereunder. 
The Customer must state in writing that the information is to be 
treated as Confidential Information and the reasons for treating it 
as Confidential Information, otherwise information will be treated 
as non-Confidential Information.
    12.4  Use of Confidential Information: The Independent 
Transmission Provider shall use Confidential Information for the 
exclusive purpose of performing its obligations hereunder and under 
any Service Agreement.
    12.5  Disclosure of Bid Information: Pursuant to Commission 
requirements, the Independent Transmission Provider shall make 
public Bid information from the Energy, Ancillary Services, and 
Transmission markets (but not the names of the Bidders making these 
Bids) three months after the Bids are submitted. The Independent 
Transmission Provider shall post the data in a way that permits 
third parties to track each individual Bidder's Bids over time. 
Prior to such disclosure, Bid information submitted to the 
Independent Transmission Provider by Market Participants shall be 
considered Confidential Information.
    12.6  Survival: This section 12 will survive the termination of 
the Independent Transmission Provider's Tariff and any associated 
Service Agreement.

Part II. Transmission Services

B. Network Access Service

Preamble

    The Independent Transmission Provider will provide Network 
Access Service pursuant to the applicable terms and conditions 
contained in the Tariff and Service Agreement. Network Access 
Service allows all Customers to access all points (i.e., all Receipt 
Points and all Delivery Points on the Independent Transmission 
Provider's system) so that every Generator can reach every Load, 
subject to physical feasibility. Specifically, Network Access 
Service offers a flexible use of the transmission grid by allowing 
Customers to: (1) Serve Load with any Resource on the system, (2) 
access any Interface to import power from a neighboring system, (3) 
integrate, economically dispatch and regulate its current and 
planned Resources to serve its Load; (4) transmit power within, 
through, and out of the Independent Transmission Provider's system; 
and (5) aggregate Resources for resale and hub-to-hub transfer.

1. Nature of Network Access Service

    1.1  Scope of Service: Network Access Service allows all 
Customers to access all points (i.e., all Receipt Point and Delivery 
Points) on the Independent Transmission Provider's system so that 
every Customer can move power from any Generator to any Load, from 
any Generator to any Trading Hub, from one Trading Hub to another, 
or from a Trading Hub to a Load. Using Network Access Service, a 
Customer can integrate Resources and Load, transfer power through or 
out of the Independent Transmission Provider's system or deliver 
power between specified Receipt and Delivery Points. The embedded 
costs of the Transmission System will be recovered through an Access 
Charge. Any Congestion costs and loss costs associated with a 
transaction will be recovered through the applicable Transmission 
Usage Charge in which the Customer causing the Congestion and losses 
bears the full cost of its Transaction. To the extent the Customer 
is willing to pay the applicable Transmission Usage Charge for its 
requested Receipt Point-to-Delivery Point combinations(s), service 
will be available and will be provided to the extent physically and 
operationally feasible. The Customer must obtain or self-supply 
Ancillary Services pursuant to Part II.C of the Tariff.
    1.2  Independent Transmission Provider Responsibilities: The 
Independent Transmission Provider shall plan, construct, operate and 
maintain its Transmission System in accordance with Good Utility 
Practice in order to provide all Customers with Network Access 
Service over the Independent Transmission Provider's Transmission 
System. The Independent Transmission Provider shall endeavor to have 
constructed and placed into service sufficient transmission 
capability to deliver all Network Access Service Customers' 
Resources to serve Load. The Independent Transmission Provider will 
offer a mechanism for participants to identify long-term planning 
and expansion needs and to propose solutions (transmission, 
generation, or demand-side).
    1.3  Service at Points without Concurrent Congestion Revenue 
Rights: Once a Customer agrees to pay the applicable Access Charge, 
it may use the Independent Transmission Provider's Transmission 
System to deliver Energy to its Network Loads from Resources when 
the Customer does not have Congestion Revenue Rights between the 
requested Receipt and Delivery Points. Such Energy shall be 
transmitted subject to the Customer paying the applicable 
Transmission Usage Charge. A Customer may revise or add Receipt 
Points or Delivery Points without an additional Access Charge.

2. Initiating Service

    2.1  Condition Precedent for Receiving Service: A request for 
Network Access Service may be performed under an umbrella Service 
Agreement pursuant to Part VII of the Tariff. A request for Network 
Access Service must contain a written Application to: [the 
Independent Transmission Provider Name and Address], submitted at 
least sixty (60) days in advance of the calendar month in which 
service is to commence. The Independent Transmission Provider will 
consider requests for such service on shorter notice when feasible. 
Requests for Network Access Service for periods of less than one 
year shall be subject to expedited procedures that shall be 
negotiated between the Parties within the time constraints provided 
in Section B.2.8.
    2.2  Application Procedures: A Customer requesting Network 
Access Service must submit an Application, with a deposit 
approximating the charge for one month of service, to the 
Independent Transmission Provider as far as possible in advance of 
the month in which service is to commence. Applications should be 
submitted by entering the information listed below on the 
Independent Transmission Provider's OASIS, which will provide a 
time-stamped record for the Application.
    2.2.1  Applications That Do Not Require the Integration of 
Resources and Load: A Completed Application shall provide all of the 
information included in 18 CFR 2.20 including, but not limited to, 
the following:
    (i) The identity, address, telephone number and facsimile number 
of the party requesting service;
    (ii) A statement that the party requesting service meets, or 
will be upon commencement of service, will meet the eligibility 
requirement under Part I of this Tariff;
    (iii) The location of the specific Receipt Points and Delivery 
Points and the identities of the Delivering Parties and the 
Receiving Parties;
    (iv) The location of the generating facility(ies) supplying the 
capacity and Energy and the location of the Load ultimately served 
by the capacity and Energy transmitted. The Independent Transmission 
Provider shall treat this information as confidential except to the 
extent that disclosure of this information is required by this 
Tariff, by regulatory or judicial order, for reliability purposes 
pursuant to Good Utility Practice or pursuant to transmission 
information sharing agreements. The Independent Transmission 
Provider shall treat this information consistent with the standards 
of conduct contained in Part 37 of the Commission's regulations;
    (v) A description of the supply characteristics of the capacity 
and Energy to be delivered; an estimate of the capacity and Energy 
expected to be delivered to the Receiving Party; and the 
transmission transfer capability requested for each Receipt Point 
and Delivery Point on the Independent Transmission Provider's 
Transmission System; Customers may combine their requests for 
service in order to satisfy the minimum transmission capability 
requirement; and
    (vi) Service Commencement Date and the term of the requested 
Network Access Service: The minimum term for Network Access Service 
is one hour.

[[Page 55543]]

    2.2.2  Applications That Require the Integration of Resources 
and Load: A Completed Application shall provide all of the 
information included in 18 CFR 2.20 including, but not limited to, 
the following:
    (i) The identity, address, telephone number and facsimile number 
of the party requesting service;
    (ii) A statement that the party requesting service meets, or 
upon commencement of service will meet, the eligibility requirement 
under Part I of this Tariff;
    (iii) A description of the Load at each Delivery Point. This 
description must separately identify and provide the Customer's best 
estimate of the total Loads to be served at each transmission 
voltage level, and the Loads to be served from each Independent 
Transmission Provider substation at the same transmission voltage 
level. The description must include a ten (10) year forecast of 
service for summer and winter Load and Resource requirements 
beginning with the first year after the service is scheduled to 
commence and extending for the duration of the service request;
    (iv) The amount and location of any demand responsive Loads 
included in the Network Load. This shall include the summer and 
winter capacity requirements for each demand responsive Load, that 
portion of the Load subject to demand response, the conditions under 
which a response can be implemented and any limitations on the 
amount and frequency of demand response. Customer should identify 
the amount of demand responsive Load (if any) included in the ten 
(10) year Load forecast provided in response to (iii) above.
    (v) A description of Network Resources (current and term of 
request projection), which shall include, for each Network Resource:

--Unit size and amount of capacity from that unit to be designated 
as Network Resource
--VAR capability (both leading and lagging) of all Generators
--Operating restrictions
--Any periods of restricted operations throughout the year
    --Maintenance schedules
    --Minimum loading level of unit
    --Normal operating level of unit
--Any must-run unit designations required for system reliability or 
contract reasons
--Approximate variable generating cost ($/MWh) for redispatch 
computations
--Arrangements governing sale and delivery of power to third parties 
from generating facilities located in the Independent Transmission 
Provider's Service Area, where only a portion of unit output is 
designated as a Network Resource
--Description of purchased power designated as a Network Resource 
including source of supply, Control Area location, transmission 
arrangements and Delivery Point(s) to the Independent Transmission 
Provider's Transmission System;
    (vi) A description of Customer's Transmission System, if 
applicable:

--Load flow and stability data, such as real and reactive parts of 
the Load, lines, transformers, reactive devices and Load type, 
including normal and Emergency ratings of all transmission equipment 
in a Load flow format compatible with that used by the Independent 
Transmission Provider
--Operating restrictions needed for reliability
--Operating guides employed by system operators
--Contractual restrictions or committed uses of the Customer's 
Transmission System, other than the Customer's Network Loads and 
Resources
--Location of Network Resources described in subsection (v) above
--Ten (10) year projection of system expansions or upgrades
--Transmission System maps that include any proposed expansions or 
upgrades; and
    (vii) Service Commencement Date and the term of the requested 
Network Access Service: The minimum term for Network Access Service 
is one hour.
    The Independent Transmission Provider shall acknowledge the 
Completed Application within ten (10) days of receipt. The 
acknowledgment must include a date by which a response, including a 
Service Agreement, will be sent to the Customer. If an Application 
fails to meet the requirements of this section, the Independent 
Transmission Provider shall notify the Customer filing the 
Application requesting service or Congestion Revenue Rights within 
fifteen (15) days of receipt and specify the reasons for such 
failure. Wherever possible, the Independent Transmission Provider 
shall attempt to remedy deficiencies in the Application through 
informal communications with the Customer. If such efforts are 
unsuccessful, the Independent Transmission Provider shall return the 
Application without prejudice to the Customer filing a new or 
revised Application that fully complies with the requirements of 
this section. The Customer will be assigned a new priority 
consistent with the date of the new or revised Application. The 
Independent Transmission Provider shall treat this information 
consistent with the standards of conduct contained in Part 37 of the 
Commission's regulations.
    2.3  Technical Arrangements to be Completed Prior to 
Commencement of Service: Network Access Service shall not commence 
until the Independent Transmission Provider and the Customer, or a 
third party, have completed installation of all equipment specified 
under the Network Operating Agreement consistent with Good Utility 
Practice and any additional requirements reasonably and consistently 
imposed to ensure the reliable operation of the Transmission System. 
The Independent Transmission Provider shall exercise reasonable 
efforts, in coordination with the Customer, to complete such 
arrangements as soon as practicable taking into consideration the 
Service Commencement Date.
    2.4  Customer Facilities: To the extent Customer owns 
transmission facilities, the provision of Network Access Service 
shall be conditioned upon the Customer's constructing, maintaining 
and operating the facilities on its side of each Delivery Point or 
interconnection necessary to reliably deliver capacity and Energy 
from the Independent Transmission Provider's Transmission System to 
the Customer. The Customer shall be solely responsible for 
constructing or installing all facilities on the Customer's side of 
each such Delivery Point or interconnection.
    2.5  Filing of Service Agreement: The Independent Transmission 
Provider must file Service Agreements or related agreements with the 
Commission to the extent required by applicable Commission 
regulations.
    2.6  Notice of Deficient Application: If an Application fails to 
meet the requirements of the Tariff, the Independent Transmission 
Provider shall notify the entity requesting service within fifteen 
(15) days of receipt of the reasons for such failure. The 
Independent Transmission Provider shall attempt to remedy minor 
deficiencies in the Application through informal communications with 
the Customer. If such efforts are unsuccessful, the Independent 
Transmission Provider shall return the Application, along with any 
deposit, with interest. Upon receipt of a new or revised Application 
that fully complies with the requirements of the Tariff, the 
Customer shall be assigned a new priority consistent with the date 
of the new or revised Application.
    2.7  Response to a Completed Application: Following receipt of a 
Completed Application for Network Access Service, the Independent 
Transmission Provider shall make a determination of physical 
feasibility as required in Section B.5.2. The Independent 
Transmission Provider shall notify the Customer as soon as 
practicable, but not later than thirty (30) days after the date of 
receipt of a Completed Application, either (i) if it will be able to 
offer Network Access Service without performing a System Impact 
Study or (ii) if such a study is needed to evaluate the impact of 
the Application pursuant to Section B.5.3. Responses by the 
Independent Transmission Provider must be made as soon as 
practicable to all Completed Applications and the timing of such 
responses must be made on a non-discriminatory basis.
    2.8  Execution of Service Agreement: Whenever the Independent 
Transmission Provider determines that a System Impact Study is not 
required and that the service can be provided, it shall notify the 
Customer as soon as practicable but no later than thirty (30) days 
after receipt of the Completed Application. Where a System Impact 
Study is required, the provisions of Section B.2.5 will govern the 
execution of a Service Agreement. Failure of a Customer to execute 
and return the Service Agreement or request the filing of an 
unexecuted Service Agreement pursuant to Section B.2.9 within 
fifteen (15) days after it is tendered by the Independent 
Transmission Provider will be deemed a withdrawal and termination of 
the Application and any deposit submitted shall be refunded with 
interest. Nothing herein limits the right of a Customer to file 
another Application after such withdrawal and termination.
    2.9  Initiating Service in the Absence of an Executed Service 
Agreement: If the Independent Transmission Provider and the Customer 
requesting Network Access Service

[[Page 55544]]

cannot agree on all the terms and conditions of the Service 
Agreement, the Independent Transmission Provider shall file with the 
Commission, within thirty (30) days after the date the Customer 
provides written notification directing the Independent Transmission 
Provider to file, an unexecuted Network Access Service Agreement 
containing terms and conditions deemed appropriate by the 
Independent Transmission Provider for such requested Transmission 
Service. The Independent Transmission Provider shall commence 
providing Transmission Service subject to the Customer agreeing to 
(i) compensate the Independent Transmission Provider at whatever 
rate the Commission ultimately determines to be just and reasonable, 
and (ii) comply with the terms and conditions of this Tariff 
including posting appropriate security deposits in accordance with 
the terms of Section B.2.2.
    2.10  Scheduling of Network Access Service: Under Network Access 
Service, a Customer can schedule transmission service or procure 
Energy through the Day-Ahead and Real-Time Markets. The scheduling 
procedures for both options are contained in Part III of this 
Tariff.

3. Network Resources

    To the extent a Customer desires the Independent Transmission 
Provider to integrate, economically dispatch, and regulate the 
Customer's Resources to serve the Customer's Load, the Customer must 
designate Resources as described below. All other Customers will 
identify Receipt Points and Delivery Points through the Day-Ahead 
and Real-Time Markets pursuant to Part III of this Tariff.
    3.1  Designation of Network Resources: All Customers desiring 
the Independent Transmission Provider to integrate, economically 
dispatch, and regulate its Resources to serve its load must 
designate sufficient Network Resources to meets its Load on a non-
interruptible basis. Network Resources shall include all generation 
owned, purchased or leased by the Customer designated to serve 
Network Load under the Tariff. Network Resources may not include 
Resources, or any portion thereof, that are committed for sale to 
non-designated third-party Load or otherwise cannot be called upon 
to meet the Customer's Network Load on a non-interruptible basis. 
Any owned or purchased Resources that were serving the Customer's 
Loads under firm agreements entered into on or before the Service 
Commencement Date shall initially be designated as Network Resources 
until the Customer terminates the designation of such Resources.
    3.2  Designation of New Network Resources: The Customer may 
designate a new Resource by providing the Independent Transmission 
Provider with as much advance notice as practicable. A designation 
of a new Network Resource must be made by a request for modification 
of service pursuant to an Application under Section B.2.
    3.3  Designation of Alternate Resources: The Customer has the 
right to obtain alternate Resources, whether through a bilateral 
contract or through the Independent Transmission Provider-
Administered Markets. Alternate Resources enable the Customer to 
substitute one Resource for another, generally on a short-term 
basis. An alternate Resource does not have to be committed to the 
Customer on a firm basis as does a Network Resource.
    3.4  Substitution of Resources and Congestion Revenue Rights: 
The Customer may replace one designated Resource with another. The 
Customer may request a reconfiguration of the Congestion Revenue 
Rights it holds for the current Resource and request Congestion 
Revenue Rights for the new Resource pursuant to B.6 of the Tariff.
    3.5  Termination of Network Resources: The Customer may 
terminate the designation of all or part of a generating Resource as 
a Network Resource at any time, but must provide notification to the 
Independent Transmission Provider as soon as reasonably practicable.
    3.6  Customer Dispatch Obligation: As a condition to receiving 
Network Access Service, the Customer agrees to dispatch its Network 
Resources as requested by the Independent Transmission Provider, 
consistent with Part II of this Tariff. To the extent practicable, 
the redispatch of Resources pursuant to this section shall be on a 
least cost, non-discriminatory basis between all Customers.
    3.7  Transmission Arrangements for Network Resources Not 
Physically Interconnected with the Independent Transmission 
Provider: The Customer shall be responsible for any arrangements 
necessary to deliver capacity and Energy from a Network Resource not 
physically interconnected with the Independent Transmission 
Provider's Transmission System. The Independent Transmission 
Provider will undertake reasonable efforts to assist the Customer in 
obtaining such arrangements, including without limitation, providing 
any information or data required by such other entity pursuant to 
Good Utility Practice.
    3.8  Limitation on Designation of Network Resources: The 
Customer must demonstrate that it owns or has committed to purchase 
generation pursuant to an executed contract in order to designate a 
generating Resource as a Network Resource. Alternatively, the 
Customer may establish that execution of a contract is contingent 
upon the availability of transmission service under the Tariff.
    3.9  Customer Owned Transmission Facilities: The Customer that 
owns existing facilities that are determined by the Order No. 888 
seven factor test to be Transmission Facilities may be eligible to 
receive consideration either through a billing credit or some other 
mechanism.

4. Designation of Network Load

    To the extent a Customer desires the Independent Transmission 
Provider to integrate, economically dispatch, and regulate the 
Customer's Resources to serve the Customer's Load, the Customer must 
designate Loads as described below.
    4.1  Network Load: The Customer must designate the individual 
Network Loads on whose behalf the Independent Transmission Provider 
will provide Network Access Service. The Network Loads shall be 
specified in the Service Agreement and shall include actual 
deliveries at Interfaces.
    4.2  New Network Loads Connected with the Independent 
Transmission Provider: The Customer shall provide the Independent 
Transmission Provider with as much advance notice as reasonably 
practicable of the designation of new Network Load that will be 
added to its Transmission System. A designation of new Network Load 
must be made through a modification of service pursuant to a new 
Application. The Independent Transmission Provider will use due 
diligence to install any transmission facilities required to 
interconnect a new Network Load designated by the Customer. The 
costs of new facilities required to interconnect a new Network Load 
shall be determined in accordance with the procedures provided in 
Section B.5.12 and shall be charged to the Customer in accordance 
with Part VIII of this Tariff.
    4.3  New Interconnection Points: To the extent the Customer 
desires to add a new Delivery Point or interconnection point between 
the Independent Transmission Provider's Transmission System and a 
Network Load, the Customer shall provide the Independent 
Transmission Provider with as much advance notice as reasonably 
practicable.
    4.4  Changes in Service Requests: Under no circumstances shall 
the Customer's decision to cancel or delay a requested change in 
Network Access Service (e.g., the addition of a new Network Resource 
or designation of a new Network Load) in any way relieve the 
Customer of its obligation to pay the costs of transmission 
facilities constructed by the Independent Transmission Provider and 
charged to the Customer as reflected in the Service Agreement. 
However, the Independent Transmission Provider must treat any 
requested change in Network Access Service in a non-discriminatory 
manner.
    4.5  Annual Load and Resource Information Updates: The Customer 
shall provide the Independent Transmission Provider with annual 
updates of Network Load and Network Resource forecasts consistent 
with those included in its Application for Network Access Service 
under the Tariff. The Customer also shall provide the Independent 
Transmission Provider with timely written notice of material changes 
in any other information provided in its Application relating to the 
Customer's Network Load, Network Resources, Transmission System or 
other aspects of its facilities or operations affecting the 
Independent Transmission Provider's ability to provide reliable 
service.

5. Service Availability

    5.1  General Conditions: The Independent Transmission Provider 
shall provide Network Access Service over, on or across its 
Transmission System to any Customer that has met the requirements of 
Section A.9.
    5.2  Determination of Available Transfer Capability: A 
description of the Independent Transmission Provider's specific 
methodology for assessing Available Transfer Capability posted on 
the Independent Transmission Provider's OASIS is contained in 
Attachment A of the Tariff. In the event

[[Page 55545]]

sufficient transmission capability may not exist to accommodate a 
Congestion Revenue Rights request, the Independent Transmission 
Provider shall respond by performing a System Impact Study.
    5.3  Notice of Need for System Impact Study: After receiving a 
request for Congestion Revenue Rights or for the reconfiguration of 
Congestion Revenue Rights, the Independent Transmission Provider 
shall conduct, to the extent necessary, a System Impact Study. A 
description of the Independent Transmission Provider's methodology 
for completing a System Impact Study is provided in Attachment B. 
The Independent Transmission Provider shall within thirty (30) days 
of receipt of a Completed Application, tender a System Impact Study 
Agreement pursuant to which the Customer shall agree to reimburse 
the Independent Transmission Provider for performing the required 
System Impact Study. For a service request to remain a Completed 
Application, the Customer shall execute the System Impact Study 
Agreement and return it to the Independent Transmission Provider 
within fifteen (15) days. If the Customer elects not to execute the 
System Impact Study Agreement, its Application shall be deemed 
withdrawn and its deposit shall be returned with interest.

5.4  System Impact Study Agreement and Cost Reimbursement

    (i) The System Impact Study Agreement must clearly specify the 
Independent Transmission Provider's estimate of the actual cost and 
time for completion of the System Impact Study. The charge shall not 
exceed the actual cost of the study. In performing the System Impact 
Study, the Independent Transmission Provider shall rely, to the 
extent reasonably practicable, on existing transmission planning 
studies. The Customer will not be assessed a charge for such 
existing studies; however, the Customer will be responsible for 
charges associated with any modifications to existing planning 
studies that are reasonably necessary to evaluate the impact of the 
Customer's request for service on the Transmission System.
    (ii) If in response to multiple Customers requesting service in 
relation to the same competitive solicitation, a single System 
Impact Study is sufficient for the Independent Transmission Provider 
to accommodate the service requests, the costs of that study shall 
be prorated among the Customers.
    5.5  System Impact Study Procedures: Upon receipt of an executed 
System Impact Study, the Independent Transmission Provider shall use 
due diligence to complete the required System Impact Study within 
sixty (60) days. The System Impact Study shall identify any system 
constraints and dispatch options, additional Direct Assignment 
Facilities or Network Upgrades required to provide the requested 
service. In the event that the Independent Transmission Provider is 
unable to complete the required System Impact Study within such time 
period, it shall so notify the Customer and provide an estimated 
completion date along with an explanation of the reasons why 
additional time is required to complete the required studies. A copy 
of the completed System Impact Study and related work papers shall 
be made available to the Customer. The Independent Transmission 
Provider shall notify the Customer immediately upon completion of 
the System Impact Study if the Transmission System will be adequate 
to accommodate all or part of a request for service, all or part of 
a request for Congestion Revenue Rights reconfiguration, or if no 
costs are likely to be incurred for new transmission facilities or 
upgrades. In order for a request to remain a Completed Application, 
within fifteen (15) days of completion of the System Impact Study 
the Customer must execute a Service Agreement or request the filing 
of an unexecuted Service Agreement, or the Application shall be 
deemed terminated and withdrawn.
    5.6  Facilities Study Procedures: If a System Impact Study 
indicates that additions or upgrades to the Transmission System are 
needed to supply the Customer's service request, Congestion Revenue 
Rights Request, or Congestion Revenue Rights Reconfiguration 
request, the Independent Transmission Provider, within thirty (30) 
days of the completion of the System Impact Study, shall tender to 
the Customer a Facilities Study Agreement pursuant to which the 
Customer shall agree to reimburse the Independent Transmission 
Provider for performing the required Facilities Study. For a service 
request to remain a Completed Application, the Customer shall 
execute the Facilities Study Agreement and return it to the 
Independent Transmission Provider within fifteen (15) days. If the 
Customer elects not to execute the Facilities Study Agreement, its 
Application shall be deemed withdrawn and its deposit shall be 
returned with interest. Upon receipt of an executed Facilities Study 
Agreement, the Independent Transmission Provider will use due 
diligence to complete the required Facilities Study within sixty 
(60) days. If the Independent Transmission Provider is unable to 
complete the Facilities Study in the allotted time period, the 
Independent Transmission Provider shall notify the Customer and 
provide an estimate of the time needed to reach a final 
determination along with an explanation of the reasons that 
additional time is required to complete the study. When completed, 
the Facilities Study shall include a good faith estimate of (i) the 
cost of Direct Assignment Facilities to be charged to the Customer, 
(ii) the Customer's appropriate share of the cost of any required 
Network Upgrades, and (iii) the time required to complete such 
construction and initiate the requested service. The Customer shall 
provide the Independent Transmission Provider with a letter of 
credit or other reasonable form of security acceptable to the 
Independent Transmission Provider equivalent to the costs of new 
facilities or upgrades consistent with commercial practices as 
established by the Uniform Commercial Code. The Customer shall have 
thirty (30) days to execute a Service Agreement or request the 
filing of an unexecuted Service Agreement and provide the required 
letter of credit or other form of security or the request no longer 
will be a Completed Application and shall be deemed terminated and 
withdrawn.
    5.7  Facilities Study Modifications: Any change in design 
arising from an inability to site or construct facilities as 
proposed will require development of a revised good faith estimate. 
New good faith estimates also will be required in the event of new 
statutory or regulatory requirements that are effective before the 
completion of construction or other circumstances beyond the control 
of the Independent Transmission Provider that significantly affect 
the final cost of new facilities or upgrades to be charged to the 
Customer pursuant to the provisions of Part II of the Tariff.
    5.8  Due Diligence in Completing New Facilities: The Independent 
Transmission Provider shall use due diligence to add necessary 
facilities or upgrade its Transmission System within a reasonable 
time. The Independent Transmission Provider will not upgrade its 
existing or planned Transmission System in order to provide the 
requested Transmission Service or Congestion Revenue Rights if doing 
so would impair system reliability or otherwise impair or degrade 
existing service or Congestion Revenue Rights.
    5.9  Obligation to Provide Transmission Service that Requires 
Expansion or Modification of the Transmission System: If the 
Independent Transmission Provider determines that it cannot 
accommodate a request for service or Congestion Revenue Rights 
because of insufficient transmission capability on its Transmission 
System, the Independent Transmission Provider must use due diligence 
to expand or modify its Transmission System to provide the requested 
transmission service, provided the Customer agrees to compensate the 
Independent Transmission Provider for such costs pursuant to the 
terms of Section B.5.12. The Independent Transmission Provider will 
conform to Good Utility Practice in determining the need for new 
facilities and in the design and construction of such facilities. 
The obligation applies only to those facilities that the Independent 
Transmission Provider along with the Transmission Owner has the 
right to expand or modify.
    5.10  Partial Interim Service: If the Independent Transmission 
Provider determines that it will not have adequate transmission 
capability to satisfy the full amount of a Completed Application for 
service, the Independent Transmission Provider nonetheless shall be 
obligated to offer and provide the portion of the requested Network 
Access Service that can be accommodated without addition of any 
facilities and through redispatch. Partial service could be of an 
amount (MW) or duration. However, the Independent Transmission 
Provider shall not be obligated to provide the incremental amount of 
requested Transmission Service (or Congestion Revenue Rights) that 
requires the addition of facilities or upgrades to the Transmission 
System until such facilities or upgrades have been placed in 
service. To the extent the Customer disagrees with the Independent 
Transmission Provider's determination of insufficient Available 
Transfer Capability (or redispatch capability),

[[Page 55546]]

the Customer may request and the Independent Transmission Provider 
shall provide its workpapers and analysis.
    5.11  Expedited Procedures for New Facilities: In lieu of the 
procedures set forth above, the Customer shall have the option to 
expedite the process by requesting the Independent Transmission 
Provider to tender at one time, together with the results of 
required studies, an ``Expedited Service Agreement'' pursuant to 
which the Customer would agree to compensate the Independent 
Transmission Provider for all costs incurred pursuant to the terms 
of the Tariff. In order to exercise this option, the Customer shall 
request in writing an expedited Service Agreement covering all of 
the above-specified items within thirty (30) days of receiving the 
results of the System Impact Study identifying needed facility 
additions or upgrades or costs incurred in providing the requested 
service. While the Independent Transmission Provider agrees to 
provide the Customer with its best estimate of the new facility 
costs and other charges that may be incurred, such estimate shall 
not be binding and the Customer must agree in writing to compensate 
the Independent Transmission Provider for all costs incurred 
pursuant to the provisions of the Tariff. The Customer shall execute 
and return such an Expedited Service Agreement within fifteen (15) 
days of its receipt or the Customer's request for service will cease 
to be a Completed Application and will be deemed terminated and 
withdrawn.
    5.12  Compensation for New Facilities: Whenever a System Impact 
Study performed by the Independent Transmission Provider in 
connection with the provision of Network Access Service identifies 
the need for new facilities, the Customer shall be responsible for 
such costs to the extent consistent with Commission policy.

6. Procedures if The Independent Transmission Provider is Unable to 
Complete New Transmission Facilities for Transmission Service

    6.1  Delays in Construction of New Facilities: If any event 
occurs that will materially affect the time for completion of new 
facilities, or the ability to complete them, the Independent 
Transmission Provider shall promptly notify the Customer. In such 
circumstances, the Independent Transmission Provider shall within 
thirty (30) days of notifying the Customer of such delays, convene a 
technical meeting with the Customer to evaluate the alternatives 
available to the Customer. The Independent Transmission Provider 
also shall make available to the Customer studies and work papers 
related to the delay, including all information that is in the 
possession of the Independent Transmission Provider that is 
reasonably needed by the Customer to evaluate any alternatives.
    6.2  Alternatives to the Original Facility Additions: When the 
review process of Section B.5.5 determines that one or more 
alternatives exist to the originally planned construction project, 
the Independent Transmission Provider shall present such 
alternatives for consideration by the Customer. If, upon review of 
any alternatives, the Customer desires to maintain its Completed 
Application subject to construction of the alternative facilities, 
it may request the Independent Transmission Provider to submit a 
revised Service Agreement for Network Access Service and a request 
for associated Congestion Revenue Rights. If the alternative 
approach solely involves Network Access Service and the Customer is 
willing to pay any applicable Congestion Charges, the Independent 
Transmission Provider shall promptly tender a Service Agreement for 
Network Access Service providing for the service. In the event the 
Independent Transmission Provider concludes that no reasonable 
alternative exists and the Customer disagrees, the Customer may seek 
relief under the dispute resolution procedures pursuant to Section 
A.10 or it may refer the dispute to the Commission for resolution.
    6.3  Refund Obligation for Unfinished Facility Additions: If the 
Independent Transmission Provider and the Customer mutually agree 
that no other reasonable alternatives exist and the requested 
service cannot be provided out of existing capability under the 
conditions of Part II of the Tariff, the obligation to provide the 
requested Transmission Service shall terminate and any deposit made 
by the Customer shall be returned with interest pursuant to 
Commission regulations 35.19a(a)(2)(iii). However, the Customer 
shall be responsible for all prudently incurred costs by the 
Independent Transmission Provider through the time construction was 
suspended.

7. Provisions Relating to Transmission Construction and Services on the 
Systems of Other Utilities

    Part VI of this Tariff details Transmission Planning and 
Expansion.

8. Network Access Service Customer Responsibilities

    8.1  Conditions Required of Customers: Network Access Service 
shall be provided by the Independent Transmission Provider only if 
the following conditions are satisfied by the Customer:
    (i) The Customer has pending a Completed Application for 
service;
    (ii) The Customer has met the creditworthiness and eligibility 
criteria set forth in Sections A.8 and A.9;
    (iii) The Customer will have arrangements in place for any other 
transmission service necessary to effect the delivery from the 
generating source to the Independent Transmission Provider prior to 
the time service under Part II of the Tariff commences;
    (iv) The Customer has agreed to pay for any facilities 
constructed and chargeable to such Customer under Part II of the 
Tariff, whether or not the Customer takes service for the full term 
of its reservation; and
    (v) The Customer has executed a Network Access Service Agreement 
or has agreed to receive service pursuant to Section B.2.9.
    8.2  Customer Responsibility for Third-Party Arrangements: Any 
scheduling arrangements that may be required by other electric 
systems shall be the responsibility of the Customer requesting 
service. The Customer shall provide, unless waived by the 
Independent Transmission Provider, notification to the Independent 
Transmission Provider identifying such systems and authorizing them 
to schedule the capacity and Energy to be transmitted by the 
Independent Transmission Provider pursuant to Part II of the Tariff 
on behalf of the Receiving Party at the Point of Delivery or the 
Delivering Party at the Point of Receipt. However, the Independent 
Transmission Provider will undertake reasonable efforts to assist 
the Customer in making such arrangements, including without 
limitation, providing any information or data required by such other 
electric system pursuant to Good Utility Practice.

9. Load Shedding and Curtailments

    9.1  Procedures: Prior to the Service Commencement Date, the 
Independent Transmission Provider and the Customer shall establish 
Load Shedding and Curtailment procedures in accordance with this 
Tariff with the objective of responding to contingencies on the 
Transmission System. The Parties shall implement such programs 
during any period when the Independent Transmission Provider 
determines that a system contingency exists and such procedures are 
necessary to alleviate such contingency. [The Independent 
Transmission Provider shall notify all affected Customers and other 
market participants (e.g., suppliers) in a timely manner of any 
scheduled Curtailment.]
    9.2  Transmission Constraints: During any period when the 
Independent Transmission Provider determines that a transmission 
constraint exists on the Transmission System that cannot be handled 
through the LMP Congestion Management System, and such constraint 
may impair the reliability of the Independent Transmission 
Provider's system, the Independent Transmission Provider shall take 
whatever actions, consistent with Good Utility Practice, that are 
reasonably necessary to maintain the reliability of the Independent 
Transmission Provider's system. To the extent the Independent 
Transmission Provider determines that the reliability of the 
Transmission System can be maintained by redispatching resources, 
the Independent Transmission Provider shall initiate procedures to 
redispatch resources on the Independent Transmission Provider's 
Transmission System on a least-cost basis without regard to the 
ownership of such resources.
    9.3  Curtailments of Scheduled Deliveries: If a transmission 
constraint on the Independent Transmission Provider's Transmission 
System cannot be relieved through the implementation of least-cost 
redispatch procedures and the Independent Transmission Provider 
determines that it is necessary to Curtail scheduled deliveries, the 
Independent Transmission Provider shall, on a non-discriminatory 
basis, Curtail the transaction(s) that effectively relieve the 
constraint. To the extent operationally feasible, the Independent 
Transmission Provider shall curtail transactions in the following 
order. Parties who do not have Congestion Revenue Rights in adequate 
amounts for their Receipt Point-Delivery Point combinations, shall 
be curtailed first. All other transactions that have a material 
impact on the transmission constraint will be curtailed on a pro 
rata basis. [The

[[Page 55547]]

Independent Transmission Provider must develop procedures addressing 
non-discriminatory Curtailment of parallel flows involving more than 
one transmission system.]
    9.4  Load Shedding: To the extent that a system Contingency 
exists on the Independent Transmission Provider's Transmission 
System and the Independent Transmission Provider determines that it 
is necessary for the Independent Transmission Provider and the 
Customer to shed Load, the Customers shall be directed by the 
Independent Transmission Provider to shed Load on a non-
discriminatory basis to alleviate the Emergency/reliability 
contingencies.
    (i) The Independent Transmission Provider will act first, 
whenever feasible, to direct Customers who have not met their 
assigned share of Resource Adequacy Requirements, pursuant to 
Section I of this Tariff, to shed load, before requiring other 
Customers to shed load, up to the amount of the lesser of: (1) The 
Resource deficiency; or (2) the Customers' Day-Ahead Energy market 
schedules. Failure to comply with the Independent Transmission 
Provider's direction to shed load shall subject Customers to the 
penalty provisions of Section I.6.3.
    9.5  System Reliability: Notwithstanding any other provisions of 
this Tariff, the Independent Transmission Provider reserves the 
right, consistent with Good Utility Practice and on a not unduly 
discriminatory basis, to Curtail Network Access Service without 
liability on the Independent Transmission Provider's part for the 
purpose of making necessary adjustments to, changes in, or repairs 
on its lines, substations and facilities, and in cases where the 
continuance of Network Access Service would endanger persons or 
property. In the event of any adverse condition(s) or disturbance(s) 
on the Independent Transmission Provider's Transmission System or on 
any other system(s) directly or indirectly interconnected with the 
Independent Transmission Provider's Transmission System, the 
Independent Transmission Provider, consistent with Good Utility 
Practice, also may Curtail Network Access Service in order to (i) 
limit the extent or damage of the adverse condition(s) or 
disturbance(s), (ii) prevent damage to generating or transmission 
facilities, or (iii) expedite restoration of service. The 
Independent Transmission Provider will give the Customer as much 
advance notice as is practicable in the event of such Curtailment. 
[The Independent Transmission Provider shall specify the rate 
treatment and all related terms and conditions applicable in the 
event that the Customer fails to respond to established Load 
Shedding and Curtailment procedures. The Independent Transmission 
Provider can assess a penalty for failure to curtail after a 
reasonable period of time.]

10. Rates and Charges

    For any Direct Assignment Facilities, Ancillary Services, and 
applicable study costs, consistent with Commission policy, along 
with the following:
    10.1  Monthly Access Charge: The Customer that is a Load-Serving 
Entity shall pay a monthly Access Charge, which shall be determined 
by multiplying its Load Ratio Share times one twelfth (1/12) of the 
Independent Transmission Provider's Annual Transmission Revenue 
Requirement specified in Part VIII. The Access Charge applies only 
to deliveries to load on the Independent Transmission Provider's 
System. The Access Charge does not apply to any deliveries to hubs, 
wheel throughs, or Exports to neighboring transmission systems.
    10.2  Determination of Customer's Monthly Network Load: The 
Customer's monthly Load is its hourly Load coincident with the 
Independent Transmission Provider's Monthly Transmission System 
Peak.
    10.3  Transmission Usage Charges: The Customer shall pay a 
Transmission Usage Charge for the quantity in MWh scheduled for 
Transmission Service. The Transmission Usage Charge will recover 
applicable Congestion Charges and losses, consistent with Sections 
F.3.3 and G.4.3, as applicable.

11. Operating Arrangements

    11.1  Operation Under the Network Operating Agreement: The 
Customer shall plan, construct, operate and maintain its facilities 
in accordance with Good Utility Practice and in conformance with the 
Network Operating Agreement.
    11.2  Network Operating Agreement: The terms and conditions 
under which the Customer shall operate its facilities and the 
technical and operational matters associated with the implementation 
of Part II of the Tariff shall be specified in the Network Operating 
Agreement. The Network Operating Agreement shall provide for the 
Parties to (i) operate and maintain equipment necessary for 
integrating the Customer within the Independent Transmission 
Provider's Transmission System (including, but not limited to, 
remote terminal units, metering, communications equipment and 
relaying equipment), (ii) transfer data between the Independent 
Transmission Provider and the Customer (including, but not limited 
to, heat rates and operational characteristics of Resources, 
generation schedules for units outside the Independent Transmission 
Provider's Transmission System, interchange schedules, unit outputs 
for dispatch, voltage schedules, loss factors and other real time 
data), (iii) use software programs required for data links and 
constraint dispatching, (iv) exchange data on forecasted Loads and 
Resources necessary for long-term planning, and (v) address any 
other technical and operational considerations required for 
implementation of Part III of the Tariff, including scheduling 
protocols. The Network Operating Agreement will recognize that the 
Customer shall either (i) self-supply, contract for, or purchase 
from the Independent Transmission Provider all necessary Ancillary 
Services consistent with Good Utility Practice, which satisfies NERC 
and the [applicable regional reliability council] requirements. The 
Independent Transmission Provider shall not unreasonably refuse to 
accept contractual arrangements with another entity for Ancillary 
Services. The Network Operating Agreement is included under Part 
VII.
    11.3  Network Operating Committee: A Network Operating Committee 
(Committee) shall be established to coordinate operating criteria 
for the Parties' respective responsibilities under the Network 
Operating Agreement. Each Customer shall be entitled to have at 
least one representative on the Committee. The Committee shall meet 
from time to time as need requires, but no less than once each 
calendar year.

12. Reservation Priority for Existing Firm Service Customers

    12.1  Right of First Refusal: Prior to the effectiveness of a 
full auction mechanism for all Congestion Revenue Rights, Congestion 
Revenue Rights will be allocated to Customers with long-term firm 
contracts under which the Customer continues to pay the Access 
Charge. To ensure that these Customers are able to maintain that 
right until the time that Congestion Revenue Rights are auctioned, 
existing firm service Customers (wholesale requirements and 
transmission-only, with a contract term of one-year or more), have 
the right to continue to take Network Access Service and agreeing to 
pay the Access Charge when the existing contract expires, rolls over 
or is renewed. If at the end of the contract term, the Independent 
Transmission Provider's Transmission System cannot accommodate all 
of the requests for Congestion Revenue Rights, the existing firm 
service Customer must agree to accept a contract term at least equal 
to a competing request by any new Customer and to pay the Access 
Charge, as approved by the Commission, for such service. This 
priority for existing firm service Customers is an ongoing right 
that may be exercised at the end of all firm contract terms of one-
year or longer. This section will remain in effect until the 
Independent Transmission Provider places into effect an auction 
mechanism for allocating all Congestion Revenue Rights.
    12.2  Notice of Rollover: Consistent with requests for new 
service described in Section B.2.1 of the Tariff, a Customer must 
submit its request to exercise rollover rights no later than sixty 
(60) days prior to the date the current service agreement expires.

C. Ancillary Services

    Ancillary Services are needed with transmission service to 
maintain reliability within and among the Service Areas affected by 
the transmission service. The Independent Transmission Provider is 
required to provide, and the Customer is required to purchase, the 
following Ancillary Services (i) Scheduling, System Control and 
Dispatch Service, (ii) Reactive Supply and Voltage Control from 
Generation Sources Service; and (iii) Energy Imbalance Service.
    The Independent Transmission Provider is required to offer to 
provide the following Ancillary Services only to the Customer 
serving Load within the Independent Transmission Provider's Service 
Area (i) Regulation and Frequency Response Service, (ii) Operating 
Reserve-Spinning Reserve Service, and (iii) Operating Reserve-
Supplement Reserve Service. The Customer serving Load within the 
Independent

[[Page 55548]]

Transmission Provider's Service Area is required to acquire these 
Ancillary Services, whether from the Independent Transmission 
Provider or a market operated by the Independent Transmission 
Provider, from a third party, or by self-supply. The Customer may 
not decline the Independent Transmission Provider's offer of 
Ancillary Services unless it demonstrates that it has acquired the 
Ancillary Services from another source. The Customer must list in 
its Application which Ancillary Services it will purchase from the 
Independent Transmission Provider.
    The Independent Transmission Provider can fulfill its obligation 
to provide Ancillary Services by acting as the Customer's agent to 
secure these Ancillary Services from others or by operating a market 
for the services. The Customer may elect to (i) have the Independent 
Transmission Provider act as its agent and procure Regulation and 
Frequence Response Service and Operating Reserves through the 
markets in Part III or (ii) secure Regulation and Frequency Response 
Service and Operating Reserves from a third party or by self-supply 
when technically feasible.

1. Scheduling, System Control and Dispatch Service

    This service is required to schedule the purchase, sale and 
movement of power through, out of, within, or into the Independent 
Transmission Provider's Service Area. This service can be provided 
only by the Independent Transmission Provider. The Customer must 
purchase this service from the Independent Transmission Provider. 
The charges for Scheduling, System Control and Dispatch Service are 
set forth below.
    1.1  Billing Units and Calculation of Rates: The Independent 
Transmission Provider shall charge each Customer based on the 
product of:
    (i) the Scheduling, System Control and Dispatch Service charge 
rates; and
    (ii) the Customer's applicable billing units for the month, as 
follows: [Independent Transmission Provider to propose rate 
methodology.]

2. Reactive Supply and Voltage Control from Generation Sources Service

    In order to maintain transmission voltages on the Transmission 
System within acceptable limits, generation facilities under the 
control of the Independent Transmission Provider are operated to 
produce (or absorb) reactive power. Thus, Reactive Supply and 
Voltage Control from Generation Sources Service (``Voltage Support 
Service'') must be provided for each Transaction on the Transmission 
System. The amount of Voltage Support Service that must be supplied 
with respect to the Customer's Transaction will be determined based 
on the reactive power support necessary to maintain transmission 
voltages within limits that are generally accepted in the region and 
consistently adhered to by the Independent Transmission Provider. 
Voltage Support Service is to be provided directly by the 
Independent Transmission Provider. The methodologies that the 
Independent Transmission Provider will use to obtain Voltage Support 
Service and the associated charges for such service are set forth 
below. [To be provided by the Independent Transmission Provider.]

3. Regulation Service

    Regulation and Frequency Response Service is necessary to 
provide for the continuous balancing of Resources (generation and 
interchange) with Load in order to maintain scheduled 
Interconnection frequency. Regulation and Frequency Response Service 
is accomplished by committing on-line generation whose output is 
raised or lowered (predominantly through the use of automatic 
generating control equipment) as necessary to follow the moment-by-
moment changes in Load. The obligation to maintain this balance 
between Resources and Load lies with the Independent Transmission 
Provider. Each Load-Serving Entity must either purchase this service 
through the Independent Transmission Provider or make alternative 
comparable arrangements to satisfy its Regulation and Frequency 
Response Service obligation.
    The Independent Transmission Provider shall establish Day-Ahead 
and Real-Time Markets for Regulation to procure through the Day-
Ahead and Real-Time Markets that portion of Regulation Requirement 
not met through Self-Supply. The full Regulation Requirement shall 
be cleared through the Day-Ahead Market. The Real-Time Market will 
provide an alternate supply for Regulation Service during the 
Operating Day where (i) Suppliers scheduled in the Day-Ahead Market 
are inadequate; (ii) a scheduled Supplier is unable to provide 
Regulation Service (e.g., the Generator tripped); (iii) the demand 
for Regulation Service increases beyond the scheduled supply; or 
(iv) other adjustments to the supply or demand of Regulation can be 
efficiently made. The Independent Transmission Provider shall select 
Suppliers in the Real-Time Market, during the Operating Day, to 
provide Regulation Service for each hour in which an insufficient 
supply of Regulation Service exists or when a supplier Bidding in 
the Real-Time market can provide Regulation service at a lower cost 
than a supplier that has been scheduled in the Day-Ahead Market.
    The Market Rules for the Day-Ahead Market for Regulation are set 
forth in Section F.4. The Market Rules for the Real-Time Market for 
Regulation are set forth in Section G.4.

4. Energy Imbalance Service

    Energy Imbalance Service is provided when a difference occurs 
between the scheduled and the actual delivery of Energy to a Load 
located within the Independent Transmission Provider's Service Area. 
This service will be provided through the Real-Time Energy Market 
operated by the Independent Transmission Provider. The procedures 
that will be used are described in Part III below.

5. Operating Reserves

    The Independent Transmission Provider shall provide procedures 
to establish adequate Operating Reserves that comply with applicable 
Reliability Rules. Operating Reserves are classified as follows:
    (i) Spinning Reserve: Operating Reserves provided by Resources 
(Generation and Demand) located within the Independent Transmission 
Provider Service Area that are already synchronized to the Power 
System and can respond to instructions to change output level within 
ten (10) minutes;
    (ii) Supplemental Reserve: Operating Reserves provided by 
Resources (Generation and Demand) that can respond to instructions 
to change output or consumption level within ten (10) minutes or 
some other specified time period.
    Operating Reserves can be ranked in terms of quality. Spinning 
Reserves are a higher quality reserve product than Supplemental 
Reserves. Supplemental Reserves that can respond to instructions on 
a shorter time frame (e.g., 10 minutes) than other Supplemental 
Reserves (e.g., 30-minutes) also have a higher quality ranking. The 
Independent Transmission Provider must substitute higher quality 
operating reserves for lower quality operating reserves when it is 
economical to do so.
    The Independent Transmission Provider shall establish Day-Ahead 
and Real-Time Markets for Operating Reserves. The full requirement 
for Operating Reserves shall be cleared through the Day-Ahead 
Market. The Real-Time Markets will provide an alternate supply for 
Operating Reserves during the Operating Day where (i) Suppliers 
scheduled in the Day-Ahead Market are inadequate; (ii) a scheduled 
Supplier is unable to provide Operating Reserves (e.g., the 
Generator tripped); (iii) the demand for Operating Reserves 
increases beyond the scheduled supply; or (iv) other adjustments to 
the supply or demand of operating reserves can be efficiently made. 
The Independent Transmission Provider shall select Suppliers in the 
Real-Time Market, during the Operating Day, to provide Operating 
Reserves for each hour in which an insufficient supply of Operating 
Reserves exists or when a supplier Bidding in the Real-Time market 
can provide Operating Reserves at lower costs than a supplier than 
has been scheduled in the Day-Ahead Market.
    The Market Rules for the Day-Ahead Markets for Operating 
Reserves are set forth in Sections F.5 and F.6. The Market Rules for 
the Real-Time Markets for Operating Reserves are set forth in 
Sections G.6 and G.7.

D. Congestion Revenue Rights

Preamble

    A Congestion Revenue Right is a right held by a Customer which 
provides the Customer with a hedge against uncertain future 
Congestion Charges by paying the holder of the right a stream of 
specified congestion revenues. This section details the specific 
types of Congestion Revenue Rights, the specific properties of 
Congestion Revenue Rights, and how Congestion Revenue Rights are 
acquired.

1. Types of Congestion Revenue Rights

    The Independent Transmission Provider shall make available, 
through the processes identified in Section D.3, Receipt Point-to-
Delivery Point Congestion Revenue Right Obligation as described 
below. In addition, upon request of Market Participants, the 
Independent Transmission Provider shall make available Receipt 
Point-to-Delivery

[[Page 55549]]

Congestion Revenue Right Options as well as Flowgate Congestion 
Revenue Rights, as soon as technically feasible.
    1.1  Receipt Point-to-Delivery Point Congestion Revenue Rights: 
A Receipt Point-to-Delivery Point right is specified by a Receipt 
Point and a Delivery Point, the total MW that are to be injected at 
the Receipt Point and withdrawn at the Delivery Point, whether the 
right is an Obligation or an Option, and the period of time for 
which the right is in effect.
    1.1.1  Obligation Rights: Receipt Point-to-Delivery Point 
Congestion Revenue Right Obligations confer to the holder (i) the 
right to collect revenues equal to the applicable Marginal 
Congestion Component of the hourly Transmission Usage Charge from 
the Receipt Point to the Delivery Point when the Marginal Congestion 
Component is positive, and (ii) the obligation to pay an amount to 
the Independent Transmission Provider equal to the absolute value of 
the applicable Marginal Congestion Component of the hourly 
Transmission Usage Charge from the Receipt Point to the Delivery 
Point when the Marginal Congestion Component is negative.
    1.1.2  Option Rights: Receipt Point-to-Delivery Point 
Transmission Option Rights confer to the holder the right to collect 
revenues equal to the applicable Congestion Charge component of the 
hourly Transmission Usage Charge from the Receipt Point to the 
Delivery Point when the Marginal Congestion Component is positive, 
but do not obligate the holder to pay the absolute value of the 
applicable Marginal Congestion Component of the hourly Transmission 
Usage Charge when the Marginal Congestion Component is negative.
    1.1.3  Types of Receipt Points and Delivery Points: The Receipt 
Points and Delivery Points specified in the Receipt Point-to 
Delivery Point Congestion Revenue Right can be a Generator bus, a 
load bus, an Interface between the Independent Transmission 
Provider's Service Area and an adjacent Service Area, or a pre-
defined set of buses (which can be either Zones or Hubs).

1.2  Flowgate Congestion Revenue Rights

    1.2.1  Definition of Flowgates and Flowgate Rights: A Flowgate 
is a transmission facility (such as a transmission line or a 
transformer or some other component of the electrical network) or 
group of facilities (e.g., an Interface) that constrains the power 
transfer capability of the network. A Flowgate Right is specified by 
a portion of the total MW capability over a particular transmission 
Flowgate in a specified direction. Flowgate Rights entitle the 
holder to collect Congestion revenues (as determined consistent with 
Section F.3.5.2) associated with the specified MW flow over the 
identified Flowgate in the specified direction in the Day-Ahead 
Market.

2. Term of Congestion Revenue Rights

    During the first two years of operation of the Independent 
Transmission Provider's Bid-based markets, the Independent 
Transmission Provider shall offer Congestion Revenue Rights for sale 
through the auction procedures in Section D.7 with terms of 1 year, 
6 months, and 1 month. Beginning in the third year of operation of 
the Independent Transmission Provider's Bid-based markets, the 
Independent Transmission Provider shall offer Congestion Revenue 
Rights with terms of 10 years, 5 years, 1 year, 6 months, and 1 
month. Upon request of Market Participants, the Independent 
Transmission Provider may also offer Congestion Revenue Rights for 
other terms. These term limitations will not apply to Congestion 
Revenue Rights acquired through the initial allocation procedures 
for implementation of Standard Market Design.

3. Scheduling Priority for Holders of Congestion Revenue Rights in the 
Event of Curtailment

    In any hour in which the Independent Transmission Provider is 
unable to accept all requested schedules for Transmission Service at 
the applicable Day-Ahead Transmission Usage Charges, holders of 
Receipt Point-to-Delivery Point Congestion Revenue Rights shall have 
scheduling priority from their designated Receipt Points to their 
designated Delivery Points over Customers that do not hold 
Congestion Revenue Rights. [The Independent Transmission Provider 
shall develop a method for determining how to implement such 
priority, which shall be inserted here.]

4. Existing Transmission Contracts

    Transmission Service pursuant to each Existing Transmission 
Contract shall be provided by the Independent Transmission Provider 
for the account of the Existing Transmission Contract Transmission 
Owner, acting as agent for the Existing Transmission Contract 
Customer. The Independent Transmission Provider shall assess to the 
Existing Transmission Contract Transmission Owner all charges and 
payments associated with providing Transmission Service pursuant to 
this Tariff. Consistent with the provisions of this Tariff, the 
Transmission Owner may acquire Congestion Revenue Rights to hedge 
against the Congestion costs associated with Transmission Service 
provided pursuant to its Existing Transmission Contracts.
    4.1  Conversion of Existing Transmission Contracts: Upon the 
mutual agreement of the parties to any Existing Transmission 
Contract, the Existing Transmission Contract Customer may terminate 
its Existing Transmission Contract in exchange for receiving 
Congestion Revenue Rights previously held by the Transmission Owner 
to support the Existing Transmission Contract described in Section 
D.3 with the same MW level of service and with the same Receipt 
Points and Delivery Points and termination date as specified in the 
Existing Transmission Contract.

5. Allocation of Congestion Revenue Rights

    5.1  Allocation of Congestion Revenue Rights: The aggregate set 
of Congestion Revenue Rights allocated to Customers shall not exceed 
an amount that is Simultaneously Feasible, as determined pursuant to 
Section D.5.8, in light of the total transmission capability in the 
Independent Transmission Provider's Service Area under normal 
operating conditions. In determining whether a set of Congestion 
Revenue Rights is Simultaneously Feasible, the Total Transfer 
Capability of the transmission system shall not be reduced by the 
transfer capability needed to support existing Customers.
    5.2  Requirement to Conduct Periodic Auctions for Congestion 
Revenue Rights. The Independent Transmission Provider shall conduct 
periodic auctions over its OASIS, consistent with Section D.5, that 
will provide Bid-based markets to buy and sell Congestion Revenue 
Rights for a variety of terms. Each auction shall provide for the 
opportunity to buy and sell Receipt Point-to-Delivery Point 
Congestion Revenue Right Obligations, as described in Section D.1. 
Upon the request of Market Participants, auctions shall provide for 
the opportunity to buy and sell Receipt Point-to-Delivery Point 
Transmission Option Rights and Flowgate Rights, as soon as it is 
technically feasible to do so.
    The periodic Congestion Revenue Rights auctions will also 
provide for the sale of Congestion Revenue Rights associated with 
transmission capability that becomes available after the initial 
allocation of Congestion Revenue Rights, for example, due to the 
expiration of initially allocated Congestion Revenue Rights.

[The Independent Transmission Provider shall file procedures which 
may have either an allocation of Congestion Revenue Rights or an 
allocation of auction revenues from the sale of Congestion Revenue 
Rights.]

6. Resale of Congestion Revenue Rights

    All holders of Congestion Revenue Rights may resell their 
Congestion Revenue Rights outside the auction held pursuant to 
Section D.3.2. However, the Independent Transmission Provider shall 
make all Settlements with Primary Holders. Buyers of resold 
Congestion Revenue Rights that elect to become Primary Holders must 
meet the eligibility criteria in Section A.9 of this Tariff.
    Sellers and potential buyers shall communicate all offers to 
sell and buy Congestion Revenue Rights, solely over the Independent 
Transmission Provider's OASIS.

7. Auctions for Congestion Revenue Rights

    The Independent Transmission Provider shall conduct periodic 
auctions to allow Market Participants to buy and sell Congestion 
Revenue Rights.
    7.1  General Description of the Auction Process: In each 
auction, Market Participants will have the opportunity to submit 
Bids to buy and sell Congestion Revenue Rights for a specified term. 
In each auction, the Independent Transmission Provider shall 
consider all Bids and shall select a combination of Bids that (i) is 
Simultaneously Feasible in light of the Transmission Capability that 
is expected to be available over the term of the transactions and 
(ii) maximizes the combined net economic value (as expressed in the 
Bids) of the selected Bids. In order to maximize the net economic 
value of the selected Bids, the auction shall allow for the 
reconfiguration of Congestion Revenue Rights. That is, the 
Congestion Revenue Rights that are offered for sale may be converted 
into Congestion Revenue Rights of a different type or with different 
Receipt and Delivery Points.
    7.2  Frequency of Congestion Revenue Rights Auction: The 
Independent

[[Page 55550]]

Transmission Provider shall conduct an Auction for Congestion 
Revenue Rights no less frequently that once in every calendar month.
    7.3  Responsibilities of the Independent Transmission Provider 
Prior to Each Auction
    7.3.1  Establish Auction Rules: The Independent Transmission 
Provider shall use the auction rules and procedures consistent with 
this Tariff. [Independent Transmission Provider may file to add 
additional auction rules.]
    7.3.2  Evaluate Creditworthiness: The Independent Transmission 
Provider shall evaluate each Bidder's ability to pay for Congestion 
Revenue Rights, consistent with the creditworthiness provisions of 
Section A.8. As a result of this evaluation, the Independent 
Transmission Provider shall state a limit before the auction on the 
value of the Congestion Revenue Rights that the entity may be 
awarded in the auction, and collect signed statements from each 
entity Bidding into the auction committing that entity to pay for 
any Congestion Revenue Rights that it is awarded in the auction. 
Bidders will not be permitted to submit Bids that exceed this 
allowable limit.
    7.3.3  Information to be Made Available to Bidders: To aid 
Market Participants in their participation in the auction, the 
Independent Transmission Provider shall make the following 
information available before each auction:
    (i) for each Generator bus, Load bus, external bus and Load Zone 
for each of the previous 5 years, if available, (a) the average 
Marginal Congestion Component of the LMP, relative to the Reference 
Bus, and (b) the average Marginal Losses Component of the LMP, 
relative to the Reference Bus;
    (ii) for each of the previous two 6-month periods, (a) 
historical flow histograms for each of the closed Interfaces, and 
(b) historically, the number of hours that the most limiting 
facilities were physically constrained;
    (iii)(a) Power Flow data to be used as the starting point for 
the auction, including all assumptions, (b) assumptions made by the 
Independent Transmission Provider relating to transmission 
maintenance outage schedules, (c) all limits associated with 
transmission facilities, contingencies, thermal, voltage and 
stability to be monitored as Constraints in the Optimum Power Flow 
determination, and (d) the Independent Transmission Provider summer 
and winter operating study results (non-simultaneous Interface 
Transfer Capabilities).
    7.3.4  Other Responsibilities: The Independent Transmission 
Provider will establish an auditable information system to 
facilitate analysis and acceptance or rejection of Bids, to provide 
a record of all Bids, and to provide all necessary assistance in the 
resolution of disputes that arise from questions regarding the 
acceptance, rejection, award and recording of Bids. The Independent 
Transmission Provider will establish a system to communicate 
auction-related information to all auction participants.
    The Independent Transmission Provider will receive Bids to buy 
Congestion Revenue Rights from any entity that meets the eligibility 
criteria established in this Tariff and will implement the auction 
Bidding rules previously established by the Independent Transmission 
Provider.
    The Independent Transmission Provider will properly utilize an 
Optimal Power Flow program to determine the set of winning Bids for 
each auction and calculate the Market Clearing Price of all 
Congestion Revenue Rights at the conclusion of the auction, in the 
manner described in this Tariff.

7.4  Responsibilities of each Buying Bidder

    7.4.1  Creditworthiness Information: Each Bidder must submit 
such information to the Independent Transmission Provider regarding 
the Bidder's creditworthiness as the Independent Transmission 
Provider may require consistent with Section A.8, along with a 
statement signed by the Bidder, representing that the Bidder is 
financially able and willing to pay for the Congestion Revenue 
Rights for which it is Bidding. The aggregate value of the Bids 
submitted by any Bidder into the auction shall not exceed that 
Bidder's ability to pay or the maximum value of Bids that Bidder is 
permitted to place, as determined by the Independent Transmission 
Provider (based on an analysis of that Bidder's creditworthiness).
    Each Bidder must pay the Market Clearing Price for each 
Congestion Revenue Right it is awarded in the auction.

7.5  Responsibilities of Each Selling Bidder

    7.5.1  Bids to Sell Congestion Revenue Rights: Each Market 
Participant desiring to sell Congestion Revenue Rights Shall include 
the following information in its Bid:
    (i) The type of Congestion Revenue Right (i.e., Receipt Point-
to-Delivery Point Congestion Revenue Right Obligation, Receipt 
Point-to-Delivery Point Transmission Option Right, or Flowgate 
Congestion Revenue Right).
    (ii) The Receipt and Delivery Points, if a Receipt Point-to-
Delivery Point Right is offered.
    (iii) The location and direction of the Flowgate, if a Flowgate 
Right is offered.
    (iv) The MWs
    (v) The minimum acceptable price, if any.
    (vi) The term.
    Each seller that offers Congestion Revenue Rights for sale that 
it has been awarded must provide verification of the award to the 
Independent Transmission Provider when the Bid is submitted.
    7.6  Selection of Winning Bids and Determination of the Market 
Clearing Price: The Independent Transmission Provider shall 
determine the winning set of Bids in each auction as the set of Bids 
that maximizes the value (as expressed in the Bids) of the 
Congestion Revenue Rights, subject to the constraint that the 
selected set of Bids must be simultaneously feasible consistent with 
Section D.5.8.
    The Market Clearing Price for each Congestion Revenue Right 
shall equal the change in the net economic value of all other 
Bidders that would result from awarding an additional 1 MW of that 
Congestion Revenue Right to a Market Participant.
    7.7  Auction Settlement: The Independent Transmission Provider 
will determine prices in the auction for feasible Congestion Revenue 
Rights, consistent with Section 6.6. Each Bidder awarded Congestion 
Revenue Rights in the auction shall pay the applicable Market 
Clearing Price for those Congestion Revenue Rights that is awarded 
in the auction. Similarly, each Congestion Revenue Right holder 
selling Congestion Revenue Rights through the Auction shall be paid 
the applicable Market Clearing Price for those Congestion Revenue 
Rights that are sold in the auction.
    7.8  Simultaneous Feasibility: The set of winning Bids selected 
in each auction shall be simultaneously feasible based on the 
Transfer Capability available for purchase within the Independent 
Transmission Provider's Service Area under normal operating 
conditions. A set of Bids shall be deemed simultaneously feasible if 
both of the following Conditions, A and B, are met:
    Condition A: Each set of injections and withdrawals associated 
with (i) winning, as well as outstanding previously-awarded, Receipt 
Point-to-Delivery Point Congestion Revenue Right Obligations along 
with (ii) any combination of winning, as well as previously awarded, 
Receipt Point-to-Delivery Point Congestion Revenue Right Option 
Rights, would not exceed any thermal, voltage, or stability limits 
within the Independent Transmission Provider's Service Area under 
normal operating conditions or for monitored contingencies.
    Condition B: For each Flowgate in each direction, the power flow 
on the Flowgate in the specified direction resulting from the set of 
injections and withdrawals identified in Condition A, when added to 
the total Flowgate Rights awarded on the Flowgate in the specified 
direction, would not exceed the capability of the Flowgate available 
in the Auction.
    The Power Flow simulations shall take into consideration the 
effects of parallel flows on the Transfer Capability of the 
Independent Transmission Provider's transmission system when 
determining which sets of injections and withdrawals are 
simultaneously feasible.
    When performing the above Power Flows, injections for Receipt 
Point-to Delivery Point Congestion Revenue Rights that specify a 
Zone or a Hub as the injection location will be modeled as a set of 
injections at each bus in the injection Zone or Hub equal to the 
product of the number of Receipt Point-to-Delivery Point Congestion 
Revenue Rights and the percentage weights for each bus in the Zone 
or Hub.
    When performing the above Power Flows, withdrawals for Receipt 
Point-to Delivery Point Congestion Revenue Rights that specify a 
Zone or Hub as the withdrawal location will be modeled as a set of 
withdrawals at each bus in the withdrawal Hub equal to the product 
of the number of Receipt Point-to Delivery Point Congestion Revenue 
Rights and the percentage weights for each bus in the Zone.
    7.9  Responsibilities of the Independent Transmission Provider 
upon Completion of the Auction: The Independent Transmission 
Provider shall not reveal the Bid Prices submitted by any Bidder in 
the Auction until three months following the date of the auction, 
except as permitted by Section A.12. When these Bid Prices are 
posted, the names

[[Page 55551]]

of the Bidders shall not be publicly revealed, but the data shall be 
posted in a way that permits third parties to track each individual 
Bidder's Bids over time.
    Upon completion of the auction, the Independent Transmission 
Provider will collect payment for all Congestion Revenue Rights 
awarded in the auction. The Independent Transmission Provider will 
disburse the revenues collected from the sale of Congestion Revenue 
Rights to the Primary Holders upon completion of the Auction 
process. Each holder of a Congestion Revenue Right that offers that 
Congestion Revenue Right for sale in the auction shall be paid the 
Market Clearing Price for each Congestion Revenue Right sold by that 
holder. All remaining Auction revenues from the auction shall be 
allocated among those who pay the Access Charge. [The Independent 
Transmission Provider will file procedures explaining how these 
revenues will be allocated.]

8. Exchanging Congestion Revenue Rights

    The Independent Transmission Provider shall allow a Customer to 
exchange its Receipt Point-to-Delivery Point Congestion Revenue 
Right Obligation for a different Receipt Point-to-Delivery Point 
Congestion Revenue Right Obligation with different Receipt and/or 
Delivery Points as long as the exchange meets the condition 
specified in Section D.6.1 is met. In addition, as soon as it is 
technically feasible, the Independent Transmission Provider shall 
allow a Customer to acquire Receipt Point-to-Delivery Point 
Transmission Option Rights and Flowgate Rights in exchange for other 
Congestion Revenue Rights that the Customer may hold, as long as the 
exchange meets the condition specified in Section D.6.1. The MW 
levels of the original Congestion Revenue Rights and the new 
Congestion Revenue Rights in the exchange need not be the same, as 
long as the exchange meets the condition specified in Section D.6.1.
    8.1  Condition for Exchanging Congestion Revenue Rights: In 
order for the Independent Transmission Provider to approve a request 
to exchange Congestion Revenue Rights, pursuant to Section D.6, the 
new Congestion Revenue Right (after being exchanged for the original 
Congestion Revenue Right), in combination with all other outstanding 
Congestion Revenue Rights held by others, must be Simultaneously 
Feasible as defined in Section D.5.8 in light of the total 
Transmission Capability in the Independent Transmission Provider's 
Service Area under normal operating conditions.

9. Congestion Revenue Rights Associated with Transmission Expansions

    The Independent Transmission Provider shall award to all Market 
Participants that fund additions to the transmission system 
Congestion Revenue Rights to equal the capability created by the 
expansion. The Congestion Revenue Rights awarded in combination with 
all other awarded Congestion Revenue Rights, must be Simultaneously 
Feasible as described in Section D.5.8 in light of the Total 
Transfer Capability available under normal operating conditions. 
Such Market Participants shall be allowed to choose any set of 
Receipt Point-to-Delivery Point Obligation Rights that meet the 
requirements for Simultaneously Feasibility. Such Market 
Participants shall also be allowed to choose any set of Receipt 
Point-to-Delivery Point Option Rights and Flowgate Rights that meet 
the requirements for Simultaneous Feasibility, as soon as it is it 
is feasible to issue such rights. Such Market Participants may elect 
to receive no Congestion Revenue Rights if, but only if, all 
outstanding Congestion Revenue Rights are Simultaneously Feasible in 
light of the Total Transfer Capability available after the additions 
under normal operating conditions. [The Independent Transmission 
Provider file a Commission-approved, non-discriminatory methodology 
for allocating Congestion Revenue Rights among multiple Market 
Participants that fund any single transmission capability addition.]

Part III. Day-Ahead and Real-Time Market Services

E. General Responsibilities and Requirements

Preamble

    The Independent Transmission Provider will operate Day-Ahead and 
Real-Time Markets for Energy and certain Ancillary Services in 
conjunction with Day-Ahead and Real-Time markets for transmission 
services. These markets will allocate transmission Transfer 
Capability and Generation Capacity among competing uses in different 
markets through Locational Marginal Pricing (LMP). The markets will 
be operated jointly to ensure that the prices for the products and 
services are internally consistent. The procedures for operating 
these markets are detailed below.

1. Day-Ahead and Real-Time Market Services

    This Part III contains the procedures for Bidding and Scheduling 
of Energy and Bid-Based Ancillary Services, Bilateral Transaction 
Schedules and Self-Schedules in the Day-Ahead Market. Part III also 
contains the time requirements, notice provisions and sequence 
followed in administering Day-Ahead financial Settlement. These 
scheduling requirements support the operations of the Day-Ahead 
Markets for Energy, Regulation and Frequency Response, and Operating 
Reserves, the determination of the Day-Ahead Transmission Usage 
Charge, and the Day-Ahead financial Settlement of Congestion Revenue 
Rights.
    Part III also contains the procedures for Scheduling and Bidding 
of Energy and Bid-Based Ancillary Services, and modification of, or 
submission of new, Bilateral Schedules and Self-Schedules, that will 
be used following the close of the Day-Ahead Market. These 
procedures include the time requirements, notice provisions and 
sequence followed in administering Real-Time Financial Settlement. 
These Bidding and scheduling requirements support the operations of 
the Real-Time Markets for Energy, Regulation and Frequency Response, 
Operating Reserves, and the determination of the Real-Time 
Transmission Usage Charge.

2. Independent Transmission Provider Authority

    The Independent Transmission Provider shall provide all Market 
Services for Energy, Ancillary Services, and Transmission Service in 
accordance with the terms of the Tariff and related agreements.
    The Independent Transmission Provider shall be the sole point of 
Application for all Market Services for Energy, Ancillary Services, 
and Transmission Service provided in the Independent Transmission 
Provider's Service Area. Each Market Participant that sells or 
purchases Energy, including demand side Resources, provides 
Ancillary Services, or Schedules Transmission Services subject to 
Transmission Usage Charges in the Independent Transmission Provider 
Administered Markets, utilizes Market Services and must take service 
as a Customer under the Tariff.
    The Independent Transmission Provider has the right to schedule 
and dispatch Scheduled Resources and to direct that schedules be 
changed in an Emergency.
    Following the start of the markets, the Independent Transmission 
Provider shall have the right to file changes to these market rules 
with the Commission to improve the competitiveness and efficiency of 
the markets.

3. Informational and Reporting Requirements

    The Independent Transmission Provider shall operate and maintain 
an OASIS that, among other things, will facilitate the posting of 
Bids to supply Energy, Ancillary Services and Demand Reductions by 
Suppliers for use by the Independent Transmission Provider and the 
posting of LMP, clearing prices for Bid-based Ancillary Services, 
and schedules for accepted Bids for Energy, Ancillary Services and 
Demand Reductions. The OASIS will be used to post schedules for 
Bilateral Transactions. The OASIS also will provide historical data 
regarding market clearing prices for each market in addition to 
Transmission Usage Charges.

4. Communication Requirements for Market Services

    Customers may utilize a variety of communications facilities to 
access the Independent Transmission Provider's OASIS, including but 
not limited to, conventional Internet service providers, wide area 
networks, and dedicated communications circuits. Customers shall 
arrange for and maintain all communications facilities for the 
purpose of communication of commercial data to the Independent 
Transmission Provider. Each Customer shall be the Customer of record 
for the telecommunications facilities and services it uses and shall 
assume all duties and responsibilities associated with the 
procurement, installation and maintenance of the subject equipment 
and software.

F. Day-Ahead Scheduling and Markets

Preamble

    The Independent Transmission Provider will operate a Day-Ahead 
Market in order to develop a joint Day-Ahead Schedule for 
Transmission Service, Energy, and Ancillary Services. The Day-Ahead 
Schedule will be developed so as to maximize the combined economic 
value of Transmission Service, Energy, and Ancillary Services, based 
on the Bids submitted.

[[Page 55552]]

1. Day-Ahead Scheduling Procedures

    1.1  Day-Ahead Trading Deadline: Market Participants may submit 
Bids for purchase and sale of Energy, Ancillary Services and 
Transmission, Bilateral Transaction Schedules, Self-Schedules, and 
Ancillary Services Self-Supply Schedules no later than [to be 
supplied by Independent Transmission Provider] for use in 
establishing the Day-Ahead Schedule.
    1.2  Rules for Self Schedules
    1.2.1  Supplier-Committed Self Schedules
    (i) Suppliers of Generation Resources for Energy may Self-
Schedule these Resources in the Day-Ahead Markets.
    (ii) Self-Schedules by Suppliers of Energy are required only to 
submit a MW quantity and a location.
    1.2.2  Independent Transmission Provider-Committed Self 
Schedules
    (i) Upon request of a Supplier, the Independent Transmission 
Provider shall develop a schedule for Generation or Demand Resources 
in which the Schedule optimizes the revenues over the Operating Day 
for the Resource. These are referred to in this Tariff as 
Independent Transmission Provider- Committed Self Schedules. This 
option will typically be used by Energy-Limited Resources, however 
this option is available to all Generation or Demand Resources.
    (ii) Independent Transmission Provider-Committed Self-Schedules 
are required only to submit a MW quantity and a location.

1.2.3  Self Supply of Ancillary Services

    (i) Suppliers of Resources for Regulation and Operating Reserves 
may Self-Supply these Resources in the Day-Ahead Markets.
    (ii) The specific rules for Self-Supply of Regulation and 
Operating Reserves are in Sections F.4-F.6.

1.3  Rules for Bilateral Transactions Schedules

1.3.1  Internal Transactions

    (i) All Internal Transactions must specify a Receipt Point, a 
Delivery Point, a MW quantity injected at the Receipt Point and a MW 
quantity withdrawn at the Delivery Point.
    (ii) Internal Transactions may also, voluntarily, submit a price 
Bid ($/MW) over some or all of the MW range. This makes the 
transaction under the control of the Independent Transmission 
Provider.

1.3.2  External Transactions

    (i) All External Transactions must specify a Receipt Point, a 
Delivery Point, a MW quantity injected at the Receipt Point and a MW 
quantity withdrawn at the Delivery Point. Either the Receipt Point 
or the Delivery Point must be a point at the boundary of the 
Independent Transmission Provider's Service Area. If the Receipt 
Point is a boundary point, then the External Transaction is an 
Import. If the Delivery Point is a boundary point, then the External 
Transaction is an Export. All External Transactions must specify a 
minimum run time.
    (ii) The Independent Transmission Provider shall offer Market 
Participants with External Transactions two options for Day-Ahead 
scheduling. (1) External Transactions can be scheduled without a 
Price Bid. The Independent Transmission Provider shall take all 
appropriate steps to accommodate such transactions, such as 
reservation of ramping capacity. (2) External Transactions can be 
scheduled in the Day-Ahead Market with a Price Bid ($/MW) over some 
or all of the MW quantity being scheduled. Transactions with a Bid 
will only enter the Day-Ahead Schedule if the price is at or below 
the LMP at the transaction sink node.
    (iii) External Transactions will be scheduled on a hourly basis.
    1.4  Rules for Bidding: The Independent Transmission Provider 
shall evaluate all eligible Bids for Energy Supply and Demand, 
Regulation and Frequency Response, Operating Reserves and Day-Ahead 
Transmission Service. The requirements for Bid eligibility and the 
Bid Specifications are in Sections F.2.3, F.3.1, F.4.4, F.5.4 and 
F.6.4.
    1.5  Bid-Based Security Constrained Unit Commitment and 
Determination of the Day-Ahead Schedule: The Independent 
Transmission Provider will develop a Security Constrained Unit 
Commitment schedule over the Operating Day using a computer 
algorithm that accepts all Self-Schedules and simultaneously 
maximizes the total value of the Bids, including Virtual Bids, 
submitted to (i) supply to (incorporating the costs of Start-up, No-
load and Incremental Energy) and purchase from the Day-Ahead Market 
for Energy; (ii) provide sufficient Ancillary Services to support 
Energy purchased from the Day-Ahead Market; and (iii) receive 
Transmission Service to support Bilateral Transaction schedules and 
Self-Schedules submitted Day-Ahead. The Independent Transmission 
Provider may substitute higher quality Ancillary Services (i.e., 
shorter response time) for lower quality Ancillary Services when 
doing so would result in an overall least Bid cost solution.
    In developing the Day-Ahead Schedule, the Independent 
Transmission Provider shall select Suppliers for Energy, Regulation 
and Frequency Response, and Operating Reserves for each hour of the 
upcoming day through its Day-Ahead Security-Constrained Unit 
Commitment, using Bids and/or schedules provided by the Suppliers. 
The Day-Ahead schedule will include commitment of sufficient 
Generators and price-sensitive Demand Bids to provide for the safe 
and reliable operation of the power system operated by the 
Independent Transmission Provider. The schedule shall honor all 
operating constraints included in the scheduled Bids. The Day-Ahead 
schedule shall list the twenty-four (24) hourly injections and 
withdrawals for: (a) each Customer whose Bid the Independent 
Transmission Provider accepts for the following Operating Day; and 
(b) Self-Schedules of Energy, Ancillary Services, and Transmission 
Service.
    1.6  Determination of the Day-Ahead Prices: The Independent 
Transmission Provider shall calculate the Day-Ahead Energy LMPs and 
Flowgate LMPs based on a dispatch of committed Generation Resources 
to meet the Load that has Bid in and been scheduled Day-Ahead. The 
Day-Ahead Energy LMPs are calculated, according to the Independent 
Transmission Provider decision, for each Generator bus, load bus, 
and sets of buses that comprise Zones or Hubs. The Transmission 
Usage Charge for Bilateral Transactions that are scheduled Day-Ahead 
is the difference between the Energy LMP for the Delivery Point and 
the Energy LMP at the Receipt Point. The methodology for calculating 
the different types of LMPs is described in Sections F.2.4 and 3.3.
    The Day-Ahead prices for Ancillary Services will be determined 
according to procedures described in Sections F.4.5, 5.5, 6.5 and 
6.6.
    1.7  Load Forecasts: All Load-Serving Entities shall provide 
their Day-Ahead Load forecasts to the Independent Transmission 
Provider. The Independent Transmission Provider shall develop an 
advisory forecast based on these forecasts and its own analysis of 
next day Load and shall post this forecast.
    1.8  Reliability-Based Security Constrained Unit Commitment: In 
cases in which the sum of all Bilateral Schedules and all Day-Ahead 
Market purchases to serve Load within the Independent Transmission 
Provider's Service Area in the Day-Ahead schedule is less than the 
Independent Transmission Provider's Day-Ahead forecast of Load, the 
Independent Transmission Provider will commit Resources in addition 
to the reserves it normally maintains to enable it to respond to 
contingencies. These additionally-committed Resources are called 
Replacement Reserves. This commitment of Replacement Reserves will 
be the result of a Bid-Based Reliability-Based Security Constrained 
Unit Commitment conducted following the Day-Ahead Security 
Constrained Unit Commitment. The purpose of this additional 
commitment of Resources is to ensure that sufficient capacity is 
available to the Independent Transmission Provider in Real-Time to 
enable it to meet its Load forecast (including associated Ancillary 
Services).
    In considering which additional Resources to schedule to meet 
the Independent Transmission Provider's Load forecast, the 
Independent Transmission Provider will evaluate whether unscheduled 
Imports can provide additional power at a price within any Bid Price 
caps set by the Independent Transmission Provider.
    The Independent Transmission Provider will develop the 
Reliability-Based Security Constrained Unit Commitment schedule over 
the Operating Day using a computer algorithm that minimizes the 
total cost of committing the additional Generation and Demand 
Resources that provide Replacement Reserves based solely on the 
Start-up and No-load Bids of the additionally committed Resources. 
The Independent Transmission Provider shall use Bids submitted into 
the Day-Ahead Market. If such Bids are not sufficient to meet the 
forecast load, the Independent Transmission Provider may solicit 
additional Bids; these additional Bids will be considered eligible 
for the Real-Time Market in addition to the Reliability-Based 
Security Constrained Unit Commitment. Resources committed in the 
Reliability-Based Security Constrained Unit Commitment are

[[Page 55553]]

obligated to Start-up and operate at their No-load level.
    1.9  Reliability Forecast: In the Security Constrained Unit 
Commitment program, system operation shall be optimized based on 
Bids over the Operating Day. However, to preserve system 
reliability, the Independent Transmission Provider may take steps to 
ensure that there will be sufficient Resources available to meet 
forecasted Load and reserve requirements over the day beginning with 
the next Operating Day, typically completing a one week look ahead.
    1.10  Posting the Day-Ahead Schedule: By [a pre-defined deadline 
to be supplied by Independent Transmission Provider] on the day 
prior to the Operating Day, the Independent Transmission Provider 
shall close the Day-Ahead scheduling process and post on its OASIS 
the Day-Ahead schedule for Energy, Regulation and Frequency 
Response, and Operating Reserves for each entity that submits a Bid 
or Self-Schedule. All schedules shall be considered proprietary, 
with the posting only visible to the appropriate scheduling Customer 
and Transmission Owners subject to the applicable Code of Conduct. 
The Independent Transmission Provider will post on the OASIS the 
aggregate Resources (Day-Ahead Energy, Regulation and Frequency 
Response and Operating Reserves schedules) and Load (Day-Ahead 
scheduled and forecast) for each Load bus or Zone, and the Day-Ahead 
LMP prices (including the Marginal Congestion cost Component and the 
Marginal Losses component) for each Generation Bus, Load Bus or Load 
Zone and Hub in each hour of the upcoming Operating Day.
    The Independent Transmission Provider shall conduct the Day-
Ahead Settlement based upon the Day-Ahead Prices determined in 
accordance with this Section.
    1.11  Day Ahead Bid Revenue Sufficiency Guarantee: The 
Independent Transmission Provider shall ensure the minimum recovery 
of each Resource's Bid prices for Resources scheduled through the 
Day-Ahead Market or in subsequent commitments for reliability. The 
is called the Bid Revenue Sufficiency Guarantee.
    (i) The Independent Transmission Provider shall determine, on a 
daily basis, if any Resource committed by the Independent 
Transmission Provider in the Day-Ahead Market will not recover 
Start-Up, No Load, and Energy Bid Price through revenues in the Day-
Ahead Energy and Ancillary Services markets.
    (ii) If the Start-Up and No Load Bids plus the net Energy and 
Ancillary Services Bid Price over the twenty-four (24) hour day of 
any Supply Resource exceeds the sum of its Day-Ahead LMP revenue and 
Ancillary Service revenue over the twenty-four (24) hour day, then 
that Supplier's Day-Ahead LMP revenue and Ancillary Service revenue 
shall be augmented by an additional payment, the Supply Bid Revenue 
Sufficiency Guarantee Payment, in the amount of the shortfall. This 
payment shall be supported through revenue collected from the Supply 
Bid Revenue Sufficiency Guarantee Charge.
    (iii) If the total Day-Ahead Energy charges to any Demand 
Resource over the twenty-four (24) hour day exceeds its maximum 
willingness to pay, as reflected by the difference of its selected 
Day-Ahead Energy Bids and Start-up Cost Bid, the Demand Resource 
shall be augmented by a payment, the Demand Bid Revenue Sufficiency 
Guarantee Payment, in the amount of the overcharge. This payment is 
supported through revenues collected from the Demand Bid Revenue 
Sufficiency Guarantee Charge.

2. Day-Ahead Market for Energy

    2.1  General: The Day-Ahead Market for Energy establishes 
clearing prices and settlement rules for Suppliers of Energy that 
have offered eligible Generation Capacity to the market and for 
Purchasers of Energy that have chosen not to Self-Supply or procure 
through bilateral contracts.
    2.2  Independent Transmission Provider Obligations: The 
Independent Transmission Provider has the obligation to provide 
services (i) to (v) for the Day-Ahead Market for Energy. The rules 
governing these services are contained in this section:
    (i) Establish and post on its OASIS rules that are consistent 
with this Tariff for eligibility to supply Energy in the Day-Ahead 
Market.
    (ii) Establish and post on its OASIS the Bid data requirements 
and rules and provide the market functions that are consistent with 
this Tariff required for determination of hourly Day-Ahead LMPs for 
Energy and selection of Day-Ahead Energy Market Suppliers and 
Purchasers.
    (iii) Establish and post on its OASIS the rules that are 
consistent with this Tariff for determination of any additional 
payments necessary to support efficient operations of the Day-Ahead 
Market for Energy and/or the efficient operation of other Day-Ahead 
Markets.
    (iv) Provide the Settlement functions associated with purchase 
and sale of Energy in the Day-Ahead Market.
    (v) Post the Day-Ahead LMPs for Energy.
    2.3  Purchaser Rules and Obligations: Purchasers of Energy in 
the Day-Ahead Market shall provide the Bid information specified in 
Sections 2.3.1 to 2.3.3.
    2.3.1  Specification of Bids: Purchasers of Day-Ahead Energy 
must provide the following Bid information. Purchasers must supply 
all information that is identified as a required Bid component. 
Purchasers may, but are not required to, submit information that is 
identified as an optional Bid component.
    (i) MW desired to be purchased, with a default value of 0 MW. 
This is a required Bid component.
    (ii) Location (transmission zone, aggregate, or single bus) that 
the purchaser desires to purchase the designated MWs of power. This 
is a required Bid component.
    (iii) Maximum price ($/MW) at which the purchaser desires to 
purchase the designated MW of power. (A purchaser may indicate its 
desire to purchase the designated MWs of power regardless of price, 
if the purchaser has demonstrated to the Independent Transmission 
Provider in advance that it is financially capable of paying the 
highest possible price for the designated MWs.) This is a required 
Bid component.
    (iv) Start-up Cost ($). This Bid component is an additional 
payment needed by the Purchaser of Energy to curtail its load This 
is an optional Bid component.
    (v) Minimum Curtailment Time (hours). This Bid component is up 
to a maximum of 24 hours. This is an optional Bid component. If a 
Minimum Curtailment Time is not indicated, then the default time 
will be one hour.
    (vi) Maximum Curtailment Time (hours). This Bid component is up 
to a maximum of 24 hours. This is an optional Bid component. If a 
Maximum Curtailment Time is not indicated, then the default time 
will be 24 hours.
    (vii) Minimum Purchase Time (at least one hour). This is an 
optional Bid component
    (viii) Maximum Purchase Time (hours). This is an optional Bid 
component.
    (ix) Hours that the purchaser desires to purchase the designated 
MWs of power. This is a required Bid component.
    2.3.2  Specification of Virtual Bids: Purchasers of Day-Ahead 
Virtual Energy must provide Bid components 2.3.1 (i) to (iii). In 
addition, the Bid shall identify that the Energy purchase is Virtual 
Energy if the purchase is not backed by actual load.
    2.3.3  Period of Bids: The Demand Bids shall be hourly Bids for 
each hour of the Operating Day in which the price ($) and quantity 
(MW) components can vary hour by hour.

2.4  Supplier Rules and Obligations

    2.4.1  Eligibility to Supply: Suppliers of Day-Ahead Energy 
shall provide the Bid information specified in Section 2.4.2 . 
Suppliers of Day-Ahead Virtual Energy shall provide the Bid 
information specified in 2.4.3- 2.4.4 .
    2.4.2  Specification of Bids. Suppliers are required to include 
the following price, quantity and data components in their 
Generation Bid. Suppliers must supply all information that is 
identified as a required Bid component. Suppliers may, but are not 
required to, submit information that is identified as an optional 
Bid component. The Bid Data requirements are additional data on 
Generator characteristics needed by the Independent Transmission 
Provider for market operations and reliability purposes.

Bid Prices and Quantities

    (i) Start-Up ($). This is an optional Bid component (Market 
Participants can opt to exclude Start-up Costs in their Energy Bid 
by setting this cost to $0). Limits on the frequency with which 
Start-up Bid Costs can be changed must be consistent with the 
requirements of Part IV, Market Power Monitoring and Mitigation.
    (ii) Minimum Generation (No-load) ($/hour). This is an optional 
Bid component (Market Participants can opt to exclude No-load Costs 
in their Energy Bid by setting this cost to $0/hour). Limits on the 
frequency with which Minimum Generation Bid Costs can be changed 
must be consistent with the requirements of Part IV, Market Power 
Monitoring and Mitigation.
    (iii) Incremental Energy ($/MWh). Market Participants must 
provide prices for the full MW range of their Operable Capacity, 
from the Hourly Economic Minimum Level to the

[[Page 55554]]

Hourly Economic Maximum Level. This is a required Bid component. 
[Independent Transmission Provider may add requirements regarding 
the number of steps or pieces in the Bid function.] The Incremental 
Energy Bid may be negative, indicating the price that the Supplier 
is willing to pay for the Generator not to be dispatched below its 
Hourly Economic Minimum Level. The upper limit on the Bid price of 
Incremental Energy over the full MW range of the Operable Capacity 
must be consistent with the requirements of Part IV, Market Power 
Monitoring and Mitigation. Any other limits on the Bid price of 
Incremental Energy must also be consistent with the requirements of 
Part IV, Market Power Monitoring and Mitigation.
    (iv) Emergency Incremental Energy ($/MWh). Market Participants 
must provide a price for the Emergency MW range of their Operable 
Capacity, from the Hourly Economic Maximum Level to the Hourly 
Emergency Maximum Level. This is a required Bid component. The upper 
limit on the Bid price of Emergency Incremental Energy must be 
consistent with the requirements of Part IV, Market Power Monitoring 
and Mitigation. Pricing rules for Emergency uses of Generation 
Resources are in Section G, 3.7(iii).

Bid Data Requirements

    (v) Normal Response Rate (MW/min). The expected response rate 
for Security Constrained Dispatch. This is a required Bid component.
    (vi) Regulation Response Rate (MW/min). The response rate for 
units providing regulation. This is a required Bid component for 
Resources offering Regulation service.
    (vii) Hourly Economic Minimum Level (MW). This is a required Bid 
component. Limits on the frequency with which the Hourly Economic 
Minimum Level can be changed must be consistent with the 
requirements of Part IV, Market Power Monitoring and Mitigation.
    (viii) Hourly Economic Maximum Level (MW). This is a required 
Bid component.
    (ix) Hourly Emergency Minimum Level (MW). This is the Minimum 
Level for a Generator in the event of an Emergency. This is a 
required Bid component.
    (x) Hourly Emergency Maximum Level (MW). This is the Maximum 
Level for a Generator in the event of an Emergency. This is a 
required Bid component.
    (xi) Start-up Time (hours). The number of hours required to 
start the Generator. This is a required Bid component.
    (xii) Minimum Run Time (hours). This Bid component is up to a 
maximum of 24 hours. This is a required Bid component. Limits on the 
Minimum Run Time of particular Generators must be consistent with 
the requirements of Part IV, Market Power Monitoring and Mitigation.
    (xiii) Maximum Run Time (hours). This is an optional Bid 
component.
    (xiv) Minimum Down Time (hours). This is an optional Bid 
component.
    (xv) Maximum Start-up Limit or Maximum Shut Down Limit in 24 
Hours (integer number). This is an optional Bid component.
    (xvi) Location.

 2.4.3  Bids to Supply Virtual Incremental Energy

    (i) A Virtual Incremental Energy Bid ($/MWh) is an Incremental 
Energy Bid that specifies that the Bid is a Virtual Transaction, 
i.e., it is not backed by a physical supply Resource. Virtual 
Incremental Energy Bids must include (1) a price, (2) a MW quantity, 
and (3) a location. The upper limit on the Bid price of Virtual 
Incremental Energy must be consistent with the requirements of Part 
IV, Market Power Monitoring and Mitigation.

2.4.4  Bids to Supply Decremental Energy

    (i) A Decremental Energy Bid ($/MWh) is a Bid to reduce the 
output of a Generator. Decremental Energy Bids must include (1) a 
price, (2) a MW quantity, and (3) a location. The upper limit on the 
Bid price of Decremental Energy must be consistent with the 
requirements of Part IV, Market Power Monitoring and Mitigation.
    (ii) A Virtual Decremental Energy Bid ($/MWh) is a Decremental 
Energy Bid that specifies that the Bid is a Virtual transaction. The 
upper limit on the Bid price of Virtual Decremental Energy must be 
consistent with the requirements of Part IV, Market Power Monitoring 
and Mitigation.
    (iii) A Decremental Emergency Energy Bid ($/MWh) is a 
Decremental Energy Bid to reduce the output of a Generator below its 
Hourly Economic Minimum Level down to its Hourly Emergency Minimum 
Level. The upper limit on the Bid price of Decremental Emergency 
Energy must be consistent with the requirements of Part IV, Market 
Power Monitoring and Mitigation. Pricing rules for Emergency uses of 
Generation Resources are in Section G, 3.7(iii).
    2.4.5  Period of Bids to Supply Energy: A Customer may submit 
Bids to Supply Incremental Energy or Decremental Energy pursuant to 
Sections F.2.4.2-2.4.4 that can vary by price ($) and quantity (MW) 
in each Hour of the Day-Ahead Market.

2.5  Calculation of Day-Ahead Locational Marginal Prices for Energy

    The Independent Transmission Provider shall calculate the price 
of Energy at the Load buses and Generation buses in the Independent 
Transmission Provider Service Area and at the Interface buses 
between the Independent Transmission Provider Service Area and 
adjacent Service Areas on the basis of Energy LMPs. LMPs can be set 
by Bids to sell or purchase Energy, including External Transaction 
Imports with Bids, and by transmission Bids. If requested by Market 
Participants the Independent Transmission Provider will establish 
Hubs and Zones based on a pre-defined set of buses. The Independent 
Transmission Provider will calculate load-weighted average Energy 
LMPs for this pre-defined set of buses, defined as Hub Prices or 
Zone Prices (or Zonal-LMPs). The Energy LMPs, Hub Prices and Zone 
Prices shall include separate components for the marginal costs of 
Congestion and the marginal costs of losses. Energy LMPs determined 
in accordance with this Section shall be calculated and posted on a 
Day-Ahead basis for each hour of the Day-Ahead Energy Market by 
[time to be provided by Independent Transmission Provider].
    2.5.1  Energy LMP Calculation: The Independent Transmission 
Provider will calculate for each bus on its system in each hour the 
Energy LMP, equal to the marginal cost of making an additional 
increment of Energy available at the bus in the hour, based on the 
Bids of sellers and buyers selected in the Day-Ahead Security 
Constrained unit Commitment for Energy supply and purchase. The 
Independent Transmission Provider shall designate one bus as the 
Reference Bus, r, for all other buses in the system. The System 
Marginal Price (SMPr), is the cost of making an 
additional increment of Energy available to the Reference Bus, based 
on Bids selected in the Day-Ahead Security Constrained Unit 
Commitment for Energy supply and Purchase. For each bus other than 
the Reference Bus, the Independent Transmission Provider shall 
determine separate components of the Energy LMP for the marginal 
costs of Congestion and losses relative to the Reference Bus, 
consistent with the following equation:

Energy LMPi = SMPr + MCCi + 
MLCi,

where SMPr is the system marginal price in each hour at 
the Reference Bus, r, in the system, MCCi is the LMP 
component representing the marginal cost of Congestion at bus i 
relative to the Reference Bus, and MLCi is the LMP 
component representing the marginal cost of losses at bus i relative 
to the Reference Bus.
    (i) Calculation of Marginal Congestion Component: The 
Independent Transmission Provider will calculate the marginal costs 
of Congestion at each bus as a component of the bus-level LMP. The 
Marginal Congestion Component (MCC) component of the Energy LMP at 
bus i is calculated using the equation:
[GRAPHIC] [TIFF OMITTED] TP29AU02.003

where: K is the number of thermal or Interface Transmission 
Constraints; GSFik is Shift Factor for the Generator at 
bus i on Flowgate k which limits flows across that Constraint when 
an increment of power is injected i and an equivalent amount of 
power is withdrawn at the Reference Bus, and FMPk is the 
Flowgate LMP on Flowgate k and is equivalent to the reduction in 
system cost expressed in $/MWh that results from an increase of 1 MW 
of the capacity on Flowgate k.
    (ii) Calculation of Marginal Losses Component: The Independent 
Transmission Provider will calculate the Marginal Losses Component 
(MLC) at each Load bus i. The MLC of the LMP at any bus i within the 
Independent Transmission Provider Service Area is calculated using 
the equation:
[GRAPHIC] [TIFF OMITTED] TP29AU02.004

where DFi = delivery factor for bus i to the system 
Reference Bus, and DFi = (1 - [part] L/ [part] 
Gi), where: L is system losses, Gi is 
generation injection at bus i, [part] L/ [part]Gi is the 
partial derivative of system losses with respect to generation 
injections at bus i, that is, the incremental change in system 
losses associated with an incremental change in the generation 
injections at bus i holding

[[Page 55555]]

constant other injections and withdrawals at all buses other than 
the Reference Bus and bus i.
    2.5.2  Hub Price Calculation: If requested by Market 
Participants, the Independent Transmission Provider shall calculate 
a Hub Price based on the Energy LMPs for a set of buses that 
comprise the Hub. These Hub Prices are the weighted average of the 
Energy LMPs at the buses that comprise the Hub. The weights will be 
pre-determined by the Independent Transmission Provider and remain 
fixed. [The Independent Transmission Provider may add procedures for 
determining the buses that comprise the Hub and procedures for 
changing the weights over time.] The Price for Hub j can be written 
as:
[GRAPHIC] [TIFF OMITTED] TP29AU02.005

where n is the number of buses in Hubj and WHi 
is the weighting factor for bus i in Hub j. The sum of the weighting 
factors shall add up to 1.

2.5.3  Zone Price Calculation

    (i) If requested by Market Participants, the Independent 
Transmission Provider shall calculate a Zone Price based on the 
Energy LMPs for a set of buses that comprise the Zone. These Zone 
Prices are the weighted average of the Energy LMPs at the set of 
buses that comprise the Zone. The Zone bus weights will equal the 
fractional share of each load bus in the total load in the Zone in 
the Hour. [The Independent Transmission Provider may add procedures 
for determining the buses that comprise the Zone, and assigning 
weights to those buses, in response to changes in retail load.]
[GRAPHIC] [TIFF OMITTED] TP29AU02.006

where n is the number of Load buses in Zone j and WZi is 
the load weighting factor for bus i in Zone j. The sum of the 
weighting factors adds up to 1.
    (ii) If the Zone price is used for Settlement purposes, it is 
subject to the following rules. (1) Each Zone shall include only the 
buses of Market Participants who agree to be in the Zone (and thus, 
who agree that their settlements will be calculated based on the 
zonal price). Alternatively, any one zone shall include only the 
buses of a single Market Participant. (2) A Market Participant who 
wants to be billed at a Zonal Price must include in its Zone all of 
the buses where Energy deliveries will be billed at the Zonal Price. 
A Market Participant shall not be allowed to settle Energy purchases 
at a bus or aggregation of buses if that bus or buses are not 
included in the Zone.

2.6  Calculation of Additional Payments and Charges

    2.6.1  Bid Revenue Sufficiency Guarantee: The Independent 
Transmission Provider shall calculate, for each Resource scheduled 
for Energy in the Day-Ahead Market, the amount of the Bid Revenue 
Sufficiency Guarantee payment, pursuant to Section F.1.11.
    2.6.2  Other Payments and Charges: [The Independent Transmission 
Provider may include in this section market rules for any other 
payments or charges associated with the efficient and reliable 
operations of the Day-Ahead Market for Energy.]

2.7  Market Rules for Shortages or Emergencies

    (i) [The Independent Transmission Provider may include in this 
section market rules, including specification of quantities of 
Energy purchased, calculation of market prices, and determination of 
out-of-market payments in the event of a shortfall in Energy due to 
a shortage of available capacity. The market rules shall be in 
accord with regional or local reliability authority rules and 
procedures and NERC guidelines.]
    (ii) [The Independent Transmission Provider may include in this 
section procedures for soliciting additional Bids for Energy in the 
event that Bids and self-scheduled provision of Energy submitted in 
the Day-Ahead Markets fall short of the Bid-in Load.]

2.8  Settlement

2.8.1  Payments by Purchasers

    (i) Each purchaser of Day-Ahead Energy shall be charged for all 
of its Load scheduled to be served from the Independent Transmission 
Provider's Day-Ahead Energy Market at the Day-Ahead LMPs applicable 
to each relevant Load bus and hour.
    (ii) If a Market Buyer elects to calculate and settle Energy 
purchases at Zonal-LMPs, and the Zonal price meets the conditions 
for settlement specified in Section 2.4(c)(ii), then the market 
buyer shall be charged for all of its load scheduled to be served 
from the Day-Ahead Energy Market at the Day-Ahead Zonal-LMPs 
applicable to each relevant Load Zone and time period.
    (iii) On any day when a Market Participant is scheduled to 
purchase any Energy in the Day-Ahead Market for Energy and/or does 
not Self-Supply a sufficient amount of its forecasted obligation 
(based on the Day-Ahead Schedule) for Regulation and Operating 
Reserves, the Market Participant shall be charged a Day-Ahead Bid 
Revenue Sufficiency Guarantee Charge. The Market Participant's Day-
Ahead Supply Bid Revenue Sufficiency Guarantee Charge on any given 
day shall equal the product of (i) the Market Participant's total 
load (in MWh) scheduled in the Day-Ahead Market (which shall equal 
the sum of the Market Participant's total purchases of Energy in the 
Day-Ahead Market for Energy plus the Market Participant's total load 
scheduled to be met from Bilateral Transactions) and (ii) the per 
unit Day-Ahead Supply Bid Revenue Sufficiency Guarantee Charge.
    The per unit Day-Ahead Supply Bid Revenue Sufficiency Guarantee 
Charge for any given day shall equal (i) the aggregate Bid Revenue 
Sufficiency Guarantee payments payable to Resources in the Day-Ahead 
Market for that day, divided by (ii) the sum of the total loads (in 
MWh) of all Market Participants that are to be charged Day-Ahead 
Supply Bid Revenue Sufficiency Charges for that day.

2.8.2  Payments to Suppliers

    (i) Suppliers of Day-Ahead Energy shall be paid for all Energy 
scheduled to be delivered in the Day-Ahead Energy Market at the Day-
Ahead LMPs applicable to each relevant generation bus.
    (ii) The Independent Transmission Provider shall pay Suppliers 
any additional payments necessary to provide Day-Ahead Energy in 
accord with efficient market operations, as specified in Section 2.5

2.8.3  Payments by Suppliers

    (i) Market Participant's Day-Ahead Demand Bid Revenue 
Sufficiency Guarantee Charge on any given day shall equal the 
product of (i) the Market Participant's total quantity (in MWh) 
scheduled in the Day-Ahead Market (which shall equal the sum of the 
Market Participant's total sales of Energy in the Day-Ahead Market 
for Energy plus the Market Participant's total supply scheduled to 
be met from Bilateral Transactions) and (ii) the per unit Day-Ahead 
Demand Bid Revenue Sufficiency Guarantee Charge.
    The per unit Day-Ahead Demand Bid Revenue Sufficiency Guarantee 
Charge for any given day shall equal (i) the aggregate Demand Bid 
Revenue Sufficiency Guarantee payments payable to Resources in the 
Day-Ahead Market for that day, divided by (ii) the sum of the total 
supply (in MWh) of all Market Participants that are to be charged 
Day-Ahead Demand Bid Revenue Sufficiency Guarantee Charges for that 
day.

3. Day-Ahead Scheduling of Transmission and Settlement Functions for 
Congestion Revenue Rights

    3.1  General: Day-Ahead scheduling of Transmission Service 
allows Market Participants to obtain Transmission Service to support 
Bilateral Transactions. This section establishes (1) rules for 
Bidding and/or scheduling Transmission Service, (2) determining 
prices (i.e., Transmission Usage Charges, Transmission Usage 
Charges) for Transmission Service, and (3) settling with Market 
Participants that are scheduled for Transmission Service in the Day-
Ahead Market. The Day-Ahead Energy LMPs shall be used to provide (1) 
the prices for sales and purchases of Energy and (2) Transmission 
Usage Charges (Transmission Usage Charges) for Transmission Service 
to support Bilateral Transactions. Because Transmission Usage 
Charges are based on the differences between Energy LMPs at the 
point of injection and point of withdrawal associated with an 
internal or external Bilateral Transaction, in their schedules 
requesting Transmission Service, Market Participants have the right 
to express willingness to pay for the Transmission Usage Charges--or 
equivalently, for the differences in the Energy LMPs.
    In addition, the Day-Ahead Energy LMPs and Flowgate LMPs are 
used for Settlement of Congestion Revenue Rights. Holders of Receipt 
Point-to-Delivery Point Congestion Revenue Rights that seek to 
settle them against Real-Time Energy LMPs can do so by scheduling 
transactions in the Day-Ahead Energy Market.

3.2  Day-Ahead Transmission Requests

    3.2.1  Information Provided by the Customer: Each Customer 
seeking to be

[[Page 55556]]

scheduled for Transmission Service in the Day-Ahead Market shall be 
required to provide the Independent Transmission Provider the 
information in (i) through (iii) below. In addition, the Customer 
shall be required to provide the information either in (iv) or (vi), 
or both. The Customer shall provide this information separately for 
each transaction involving a different Receipt and/or Delivery 
Point. The Customer shall have the option of providing the 
information in (v).
    (i) MW to be transmitted;
    (ii) The Point of Receipt and the Point of Delivery;
    (iii) The hours when the power is to be transmitted;
    (iv) The maximum Transmission Usage Charge ($ per MW) that the 
Customer is willing to pay to receive the Transmission Service. The 
Customer may indicate that it desires the indicated Transmission 
Service regardless of the Transmission Usage Charge, if the Customer 
has demonstrated to the Independent Transmission Provider that it is 
capable of paying the highest possible Transmission Usage Charge. 
The Customer may separately indicate the maximum Charge for Marginal 
Costs of Congestion and the maximum charge for Marginal Losses that 
it is willing to pay.
    (v) The minimum number of consecutive hours that the Customer 
desires to receive the Transmission Service.
    (vi) The maximum total Transmission Usage Charge (in $ per MW) 
that the Customer is willing to pay to receive Transmission Service 
over the total number of scheduled hours.
    (vii) Whether the Customer desires to provide additional Energy 
at the receipt point, in an amount that reflects the Marginal Losses 
associated with the Transmission Service (which the Independent 
Transmission Provider shall determine at the close of the Day-Ahead 
Market) in lieu of paying the charge for Marginal Losses.
    3.3  Calculation of Day-Ahead Transmission Usage Charges: The 
Independent Transmission Provider shall charge a Transmission Usage 
Charge to all Bilateral Transactions whose transmission service was 
scheduled in the Day-Ahead Market. This charge is the product of (a) 
the amount of Energy scheduled to be withdrawn by that Customer in 
each hour in MWh; and (b) the Day-Ahead LMP at the Point of Delivery 
(which could be a Load Zone in which Energy is scheduled to be 
withdrawn or the external bus where Energy is scheduled to be 
withdrawn if Energy is scheduled to be withdrawn at a location 
outside the Independent Transmission Provider Service Area), minus 
the Day-Ahead LMP at the Point of Receipt, in $/MWh. The Independent 
Transmission Provider shall divide each Transmission Usage Charge 
into separate components for Marginal Costs of Congestion and 
Marginal Costs of Losses.
    3.3.1  Marginal Congestion Component: The Marginal Congestion 
Component of the Transmission Usage Charge shall be calculated as 
the Marginal Congestion Component of the Day-Ahead LMP at the 
Delivery Point minus the Marginal Congestion Component of the Day-
Ahead LMP at the Receipt Point, as described in Section F.2.5(i).
    3.3.2  Marginal Losses Component: The Marginal Losses Component 
of the Transmission Usage Charge shall be calculated as the Marginal 
Losses Component of the Day-Ahead LMP at the Delivery Point minus 
the Marginal Losses Component of the Day-Ahead LMP at the Receipt 
Point, as described in Section F.2.5(ii).
    3.4  Flowgate LMP Calculation: The Independent Transmission 
Provider will, in addition to the calculation of the Energy LMPs, 
calculate Flowgate Locational Marginal Prices (FMPs) on the set of 
transmission constraints. The calculation for the Flowgate LMP (FMP) 
for each Transmission Constraint is defined in Section F.2.5.1(i). 
Independent Transmission Providers that offer Flowgate Rights must 
also calculate the Day-Ahead Flowgate LMPs (FMPs) on the 
Transmission Elements designated as Flowgates, based on a weighted 
average of the Transmission LMPs on the Transmission Elements that 
comprise the Flowgate:
[GRAPHIC] [TIFF OMITTED] TP29AU02.007

where: f is the index of Flowgates; k is a Transmission Element in 
the set of Flowgates, K; m is the subset of the Transmission 
Elements that comprise Flowgate f; and Wk are the weights 
attached to each of the m Transmission Elements that comprise 
Flowgate f. The sum of the weighting factors adds up to 1. For 
Flowgates comprised of one Transmission Element, the Wk 
for that element is equal to 1. The Independent Transmission 
Provider shall determine the Wk for Transmission elements 
defined as Flowgates.

3.5  Settlement of Congestion Revenue Rights

    3.5.1  Settlement of Receipt Point-to-Delivery Point Congestion 
Revenue Rights: For each hour in the Day-Ahead Market, the 
Independent Transmission Provider shall determine the Marginal 
Congestion Component of each Transmission Usage Charge associated 
with Transmission Service from a designated Receipt Point to a 
designated Delivery Point specified in each Receipt Point-to-
Delivery Point Congestion Revenue Right (including both Obligation 
and Option Rights), consistent with Section F.3.3.1. In each 
instance when the applicable Marginal Congestion Component is 
positive, the Independent Transmission Provider shall pay to the 
Primary Holder of the Congestion Revenue Right an amount equal to 
the applicable hourly Marginal Congestion Component multiplied by 
the specified MWs. In each instance when the applicable Marginal 
Congestion Component is negative, the Independent Transmission 
Provider shall charge to each Primary Holder of an Obligation Right 
(but not the Primary Holder of an Option Right) an amount equal to 
the absolute value of the applicable Marginal Congestion Component 
multiplied by the specified MWs.
    3.5.2  Settlement of Flowgate Rights: For each hour in the Day-
Ahead Market, the Independent Transmission Provider shall determine, 
consistent with the provisions in Section F.3.4, the Flowgate LMP in 
each direction associated with each Flowgate on the transmission 
system operated by the Independent Transmission Provider.
    (i) Holders of Flowgate Rights. For each hour of the Day-Ahead 
Market, the Independent Transmission Provider shall pay each Primary 
Holder of a Flowgate Right an amount equal to the applicable hourly 
Flowgate LMP multiplied by the MWs specified in the Primary Holder's 
Flowgate Right.

3.6  Disposition of Congestion Revenue Surplus or Deficit

    3.6.1  Hourly Congestion Charge Collection: The Hourly 
Congestion Charge Collection is defined here as the sum of the 
Hourly Energy Congestion Charge Collection plus the Hourly 
Transmission Congestion Charge Collection. The Hourly Energy 
Congestion Charge Collection is defined for any hour of the Day-
Ahead Market as (i) the net amounts charged to purchasers of Energy 
in the Independent Transmission Provider's Day-Ahead Market 
associated with the Marginal Congestion Component of the hourly LMPs 
at the purchasers' buses, less (ii) the net amounts paid to sellers 
of Energy in the Independent Transmission Provider's Day-Ahead 
Market associated with the Marginal Congestion Component of the 
hourly LMPs at the sellers' buses. The Hourly Transmission 
Congestion Charge Collection is defined for any hour of the Day-
Ahead Market as the net amounts charged to Customers for 
Transmission Service scheduled in the Day-Ahead Market associated 
with the Marginal Congestion Component of the applicable hourly 
Transmission Usage Charges.
    3.6.2  Hourly Net Congestion Revenue Owed to Congestion Revenue 
Rights Holders: The Hourly Net Congestion Revenue owed to Congestion 
Revenue Rights Holders for any hour in the Day-Ahead Market is 
defined here as the net hourly amounts payable to Primary Congestion 
Revenue Rights Holders pursuant to Sections F.3.5.1 and F.3.5.2.
    3.6.3  Determination and Disposition of Congestion Revenue 
Surplus or Deficit: For each hour of the Day-Ahead Market, the 
Independent Transmission Provider shall calculate the Hourly 
Congestion Charge Collection and the Hourly Net Congestion Revenue 
Owed to Congestion Revenue Rights

[[Page 55557]]

Holders. For each hour of the Day-Ahead Market where the Hourly 
Congestion Charge Collection exceeds the Hourly Net Congestion 
Revenue Owned to Congestion Revenue Rights Holders, the Independent 
Transmission Provider shall allocate the revenue surplus to the 
Transmission Owners. For each hour of the Day-Ahead Market where the 
Hourly Congestion Charge Collection is less than the Hourly Net 
Congestion Revenue Owned to Congestion Revenue Rights Holders, the 
Independent Transmission Provider shall charge the revenue deficit 
to the Transmission Owners.

3.7  Disposition of Marginal Loss Revenue Surplus

    3.7.1  Hourly Marginal Loss Charge Collection: The Hourly 
Marginal Loss Charge Collection is defined here as the sum of the 
Hourly Energy Marginal Loss Charge Collection plus the Hourly 
Transmission Marginal Loss Charge Collection. The Hourly Energy 
Marginal Loss Charge Collection is defined for any hour of the Day-
Ahead Market as (i) the net amounts charged to purchasers of Energy 
in the Independent Transmission Provider's Day-Ahead Market 
associated with the Marginal Losses Component of the hourly LMPs at 
the purchasers' buses, less (ii) the net amounts paid to sellers of 
Energy in the Independent Transmission Provider's Day-Ahead Market 
associated with the Marginal Losses Component of the hourly LMPs at 
the sellers' buses. The Hourly Transmission Marginal Loss Charge 
Collection is defined for any hour of the Day-Ahead Market as the 
net amounts charged to Customers for Transmission Service scheduled 
in the Day-Ahead Market associated with the Marginal Cost Component 
of the applicable hourly Transmission Usage Charges.
    3.7.2  Determination and Disposition of Marginal Loss Revenue 
Surplus: For each hour of the Day-Ahead Market, the Independent 
Transmission Provider shall calculate the Hourly Marginal Loss 
Charge Collection and the Hourly Net Energy Revenue Owed to 
Generators for losses associated with all Transactions. For each 
hour of the Day-Ahead Market where the Hourly Marginal Loss Charge 
Collection exceeds the Hourly Net Energy Revenue Owed to Generators 
for Losses associated with all Transactions, the Independent 
Transmission Provider shall allocate the revenue surplus to 
reduction in the charge for Network Access Service. [The Independent 
Transmission Provider shall determine the exact allocation to each 
Customer and will file procedures for determining the allocation of 
the revenue surplus to each Customer.]

4. Day-Ahead Market for Regulation and Frequency Response

    4.1  General: The Day-Ahead Market for Regulation establishes 
clearing prices and settlement rules for Suppliers that have offered 
eligible Regulation capacity to the market. The Transmission 
Provider shall procure Regulation through this market on behalf of 
Load-Serving Entities that have chosen not to Self-supply or 
purchase through bilateral contracts. Both Generation and Load may 
Bid to provide Regulation in the Day-Ahead Market if they meet the 
criteria for eligibility.
    4.2  Independent Transmission Provider Obligations: The 
Independent Transmission Provider has the obligation to provide 
services (i) to (vii) for the Day-Ahead Market for Regulation. The 
rules governing these services are contained in this section:
    (i) Establish and post on its OASIS Regulation criteria and 
requirements in accord with regional or local reliability authority 
rules and NERC guidelines.
    (ii) Establish and post on its OASIS a Total Regulation 
Requirement for the Independent Transmission Provider's Service Area 
for each hour of the Operating Day. This hourly requirement enters 
the Day-Ahead Security Constrained Unit Commitment. The Total 
Regulation Requirement may be subdivided into locational Regulation 
Requirements; that is, those assigned to specific locations (or 
Zones) within the Service Area.
    (iii) Allocate the obligation for meeting the Total Regulation 
Requirement among Load-Serving Entities. The obligation of each 
Load-Serving Entity in any hour shall be equal to the product of (1) 
the Load-Serving Entity's Real-Time load in the hour as a percentage 
of the total Real-Time load in the Independent Transmission 
Provider's Service Area in the hour and (2) the total Day-Ahead 
Total Regulation Requirement for the hour. The Load-Serving entity's 
forecasted Regulation obligation for purposes of Section 
F.2.8.1(iii) shall be equal to the product of (1) the Load-Serving 
Entity's Day-Ahead scheduled load in an hour and (2) the total Day-
Ahead Regulation requirement in the hour.
    (iv) Establish and post on its OASIS rules for eligibility to 
supply Regulation in the Day-Ahead Market that are consistent with 
this Tariff, including minimum technical requirements and 
performance standards for a Generator or Load to provide Regulation 
in response to signals sent by the Independent Transmission 
Provider.
    (v) Establish and post on its OASIS the Bid data requirements 
and rules for self-scheduling and Bidding, and provide the market 
functions required for determination of hourly Day-Ahead Spinning 
Regulation Market Clearing Prices and selection of Day-Ahead 
Regulation Market Suppliers. Establish and post on its OASIS how 
these pricing and selection rules are modified to account for 
locational Regulation requirements. Establish how these pricing and 
selection rules are modified in the event of shortages in Bid-in 
Regulation capacity. [The Independent Transmission Provider shall 
include procedures for self-supply.]
    (vi) Establish and post on its OASIS the rules for determination 
of any additional payments necessary to support efficient operations 
of the Day-Ahead Regulation Market and the efficient joint operation 
of the Day-Ahead Market for Regulation and other Day-Ahead Markets.
    (vi) Provide the Settlement functions associated with purchase 
and sale of Regulation in the Day-Ahead Market.
    (vii) Post the Day-Ahead Regulation Market Clearing Prices.
    4.3  Purchaser Rules and Obligations: The Purchaser of 
Regulation Service has the obligations and rights set forth in (i) 
through (iv):
    (i) Each Load-Serving Entity is required to fulfill its 
Operating Day Regulation obligation on the basis of either or both 
Self-Supply or procurement from the Day-Ahead and Real-Time markets 
for Regulation. The Transmission Provider shall procure Regulation 
Reserve on behalf of Load-Serving Entities and determine the final 
cost of each MW purchased.
    (ii) A Load-Serving entity may meet its Regulation obligation 
through Self-Supply by offering into the Day-Ahead Market for 
Regulation its own Resources capable of supplying Regulation or 
Resources for which it has made contractual arrangements with third 
parties able to provide Regulation on a comparable basis. Such self-
supplied Resources must be placed under the Independent Transmission 
Provider's control, and must meet the Independent Transmission 
Provider's rules for eligibility to supply Regulation (see Section 
5.2 and 5.4.1). These self-supplied Resources are scheduled in the 
Day-Ahead Market for Regulation at a Supply Bid Price of $0/MWh. 
Also, a Load-Serving Entity shall be paid the applicable Day-Ahead 
Market Clearing Price for any Regulation self-supplied in excess of 
its obligation.
    (iii) A Load-Serving Entity that has not fulfilled all of its 
Regulation obligation through Self-Supply is required to allow the 
Independent Transmission Provider to procure sufficient Regulation 
that it has not self-supplied through the Day-Ahead, and if 
necessary, the Real-Time Regulation Market to fulfill the obligation 
that is not self-supplied.

4.4  Supplier Rules and Obligations

    4.4.1  Eligibility to Supply: To be eligible to supply 
Regulation in the Day-Ahead Market for Regulation, a Supplier or a 
Generator contracted by a Supplier must meet criteria (i) to (v), as 
follow.
    (i) Suppliers of Regulation may use only Generators and/or Load 
that are electrically within the Independent Transmission Provider's 
Service Area.
    (ii) Suppliers of Regulation may use only Generators and/or Load 
that are able to respond to AGC Base Point Signals sent by the 
Independent Transmission Provider pursuant to the Independent 
Transmission Provider procedures.
    (iii) Suppliers of Regulation may use only Generators and/or 
Load that meet Independent Transmission Provider standards for 
Generator or Load performance.
    (iv) Suppliers of Regulation shall not use, contract to provide, 
or otherwise commit the capability that is designated to provide 
Regulation to provide Energy or Spinning Reserve to any party other 
than the Independent Transmission Provider.
    (v) Suppliers of Regulation shall provide the Bid information 
specified in Section F.4.4.2.
    4.4.2  Specification of Bids: Suppliers of Regulation must 
provide the Bid information in (i) to (vii), as follows.
    (i) Availability Bid price ($/MWh).
    (ii) Regulation Capability (MW) of the Generator supplying 
Regulation.

[[Page 55558]]

    (iii) Response Rate (MW/Minute) of the Generator supplying 
Regulation.
    (iv) Upper and Lower Regulation Limits (MW).
    (v) Hours of availability to provide Regulation.
    (vi) Any additional physical data required by the Independent 
Transmission Provider
    (vii) Location of Resources
    4.5  Calculation of Market Clearing Price: The Independent 
Transmission Provider shall calculate a Market Clearing Price for 
the Day Ahead Market for Regulation, using the following 
methodology.
    The Independent Transmission Provider shall establish a Supplier 
Regulation Price for each Supplier based on the sum of the 
Supplier's Availability Bid and its Day-Ahead Unit-Specific 
Opportunity Cost (as defined below). The hourly Day-Ahead Regulation 
Market Clearing Price shall be the higher of (i) the highest 
Supplier Regulation Price needed to meet the Independent 
Transmission Provider's Regulation Requirement for each hour of the 
Next Day, or (ii) the highest Market Clearing Price in the hour for 
Operating Reserves.
    The Unit-Specific Opportunity Costs of a Resource Bidding to 
sell Regulation each hour shall be equal to the product of:
    (i) the deviation of the Regulation set point of the Generator 
that is required in order to provide Regulation from the Resource's 
expected output level if it had been scheduled or dispatched in 
economic merit order to provide Energy, times
    (ii) the greater of (a) the $/MWh difference between the 
expected Energy LMP at the generation bus for the Resource and the 
Bid price for Energy from the Resource (at the megawatt level of the 
Regulation set point for the Resource) in the Real-Time Energy 
Market and (b) zero.

4.6  Calculation of Additional Payments and Charges

    4.6.1  Bid Revenue Sufficiency Guarantee: The Independent 
Transmission Provider shall calculate for each Resource scheduled 
for Regulation in the Day-Ahead Market the amount of the Bid Revenue 
Sufficiency Guarantee payment, pursuant to Section F.1.11.
    4.6.2  Other Payments and Charges: [The Independent Transmission 
Provider may include in this section market rules for any other 
payments or charges associated with the efficient and reliable 
operations of the Day-Ahead Market for Regulation.]

4.7  Market Rules for Shortages

    (i) [The Independent Transmission Provider may include in this 
section market rules, including calculation of market prices and 
determination of out of market payments, in the event of a shortfall 
in Regulation in the Day-Ahead Market due to a shortage of available 
capacity. The market rules shall be in accord with regional or local 
reliability authority rules and procedures and NERC guidelines.]
    (ii) [The Independent Transmission Provider may include in this 
section procedures for soliciting additional Bids for Regulation in 
the event that Bids and self-supplied provision of Regulation 
submitted in the Day-Ahead Markets fall short of the Regulation 
Requirement for the Operating Day.
    4.8  Settlement: The Independent Transmission Provider will 
provide timely settlement of sales of Regulation in the Day-Ahead 
Market for Regulation pursuant to Section 4.8.1.

4.8.1  Payments to Suppliers

    (i) The Independent Transmission Provider shall pay each 
Supplier, the hourly Day-Ahead Market Clearing Price for Regulation 
times the Quantity (MW) of the Supplier's Regulation scheduled 
(i.e., selected) in the hour.

5. Day-Ahead Market for Operating Reserve--Spinning Reserve

    5.1  General: The Independent Transmission Provider shall 
establish bid-based markets for the types of Operating Reserve--
Spinning Reserves (e.g., 10-minute, 30-minute) necessary to meet 
local reliability authority rules or NERC guidelines. Day-Ahead 
Markets for Spinning Reserve shall be used to provide clearing 
prices and settlement rules for Suppliers of Spinning Reserve that 
have offered eligible Spinning Reserve capacity to the market. The 
Transmission Provider shall procure Spinning Reserves in this market 
on behalf of Purchasers of Spinning Reserve that have chosen not to 
self-supply or procure through bilateral contracts. Both Generation 
and Load may Bid to provide Spinning Reserve in the Day-Ahead Market 
if they meet criteria for eligibility.
    5.2  Independent Transmission Provider Obligations: The 
Independent Transmission Provider has the obligation to provide 
services (i) to (vii) for the Day-Ahead Market for Spinning Reserve. 
The rules governing these services are contained in this section:
    (i) Establish and post on its OASIS Spinning Reserve criteria 
and requirements in accord with regional or local reliability 
authority rules and NERC guidelines.
    (ii) Establish and post on its OASIS a Total Spinning Reserve 
Requirement for the Independent Transmission Provider's Service Area 
for each hour of the Operating Day. This hourly requirement enters 
the Day-Ahead Security Constrained Unit Commitment. The Total 
Spinning Reserve Requirement may be sub-divided into locational 
Spinning Reserve Requirements; that is, assigned to specific 
locations (or Zones) within the Service Area.
    (iii) Allocate the obligation for meeting the Total Spinning 
Reserve Requirement among Load-Serving Entities. The obligation of 
each Load-Serving Entity in any hour shall be equal to the product 
of (1) the Load-Serving Entity's Real-Time load in the hour as a 
percentage of the total Real-Time load in the Independent 
Transmission Provider's Service Area in the hour and (2) the total 
Day-Ahead Total Spinning Reserve Requirement for the hour. The Load-
Serving Entity's forecasted Spinning Requirement obligation for 
purposes of Section F.2.8.1(iii) shall be equal to (1) the Load-
Serving Entity's Day-Ahead scheduled load in an hour multiplied by 
(2) the total Day-Ahead Spinning Reserve requirement in the hour.
    (iv) Establish and post on its OASIS rules for eligibility to 
supply Spinning Reserve in the Day-Ahead Market that are consistent 
with this Tariff, including minimum technical requirements and 
performance standards for a Generator or Load to provide Spinning 
Reserve.
    (v) Establish and post on its OASIS the Bid data requirements 
and rules for self-scheduling and Bidding that are consistent with 
this Tariff, and provide the market functions required for 
determination of hourly Day-Ahead Spinning Reserve Market Clearing 
Prices and selection of Day-Ahead Spinning Reserve Market Suppliers. 
Establish how these pricing and selection rules are modified to 
account for locational Spinning Reserve requirements. Establish how 
these pricing and selection rules are modified in the event of 
shortages in Bid-in Spinning Reserve capacity.
    (vi) Establish and post on its OASIS the rules for determination 
of any additional payments necessary to support efficient operations 
of the Day-Ahead Market for Spinning Reserve and the efficient joint 
operation of the Day-Ahead Market for Spinning Reserve and other 
Day-Ahead Markets.
    (vii) Provide the Settlement functions associated with sale of 
Spinning Reserve in the Day-Ahead Market.
    (vii) Post the Day-Ahead Market Clearing Prices for Spinning 
Reserve.

5.3  Purchaser Rules and Obligations

    (i) Each Load-Serving Entity is required to fulfill its 
Operating Day Spinning Reserve obligation on the basis of either or 
both self-supply or procurement from the Day-Ahead and Real-Time 
markets for Spinning Reserve. The Independent Transmission Provider 
shall procure Spinning Reserve on behalf of Load-Serving Entities 
and determine the final cost of each MW purchased.
    (ii) A Load-Serving Entity may meets its Spinning Reserve 
obligation through Self-Supply by offering its own Resources capable 
of supplying Spinning Reserves or Resources for which it has made 
contractual arrangements with third parties able to provide Spinning 
Reserves on a comparable basis. Such self-supplied Resources must be 
placed under the Independent Transmission Provider's control, and 
must meet the Independent Transmission Provider's rules for 
eligibility (see Section 5.2 and 5.4.1). These self-supplied 
Resources are scheduled in the Day-Ahead Spinning Reserves Market. A 
Load-Serving Entity shall be paid the applicable Day-Ahead Market 
clearing price for any Spinning Reserve self-supplied in excess of 
its obligation.
    (iii) A Load-Serving Entity that has not fulfilled all of its 
Spinning Reserve obligation through Self-Supply is required to allow 
the Independent Transmission Provider to procure sufficient Spinning 
Reserve that it has not Self-Supplied through the Day-Ahead and, if 
necessary, Real-Time Spinning Reserve market to fulfill the 
obligation that is not Self-Supplied.

5.4  Supplier Rules and Obligations

    5.4.1  Eligibility to Supply: To be eligible to supply Spinning 
Reserve in the Day-Ahead Market for Spinning Reserve, a Supplier or 
a Generator contracted by a Supplier must meet criteria (i) to (iv), 
as follow.
    (i) Suppliers of Spinning Reserve may use only Generators and/or 
Load that are

[[Page 55559]]

electrically within the Independent Transmission Provider's Service 
Area.
    (ii) Suppliers of Spinning Reserve may use only Generators and/
or Load that meet Independent Transmission Provider standards for 
Generator performance; similarly, Demand Resources must meet 
Independent Transmission Provider standards for response capability.
    (iii) Suppliers of Spinning Reserve shall not use, contract to 
provide, or otherwise commit the capability that is designated to 
provide Spinning Reserve to provide Energy, Regulation or 
Supplemental Reserve to any party other than the Independent 
Transmission Provider.
    (iv) Suppliers of Spinning Reserve shall provide the Bid 
information specified in Section 5.4.2.
    5.4.2  Specification of Bids: Suppliers of Spinning Reserve must 
provide the Bid information in (i) to (vi), as follows.
    (i) Availability Bid price ($/MWh).
    (ii) Response Rate (MW/Minute) of the Generator supplying 
Spinning Reserve.
    (iii) Hours of availability to provide Spinning Reserve.
    (iv) Any additional physical data required by the Independent 
Transmission Provider.
    (v) Location of Resource.

5.5  Calculation of Market Clearing Price

    5.5.1  Methodology for Calculation of Clearing Price: The 
Independent Transmission Provider shall calculate a Market Clearing 
Price for the Day Ahead Market for Spinning Reserve, using the 
following methodology.
    The Independent Transmission Provider shall establish a Supplier 
Spinning Reserve Price for each Supplier based on the sum of the 
Supplier's Availability Bid and its Day-Ahead Unit-Specific 
Opportunity Cost (as defined below). The hourly Day-Ahead Spinning 
Reserve Market Clearing Price shall be the higher of (i) the highest 
Supplier Spinning Reserve Price needed to meet the Independent 
Transmission Provider's Spinning Reserve Requirement for each hour 
of the Next Day, or (ii) the highest Market Clearing Price in the 
hour for Supplemental Reserves.
    The Unit-Specific Opportunity Costs of a Resource Bidding to 
sell Spinning Reserve each hour shall be equal to the product of:
    (i) the deviation of the set point (MWh) of the Generator that 
is required in order to provide Spinning Reserve from the Resource's 
output level if it had been scheduled or dispatched in economic 
merit order to provide Energy, times
    (ii) the greater of (a) the $/MWh difference between the Energy 
LMP at the generation bus for the Resource and the Bid price for 
Energy from the Resource (at the megawatt level of the Spinning 
Reserve set point for the Resource) in the Day-Ahead Energy Market 
and (b) zero.
    5.5.2  Calculation of Zonal or Locational Prices: Separate Day-
Ahead Spinning Reserve Market Clearing Prices will be calculated for 
Spinning Reserve located in each distinct Reserve Location for which 
there is a separate Spinning Reserve requirement. When there are no 
binding transmission constraints between Reserve Locations, the Day-
Ahead Ancillary Price for Spinning Reserve shall be the same in each 
of the locations.
    5.5.3  Transmission for Operating Reserves: A Supplier located 
outside of a particular Reserve Location may provide Spinning 
Reserves if the necessary transmission arrangements to deliver 
Energy from the Supplier's capacity to the Reserve Location are 
made. The cost of any transmission service would have to be included 
in evaluating the total cost of Operating Reserves.

5.6  Calculation of Additional Payments and Charges

    5.6.1  Bid Revenue Sufficiency Guarantee: The Independent 
Transmission Provider shall calculate, for each Resource scheduled 
for Spinning Reserve in the Day-Ahead Market the amount of the Bid 
Revenue Sufficiency Guarantee payment, pursuant to Section F.1.11.
    5.6.2  Other Payments and Charges: [The Independent Transmission 
Provider may include in this section market rules for any other 
payments or charges associated with the efficient and reliable 
operations of the Day-Ahead Markets for Spinning Reserves.]

5.7  Market Rules for Shortages

    (i) [The Independent Transmission Provider may include in this 
section market rules, including specification of quantities, 
calculation of market prices, and determination of out of market 
payments in the event of a shortfall in the required system 
requirements for Spinning Reserves due to a shortage of available 
capacity. The market rules shall be in accord with regional or local 
reliability authority rules and procedures and NERC guidelines.]
    (ii) [The Independent Transmission Provider may include in this 
section procedures for soliciting additional Bids for Spinning 
Reserves in the event that Bids and self-supplied provision of 
Spinning Reserves submitted in the Day-Ahead Markets fall short of 
the required system requirements for Spinning Reserves.]
    5.8  Settlement: The Independent Transmission Provider will 
provide timely settlement of purchases and sales of Spinning Reserve 
in the Day-Ahead Market for Spinning Reserve pursuant to Sections 
5.8.1.

5.8.1  Payments to Suppliers

    (i) The Independent Transmission Provider shall pay each 
Supplier the hourly Day-Ahead Spinning Reserve Market Clearing Price 
times the quantity (MW) of the Supplier's Spinning Reserve 
capability provided in the hour.

6. Day-Ahead Markets for Operating Reserve-Supplemental Reserve

    6.1  General: The Independent Transmission Provider shall 
establish the types of Supplemental Reserves (e.g., 10-minute, 30-
minute, 60-minute) necessary to meet local reliability authority 
rules and NERC guidelines. Day-Ahead Markets for Supplemental 
Reserves establish clearing prices and settlement rules for 
Suppliers of Supplemental that have offered eligible Supplemental 
Reserve capacity to the market. The Transmission Provider shall 
procure Supplemental Reserves in this market on behalf of Purchasers 
of Supplemental Reserves that have chosen not to Self-supply or 
procure through bilateral contracts. Both Generation and Load may 
Bid to provide Supplemental Reserves in the Day-Ahead Market if they 
meet criteria for eligibility.
    6.2  Independent Transmission Provider Obligations: The 
Independent Transmission Provider has the obligation to provide 
services (i) to (viii) for the Day-Ahead Markets for Supplemental 
Reserves. The rules governing these services are contained in this 
section:
    (i) Establish and post on its OASIS Supplemental Reserve 
criteria and requirements in accord with regional or local 
reliability authority rules and NERC guidelines.
    (ii) Establish and post on its OASIS Total Supplemental Reserves 
Requirements for the Independent Transmission Provider's Service 
Area for each Hour of the Operating Day. This hourly requirement 
enters the Day-Ahead Security Constrained Unit Commitment. The Total 
Supplemental Reserve Requirements may be subdivided into locational 
Supplemental Reserve Requirements; that is, assigned to specific 
locations (or zones) within the Service Area.
    (iii) Allocate the obligation for meeting the Total Supplemental 
Reserve Requirement among Load-Serving Entities. The obligation of 
each Load-Serving Entity in any hour shall be equal to the product 
of (1) the Load-Serving Entity's Real-Time load in the hour as a 
percentage of the total Real-Time load in the Independent 
Transmission Provider's Service Area in the hour and (2) the Total 
Day-Ahead Total Supplemental Reserve Requirement for the hour. The 
Load-Serving Entity's forecasted Supplemental Reserve obligation for 
purposes of Section F.2.8.1 (iii) shall be equal to the product of 
(1) the Load-Serving Entity's Day-Ahead scheduled load in the hour 
as a percent of the total Day-Ahead load in the Independent 
Transmission Provider's Service Area in the hour and (2) the Total 
Day-Ahead Supplemental Reserve Requirement in the hour.
    (iv) Establish and post on its OASIS rules for eligibility to 
supply Supplemental Reserves in the Day-Ahead Market that are 
consistent with this Tariff, including minimum technical 
requirements and performance standards for a Generator and/or Load 
to provide Supplemental Reserves.
    (v) Establish and post on its OASIS the Bid data requirements 
and rules for self-scheduling and Bidding that are consistent with 
this Tariff, and provide the market functions required for 
determination of hourly Day-Ahead Supplemental Reserves Market 
Clearing Prices and selection of Day-Ahead Supplemental Reserves 
Market Suppliers. Establish how these pricing and selection rules 
are modified to account for locational Supplemental Reserves 
requirements. Establish how these pricing and selection rules are 
modified in the event of a shortage of Bid-in Supplemental Reserve 
capacity.
    (vi) Provide the Settlement functions associated with purchase 
and sale of Supplemental Reserves in the Day-Ahead Market.
    (vii) Post the Day-Ahead Supplemental Reserves Market Clearing 
Prices.

[[Page 55560]]

6.3  Purchaser Rules and Obligations:

    (i) Each Load-Serving Entity is required to fulfill its 
Operating Day Supplemental Reserves obligation on the basis of 
either or both Self-Supply or procurement from the Day-Ahead and 
Real-Time markets for Supplemental Reserves. The Independent 
Transmission Provider shall procure Supplemental Reserve on behalf 
of Load-Serving Entities and determine the final cost of each MW 
purchased.
    (ii) A Load-Serving Entity may meet its Supplemental Reserve 
obligation through Self-Supply by offering into the Day-Ahead Market 
for Supplemental Reserves its own Resources capable of supplying 
Supplemental Reserves or Resources for which it has made contractual 
arrangements with third parties able to provide Supplemental 
Reserves on a comparable basis. Such self-supplied Resources must be 
placed under the Independent Transmission Provider's control, and 
must meet the Independent Transmission Provider's rules for 
eligibility (see Sections 6.2 and 6.4.1). These self-supplied 
Resources are scheduled in the Day-Ahead Reserves Market. A Load-
Serving Entity shall be paid the applicable Day-Ahead Market 
clearing price for any Supplemental Reserve self-supplied in excess 
of its obligation.
    (iii) A Load-Serving Entity that has not fulfilled all of its 
Supplemental Reserves obligation through self-supply is required to 
allow the Independent Transmission Provider to procure sufficient 
Supplemental Reserves that it has not Self-Supplied through the Day-
Ahead and, if necessary, Real-Time Supplemental Reserves market to 
fulfill the obligation that is not Self-Supplied.

6.4  Supplier Rules and Obligations

    6.4.1  Eligibility to Supply: To be eligible to supply 
Supplemental Reserves in the Day-Ahead Markets for Supplemental 
Reserve, a Supplier or a Generator contracted by a Supplier must 
meet criteria (i) to (iv), as follow.
    (i) Subject to Independent Transmission Provider requirements, 
Suppliers of Supplemental Reserves may use Generators and/or Load 
that are electrically within or outside the Independent Transmission 
Provider's Service Area.
    (ii) Suppliers of Supplemental Reserves may use only Generators 
and/or Load that meet Independent Transmission Provider standards 
for Generator performance.
    (iii) Suppliers of Supplemental Reserves shall not use, contract 
to provide, or otherwise commit the capability that is designated to 
provide Supplemental Reserves to provide Energy, Regulation and 
Frequency Response, or Spinning Reserve to any party other than the 
Independent Transmission Provider.
    (iv) Suppliers of Supplemental Reserves shall provide the Bid 
information specified in Section 4.2.
    6.4.2  Specification of Bids: Suppliers of Supplemental Reserves 
must provide the Bid information in (i) to (iv), as follows.
    (i) Availability Bid price ($/MWh).
    (ii) Response Rate (MW/Minute) of the Resource supplying 
Supplemental Reserve.
    (iii) Hours of availability to provide Supplemental Reserve.
    (iv) Any additional physical data required by the Independent 
Transmission Provider.
    (v) Location of Resource.

6.5  Calculation of Market Clearing Prices for Supplemental Reserves

    6.5.1  Methodology for Calculation of Prices: The Independent 
Transmission Provider shall calculate a Market Clearing Price for 
each Day-Ahead Market for Supplemental Reserves, using the following 
methodology.
    The Independent Transmission Provider shall establish a Supplier 
Estimated Supplemental Reserve Price for each Supplier based on the 
sum of the Supplier's Availability Bid and its Day-Ahead Unit-
Specific Opportunity Cost (as defined below). The hourly Day-Ahead 
Supplemental Reserve Market Clearing Price shall be the higher of 
(i) the highest Supplier Supplemental Reserve Price needed to meet 
the Independent Transmission Provider's Supplemental Reserve 
Requirement for each hour of the Next Day, or (ii) the Market 
Clearing Price in the hour for a lower quality Supplemental Reserve.
    The Unit-Specific Opportunity Costs of a Resource Bidding to 
sell Supplemental Reserves each hour shall be equal to the product 
of:
    (i) the deviation of the set point (MWh) of the Generator that 
is expected to be required in order to provide Supplemental Reserve 
from the Resource's output level if it had been scheduled or 
dispatched in economic merit order to provide Energy, times
    (ii) the absolute value of the difference between the Energy LMP 
at the generation bus for the Resource and the Bid price for Energy 
from the Resource (at the megawatt level of the Supplemental Reserve 
set point for the Resource) in the Day-Ahead Energy Market.
    6.5.2  Calculation of Zonal or Locational Prices: Separate Day-
Ahead Supplemental Reserve Market Clearing Prices will be calculated 
for Supplemental Reserve located in each distinct Reserve Location 
for which there is a separate Supplemental Reserve requirement. When 
there are no binding transmission constraints between Reserve 
Locations, the Day-Ahead Ancillary Price for Supplemental Reserve 
shall be the same in each of the locations.
    6.5.3  Transmission for Operating Reserves: A Supplier located 
outside of a particular Reserve Location may provide 10-Minute 
Supplemental Reserve if the necessary arrangements Energy from the 
Supplier's capacity to the Reserve Location are made. The cost of 
any transmission service would have to be included in evaluating the 
total cost of Operating Reserves.

6.6  Calculation of Additional Payments and Charges

    6.6.1  Bid Revenue Sufficiency Guarantee: The Independent 
Transmission Provider shall calculate, for each Resource scheduled 
for Supplemental Reserves in the Day-Ahead Market the amount of the 
Bid Revenue Sufficiency Guarantee payment, pursuant to Section 
F.1.11.
    6.6.2  Other Payments and Charges: [The Independent Transmission 
Provider may include in this section market rules for any other 
payments or charges associated with the efficient and reliable 
operations of the Day-Ahead Markets for Supplemental Reserves.]

6.7  Market Rules for Shortages

    (i) [The Independent Transmission Provider may include in this 
section market rules, including specification of quantities of 
Supplemental Reserve purchased, calculation of market prices, and 
determination of out-of-market payments in the event of a shortfall 
in the required system requirements for Supplemental Reserves due to 
a shortage of available capacity. The market rules shall be in 
accord with regional or local reliability authority rules and 
procedures and NERC guidelines.]
    (ii) [The Independent Transmission Provider may include in this 
section procedures for soliciting additional Bids for Supplemental 
Reserves in the event that Bids and self-supplied provision of 
Supplemental Reserves submitted in the Day-Ahead Markets fall short 
of the required system requirements for Supplemental Reserves.]
    6.8  Settlement: The Independent Transmission Provider will 
provide timely settlement of sales of Supplemental Reserves in the 
Day-Ahead Markets for Supplemental Reserves pursuant to Sections 
6.8.1.

6.8.1  Payments to Suppliers

    (i) The Independent Transmission Provider shall pay each 
Supplier the hourly Day-Ahead Supplemental Reserve Market Clearing 
Price times the quantity (MW) of the Supplier's Supplemental Reserve 
capability provided in the hour.

G. Post-Day-Ahead Scheduling and Real-Time Markets

Preamble

    The Independent Transmission Provider will operate a Real-Time 
Market in order to develop a post Day-Ahead Schedule and Real Time 
Dispatch Schedule for Transmission Service, Energy, and Ancillary 
Services. The Real-Time Schedule will be developed so as to maximize 
the combined economic value of transmission service, Energy, and 
Ancillary Services, based on the Bids submitted.

1. Post-Day-Ahead Bidding and Scheduling Procedures

    1.1  General: The Independent Transmission Provider shall 
establish procedures for modification of the Day-Ahead Schedule and 
development of the Real-Time Schedule and dispatch that incorporate 
components (i) to (vi), as follow.
    (i) The Independent Transmission Provider will allow Market 
Participants that have had selected in the Day-Ahead Schedule (1) a 
Quantity of Energy, whether a purchase or sale, Regulation or 
Operating Reserve, (2) a Bilateral Transaction, or (3) a Self-
Schedule or Self-Supply, to change the Quantities in the Schedule at 
any time following the close of the Day-Ahead Market but before the 
[Scheduling Deadline to be provided by the Independent Transmission 
Provider] prior to each Dispatch Hour in the Operating Day.
    (ii) The Independent Transmission Provider will allow Suppliers 
or Purchasers of Energy and Suppliers of Regulation or

[[Page 55561]]

Operating Reserves that have capacity not selected in the Day-Ahead 
Schedule to submit new Bids, including Prices ($/MW) and Quantities 
(MW), into the Real-Time Market. [Independent Transmission Provider 
will provide schedule.]
    (iii) The Independent Transmission Provider will allow Market 
Participants to submit new Bilateral Transactions and Self-Schedules 
at any time following the close of the Day-Ahead Market but before 
the [Scheduling Deadline to be provided by the Independent 
Transmission Provider] prior to each Dispatch Hour in the Operating 
Day.
    (iv) The Independent Transmission Provider will post on its 
OASIS the Deadlines for Scheduling Revised or New Quantities and for 
submission of Price Bids into the Real-Time Market, consistent with 
the Tariff.
    (v) The Independent Transmission Provider shall establish 
scheduling procedures for External Transactions during each Hour and 
Quarter-Hour of the Operating Day, consistent with the requirements 
established by the Commission.
    (vi) A Supplier or Purchaser in the Real-Time Market, as well as 
a Bilateral Schedule or Self-Schedule that submits a Price Bid, that 
follows Independent Transmission Provider Dispatch Instructions that 
deviate from the previously selected schedules submitted by the 
Supplier or Purchaser in the Day-Ahead Market, shall be provided 
with a Bid Revenue Sufficiency Guarantee, pursuant to Section G.2.3.

1.2  Rules for Self Schedules

1.2.1  Supplier-Committed Self Schedules

    (i) Suppliers that wish to increase the amount of Energy 
scheduled above the amounts scheduled in the Day-Ahead Market, 
regardless of the applicable Real-Time Energy LMP, may so inform the 
Independent Transmission Provider [before the scheduling deadline 
provided by the Independent Transmission Provider] prior to each 
Dispatch Hour in the Operating Day.
    (ii) Such Suppliers of Energy are required to submit a MW 
quantity and a location.

1.3  Rules for Bilateral Transactions

1.3.1  Internal Transactions

    (i) All Internal Transactions submitted or modified after the 
Day-Ahead Schedule must specify a Receipt Point, a Delivery Point, a 
MW quantity injected at the Receipt Point and a MW quantity 
withdrawn at the Delivery Point.
    (ii) Internal Transactions may voluntarily submit a Price Bid 
($/MW) over some or all of the MW range which indicates the 
Customer's willingness to reduce or eliminate the Transaction in the 
next Security Constrained Dispatch time period at the Independent 
Transmission Provider's instruction when the applicable Real-Time 
Transmission Usage Charge reaches or exceeds the price Bid.
    (iii) Internal Transactions may voluntarily submit a Decremental 
Energy Bid (in $/MW) over some or all of the MW range, which 
indicates the Customer's willingness to reduce the amount of Energy 
supplied at the Receipt Point at the Independent Transmission 
Provider's instruction (while retaining the amount of Energy 
withdrawn at the Delivery Point) when the Real-Time Energy LMP at 
the Receipt Point falls below the Decremental Energy Bid.

1.3.2  External Transactions

    (i) All External Transactions submitted or modified after the 
Day-Ahead Schedule must specify a Receipt Point, a Delivery Point, a 
MW quantity injected at the Receipt Point and a MW quantity 
withdrawn at the Delivery Point. Either the Receipt Point or the 
Delivery Point must be a point at the boundary of the Independent 
Transmission Provider Service Area. All External Transactions must 
specify a minimum run time.
    (ii) The Independent Transmission Provider shall offer Market 
Participants with External Transactions submitted after the Day-
Ahead Schedule or modifying the Day-Ahead Schedule two options for 
scheduling. (1) External Transactions can be scheduled without a 
Price Bid. (2) External Transactions can be scheduled with a Price 
Bid ($/MW) over some or all of the MW quantity being scheduled.
    (iii) External Transactions that are Exports may voluntarily 
submit a Decremental Energy Bid (in $/MW) over some or all of the MW 
range, which indicates the Customer's willingness to reduce the 
amount of Energy supplied at the Receipt Point at the Independent 
Transmission Provider's instruction (while retaining the amount of 
Energy withdrawn at the Delivery Point) when the Real-Time Energy 
LMP at the Receipt Point falls below the Decremental Energy Bid. 
External Transactions that are imports may voluntarily submit an 
Incremental Energy Bid (in $/MW) over some or all of the MW range, 
which indicates the Customer's willingness to reduce the amount of 
Energy withdrawn at the Delivery Point at the Independent 
Transmission Provider's instruction (while retaining the amount of 
Energy injected at the Receipt Point) when the Real-Time Energy LMP 
at the Delivery Point rises above the Incremental Energy Bid.
    (iv) The Independent Transmission Provider will adjust External 
Transactions schedules on quarter hour notice.
    (v) The Independent Transmission Provider shall accept Short 
Notice External Transactions (SNETs) following the Real-Time Trading 
Deadline up to some later SNET Deadline set by the Independent 
Transmission Provider. SNETs are not eligible to set Real-Time LMPs. 
SNETs have the lowest priority in the event of Curtailment of 
Customers.
    1.4  Rules for Bidding: The Independent Transmission Provider 
shall evaluate accept all eligible Bids for Energy Supply and 
Demand, Regulation, and Operating Reserves. The requirements for Bid 
eligibility and the Bid Specifications are in Sections G 3.4, G.5.4 
and G.7.4.

2. Security Constrained Intra-Day Unit Commitment and Dispatch

    2.1  Intra-Day Security Constrained Unit Commitment: The 
Independent Transmission Provider may undertake a periodic intra-day 
Security-Constrained Unit Commitment for Resources with Start-up and 
No-load costs not committed in the Day-Ahead Schedule.
    2.2  Security Constrained Dispatch: The Independent Transmission 
Provider shall run a Security Constrained Dispatch every five 
minutes to minimize the total Bid Production Costs of meeting the 
system Load and maintaining scheduled interchanges with adjacent 
Service Areas over the next Security Constrained Dispatch Interval. 
Bid Production Costs, for this purpose, will be calculated using 
selected Day-Ahead and Real-Time Bids for Energy and Ancillary 
Services submitted into the Real-Time Market. The Independent 
Transmission Provider shall dispatch the Power System consistent 
with the Bids that are submitted by Suppliers and accepted by the 
Independent Transmission Provider, while satisfying the actual 
system Load.
    2.3  Intra-Day Bid Revenue Sufficiency Guarantee: The 
Independent Transmission Provider shall ensure the minimum recovery 
of each Reserve's Bid prices for Resources scheduled after the close 
of the Day-Ahead Market, committed on an intra-day basis, or 
dispatched through the Real-Time Market.
    (i) The Independent Transmission Provider shall determine, on a 
daily basis, if any Resource committed by the Independent 
Transmission Provider in the Real-Time Market will not recover its 
Start-Up, No Load and Energy Bid Price through revenues in the Real-
Time Energy and Ancillary Services markets.
    (ii) If the Start-Up and No Load Bids plus the net Energy and 
Ancillary Services Bid Price over the twenty-four (24) hour day of 
any Supply Resource scheduled, committed, or dispatched by the 
Independent Transmission Provider exceeds its Real-Time LMP revenue 
and Ancillary Service Revenue over the twenty-four (24) hour day, 
then that Supplier's Real-Time LMP revenue, the Real-Time Supply Bid 
Revenue Sufficiency Guarantee payment, shall be augmented by an 
additional payment in the amount of the shortfall. Resources not 
scheduled, committed, or dispatched by the Independent Transmission 
Provider, but which continue to operate shall not receive such a 
payment. This payment shall be supported through revenue collected 
from the Supply Bid Revenue Sufficiency Guarantee Charge.
    (iii) If the total Real-Time Energy charges to any Demand 
Resource over the twenty-four (24) hour day exceeds its maximum 
willingness to pay, as reflected by the difference of its Real-Time 
Energy Bids and Start-up Cost Bid, the Demand Resource shall be 
augmented by a payment, the Demand Bid Revenue Sufficiency Guarantee 
Payment, in the amount of the overcharge. This payment is supported 
through revenues collected from the Demand Bid Revenue Sufficiency 
Guarantee Charge.

3. Real-Time Market for Energy

    3.1  General: The Real-Time Market for Energy establishes 
clearing prices and settlement rules for Suppliers of Energy that 
have offered eligible Energy capacity to the market and for 
Purchasers of Energy that have chosen not to self-supply or procure 
through bilateral contracts.
    3.2  Independent Transmission Provider Obligations: The 
Independent Transmission Provider has the obligations to provide 
services (i) to (v) for the Real-Time Market for

[[Page 55562]]

Energy. The rules governing these services are contained in this 
section.
    (i) Establish and post on its OASIS rules that are consistent 
with this Tariff for eligibility to supply Energy in the Real-Time 
Market.
    (ii) Establish and post on its OASIS the Bid data requirements 
and rules that are consistent with this Tariff and provide the 
market functions required for determination of hourly Real-Time 
Energy Market Clearing Prices and selection of Real-Time Energy 
Market Suppliers.
    (iii) Establish and post on its OASIS the rules that are 
consistent with this Tariff for determination of any Additional 
Payments necessary to support efficient operations of the Real-Time 
Energy Market and/or the efficient operation of other Real-Time 
Markets.
    (iv) Provide the Settlement functions associated with purchase 
and sale of Energy in the Real-Time Market.
    (v) Post the Real-Time LMPs for Energy.
    3.3  Purchaser Rules and Obligations
    3.3.1  Specification of Bids. Bids to Purchase Energy in the 
Real-Time Market for Energy shall have the same price, quantity and 
data requirements as Bids to Purchase Energy in the Day-Ahead Market 
for Energy, as set forth in Section F.2.3.1. Virtual Demand Bids are 
not permitted in the Real-Time Market.
    3.4  Supplier Rules and Obligations
    3.4.1  Eligibility to Supply
    (i) Suppliers of Real-Time Energy may not re-submit capacity 
selected for Energy in the Day-Ahead Market. Suppliers of Real-Time 
Energy may lower the Bid Price of capacity not selected for Energy 
in the Day-Ahead Market.
    (ii) Suppliers of Real-Time Energy shall provide the Bid 
information specified in Section F.2.4.2.
    3.4.2  Specification of Bids: Bids to Supply Energy in the Real-
Time Energy Market, including Incremental and Decremental Energy, 
have the same price, quantity and data requirements as Bids to 
Supply Energy in the Day-Ahead Market for Energy, as set forth in 
Sections F.2.3 (b)-(d). Virtual Supply Bids are not permitted in the 
Real-Time Market.
    3.4.3  Period of Bids to Supply Energy: Bids to Supply 
Incremental Energy or Decremental Energy pursuant to Sections 
F.3.4.1-3.4.2 can vary by price ($) and quantity (MW) in each Hour 
of the Real-Time Market.
    3.5  Calculation of Real-Time Locational Marginal Prices for 
Energy
    (i) Immediately in advance of each Security Constrained Dispatch 
Interval, the Independent Transmission Provider shall post the Real-
Time Energy LMPs for each bus on its system that it estimates will 
clear the market and match Generation with Load during the upcoming 
Security Constrained Dispatch Interval, based on the Real-Time Bids 
submitted. These estimated Energy LMPs shall be called Ex Ante LMPs. 
The pricing calculations for each of these LMPs should be the same 
as those for the Day-Ahead Market, as set forth in Section F.2.4, 
with the modifications contained in this Section G.3.5.
    (ii) Power system operations in the Real-Time Market, including, 
but not limited to, the determination of the least costly means of 
serving Load, depend upon the availability of a complete and 
consistent representation of Generator outputs, Loads, and power 
flows on the network. In calculating LMPs, the Independent 
Transmission Provider shall obtain a complete and consistent 
description of conditions on the electric network by using the most 
recent power flow solution produced by the Independent Transmission 
Provider's dispatch software and/or software that measures actual 
system conditions in Real-Time, such as a State Estimator.
    3.5.1  Ex Post Energy LMP Calculation: At the close of each 
Security Constrained Dispatch Interval, the Independent Transmission 
Provider shall calculate Energy LMPs for each bus on its system that 
shall be used for settlement of the Real-Time Market. These LMPs 
shall be called Ex Post Energy LMPs. The Ex Post Energy LMP for a 
Security Constrained Dispatch Interval at a given bus shall be equal 
to the lower of (a) the Ex Ante Energy LMP for that bus; and (b) the 
marginal cost of making available to the bus the Energy actually 
produced during the Security Constrained Dispatch Interval by 
suppliers that submitted Real-Time Energy Bids.
    3.5.2  Determination of Energy LMPs by Fixed Block Resources: In 
calculating LMPs in the Day-Ahead Market, the Bid of any Fixed Block 
Unit (i.e., a unit whose output cannot be adjusted in increments as 
small as 1 MW) will not be considered in calculating the Day-Ahead 
LMP at any bus. In calculating LMPs in the Real-Time Market, the 
price Bid of a Fixed Block Unit may set LMP, but only when some 
portion of its Energy is necessary to meet Load, displace higher 
cost Energy, or satisfy Operating Reserves Requirements. The 
marginal cost of a Fixed Block Unit that forces more economic units 
to be backed down will not set Real-Time LMP unless needed to meet 
Load, displace higher price Energy or meet Reserves requirements. 
The marginal cost of a Fixed Block Unit will not set Real-Time LMP 
at any other time, including those times when it is scheduled solely 
to meet its minimum runtime requirements or because of 
inflexibilities in its operation.
    3.5.3  Five Minute Real-Time LMPs: During the Operating Day, the 
LMP calculation shall be performed every [five minutes, or some 
other minute by minute interval determined by the system technology 
and software], using the Independent Transmission Provider's LMP 
methodology, producing a set of Real-Time Prices based on system 
conditions during the preceding interval.
    3.6  Calculation of Additional Payments and Charges
    3.6.1  Bid Revenue Sufficiency Guarantee: The Independent 
Transmission Provider shall calculate, for each Resource scheduled, 
committed or dispatched for Energy in the Real-Time Market, the 
amount of the Bid Revenue Sufficiency Guarantee payment, pursuant to 
Section G.2.3.
    3.6.2  Undergeneration by Suppliers
    (i) [The Independent Transmission Provider may file to establish 
pricing rules, including market-based penalties, for Suppliers of 
Energy that persistently provide less Energy in Real-Time than 
instructed. One market-based penalty is to require the Supplier to 
buy Regulation at the Real-Time Market Clearing Price for Regulation 
in a quantity equivalent to the Energy not provided.]
    (ii) [Exemptions: If the Independent Transmission Provider 
proposes penalties, suppliers, such as intermittants, that have 
constraints on following Dispatch Instructions or other operating 
limitations should be exempt from these penalties.]
    (iii) Replacement Reserve Penalty [The Transmission Provider may 
file to establish market-based penalties for Suppliers of Regulation 
that provide less Regulation in Real-Time than instructed.]
    3.6.3  Other Payments and Charges: [The Independent Transmission 
Provider may include in this section market rules for any other 
payments or charges associated with the efficient and reliable 
operations of the Real-Time Markets for Energy.]
    3.7  Market Rules for Shortages or Emergencies
    (i) [The Independent Transmission Provider may include in this 
section market rules, including calculation of market prices and 
determination of out-of-market payments, in the event of a shortfall 
in Energy in the Real-Time Market due to a shortage of available 
capacity or an Emergency. The market rules shall be in accord with 
regional or local reliability authority rules and procedures and 
NERC guidelines.]
    (ii) After the Day-Ahead Schedule is published, and up to a pre-
specified period prior to each Dispatch Hour, the Independent 
Transmission Provider may, after giving notice to affected 
Resources, in order to prevent or address an Emergency, raise their 
Bid-in upper operating limits to their maximum and make the 
additional capacity available to the Scheduling for the Real-Time 
Market.
    (iii) In the event of Emergency, Incremental Energy purchased 
above a Generator's Hourly Economic Maximum Level and up to the 
Generator's Hourly Emergency Maximum Level will be settled at the 
Real-Time LMPs. Decremental Energy purchased below the Hourly 
Economic Minimum Level and up to the Hourly Emergency Minimum Level 
will be settled at the higher of (1) the Bid Price for the 
Decremental Emergency Energy and (2) Real-Time LMPs.
    3.8  Settlement: The Independent Transmission Provider will 
provide timely settlement of purchases and sales of Energy in the 
Real-Time Market for Energy pursuant to Sections G.3.7.1 and 
G.3.7.2.
    3.8.1  Settlement when Actual Energy Injections are Less than 
Scheduled Energy Injections: When the actual Energy injections from 
a Supplier over a Security Constrained Dispatch Interval are less 
than its Energy scheduled in the Day-Ahead Market to be injected 
over that SCE interval, the Supplier shall pay for the difference in 
a charge equal to the product of: (a) the Real-Time Energy LMP 
calculated for that Security Constrained Dispatch Interval at the 
applicable Supplier's bus; and (b) the difference between the

[[Page 55563]]

scheduled Energy injections and the actual Energy injections at that 
bus.
    3.8.2  Settlement when Actual Energy Injections are Greater than 
Scheduled Energy Injections: When the actual Energy injections from 
a Supplier over a Security Constrained Dispatch Interval are greater 
than the Energy scheduled in the Day-Ahead Market to be injected 
over that Security Constrained Dispatch Interval, the Supplier shall 
be paid for the difference in a payment equal to the product of: (a) 
the Real-Time Energy LMP calculated for that Security Constrained 
Dispatch Interval at the applicable Supplier's bus; and (b) the 
difference between the actual Energy injections and the scheduled 
Energy injections at that bus.
    3.8.3  Settlement when Actual Energy Withdrawals are Less than 
Scheduled Energy Withdrawals: When a Customer's actual Energy 
withdrawals over a Security Constrained Dispatch Interval are less 
than its Energy withdrawals scheduled in the Day-Ahead Market over 
that Security Constrained Dispatch Interval, the Customer shall be 
paid the product of: (a) the Real-Time Energy LMP calculated for 
that Security Constrained Dispatch Interval at the applicable 
Customer's bus (or at the Customer's zone, if the Customer elects to 
calculate and settle Energy purchases at Zonal-LMPs and meets the 
conditions specified in Section F.2.4(c)(ii)); and (b) the 
difference between the scheduled Energy withdrawals and the actual 
Energy withdrawals at that bus.
    3.8.4  Settlement when Actual Energy Withdrawals are Greater 
than Scheduled Energy Withdrawals: When a Customer's actual Energy 
withdrawals over a Security Constrained Dispatch Interval are 
greater than its Energy withdrawals scheduled in the Day-Ahead 
Market over that Security Constrained Dispatch Interval, the 
Customer shall pay for the difference in a charge equal to the 
product of: (a) The Real-Time Energy LMP calculated for that 
Security Constrained Dispatch Interval at the applicable Customer's 
bus (or at the Customer's zone, if the Customer elects to calculate 
and settle Energy purchases at Zonal-LMPs and meets the conditions 
specified in Section F.2.4(c)(ii)); and (b) the difference between 
the actual Energy withdrawals and the scheduled Energy withdrawals 
at that bus.

4. Real-Time Scheduling for Transmission

    4.1  General: As in the Day-Ahead Market, Real-Time Energy LMPs 
serve dual functions, providing (1) the prices for sales and 
purchases of Energy and (2) market-based prices for Congestion 
Management, including Congestion Charges to Bilateral Transactions, 
and Marginal Losses.
    4.2  Transmission Bids: Customers may submit Bilateral 
Transaction Schedules that indicate whether or not they are willing 
to pay the Marginal Congestion Charge component of the Transmission 
Usage Charge. If the Bid indicates that the Customer is not willing 
to pay Congestion Charges, then the Bilateral Transaction will be 
scheduled only if there is no Marginal Congestion Charge in the 
Real-Time Market. If the Bid indicates that the Customer is willing 
to pay Congestion Charges, then the Bilateral Transaction will be 
scheduled regardless of the Marginal Congestion Charge in the Real-
Time Market.

4.3  Real-Time Transmission Usage Charges

    The Independent Transmission Provider shall charge a 
Transmission Usage Charge to all Bilateral Transactions whose 
transmission service was scheduled after the determination of the 
Day-Ahead schedule, or who schedule additional transmission service 
after the determination of the Day-Ahead schedule. This charge is 
the product of (a) the amount of Energy scheduled (as of pre-
determined trading deadline) to be withdrawn by that Customer in 
each hour, minus the amount of Energy scheduled Day-Ahead to be 
withdrawn by that Customer in that hour, in MWh; and (b) the Real-
Time LMP at the Point of Delivery (which could be a Load Zone in 
which Energy is scheduled to be withdrawn or the external bus where 
Energy is scheduled to be withdrawn if Energy is scheduled to be 
withdrawn at a location outside the Independent Transmission 
Provider Service Area), minus the Real-Time LMP at the Point of 
Receipt, in $/MWh. The Independent Transmission Provider shall 
divide each Transmission Usage Charge into separate components for 
Marginal Costs of Congestion and Marginal Costs of Losses.
    4.3.1  Marginal Congestion Component: The Marginal Congestion 
Component of the Transmission Usage Charge shall be calculated as 
the Marginal Congestion Component of the Real-Time LMP at the 
Delivery Point minus the Marginal Congestion Component of the Real-
Time LMP at the Receipt Point, as described in Section F.2.5(i).
    4.3.2  Marginal Losses Component: The Marginal Losses Component 
of the Transmission Usage Charge shall be calculated as the Marginal 
Losses Component of the Real-Time LMP at the Delivery Point minus 
the Marginal Losses Component of the Real-Time LMP at the Receipt 
Point, as described in Section F.2.5(ii).
    4.4  Calculation of Flowgate LMPs: The Independent Transmission 
Provider shall calculate and post Ex-Post Flowgate LMPs for the 
Real-Time Market.
    4.5  Marginal Loss Charge Collection: The Real-Time Marginal 
Loss Charge Collection for any SCD interval is defined here as the 
sum of the Real-Time Energy Marginal Loss Charge Collection plus the 
Real-Time Transmission Marginal Loss Charge Collection for that SCD 
interval. The Real-Time Energy Marginal Loss Charge Collection is 
defined for any SCD interval of the Real-Time Market as (i) the sum 
of the net amounts associated with the Marginal Loss Component of 
the applicable Real-Time Energy LMP charged to: (a) each Supplier 
whose actual Energy injections over the SCD interval are less than 
its Energy scheduled in the Day-Ahead Market to be injected over 
that SCD interval and (b) each Purchaser whose actual Energy 
withdrawals over the SCD interval exceed its Energy scheduled in the 
Day-Ahead Market to be withdrawn over that SCD interval; less: (ii) 
the sum of the net amounts associated with the Marginal Loss 
Component of the applicable Real-Time Energy LMP paid to (c) each 
Supplier whose actual Energy injections over the SCD interval exceed 
its Energy scheduled in the Day-Ahead Market to be injected over 
that SCD interval and (d) each Purchaser whose actual Energy 
withdrawals over the SCD interval are less than its Energy scheduled 
in the Day-Ahead Market to be withdrawn over that SCD interval. The 
Real-Time Transmission Marginal Loss Charge Collection for any SCD 
interval is defined for any SCD interval of the Real-Time Market as 
the net amounts charged to Customers for Transmission Service 
scheduled in the Real-Time Market for the SCD interval associated 
with the Marginal Cost Component of the applicable hourly 
Transmission Usage Charges; less the net amounts associated with the 
Marginal Cost Component of the applicable hourly Transmission Usage 
Charges paid to Customers for Transmission Service scheduled in the 
Day-Ahead Market for reductions in Transmission Service in the Real-
Time Market during the SCD interval.
    4.5.1  Determination and Disposition of Marginal Loss Revenue 
Surplus: For each SCD interval of the Real-Time Market, the 
Independent Transmission Provider shall calculate the Marginal Loss 
Charge Collection and the Net Energy Revenue Owed to Generators for 
Losses associated with all Transactions. For each SCD interval of 
the Real-Time Market where the Marginal Loss Charge Collection 
exceeds the Net Energy Revenue Owed to Generators for Losses 
associated with all Transactions, the Independent Transmission 
Provider shall allocate the revenue surplus to reduction in the 
charge for Network Access Service. [The Independent Transmission 
Provider shall determine the exact allocation to each Customer and 
will file procedures for determining the allocation of the revenue 
surplus to each Customer.]
    4.6  Disposition of Other Real-Time Revenue Surplus or Deficit: 
The Independent Transmission Provider shall calculate, for each 
Operating Day, the interval of the Real-Time Market, and the net 
revenue surplus or deficit from the operation of the Real-Time 
Market (defined as the difference between the revenues collected 
from all sources and all payment made to all sources, excluding the 
surplus for losses calculated pursuant to Section G.4.5). The 
Independent Transmission Provider shall allocate the revenue surplus 
or deficit for the Operating Day to the Transmission Owners. [The 
Independent Transmission Provider shall file procedures for 
determining the allocation of the surplus or deficit to Transmission 
Owners.]

5. Real-Time Market for Regulation

    5.1  General: The Transmission Provider may require additional 
Regulation capability in response to system conditions in the 
Operating Day. The Real-Time Market for Regulation establishes 
clearing prices and settlement rules for eligible Suppliers of 
Regulation that have offered Regulation capacity following the close 
of the Day-Ahead Market. The Transmission Provider shall procure 
Regulation in this market on behalf of Purchasers who choose not to 
Self-supply or purchase through bilateral contracts. Both Generation 
and Load may to provide Regulation in the Real-Time Market if they 
meet criteria for eligibility.

[[Page 55564]]

    5.2  Independent Transmission Provider Obligations: The 
Independent Transmission Provider has the obligation to provide 
services (i) to (viii) for the Real-Time Market for Regulation. The 
rules governing these services are contained in this section:
    (i) Establish and post on its OASIS criteria and requirements in 
accord with local reliability authority rules and NERC guidelines 
such that there is sufficient provision of Regulation in the Real-
Time Dispatch.
    (ii) Establish and post on its OASIS rules for eligibility to 
supply Regulation in the Real-Time Market.
    (iii) Provide Base Point Signals to Generators providing 
Regulation to direct the Generator's output.
    (iv) Establish and post on its OASIS the Bid data requirements 
and rules and provide the market functions required for 
determination of hourly Real-Time Regulation Market Clearing Prices 
and selection of Real-Time Regulation Market Suppliers. Establish 
how the pricing rules and selection procedures will be modified in 
the event of a shortage of Regulation capacity during the Operating 
Day.
    (v) Monitor the Suppliers' performance to ensure that they 
provide Regulation Service as required.
    (vi) Establish and post on its OASIS the rules for determination 
of any Additional Payments necessary to support efficient operations 
of the Real-Time Regulation Market and/or the efficient operation of 
other Real-Time Markets.
    (vii) Provide the Settlement functions associated with purchase 
and sale of Regulation in the Real-Time Market.
    (viii) Post the Real-Time Regulation Market Clearing Prices.
    5.3  Purchaser Rules and Obligations
    (i) Market Participants with a Regulation Requirement may 
fulfill their requirement by (1) self-scheduling an eligible 
Generator or Demand-Side Resource, (2) a bilateral contract with an 
eligible Supplier, or (3) purchasing from the Regulation Market.
    (ii) Self-suppliers and purchasers of Regulation through 
Bilateral Contract must provide data on location and physical 
capabilities of the Generator or Supplier providing Regulation (see 
Section 4.2).

5.4  Supplier Rules and Obligations

5.4.1  Eligibility to Supply

    (i) Suppliers of Regulation may only use Generators and/or Load 
that are electrically within the Independent Transmission Provider's 
Service Area.
    (ii) Suppliers of Regulation may only use Generators and/or Load 
that are able to respond to AGC Base Point Signals sent by the 
Independent Transmission Provider pursuant to the Independent 
Transmission Provider Procedures.
    (iii) Suppliers of Regulation may only use Generators and/or 
Load that meet Independent Transmission Provider standards for 
Generator performance.
    (iv) Suppliers of Regulation shall not use, contract to provide, 
or otherwise commit the capability that is designated to provide 
Regulation to provide Energy or Spinning Reserve to any party other 
than the Independent Transmission Provider.
    (v) Suppliers of Regulation shall provide the Bid information 
specified in Section 4.2.
    (vi) Suppliers of Real-Time Regulation may not re-submit 
capacity selected for Energy in the Day-Ahead Market. Suppliers of 
Real-Time Regulation may lower the Bid Price of capacity selected 
for Energy in the Day-Ahead Market.

5.4.2  Specification of Bids

    Suppliers of Regulation must provide the following Bid 
information:
    (i) Availability Bid price ($/MWh).
    (ii) Regulation Capability (MW) of the Generator supplying 
Regulation.
    (iii) Response Rate (MW/Minute) of the Generator supplying 
Regulation.
    (iv) Upper and Lower Regulation Limits (MW).
    (v) Hours of availability to provide Regulation.
    (vi) Any additional physical data required by the Independent 
Transmission Provider.

5.4.3  Bidding and Scheduling Process

    (i) Bids rejected by the Independent Transmission Provider in 
the Day-Ahead Market may be modified and resubmitted into the Real-
Time Market by the Supplier to the Independent Transmission 
Provider. [The Independent Transmission Provider Tariff will provide 
Procedures].
    (ii) Bids in the Day-Ahead Market that are not accepted by the 
Independent Transmission Provider shall be automatically considered 
for the Real-Time Market, unless withdrawn by the Supplier.
    (iii) If a Supplier reduces its available MW subsequent to being 
scheduled to provide Regulation or Operating Reserves (either Day-
Ahead or in a Supplemental Commitment), and if it, as a result, can 
no longer provide both the amount of Energy it was scheduled to 
provide Day-Ahead and the amount of Regulation and Operating 
Reserves it was scheduled to provide, the Independent Transmission 
Provider will first reduce the amount of Operating Reserves it is 
scheduled to provide, and then will reduce the amount of Regulation 
it is scheduled to provide, until the total amount of Energy, 
Regulation and Operating Reserves it is scheduled to provide is 
equal to its available MW (or until it is no longer scheduled to 
provide Regulation or Operating Reserves).
    5.5   Calculation of Market Clearing Price: The Independent 
Transmission Provider shall calculate a Market Clearing Price for 
the Real-Time Market for Regulation, using the following 
methodology.
    The Independent Transmission Provider shall establish a Supplier 
Regulation Price for each Supplier based on the sum of the 
Supplier's Availability Bid and its Real-Time Unit-Specific 
Opportunity Cost (as defined below). The Real-Time Regulation Market 
Clearing Price shall be the higher of (i) the highest Supplier 
Regulation Price needed to meet the Independent Transmission 
Provider's Regulation Requirement for each Dispatch Interval, or 
(ii) the highest Market Clearing Price in Dispatch Interval for 
Spinning Reserves or Supplemental Reserves.
    The Unit-Specific Opportunity Costs of a Resource for bidding to 
sell Regulation shall be equal to the product of:
    (i) the deviation of the Regulation set point of the Generator 
that is required to provide Regulation from the Resource's output 
level if it had been scheduled or dispatched in economic merit order 
to provide Energy, times
    (ii) the greater of (a) the $/MWh difference between the Real-
Time Energy LMP at the generation bus for the Resource and the Real-
Time Bid price for Energy from the Resource (at the megawatt level 
of the Regulation set point for the Resource) in the Real-Time 
Energy Market or (b) zero.
    5.6  Calculation of Additional Payments and Charges
    5.6.1  Bid Revenue Sufficiency Guarantee: Resources scheduled 
for Regulation in the Real-Time Market are eligible for the Bid 
Revenue Sufficiency Guarantee, pursuant to Section G.2.3.
    5.6.2  Failure to Provide Regulation in Real-Time: The 
Independent Transmission Provider shall, if a Resource providing 
Regulation Service trips off line, immediately attempt to re-
establish a supply for the remainder of that Resource's commitment. 
Any additional cost incurred by the Independent Transmission 
Provider as a result of covering the defaulting Resource's remaining 
commitment shall be reimbursed to the Independent Transmission 
Provider by the defaulting Supplier. If the Availability payment for 
the replacement Regulation Service decreases, the Independent 
Transmission Provider shall not pay the defaulting Supplier the 
difference in cost.
    5.6.3  Other Payments and Charges: [The Independent Transmission 
Provider may include in this section market rules for any other 
payments or charges associated with the efficient and reliable 
operations of the Real-Time Markets for Regulation.]

5.7  Market Rules for Shortages or Emergencies

    (i) [The Independent Transmission Provider may include in this 
section market rules, including specification of quantities and 
calculation of prices, in the event of a shortfall in the required 
system requirements for Regulation in the Real-Time Market. The 
market rules shall be in accord with regional or local reliability 
authority rules and procedures and NERC guidelines.]
    5.8  Settlement: The Independent Transmission Provider will 
provide timely settlement of purchases and sales of Regulation in 
the Real-Time Market for Regulation pursuant to Sections 5.8.1and 
5.8.2.

5.8.1  Payments by Purchasers

    (i) The Independent Transmission Provider shall calculate the 
total obligation for Regulation for each Load-Serving Entity for 
each hour of the Operating Day. The total hourly obligation for each 
Load-Serving Entity in an Operating Day shall equal the product of 
(a) the total Regulation requirement for the Independent 
Transmission Provider's Service Area for the hour of the Operating 
Day and (b) the ratio of (1) the Load-Serving Entity's total actual 
Load in the hour to (2) the total actual Load in the Independent 
Transmission Provider's Service Area in the hour of the of the 
Operating Day. The net obligation for Regulation of a Load-Serving 
Entity in an hour of the Operating Day shall be equal to

[[Page 55565]]

the greater of (a) the Load-Serving Entity's total obligation minus 
the amount of Regulation that it has Self-Supplied in the Day-Ahead 
Market or (b) zero.
    (ii) For each hour of the Operating Day, each Load-Serving 
Entity shall be charged an amount equal to the product of (1) the 
aggregate net amount paid by the Independent Transmission Provider 
in the Day-Ahead and Real-Time Markets to procure Regulation for the 
hour, and (2) the ratio of (a) the Load-Serving Entity's net 
obligation for Regulation in the hour to (b) the sum of the net 
obligations for Regulation of all Load-Serving Entities in the 
Independent Transmission Provider's Service Area in the hour.

5.8.2  Payments to Suppliers

    (i) The Independent Transmission Provider shall pay Suppliers 
the Real-Time Regulation Market Clearing Price times the quantity 
(MW) of Regulation capability.
    (ii) The Independent Transmission Provider shall pay Suppliers 
any Additional Payments necessary to provide Real-Time Regulation in 
accord with efficient market operations.

5.9  Monitoring Suppliers and Generators

    (i) The Independent Transmission Provider may establish:
    (1) Resource performance measurement criteria;
    (2) Procedures to disqualify Suppliers using Resources that 
consistently fail to meet such criteria; and
    (3) Procedures to re-qualify disqualified Suppliers, which may 
include a requirement to first demonstrate acceptable performance 
for a time.
    (ii) The Independent Transmission Provider shall establish and 
implement a Performance Tracking System to monitor the performance 
of Resources that provide Regulation Service.
    (iii) Payments by the Independent Transmission Provider to each 
Supplier of Regulation Service may be based on the Resource's 
performance with respect to the performance indices. Suppliers that 
fail to perform at a level consistent with these indices may forfeit 
all or a substantial portion of their Availability payments, which 
would otherwise be payable for the subject hour. Suppliers that 
consistently fail to perform adequately may be disqualified by the 
Independent Transmission Provider, pursuant to Independent 
Transmission Provider Procedures. [The Independent Transmission 
Provider would include such procedures in this section.]

6.  Real-Time Market for Operating Reserve--Spinning Reserve

    6.1  General: The Transmission Provider may require additional 
Spinning Reserves capability in response to system conditions in the 
Operating Day. The Real-Time Market for Spinning Reserve establishes 
clearing prices and settlement rules for eligible Suppliers of 
Spinning Reserve that have offered Spinning Reserve capacity to the 
market. The Transmission Provider shall procure Regulation in this 
market on behalf of Purchasers who choose not to Self-supply or 
purchase through Bilateral Contracts. Both Generation and Load may 
Bid to provide Spinning Reserve in the Real-Time Market if they meet 
criteria for eligibility.
    6.2  Independent Transmission Provider Obligations: The 
Independent Transmission Provider has the obligation to provide 
services (i) to (viii) for the Real-Time Market for Spinning 
Reserve. The rules governing these services are contained in this 
section:
    (i) Establish and post on its OASIS Spinning Reserve criteria 
and requirements in accord with local reliability authority rules 
and NERC guidelines.
    (ii) Establish and post on its OASIS rules for eligibility to 
supply Spinning Reserve in the Real-Time Market.
    (iii) Establish and post on its OASIS minimum technical 
requirements and performance standards for a Generator and/or Load 
to provide Spinning Reserve.
    (iv) Establish and post on its OASIS the Bid data requirements 
and rules and provide the market functions required for 
determination of hourly Real-Time Spinning Reserve Market Clearing 
Prices and selection of Real-Time Spinning Reserve Market Suppliers. 
It shall make this selection with the objective of minimizing the 
cost of meeting Load and providing all necessary Ancillary Services 
in that hour. Establish how the pricing rules and selection 
procedures will be modified in the event of a shortage of Spinning 
Reserve capacity during the Operating Day.
    (v) Establish and post on its OASIS the rules for determination 
of any Additional Payments necessary to support efficient operations 
of the Real-Time Spinning Reserve Market and/or the efficient 
operation of other Real-Time Markets.
    (vi) Provide the Settlement functions associated with purchase 
and sale of Spinning Reserve in the Real-Time Market.
    (vii) Post the Real-Time Spinning Reserve Market Clearing 
Prices.

6.3  Purchaser Rules and Obligations

    6.3.1  Market Participants with a Spinning Reserve Requirement 
may fulfill their requirement by
    (i)(1) self-supplying an eligible Generator or Demand-Side 
Resource; (2) a bilateral contract with an eligible Supplier; or (3) 
purchasing from the Spinning Reserve Market.
    (ii) Self-suppliers and purchasers of Spinning Reserve through 
Bilateral Contract must provide data on location and physical 
capabilities of the Generator or Supplier providing Spinning Reserve 
(see Section 4.2)
    6.4  Supplier Rules and Obligations: Suppliers whose Generators 
or demand side Resources have not been scheduled to provide Spinning 
Reserve and which still have Capacity that is synchronized with the 
grid and has not been committed for use in any other way may submit 
Bids to provide Spinning Reserve to the Independent Transmission 
Provider.

6.4.1  Eligibility to Supply

    (i) Suppliers of Spinning Reserve may only use Generators and/or 
Load that are electrically within the Independent Transmission 
Provider's Service Area.
    (ii) Suppliers of Spinning Reserve may only use Generators and/
or Load that meet Independent Transmission Provider standards for 
Generator performance.
    (iii) Suppliers may not contract to provide, or otherwise commit 
any Capacity from a Generator that has been scheduled to operate or 
to provide Operating Reserves, in either the Day-Ahead commitment or 
any supplemental commitment conducted by the Independent 
Transmission Provider.
    (iv) Suppliers of Spinning Reserve shall not use, contract to 
provide, or otherwise commit the capability that is designated to 
provide Spinning Reserve to provide Energy, Regulation or 
Supplemental Reserve to any party other than the Independent 
Transmission Provider. Suppliers may enter into alternate sales 
arrangements utilizing any capacity that has not been scheduled to 
operate or to provide Operating Reserves.
    (v) Suppliers of Spinning Reserve shall provide the Bid 
information specified in Section 4.2.
    (vi) Suppliers may not increase the Energy Bids made for the 
portions of those Generators that have been scheduled Day-Ahead to 
provide Spinning Reserve.
    (vii) Suppliers selected for Spinning Reserve in the Day-Ahead 
Market may not re-submit that capacity at a higher price into the 
Real-Time Market for Spinning Reserve. They may lower the Bid Price 
of the capacity not selected Day-Ahead to ensure selection in the 
Real-Time Market.
    6.4.2  Specification of Bids: Suppliers of Spinning Reserve must 
provide the following Bid information:
    (i) Response Rate (MW/Minute) of the Generator supplying 
Spinning Reserve.
    (ii) Hours of availability to provide Spinning Reserve.
    (iii) Any additional physical data required by the Independent 
Transmission Provider.

6.5  Calculation of Market Clearing Price

    6.5.1  Methodology for Calculation of Prices: The Independent 
Transmission Provider shall calculate a Market Clearing Price for 
the Real-Time Market for Spinning Reserve, using the following 
methodology.
    The Independent Transmission Provider shall establish a Supplier 
Spinning Reserve Price for each Supplier based on its Real-Time 
Unit-Specific Opportunity Cost (as defined below). The Real-Time 
Spinning Reserve Market Clearing Price shall be the higher of (i) 
the highest Supplier Spinning Reserve Price for each Dispatch 
Interval needed to meet the Independent Transmission Provider's 
Spinning Reserve Requirement, or (ii) the highest Market Clearing 
Price in the Dispatch Interval for Supplemental Reserves.
    The Unit-Specific Opportunity Costs of a Resource Bidding to 
sell Spinning Reserve shall be equal to the product of:
    (i) the deviation of the set point (MWh) of the Generator that 
is required to provide Spinning Reserve from the Resource's output 
level if it had been scheduled or dispatched in economic merit order 
to provide Energy, times
    (ii) the greater of (a) the $/MWh difference between the Real-
Time Energy LMP at the generation bus for the Resource and the Bid 
price for Energy from the Resource (at the megawatt level of the 
Spinning Reserve set

[[Page 55566]]

point for the Resource) in the Real-Time Energy Market or (b) zero.
    6.5.2  Calculation of Zonal or Locational Prices: Separate Real-
Time Spinning Reserve Market Clearing Prices will be calculated for 
Spinning Reserve located in each distinct Reserve Location for which 
there is a separate Spinning Reserve requirement. When there are no 
binding transmission constraints between Reserve Locations, the 
Real-Time Spinning Reserve Market Clearing Price shall be the same 
in each of the locations.
    6.5.3  Transmission for Operating Reserves. A Supplier located 
outside of a particular Reserve Location may provide Spinning 
Reserves if the necessary transmission arrangements to deliver 
Energy from the Supplier's capacity to the Reserve Location are 
made. The cost of any transmission service would have to be included 
in evaluating the total cost of Operating Reserves.
    Suppliers scheduled for Spinning Reserve shall not receive 
Opportunity Cost payments for capacity that was not available to be 
scheduled to generate Energy.

6.6  Calculation of Additional Payments and Charges

    6.6.1  Bid Revenue Sufficiency Guarantee: Resources scheduled 
for Spinning Reserve in the Real-Time Market are eligible for the 
Bid Revenue Sufficiency Guarantee, pursuant to Section G.2.3.
    6.6.2  Failure to Perform in Real-Time: When reserve is 
activated, the Independent Transmission Provider shall measure 
actual performance against expected performance and may charge 
financial penalties to Suppliers of Spinning Reserve which fail to 
perform in accordance with their accepted Bids. [The Independent 
Transmission Provider may file penalties.]
    6.6.3  Other Payments and Charges: [The Independent Transmission 
Provider may include in this section market rules for any other 
payments or charges associated with the efficient and reliable 
operations of the Real-Time Markets for Spinning Reserves.]
    6.7  Market Rules for Shortages or Emergencies
    (i) [The Independent Transmission Provider may include in this 
section market rules, including specification of quantities, 
calculation of market clearing prices, and determination of out of 
market payments in the event of a shortfall in the required system 
requirements for Spinning Reserves due to a shortage of available 
capacity or an Emergency.]
    (ii) In the event of a shortfall of total capacity available for 
Operating Reserves in the Real-Time Market, the Independent 
Transmission Provider shall first reduce the amount of Supplemental 
Reserve that is procured, followed by the amount of Supplemental 
Reserve, followed by the amount of Spinning Reserve.
    6.8  Settlement: The Independent Transmission Provider will 
provide timely settlement of purchases of Spinning Reserves and 
sales of Spinning Reserve in the Real-Time Market for Spinning 
Reserve pursuant to Sections 6.8.1 and 6.8.2.

6.8.1  Payments by Purchasers

    (i) The Independent Transmission Provider shall calculate the 
total obligation for Spinning Reserve for each Load-Serving Entity 
for each hour of the Operating Day. The hourly total obligation of 
each Load-Serving Entity in an Operating Day shall equal the product 
of (a) the total Spinning Reserve Requirement for the Independent 
Transmission Provider's Service Area for the hour of the Operating 
Day and (b) the ratio of (1) the Load-Serving Entity's total actual 
Load in the hour to (2) the total actual Load in the Independent 
Transmission Provider's Service Area in the hour of the Operating 
Day. The net obligation for Spinning Reserve of a Load-Serving 
Entity in an hour of the Operating Day shall be equal to the greater 
of the Load-Serving Entity's total obligation minus the amount of 
Spinning Reserve that is Self-Supplied in the Day-Ahead Market or 
(b) zero.
    (ii) For each hour of the Operating Day, each Load-Serving 
Entity shall be charged an amount equal to the product of (1) the 
aggregate net amount paid by the Independent Transmission Provider 
in the Day-Ahead and Real-Time Markets to procure Spinning Reserve 
for the hour and (2) the ratio of the Load-Serving Entity's net 
obligation for Spinning Reserve in the hour to the sum of the net 
obligations for Spinning Reserve of all Load-Serving Entities in the 
Independent Transmission Provider's Service Area in the hour.

6.8.2  Payments to Suppliers

    (i) The Independent Transmission Provider shall pay each 
Supplier selected to provide more Spinning Reserve in an hour than 
it was scheduled Day-Ahead the Real-Time Spinning Reserve Market 
Clearing Price at its location, multiplied by the amount (MW) of 
Spinning Reserve that Supplier provided that was in excess of the 
amount scheduled to be provided Day-Ahead, if any.

6.8.3  Payments by Suppliers

    (i) The Supplier shall pay the Independent Transmission Provider 
for any Spinning Reserve that it was scheduled Day-Ahead to provide 
in an hour but did not provide. The payment will be the Real-Time 
Spinning Reserve Market Clearing Price at its location, multiplied 
by the amount (MW) of scheduled Spinning Reserve that Supplier did 
not provide.
    (ii) The Supplier shall pay the Independent Transmission 
Provider any Additional Payments associated with failure to perform 
according to its Real-Time schedule, pursuant to Section 6.6.
    6.9  Failure to Provide Operating Reserves: If a Supplier 
reduces its available capacity subsequent to being scheduled to 
provide Regulation Service or Operating Reserves (either Day-Ahead 
or in a commitment of Replacement Reserves), and if the Independent 
Transmission Provider must, as a result, reduce the amount of 
Operating Reserves that Supplier is scheduled to provide in 
accordance with this Tariff, the Independent Transmission Provider 
will first reduce the lowest quality Supplemental Reserve that 
Generator is scheduled to provide.
    If it is still necessary to reduce the amount of Operating 
Reserves that Supplier is scheduled to provide, the Independent 
Transmission Provider will reduce the amount, in order of quality, 
of the higher quality Supplemental Reserves that Generator is 
scheduled to provide.
    Finally, if it is still necessary to reduce the amount of 
Operating Reserves that Supplier is scheduled to provide, the 
Independent Transmission Provider will reduce the amount of Spinning 
Reserve that Generator is scheduled to provide.
    If a Supplier scheduled Day-Ahead to provide Operating Reserves 
trips off-line and consequently is unable to provide Spinning 
Reserve, or if the amount of Operating Reserves a Supplier is 
scheduled to provide is decreased due to a reduction in that 
Supplier's capacity, it shall be charged the Real-Time Operating 
Reserve price at its location in each hour for the relevant category 
of Operating Reserves applied to the reduction in the amount of 
Operating Reserves it was scheduled Day-Ahead to provide at that 
location.
    If the Independent Transmission Provider calls for a Supplier of 
any category of Operating Reserves (other than a Supplier that has 
previously tripped off-line) to generate Energy with part or all of 
the capacity that the Independent Transmission Provider has 
scheduled to provide any category of Operating Reserves, and that 
Supplier fails to provide the amount of Energy requested by the 
Independent Transmission Provider within the time applicable for the 
scheduled Operating Reserves, the Independent Transmission Provider 
shall:
    (i) not pay the non-performing Supplier for any shortfall in the 
amount of Energy provided;
    (ii) charge the Supplier for any shortfall in the amount of 
Energy provided, at the Real-Time LMP for Energy at that Supplier's 
location;
    (iii) charge the Supplier a regulation penalty; and
    (iv) reduce any Availability payments for the scheduled 
Operating Reserves, and any Opportunity Cost payments, if 
applicable, that the Supplier would otherwise have received for the 
24-hour billing period in which that Supplier failed to perform as 
scheduled. The Availability payments and the Opportunity Cost 
payments, if applicable, that the Supplier would have received will 
be calculated by multiplying the average ratio of the amount of 
Energy supplied to the amount of Energy scheduled, during any 
activation of that Supplier during that 24-hour billing period by 
the applicable Availability payments and Opportunity Cost payments, 
if applicable, that the Supplier would otherwise have received.
    If a Generator providing Operating Reserves has repeatedly 
failed to provide Energy when called upon by the Independent 
Transmission Provider, the Independent Transmission Provider may 
preclude that Generator from providing Operating Reserves in the 
future. If a specific Generator has been precluded from supplying 
Operating Reserves, the Independent Transmission Provider shall 
require that Generator to pass

[[Page 55567]]

a re-qualification test before accepting any additional Bids to 
supply Operating Reserves from that Generator.

7. Real-Time Markets for Operating Reserves--Supplemental Reserves

    7.1  General: The Transmission Provider may require additional 
Supplemental Reserves capability in response to system conditions in 
the Operating Day. The Real-Time Markets for Supplemental Reserves 
establish clearing prices and settlement rules for eligible 
Suppliers of Supplemental Reserve that have offered Supplemental 
Reserve capacity to the market. The Transmission Provider shall 
procure Supplemental Reserves for Purchasers that have chosen not to 
Self-supply or purchase through Bilateral Contracts. Both Generation 
and Load may Bid to provide Supplemental Reserves in the Real-Time 
Market if they meet criteria for eligibility.
    7.2  Independent Transmission Provider Obligations: The 
Independent Transmission Provider has the obligation to provide 
services (i) to (vii) for the Real-Time Markets for Supplemental 
Reserves. The rules governing these services are contained in this 
section:
    (i) Establish and post on its OASIS Supplemental Reserves 
criteria and requirements in accord with local reliability authority 
rules and NERC guidelines.
    (ii) Establish and post on its OASIS rules for eligibility to 
supply Supplemental Reserves in the Real-Time Market.
    (iii) Establish and post on its OASIS minimum technical 
requirements and performance standards for a Generator to provide 
Supplemental Reserves.
    (iv) Establish and post on its OASIS the Bid data requirements 
and rules and provide the market functions required for 
determination of hourly Real-Time Supplemental Reserves Market 
Clearing Prices and selection of Real-Time Supplemental Reserves 
Market Suppliers. Establish how the pricing rules and selection 
procedures will be modified in the event of a shortage of 
Supplemental Reserves capacity during the Operating Day.
    (v) Establish and post on its OASIS the rules for determination 
of any Additional Payments necessary to support efficient operations 
of the Real-Time Supplemental Reserves and/or the efficient 
operation of other Real-Time Markets.
    (vi) Provide the Settlement functions associated with purchase 
and sale of Supplemental Reserves in the Real-Time Market.
    (vii) Post the Real-Time Supplemental Reserves Market Clearing 
Prices.

7.3  Purchaser Rules and Obligations

    (i) Market Participants with Supplemental Reserves requirements 
may fulfill their requirement by (1) self-supplying an eligible 
Generator or Demand-Side Resource, (2) a bilateral contract with an 
eligible Supplier, or (3) purchasing from the Supplemental Reserves 
Market.
    (2) Self-suppliers and purchasers of Supplemental Reserves 
through Bilateral Contracts must provide data on location and 
physical capabilities of the Generator or Supplier providing 
Supplemental Reserve (see Section 4.2).

7.4  Supplier Rules and Obligations:

    (i) During the day, Suppliers that have not been scheduled to 
provide Supplemental Reserves and which still have capacity that has 
not been committed for use in any other way may submit Bids to 
provide Supplemental Reserves to the Independent Transmission 
Provider.
    (ii) The Real-Time Bids may differ from Bids that were made by 
those Suppliers in the Day-Ahead commitment subject to possible Bid 
restrictions imposed to mitigate market power.
    (iii) Suppliers Bidding to supply Supplemental Reserves that 
have not already been scheduled to provide Supplemental Reserves may 
change their Real-Time Bids from one hour to the next subject to 
possible Bid restrictions imposed to mitigate market power.
    (iv) The Independent Transmission Provider shall notify each 
Supplier of Supplemental Reserves that has been scheduled in the 
Real-Time dispatch of the amount of Supplemental Reserves it must 
provide. Any Supplier whose Bid to provide Supplemental Reserves is 
accepted by the Independent Transmission Provider in the Real-Time 
dispatch must make its Generators or demand side Resources available 
for dispatch by the Independent Transmission Provider. Suppliers of 
Supplemental Reserves shall respond to direction by the Independent 
Transmission Provider to activate.

7.4.1  Eligibility to Supply

    (i) Subject to Independent Transmission Provider requirements, 
Suppliers of Supplemental Reserves may use Generators and/or Load 
that are electrically within or outside the Independent Transmission 
Provider's Service Area.
    (ii) Suppliers of Supplemental Reserve may only use Generators 
and/or Load that meet Independent Transmission Provider standards 
for Generator performance.
    (iii) Suppliers of Supplemental Reserves shall not use, contract 
to provide, or otherwise commit the capability that is designated to 
provide Supplemental Reserves to provide Energy, Regulation or 
Spinning Reserve to any party other than the Independent 
Transmission Provider.
    (iv) Suppliers of Supplemental Reserves shall provide the Bid 
information specified in Section 4.2.
    (v) Suppliers may not use, contract to provide or otherwise 
commit any capacity on any Resource that has been scheduled to 
provide Supplemental Reserves in the Day-Ahead commitment or in the 
Real-Time dispatch.
    7.4.2  Specification of Bids: Suppliers of Supplemental Reserves 
must provide the following Bid information:
    (i) Response Rate (MW/Minute) of the Generator supplying 
Supplemental Reserve.
    (ii) Hours of availability to provide Supplemental Reserve.
    (iii) Any additional physical data required by the Independent 
Transmission Provider.

7.5  Calculation of Market Clearing Price for Supplemental Reserve

    7.5.1  Methodology for Calculation of Prices: The Independent 
Transmission Provider shall calculate a Market Clearing Price for 
each Real-Time Market for Supplemental Reserves, using the following 
methodology.
    The Independent Transmission Provider shall establish a Supplier 
Supplemental Reserve Price for each Supplier based on Unit-Specific 
Opportunity Cost (as defined below). The Real-Time Supplemental 
Reserve Market Clearing Price shall be the higher of (i) the highest 
Supplier Supplemental Reserve Price needed to meet the Independent 
Transmission Provider's Supplemental Reserve Requirement for each 
Dispatch Interval, or (ii) the Market Clearing Price in any Dispatch 
Interval for any lower quality Supplemental Reserve.
    The Unit-Specific Opportunity Costs of a Resource Bidding to 
sell Supplemental Reserve in each Dispatch Interval shall be equal 
to the product of:
    (i) the deviation of the set point (MWh) of the Generator that 
is required in order to provide Supplemental Reserve from the 
Resource's output level if it had been scheduled or dispatched in 
economic merit order to provide Energy, times
    (ii) the absolute value of the difference between the Real-Time 
Energy LMP at the generation bus for the Resource and the Bid price 
for Energy from the Resource (at the megawatt level of the 
Supplemental Reserve set point for the Resource) in the Real-Time 
Energy Market.
    7.5.2  Calculation of Zonal or Locational Prices. Separate Real-
Time Supplemental Reserve Market Clearing Prices will be calculated 
for Supplemental Reserve located in each distinct Reserve Location 
for which there is a separate Supplemental Reserve requirement. When 
there are no binding transmission constraints between Reserve 
Locations, the Real-Time Ancillary Price for Supplemental Reserve 
shall be the same in each of the locations.
    7.5.3  Transmission for Operating Reserves. A Supplier located 
outside of a particular Reserve Location may provide Supplemental 
Reserve if the necessary transmission arrangements to deliver Energy 
from the Supplier's capacity to the Reserve Location are made. The 
cost of any transmission service would have to be included in 
evaluating the total cost of Operating Reserves.

7.6  Calculation of Additional Payments and Charges

    7.6.1  Bid Revenue Sufficiency Guarantee: Resources scheduled 
for Supplemental Reserves in the Real-Time Market are eligible for 
the Bid Revenue Sufficiency Guarantee, pursuant to Section G.2.3.
    7.6.2  Failure to Perform in Real-Time: When reserve is 
activated, the Independent Transmission Provider shall measure 
actual performance against expected performance and shall charge 
financial penalties as detailed in Section 6.9, to Suppliers of 
Reserves which fail to perform in accordance with their accepted 
Bids. [The Independent Transmission Provider may file penalties.]
    7.6.3  Exceptions: Notwithstanding anything to the contrary in 
this Rate Schedule, no payments shall be made to any Supplier 
providing Operating Reserves for reserves provided by that Supplier 
in excess

[[Page 55568]]

of the amount of Operating Reserves scheduled by the Independent 
Transmission Provider either Day-Ahead or in any subsequent 
schedule.
    The market clearing price paid to Suppliers of any category of 
Operating Reserve shall not be determined by any Bid to supply 
Operating Reserve that has not been accepted by the Independent 
Transmission Provider.
    7.6.5  Other Payments and Charges: [The Independent Transmission 
Provider may include in this section market rules for any other 
payments or charges associated with the efficient and reliable 
operations of the Real-Time Markets for Supplemental Reserves.]

7.7  Market Rules for Shortages or Emergencies:

    (i) [The Independent Transmission Provider may include in this 
section market rules, including specification of quantities, 
calculation of market clearing prices, and determination of out of 
market payments in the event of a shortfall in the required system 
requirements for Supplemental Reserves due to a shortage of 
available capacity or an Emergency.]
    (ii) In the event of a shortfall of total capacity available for 
Supplemental Reserves in the Real-Time Market, the Independent 
Transmission Provider shall first reduce the amount of any lower 
quality Supplemental Reserve that is procured, in order of quality, 
followed by the amount of higher quality Supplemental Reserves.
    7.8  Settlement: The Independent Transmission Provider will 
provide timely settlement of purchases of Supplemental Reserves and 
sales of Supplemental Reserves in the Real-Time Market pursuant to 
Sections 7.8.1 and 7.8.2.

7.8.1  Payments by Purchasers

    (i) The Independent Transmission Provider shall calculate the 
total obligation for Supplemental Reserve for each Load-Serving 
Entity for each hour of the Operating Day. The hourly total 
obligation of each Load-Serving Entity in an Operating Day shall 
equal the product of (a) the total Supplemental Reserve Requirement 
for the Independent Transmission Provider's Service Area for the 
hour of the Operating Day and (b) the ratio of (1) the Load-Serving 
Entity's total actual Load in the hour to (2) the total actual Load 
in the Independent Transmission Provider's Service Area in the hour 
of the Operating Day. The net obligation for Supplemental Reserve of 
a Load-Serving Entity in an hour of the Operating Day shall be equal 
to the greater of the Load-Serving Entity's total obligation minus 
the amount of Supplemental Reserve that is Self-Supplied in the 
Real-Time Market or (b) zero.
    (ii) For each hour of the Operating Day, each Load-Serving 
Entity shall be charged an amount equal to the product of (1) the 
aggregate net amount paid by the Independent Transmission Provider 
in the Real-Time Markets to procure Supplemental Reserve for the 
hour and (2) the ratio of the Load-Serving Entity's net obligation 
for Spinning Reserve in the hour to the sum of the net obligations 
for Supplemental Reserve of all Load-Serving Entities in the 
Independent Transmission Provider's Service Area in the hour.

7.8.2  Payments to Suppliers

    (i) The Independent Transmission Provider shall pay each 
Supplier selected to provide more Supplemental Reserve in an hour 
than it was scheduled Day-Ahead the Real-Time Supplemental Reserve 
Market Clearing Price at its location, multiplied by the amount (MW) 
of Supplemental Reserve that Supplier provided that was in excess of 
the amount scheduled to be provided Day-Ahead, if any.

7.8.3  Payments by Suppliers

    (i) The Supplier shall pay the Independent Transmission Provider 
for any Supplemental Reserves that it was scheduled Day-Ahead to 
provide in an hour but did not provide. The payment will be the 
Real-Time Supplemental Reserve Market Clearing Price at its 
location, multiplied by the amount (MW) of Day-Ahead scheduled 
Supplemental Reserve that the Supplier did not provide.
    (ii) The Supplier shall pay the Independent Transmission 
Provider any Additional Payments associated with failure to perform 
according to its Real-Time schedule, pursuant to Section 7.6.3.

8. Other Real-Time Payments and Charges

8.1  Bid Revenue Sufficiency Guarantee Payments for Replacement 
Reserves

    8.1.1  Payments to Suppliers. The Independent Transmission 
Provider shall determine, on a daily basis, if any Resource that it 
has committed to provide Replacement Reserves for the operating day 
pursuant to Section F.1.8 has not recovered its Start-up, No-load, 
and Energy Bid Prices through revenues in the Real-Time Energy and 
Ancillary Services Markets. If the Start-up, No-load, and Energy 
Bids over the twenty-four (24) hour Operating Day of any such 
Resource exceed its combined Revenue from the Real-Time Markets for 
Energy and Ancillary Services, then that Resource's revenue shall be 
augmented by an additional payment, called the Real-Time Bid Revenue 
Sufficiency Guarantee payment, in the amount of the revenue 
shortfall.
    8.1.2  Charges to Customers. A purchase of Real-Time Energy is 
deemed to be made by any Customer whose actual Energy injections in 
any hour of the Operating Day is less than its injections scheduled 
for that hour in the Day-Ahead Market, and by any Customer whose 
actual Energy withdrawals in any hour in the Operating Day exceed 
its withdrawals scheduled for that hour in the Day-Ahead Market. All 
uninstructed purchases of Real-Time Energy, i.e., Real-Time Energy 
purchased by a Customer without being instructed to do so by the 
Independent Transmission Provider, shall be subject to a Replacement 
Reserves charge. The Independent Transmission Provider shall 
calculate Replacement Reserves charges for the Operating Day as 
follows. The Independent Transmission Provider shall calculate the 
sum of all uninstructed purchases of Real-Time Energy over the 
Operating Day and shall compare that sum to the aggregate MWhs of 
Replacement Reserves that it committed over the Operating Day 
pursuant to Section F.1.8.
    (i) If the sum of all uninstructed purchases of Real-Time Energy 
greater than or equal to the aggregate MWhs of Replacement Reserves 
committed over the Operating Day, then the Replacement Reserve 
charge for each Customer i shall be calculated as:

Replacement Reserve charge for Customer i = (P/U) x ui;
where:

P is the sum of the aggregate payments made pursuant to Section 
G.8.1.1 for the Operating Day;
U is the sum of all uninstructed purchases of Real-Time Energy by 
all Customers (in MWhs) over the Operating Day; and
ui is the aggregate uninstructed purchases of Real-Time 
Energy by Customer i over the Operating Day.
    (ii) If the sum of all uninstructed purchases of Real-Time 
Energy is less than the aggregate MWhs of Replacement Reserves 
committed over the Operating Day, then the Replacement Reserve 
charge for each Customer i shall be calculated as:

Replacement Reserve charge for Customer i = (P/R) x d;
where:

P is the sum of the aggregate payments made pursuant to Section 
G.8.1.1 for the Operating Day;
R is the aggregate MWhs of Replacement Reserves that the Independent 
Transmission Provider has committed over the Operating Day pursuant 
to Section F.1.8.
ui is the aggregate uninstructed purchases of Real-Time 
Energy by Customer i over the Operating Day.
    8.1.3  Unrecovered Bid Revenue Sufficiency Guarantee Payments. 
Any amounts of Bid Revenue Sufficiency Guarantee payments for an 
Operating Day made pursuant to Section G.8.1.1 that are not 
recovered through Replacement Reserve charges for the Operating Day 
pursuant to Section G.8.1.2 shall be recovered in a separate charge 
to all Load-Serving Entities in the Independent Transmission 
Provider's Service Area. The charge for each Load-Serving Entity for 
the Operating Day shall equal to the product of (a) the total 
amounts of Bid Revenue Sufficiency Guarantee payments for an 
Operating Day made pursuant to Section G..8.1.1 that are not 
recovered through Replacement Reserve charges for the Operating Day 
pursuant to G.8.1.2 and (b) the ratio of (1) the Load-Serving 
Entity's total actual Load over the Operating Day to (2) the total 
actual Load within the Independent Transmission Provider's Service 
Area over the Operating Day.

8.2  Other Real-Time Bid Revenue Sufficiency Guarantee Payments

    8.2.1  Payments to Suppliers. The Independent Transmission 
Provider shall pay each Resource scheduled, committed, or dispatched 
by the Independent Transmission Provider after the close of the Day-
Ahead Market (other than a Resource committed to supply Replacement 
Reserves) the real-time Bid Revenue Sufficiency Guarantee payment 
for the Operating Day, calculated pursuant to Section G.2.3(ii).
    8.2.2  Charges to Customers. A purchase of Real-Time Energy is 
deemed to be made by any Customer whose actual Energy injections in 
any hour of the Operating Day

[[Page 55569]]

is less than its injections scheduled for that hour in the Day-Ahead 
Market, and by any Customer whose actual Energy withdrawals in any 
hour in the Operating Day exceed its withdrawals scheduled for that 
hour in the Day-Ahead Market. Each Customer purchasing Real-Time 
Energy shall pay a Real-Time Bid Revenue Sufficiency Guarantee 
payment. The Bid Revenue Sufficiency Guarantee payment for any 
Customer i for the Operating Day shall be calculated based on the 
following formula:

Bid Revenue Sufficiency Guarantee for Customer i = G x 
(Ci / D)
    where:

G is the sum of all Bid Revenue Sufficiency Guarantee payments made 
for the Operating Day pursuant to Section G.8.2.1;
Ci is the total purchases of Real-Time Energy by Customer 
i during the Operating Day; and
D is the sum of the total purchases of Real-Time Energy by all 
Customers over the Operating Day.

Part IV. Market Monitoring

    Each Independent Transmission Provider must file a market 
monitoring plan in accordance with the Commission's regulations as 
part of this Tariff.

H. Market Power Mitigation and Market Monitoring

1. Market Power Mitigation

    1.1  Participating Generator Agreements: The participating 
generator agreement between the Independent Transmission Provider 
and a generator will include a provision to require that all 
available capacity of the generator must be scheduled or offered to 
the Day-Ahead and Real-Time markets at bids that do not exceed 
specified Bid caps under non-competitive conditions to be specified 
in the agreement.

1.2  Determination of Bid Caps

    1.2.1  The Safety-Net Bid Cap: The MMU will establish a safety-
net Bid cap that will apply to all markets at all times.
    1.2.2  Generator-specific Bid Caps: The MMU will establish for 
each Generator identified in Section H.1.4.1 below Bid caps that may 
apply to each Bid-in parameter when mitigation is warranted. These 
shall include: Bid caps for Energy, regulation service, operating 
reserves, start-up costs, no-Load costs, incremental and decremental 
Energy costs, and any other parameter allowed to vary in Day-Ahead 
and Real-Time markets.
    1.3  Determination of Available Capacity: Available capacity is 
all capacity not scheduled or on an outage.
    1.3.1  Adjustments to Available Capacity to Reflect Risk of 
Forced Outages in Real-Time Market: Independent Transmission 
Provider may file provisions.
    1.3.2  Available Capacity Reduced by Forced Outages Subject to 
Audit: Units declaring a forced outage would be subject to audit by 
the MMU. If the outage was not proved to be justified, then the 
Generator shall be subject to a penalty. [The Independent 
Transmission Provider shall specify the type of penalty.]

1.4  Determination of Non-competitive Conditions

    1.4.1  Local Non-competitive Conditions: The MMU shall identify 
specific Generators that are frequently needed to support the 
operation of the grid and sellers that own facilities in identified 
Load pockets with fewer than ----independent suppliers. 
Participating Generator Agreements for these entities will require 
that they be subject to Local Market Power Mitigation.
    1.4.2  Other Non-competitive Conditions: The MMU shall identify 
other non-competitive conditions as necessary.

1.5  Triggering Mitigation

    1.5.1  Market Power Mitigation Independent of Market Conditions: 
The Independent Transmission Provider may not accept any Bid into 
the Day-Ahead or Real-Time markets that exceeds the higher of: (a) 
the safety-net Bid cap specified in Section H.1.2.1; or (b) the bid 
cap specified in a Participating Generator Agreement.
    1.5.2  Market Power Mitigation Triggered by Section H.1.4.1: 
When mitigation is triggered by Section H.1.4.1, the units will be 
required to offer all available capacity to the Day-Ahead and Real-
Time markets at bids that do not exceed applicable bid caps 
determined in H.1.2.2.
    1.5.3  Market Power Mitigation Triggered by Section H.1.4.2: To 
be specified.

2. Market Monitoring Plan

    The transmission and power markets administered by the 
Independent Transmission Provider will be monitored on an on-going 
basis by the Market Monitoring Unit (MMU). The MMU reports directly 
to the Commission and the governing board of the transmission 
provider.
    2.1  Data Requirements and Data Collection: The MMU shall 
collect and evaluate data provided by the Independent Transmission 
Provider and Market Participants in order to identify inefficiencies 
in the markets or the market design, and individual Market 
Participant behavior that may be a prohibited exercise of market 
power or a violation of this Tariff or other market rules.
    2.1.1  Obligations of Market Participants: As a condition of 
participating in the markets operated by the Independent 
Transmission Provider, all Market Participants shall be required to 
comply with information requests from the MMU. Any disputes 
concerning whether the information is necessary or how the 
information is to be provided or how any confidential information 
could be used should first be attempted to be resolved either 
through dispute resolution or the Commission's Office of Market 
Oversight and Investigations (Hotline). If the parties are then 
unable to resolve the dispute, a complaint under Section 206 of the 
Federal Power Act may be filed.
    2.1.2  Generator-Specific data: The MMU shall have the 
responsibility to collect all Generator-specific data needed to 
evaluate whether a seller is exercising market power and to 
establish Bid restrictions that may be imposed when markets are not 
sufficiently competitive. The data shall include, at a minimum: 
start-up, no Load, and shut-down costs, environmental restrictions, 
fuel costs, maintenance costs, heat rates, ramp rates, high and low 
operating levels, and minimum run times.
    2.1.3  Data Acquired in the Course of Conducting Market 
Operations: The MMU shall have immediate access to all Bid data 
submitted to the Independent Transmission Provider.
    2.1.4  Other Publically Available Data: The Market Monitor shall 
collect all data needed to assess the overall competitiveness of its 
markets. The data would include, but not be limited to, information 
on market shares of Generation Capacity by type and location, 
information on planned and unplanned Generator and transmission 
outages, and plans for transmission expansions and upgrades, and 
Generator interconnection requests.
    2.1.5  Confidentiality: All information obtained by the MMU, 
that is specific to a Market Participant, shall be treated 
confidentially.
    2.2  Framework for Analyzing Market Structure and Generator 
Conduct
    2.2.1  Obligations of the Market Monitor: The MMU shall conduct 
a structural analysis of the markets in the region to include in a 
state of the market report to the Commission, the committee of state 
representatives, and the transmission provider's Board of Directors. 
In addition, the MMU must evaluate the conduct of Market 
Participants. Any flaws in the market rules that are identified by 
the Market Monitor, and any Market Participant conduct that 
indicates exercises of market power, shall be remedied 
prospectively, unless the conduct violates existing rules, in which 
case the consequences shall be predetermined and specified in this 
Tariff.
    2.2.1  Structural Analysis: The MMU shall develop an analysis of 
the overall competitiveness of the markets operated by the 
Transmission Provider. The analysis will be performed at least 
annually and will report on the following at a minimum: market 
concentration by Generator type and region, transmission constraints 
and Load pockets that may give rise to market power concerns, 
conditions for entry or new supply, the development of demand 
response, and development of a competitive benchmark.
    2.2.2  Conduct Analysis: The MMU will monitor the conduct of 
individual Market Participants. The Market Monitor shall review 
planned transmission and generation outages to ensure that 
scheduling outages are not used to enhance or create opportunities 
to exercise Generator market power. Analysis of Market Participant 
conduct may include a review of Bidding behavior to identify any 
auction design flaws that may give Market Participants an 
unanticipated incentive and ability to manipulate market-clearing 
prices or up-lift payments. Finally, the Market Monitor shall 
evaluate the effectiveness of the Participating Generator Agreements 
in mitigating market power where market structure is not 
sufficiently competitive.
    2.3  Annual Reports: No later than May 31 of each year, the 
Market Monitor shall file a State of the Markets Report with the 
Commission which includes the results of the Market Monitor's 
structural and conduct analyses. This report shall address such

[[Page 55570]]

items as market concentration, demand response programs, Load 
pockets, and transmission constraints and an assessment of the 
performance of the markets administered by the Transmission 
Provider. In addition, this report shall identify any actions taken 
by the Market Monitor.
    2.4  Periodic Reports: The Market Monitor shall submit a report 
to the Commission if it detects behavior that cannot be cured within 
the Market Monitor's authority or if it detects behavior that would 
require a change in market rules. These reports should be made as 
soon as practicable after the behavior is detected.

3. Rules for Market Participant Conduct: Market Participants must 
comply with the following rules:

    3.1  Physical Withholding: Entities may not physically withhold 
the output of an Electric Facility (Generating unit or Transmission 
Facility) by (a) falsely declaring that an Electric Facility has 
been forced out of service or otherwise become unavailable, or (b) 
failing to comply Section H.1.5.2.
    3.2  Economic Withholding: Entities may not economically 
withhold by submitting high bids that are not consistent with the 
caps specified in Section H.1.2.
    3.3  Availability Reporting: Entities must comply with all 
reporting requirements governing the availability and maintenance of 
a Generating Unit or Transmission Facility, including proper Outage 
scheduling requirements. Entities must immediately notify the 
Transmission Provider when capacity changes or resource limitations 
occur that affect the availability of the unit or facility or the 
ability to comply with dispatch instructions.
    3.4  Factual Accuracy: All applications, schedules, reports, or 
other communications to the Transmission Provider or the Market 
Monitor must be submitted by a responsible company official who is 
knowledgeable of the facts submitted. All information submitted must 
be true to the best knowledge of the person submitting the 
information.
    3.5  Information Obligation: Entities must comply with requests 
for information or data by the Market Monitor or the Transmission 
Provider that are consistent with the Tariff.
    3.6  Cooperation: Entities must assist and cooperate in 
investigations or audits conducted by the Market Monitor.
    3.7  Physical Feasibility: All Bids or schedules that designate 
Resources must be physically feasible within the limits of the 
Resource, i.e., the Resource is physically capable of supplying the 
Energy, Ancillary Service, or demand response needed to fulfill a 
schedule or Bid according to the physical limitations of the 
Resource.
    3.8  Enforcement: The Market Monitor is responsible for the 
enforcement of the rules in this section. Violations of these rules 
will be subject to the following penalties: [to be added]

I. Long-Term Resource Adequacy

    This section sets forth terms and conditions requiring each 
Load-Serving Entity to meet its share of the region's Resource 
Adequacy Requirement. The Resource Adequacy Requirement will ensure 
that in the future each Load-Serving Entity will have secured 
generation, transmission, and demand response resources sufficient 
to meet real-time load and a reasonable operating reserve margin 
necessary to maintain the stable and reliable operation of the 
transmission system.
    [Additional details will be completed and filed by each 
Independent Transmission Provider as part of its compliance filing.]

1. Data Submission for the annual forecast of future regional load

    (i) [There may be regional variation in forecast methodology. 
Some regions may wish to do a bottom up forecast. The following 
wording will then be needed.] [Annually, on or before ---------- 
(each Independent Transmission Provider shall insert the relevant 
date here), each Load Serving Entity shall submit its demand 
forecast for the Planning Horizon.]

2. Assignment of Resource Adequacy Requirements

    (ii) Annually, on or before ---------- [each Independent 
Transmission Provider shall insert the relevant date here], the 
Independent Transmission Provider shall assign a share of the 
region's Resource Adequacy Requirement to each Load Serving Entity 
within the region based on the ratio of the load.

3. Load Serving Entity's submission for Resource Adequacy Requirements

    (i) Annually, on or before ---------- [each Independent 
Transmission Provider shall insert the relevant date here], each 
Load Serving Entity shall submit a proposed plan to meet its 
assigned Resource Adequacy Requirement to the Independent 
Transmission Provider.
    (ii) Plans for meeting the assigned Resource Adequacy 
Requirement may rely upon generation, transmission, and/or demand 
response, subject to the standards set forth in this section of the 
Tariff, and Independent Transmission Provider's review of 
operational feasibility.
    (iii) The Independent Transmission Provider shall audit each 
plan for compliance with the standards set forth in Section I.4 and 
for operational feasibility. [Each Independent Transmission Provider 
shall establish a review and resubmission process, with reasonable 
time frames, to achieve compliant and operationally feasible plans 
within a specified end date.]

4. Resource Adequacy Requirement Standards

    (ii) Each Load-Serving Entity must satisfy the Independent 
Transmission Provider that the resources to be relied upon for 
future Resource Adequacy Requirements are in compliance with the 
standards of this section of the Tariff and are operationally 
feasible, dedicated to serving the Load-Serving Entity without prior 
or conflicting claim, and can be delivered to the load to be served 
as and if needed to meet future requirements.
    (ii) [Each Independent Transmission Provider shall list in its 
open access electricity transmission Tariff specific requirements it 
intends to impose on each Load-Serving Entity such that the Load 
Serving Entity's resources qualify to meet its share of the Resource 
Adequacy Requirement.]

5. Penalties

    [Each Independent Transmission Provider shall list in its open 
access electricity transmission Tariff specific penalties it intends 
to impose.]
    (i) Each Load-Serving Entity that has not met its allocated 
share of the Resource Adequacy Requirement, shall be subject to 
penalty rates for spot market energy purchases during the last year 
of the Planning Horizon to the extent of the resource shortage 
whenever the Independent Transmission Provider's market has 
available less than a minimally acceptable level of operating 
reserves.
    (ii) Penalties will increase on a graduated basis as the 
Independent Transmission Provider's operating reserves level falls 
below minimally acceptable levels. (For example, for deficiencies up 
to 1 percent, the penalty would be $500/MWh, plus the prevailing 
market price for energy. As the operating reserve level falls, the 
premium of the penalty over the prevailing market price for energy 
would increase: over 1 percent up to 2 percent, the penalty would be 
$600/MWh; over 2 percent up to 3 percent, the penalty would be $700/
MWh; and so forth.)

6. Curtailment

    (i) A Load-Serving Entity that fails to implement curtailment 
(load shedding) when ordered by the Independent Transmission 
Provider shall be assessed a penalty of $1,000 per MWh, in addition 
to the LMP, for all unauthorized energy taken following an 
instruction to implement curtailment (load shedding).

Part V. Other

J. Generation Interconnection Procedures (to be provided in a 
separate rule)

Part VI. Transmission Planning and Expansion

K. Transmission Planning and Expansion

    Each Independent Transmission Provider must file its 
transmission planning and expansion plan as part of this Tariff.

Part VI. Pro Forma Service Agreements

Form Of Service Agreement For Network Access Transmission Service

    1.0  This Service Agreement, dated as of------------, is entered 
into, by and between------------ (the Independent Transmission 
Provider), and ------------ (``Customer'').
    2.0  The Customer has been determined by the Independent 
Transmission Provider to have a Completed Application for Network 
Access Service under the Tariff.
    3.0  The Customer has provided to the Independent Transmission 
Provider an Application deposit, if applicable, in accordance with 
the provisions of Section B.2.2 of the Tariff.
    4.0  Service under this agreement shall commence on the later of 
(1) the requested service commencement date, or (2) the date on 
which construction of any Direct Assignment Facilities and/or 
Network Upgrades are completed, or (3) such other

[[Page 55571]]

date as it is permitted to become effective by the Commission. 
Service under this agreement shall terminate on such date as 
mutually agreed upon by the parties.
    5.0  The Independent Transmission Provider agrees to provide and 
the Customer agrees to take and pay for Network Access Service in 
accordance with the provisions of Part II of the Tariff and this 
Service Agreement.
    6.0  Any notice or request made to or by either Party regarding 
this Service Agreement shall be made to the representative of the 
other Party as indicated below.

Independent Transmission Provider:
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Customer:
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------

    7.0  The Tariff is incorporated herein and made a part hereof.
    IN WITNESS WHEREOF, the Parties have caused this Service 
Agreement to be executed by their respective authorized officials.

    Independent Transmission Provider:

By:--------------------------------------------------------------------
    Name
Title------------------------------------------------------------------
Date-------------------------------------------------------------------

Customer:
By:--------------------------------------------------------------------
    Name
Title------------------------------------------------------------------
Date-------------------------------------------------------------------

Specifications For Network Access Service for Customers with Designated 
Resources and for Long-Term Customers without Designated Resources

1.0  Term of Transaction:----------------------------------------------
    Start Date:--------------------------------------------------------
    Termination Date:--------------------------------------------------

2.0  Description of capacity and Energy to be transmitted by 
Independent Transmission Provider including the electric Service Area 
in which the transaction originates.-----------------------------------
-----------------------------------------------------------------------

3.0  Receipt Points or Network Resource(s):----------------------------
-----------------------------------------------------------------------
    Delivering Party:--------------------------------------------------

4.0  Delivery Points or Network Load:----------------------------------
    Receiving Party:---------------------------------------------------

5.0  Designation of party(ies) subject to reciprocal service 
obligation:------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------

6.0  Name(s) of any Intervening Systems providing transmission service:

-----------------------------------------------------------------------
8.0  Service under this Agreement may be subject to some combination 
of the charges detailed below plus any applicable Congestion 
Charges. (The appropriate charges for individual transactions will 
be determined in accordance with the terms and conditions of the 
Tariff.)

8.1  Network Access Charge:--------------------------------------------
-----------------------------------------------------------------------

8.2  System Impact and/or Facilities Study Charge(s):------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------

8.3  Direct Assignment Facilities Charge:------------------------------
-----------------------------------------------------------------------
8.4  Ancillary Services Charges:---------------------------------------

-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Form of Service Agreement for Market Services

    1. This Service Agreement dated as of ---------------- is 
entered into by and between ---------------- (Independent 
Transmission Provider) and ---------------- (Customer).
    2. The Customer represents and warrants that it has met all 
applicable requirements set forth in the Independent Transmission 
Provider's Tariff and has complied with all applicable Procedures 
under the Tariff.
    3. The Independent Transmission Provider agrees to provide and 
the Customer agrees to pay for Market Services in accordance with 
the provisions of the Independent Transmission Provider's Tariff and 
to satisfy all obligations under the terms and conditions of the 
Independent Transmission's Provider's Tariff, as may be amended from 
time-to-time, filed with the Federal Energy Regulatory Commission 
(Commission). The Independent Transmission Provider and the Customer 
all agree that this Service Agreement shall be subject to, and shall 
incorporate by reference, all of the terms and conditions of the 
Independent Transmission Provider's Tariff and Procedures.
    4. It is understood that, in accordance with the Independent 
Transmission Provider's Tariff, the Independent Transmission 
Provider may amend the terms and conditions of this Service 
Agreement by notifying the Customer in writing and make the 
appropriate filing with the Commission.
    5. The Customer represents and warrants that:
    (a) The Customer is an entity duly organized, validly existing 
and/or otherwise qualified to do business under the laws of the 
State of ------------ and is in good standing under its [insert 
organizational document] and the laws of the State of [insert state 
of organization];
    (b) This Service Agreement, or any Transaction entered into 
pursuant to the Service Agreement, as applicable, has been duly 
authorized;
    (c) The execution, delivery and performance of this Service 
Agreement will not materially conflict with, constitute a material 
breach of, or a material default under, any of the terms, 
conditions, or provisions of any law or order of any agency of 
government, the [insert organizational document] of the Customer, 
any contractual limitation, organizational limitation or outstanding 
trust indenture, deed of trust, mortgage, loan agreement, other 
evidence of indebtedness, or any other agreement or instrument to 
which Customer is a party or by which it or any of its property is 
bound, or in a material breach of, or a material default under, any 
of the foregoing; and
    (d) This Service Agreement is the legal, valid, and binding 
obligation of the Customer enforceable in accordance with its terms, 
except as it may be rendered unenforceable by reason of bankruptcy 
or other similar laws affecting creditors' rights, or general 
principles of equity.
    The Customer warrants and covenants that, during the term of the 
Service Agreement, the Customer shall be in compliance with all 
federal, state, and local laws, rules, and regulations related to 
the Customer's performance under the agreement.
    4. Service under this Service Agreement shall commence on the 
later of: --------------, or such other date as it is permitted to 
become effective by the Commission. Service under this Service 
Agreement shall terminate on ------------.
    5. The Independent Transmission Provider agrees to provide and 
the Customer agrees to take and pay for, or to supply to the 
Independent Transmission Provider, Energy, capacity, and Ancillary 
Services in accordance with the provisions of the Independent 
Transmission Provider's Tariff and this Service Agreement.
    6. Any notice or request made to or by either Party regarding 
this Service Agreement shall be made to the representative of the 
other Party as indicated below:

Independent Transmission Provider:
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Customer:
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
    7. Cancellation Rights:
    If the Commission or any regulatory agency having authority over 
this Service Agreement determines that any part of this Service 
Agreement must be changed, the Independent Transmission Provider 
shall offer to the Customer an amended Service Agreement reflecting 
such changes. In the event that the Customer does not execute such 
an amendment within thirty (30) days, or longer if the Parties 
mutually agree to an extension, after the Commission's action, this 
Service Agreement and the amended Service Agreement shall be void.
    8. Early Termination by the Customer:
    The Customer may terminate service under this Service Agreement 
no earlier than ninety (90) days after providing the Independent 
Transmission Provider with written notice of the Customer's 
intention to terminate; except that a Load-Serving Entity must 
continue to take service under the Independent Transmission 
Provider's Tariff as long as it continues to serve Load within the 
Independent Transmission Provider's Service Area. In the event that 
tax-exempt financing of a Customer is jeopardized by its 
participation under this Service Agreement, the Customer is 
jeopardized by its participation under this Service Agreement, the 
Customer may terminate this Service Agreement upon thirty (30) days 
written notice to the Independent Transmission Provider. The 
Customer's provision of notice to terminate service under this 
Service Agreement shall not relieve the Customer of its obligation 
to pay any rates, charges, or

[[Page 55572]]

fees due under this Service Agreement, and which are owed as of the 
date of termination.
    9. The Customer hereby appoints the Independent Transmission 
Provider as its agent for the limited purpose of effectively 
transacting on the Customer's behalf in accordance with the 
Customer's written instructions, listed herein and the terms of the 
Independent Transmission Provider's Tariff and Procedures. The 
Customer agrees to pay all amounts due and chargeable to the 
Customer in accordance with the terms of the Independent 
Transmission Provider's Tariff and Procedures.
    IN WITNESS WHEREOF, the Parties have caused this Service 
Agreement to be executed by their respective authorized officials.

Independent Transmission Provider:-------------------------------------
By:--------------------------------------------------------------------
Dated:-----------------------------------------------------------------
Title:-----------------------------------------------------------------

Customer:--------------------------------------------------------------
By:--------------------------------------------------------------------
Dated:-----------------------------------------------------------------
Title:-----------------------------------------------------------------

Form of Participating Generator Agreement

    [To be provided by Independent Transmission Provider.]

Part VII. Attachments

Attachment A--Methodology To Assess Available Transfer Capability

    To be filed by the Independent Transmission Provider based on 
the following guidelines:
    Available Transfer Capability must be calculated on a regional 
basis by an independent entity. In an RTO or ISO, the Independent 
Transmission Provider may calculate Available Transfer Capability. 
Vertically integrated utilities not a part of an RTO or ISO must 
contract with an independent entity to calculate Available Transfer 
Capability on its system. The calculation of Available Transfer 
Capability must take into account the effect of other transmission 
systems in the interconnection (e.g., loop flow and parallel path 
flows).

Attachment B--Methodology for Completing a System Impact Study

    To be filed by the Independent Transmission Provider.

Attachment C--Network Operating Agreement

    To be filed by the Independent Transmission Provider.

Attachment D--Index Of Network Access Service Customers

 
              Customer                     Date of Service Agreement
------------------------------------------------------------------------
 
------------------------------------------------------------------------

Attachment E--Index Of Market Services Customers

 
              Customer                     Date of Service Agreement
------------------------------------------------------------------------
 
------------------------------------------------------------------------

Attachment F--Rates

    To be filed by the Independent Transmission Provider.

Attachment G--List of Existing Transmission Contracts

 
               Customer                Commission  Designation      Date of Contract         Termination Date
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------

Appendix C--Examples of Flaws in the Current Regulatory Environment

    We set forth below specific examples of undue discrimination and 
impediments to competition that continue to exist in the electric 
industry. Some of the examples that we provide do not use specific 
names because they are for the most part based on complaints made 
through the Commission's Enforcement Hotline, which are handled on a 
confidential basis. Other examples, which illustrate the potential 
for discrimination, establish that transmission providers have both 
the incentive and ability to exercise transmission market power 
against competitors in the market to supply energy.

Available Transfer Capability and Affiliates

    The following is an example derived from informal, non-public 
inquiries to the Commission \1\ regarding a transmission provider 
favoring itself or its affiliate using Available Transfer Capability 
postings:
---------------------------------------------------------------------------

    \1\ Because this example is based on non-public inquiries, we 
have not identified the companies.
---------------------------------------------------------------------------

    In February, a competing generator recognizes an opportunity to 
sell power into a vertically integrated transmission provider's 
system during the summer months (June, July, and August) and, 
therefore, requests monthly firm service for the desired points for 
that time period. The transmission provider, which would prefer that 
its merchant function capture the sales anticipated by the 
competitor, now must evaluate whether sufficient Available Transfer 
Capability will be available to honor its competitor's request. 
Although the formula for calculating Available Transfer Capability 
is required to be public, the transmission provider has the sole 
responsibility for, and a great deal of discretion in, its 
calculation, and will be very conservative in its estimates of 
expected contingencies, outages and the like. In this example, the 
transmission provider assumes two generating units will be 
unavailable, reducing Available Transfer Capability below the level 
where the requested transmission can occur, so it denies the request 
for summer service. But after the competitor's request is denied, 
the transmission provider's affiliate can ask in May for weekly firm 
service over the summer. So, when the affiliate's request is made, 
it is granted. Discretion on the part of the transmission provider 
in calculating Available Transfer Capability coupled with the 
affiliate's knowledge of how the calculations work enable the 
affiliate to secure the necessary firm service and win the sale 
opportunity.

Discretionary Use of TLRs

    The following is another example derived from informal, non-
public inquiry by the Commission regarding how TLRs are used.\2\
---------------------------------------------------------------------------

    \2\ Because this example is based on non-public inquiries, we 
have not identified the companies.
---------------------------------------------------------------------------

    The facts: There are three neighboring, interconnected 
transmission systems, WestCo, CentralCo, and EastCo. (Their relative 
locations match their names).
    CentralCo has 10,000 MW of generation and 8,000 MW of load west 
of a constrained line that divides its system. The line is limited 
to 1,500 MW of transfer capability. CentralCo has 1,000 MW of 
generation and 2,000 MW of load east of the constraint. Its cost of 
generation on either side of the constraint is comparable, and 
averages about $25 per MWh.
    Under its normal dispatch pattern, CentralCo would generate 
1,000 MW from its generation in the east to serve the eastern load, 
and would generate 9,000 MW from its western generation, 8,000 MW to 
meet its western load and 1,000 to meet the remainder of the 2,000 
MW load in the east. This means that 1,000 MW of generation would 
usually flow across the constrained line for CentralCo to meet its 
own load, leaving 500 MW of west-to-east ATC on the constrained 
line.
    NewGen, a generator located in WestCo's service area, wants to 
sell 100 MW for one day to a buyer in EastCo's service area. 
NewGen's cost of generation is $22 per MWh.
    To make the sale, NewGen must secure 100 MW of transmission 
across CentralCo's system (including the constrained line), to make 
the sale. Therefore, NewGen requests transmission service through 
CentralCo's system. Under normal operating conditions, CentralCo's 
constrained line has available 500 MW of Available Transfer 
Capability, leaving plenty of transfer capability to accommodate the 
sale. Since its OASIS lists 500 MW of Available Transfer Capability, 
CentralCo grants the request.
    If CentralCo were an RTO, it would have no financial interest in 
which generator makes any particular sale, and would focus on 
ensuring optimal and reliable system operation. Thus, it would 
dispatch the system to ensure that the 100 MW NewGen transaction 
would flow, since it could do so while still optimizing the dispatch 
of the CentralCo generators. But CentralCo has a financial incentive 
to block the NewGen transaction in order to make the sale itself and 
it has the information to make it happen. CentralCo, as transmission 
provider, knows the flow patterns on its system and the identity 
(and affiliation) of all generators flowing power on its system. 
This means that CentralCo's transmission arm would not need to 
engage in any prohibited off-OASIS

[[Page 55573]]

communications to dispatch the system in a way that favors its own 
affiliate.
    CentralCo can block a portion of the competitor's transaction by 
changing its own dispatch pattern and declaring a TLR across the 
constrained line. CentralCo would reduce generation on the east side 
to 500 MW and increase generation from the west by the same amount 
to meet the eastern load. This would increase its own use of the 
constrained line to 1,500 MW which, in addition to the 100 MW of 
scheduled use by NewCo, would exceed the thermal limits of the line. 
CentralCo, as security coordinator for its own system, has great 
discretion as to when and for how long to declare a TLR across the 
constrained line. In this situation, rather than redispatching its 
own generators to accommodate NewGen's transaction, it could declare 
a TLR and curtail a portion of the NewGen's transmission 
transaction.
    By curtailing transmission for a portion of the competitor's 
sale, this TLR allows CentralCo to step in to provide EastCo's 
needed 100 MW (following NewCo's transmission curtailment), possibly 
at an inflated price due to the TLR and the buyer's need to 
immediately secure replacement power.
    The Commission is concerned that the use of emergency procedures 
offers opportunities for discrimination. A high incidence of TLRs 
reduces certainty in the market because it frustrates the 
expectations of bulk power sellers and their customers.\3\ In turn, 
it provides a disincentive for market participants to take 
transmission risks and decreases overall liquidity in the 
transmission market.\4\ The practice of using TLRs to manage 
congestion contributes to transmission and energy prices that are 
not just and reasonable and must be remedied.
---------------------------------------------------------------------------

    \3\ See Staff Report to the Federal Energy Regulatory Commission 
on the Bulk Power Markets In The United States (Nov. 1, 2000), 
available in <http://www.ferc.gov/electric/bulkpower/midwest.pdf, at 2-32. See Staff Report to the Federal 
Energy Regulatory Commission on the Bulk Power Markets In The United 
States (Nov. 1, 2000), available in <http://www.ferc.gov/electric/bulkpower/southeast.pdf, at 3-38.
    \4\ See Staff Report to the Federal Energy Regulatory Commission 
on the Bulk Power Markets In The United States (Nov. 1, 2000), 
available in <http://www.ferc.gov/electric/bulkpower/midwest.pdf, at 2-33 (reporting eroded confidence and 
decreased liquidity in the Midwest market).
---------------------------------------------------------------------------

Lack of Common Set of Rules Governing Transmission

1. Balancing Authority

    A market participant that operates a control area may derive a 
market benefit. The primary function of a control area operator is 
to maintain a balance between the energy coming onto the grid and 
the energy being taken off. The North American Electric Reliability 
Council (NERC) refers to this primary function as balancing and the 
responsible entity as the balancing authority.\5\ The balancing 
authority has generating resources that it may call on for balancing 
but also may rely on a neighboring balancing authority for balancing 
energy, which it must pay back. The payback is typically 
accomplished by returning energy at a later time.
---------------------------------------------------------------------------

    \5\ Because most transmission systems were operated by 
vertically integrated utilities that performed many types of control 
functions, the term ``control area operator'' now lacks precision 
regarding which of these functions is being referred to in a 
particular context. Recently, NERC adopted new terminology for use 
in rewriting its reliability standards. It is eliminating the terms 
``control area'' and ``control area operator'' and replacing these 
with several other terms that describe more precisely the functions 
performed. NERC refers to the entity responsible for maintaining 
system frequency by arranging for generation to balance load as the 
``balancing authority.'' It is this function that is the subject of 
the first example. See The NERC Functional Model: Functions and 
Relationships for Interconnected Systems Operation and Planning 
(visited June 11, 2002) <http://www.ferc.gov/Electric/RTO/mrkt-strct-comments/02-19-02/CACTR-Final-Report-Functional-Model.pdf for more information on the NERC functional 
model. See also Transcript of Assignment of RTO Characteristics and 
Functions Technical Conference, Docket No. RM01-12-000, at 12-34 
(Feb. 19, 2002).
---------------------------------------------------------------------------

    A transmission customer outside the organized spot market of an 
ISO or RTO is expected to keep its own grid energy inputs and 
withdrawals in balance. For example, the customer may be a municipal 
utility that buys 50 megawatts from noon to 1 o'clock to meet a load 
that is expected to hover around 50 megawatts at that hour. The 
transmission customer cannot achieve exact balance in part because 
retail loads are not completely predictable.\6\ To the extent the 
customer does not achieve exact balance, the balancing authority 
supplies or absorbs energy for balancing, charging the customer for 
the energy. For an excessive deviation from the scheduled amount of 
energy delivery, the transmission customer may have to pay a penalty 
rate under the public utility's tariff, intended to encourage good 
scheduling behavior so as to maintain reliable system operation.
---------------------------------------------------------------------------

    \6\ A customer can achieve such balance through dynamic 
scheduling, which effectively takes it out of the control area.
---------------------------------------------------------------------------

    A balancing authority outside an RTO or ISO is today typically 
also a market participant that serves its own power customers. In 
most cases, it is a large vertically integrated public utility that 
generates and buys power to meet the power needs of its native load. 
Such a balancing authority may be able to lower the cost of 
acquiring balancing energy and achieve a competitive advantage over 
other market participants that do business on its transmission 
system. It can rely on a neighboring balancing authority to loan it 
energy without having to pay for the energy. Further, it may avoid a 
penalty for excessive deviation. It can later return the energy 
taken in kind to the neighboring authority and may thus face a lower 
balancing cost than other energy providers. Although this problem 
may incur infrequently, it results in an undue cost preference for 
the investor-owned utility and its customers vis-a-vis the costs 
that other energy providers incur and pass on to their customers.
    NERC has recognized a related reliability problem associated 
with excessive unplanned borrowing of energy in a highly competitive 
market and is in the process of writing new rules to alleviate this 
problem.\7\ Because compliance with NERC's rules is voluntary, one 
NERC region filed on behalf of the public utilities in its region so 
that its rule relating to balancing would be mandatory. On May 31, 
2000, the Commission approved a tariff filed by the East Central 
Area Reliability Council, which is the NERC regional reliability 
council for an area centered around Indiana, Ohio, and western 
Pennsylvania.\8\ The tariff, designed to maintain reliability in an 
increasingly competitive region, is intended to eliminate any 
economic incentive that may exist under current reliability rules 
for a particular balancing authority to borrow large amounts of 
energy from neighboring authorities when the price of power is high 
and return it in kind when the price is low.\9\ It does not, 
however, fully eliminate the economic advantage that a balancing 
authority that is also a market participant may have over other 
energy suppliers.
---------------------------------------------------------------------------

    \7\ See, e.g., Board of Trustees Meeting Highlights (visited May 
31, 2002) <http://www.nerc.com/pub/sys/all--updl/docs/bot/
bot0106h.pdf
    \8\ See East Central Area Reliability Council, 91 FERC [para] 
61,197 (2000).
    \9\ See id. at 61,693-94.
---------------------------------------------------------------------------

    The Commission, in the proposed rule leading to Order No. 2000, 
using the then-current terminology of the control area operator, 
said that, in an RTO,

unequal access to balancing options can lead to unequal access in 
the quality of transmission service, and that this could be a 
significant problem for RTOs that serve some customers who operate 
control areas and other customers who do not.\10\
---------------------------------------------------------------------------

    \10\ Order No. 2000 at 31,142.
---------------------------------------------------------------------------

The Commission concluded in Order No. 2000 that

control area operators should face the same costs and price signals 
as other transmission customers and, therefore, also should be 
required to clear system imbalances through a real-time balancing 
market. We believe that providing options for clearing imbalances 
that differ among customers would be unduly discriminatory.\11\
---------------------------------------------------------------------------

    \11\ Id.

    The Commission has not addressed this issue generically, 
however, for public utility transmission providers that are not in 
an RTO. There is a need for a tariff that addresses this issue 
explicitly for all public utility transmission providers.

2. Receipt and Delivery Point Flexibility

    The Order No. 888 pro forma tariff provides nondiscriminatory 
rules governing the designation of receipt points, where power 
enters the transmission provider's system, and delivery points, 
where power exits the system. There are different such rules for 
network integration and point-to-point transmission customers, as 
required by the Order No. 888 pro forma tariff. Transmission 
customers say that these tariff provisions allow a vertically 
integrated public utility with a native load to provide itself with 
greater flexibility regarding designation of receipt and delivery 
points through practices that have become known in the industry as 
``parking'' and ``hubbing.''

[[Page 55574]]

    To illustrate, a point-to-point transmission customer, such as a 
power marketer, may be required to reserve transmission for a 
complete transaction, that is, from an actual generator to an actual 
power-consuming load. If it is announced today, for example, that 
generation will be available tomorrow from a particular generator, 
the marketer may be able to buy the power but unable to reserve the 
transmission if it has not yet identified a buyer and named its 
location on the grid. That is, it can name a point of receipt but 
cannot yet name a point of delivery, so it may be denied a 
reservation for firm transmission service.
    A vertically integrated transmission provider with a native 
load, however, can buy the power from the same generator, naming 
that generator as the point of receipt and its native load network 
as the point of delivery, saying it intends to reduce its own 
generation to meet its native load power needs. The transmitting 
public utility is given a transmission reservation. Later, the 
public utility can find a buyer for the power and say it is making a 
sale from its freed-up generation, designated as the point of 
receipt, to the buyer's point of delivery--taking a second 
transmission reservation for the same power. In effect, the public 
utility will have reserved transmission for a purchase from the 
generator and a sale to the buyer in a manner that is not available 
to the marketer. The public utility is said to have ``parked'' the 
power at its native load location while it sought a buyer for the 
power. Parking can also occur if the buyer is known and transmission 
to the buyer is reserved, allowing the public utility time to search 
for a seller to match the buyer's power needs. The time delay 
involved in parking affords flexibility to a vertically integrated 
transmission provider that is not available to all transmission 
customers.
    ``Hubbing'' is similar but does not necessarily involve a time 
delay. Instead, it involves having more than one seller or more than 
one buyer, or both. Using the method just described for parking, a 
transmitting public utility with a native load may reserve 
transmission to buy power from several sellers and to sell power to 
several buyers. In effect, it may use its combined native load 
transmission network location as a hub for trading. It may acquire a 
portfolio of generators from which to obtain power to meet the power 
needs of a collection of power buyers, without having to match 
individual buyers and sellers. This hubbing allows the public 
utility to capture market efficiencies by combining resources to 
satisfy collective needs, and to gain a competitive advantage over 
others who cannot establish a hub because they are required by 
Point-to-Point Transmission Service rules to match a particular 
generator with a particular load for each transmission reservation.
    This example shows another undesirable difference between two 
transmission services available to both wholesale and unbundled 
retail customers, Network Integration Transmission Service and 
Point-to-Point Transmission Service.
    Today, the Commission concludes that the inherent differences in 
flexibility between the two types of tariff services, including the 
one described above, are resulting in undue preferences and thereby 
impeding the most efficient trading of power over the interstate 
transmission grid. Accordingly, the Commission proposes to create a 
single transmission service and equalize the playing field so that 
all transmission customers can park, hub or exercise equal 
creativity and flexibility in structuring transactions and serving 
customers.

3. Transmission Transfer Capability Set Aside for Reliability

    Transmission transfer capability may be set aside by the 
transmission provider for either of two reliability-related reasons. 
One relates to the reliability of the transmission system itself and 
the other relates to generation reliability. As an example of the 
first, the power loading on a transmission line may be less than the 
line's capacity so that it can take up the power flows it must 
absorb if a parallel line should go out of service. The industry 
refers to this type of unused transmission capacity as a 
transmission reliability margin, or TRM. While reliability rules 
forbid a transmission provider from loading a line beyond its 
reliability limit, these rules are not necessarily mandatory or 
enforceable. However, there have been few complaints about 
discriminatory violations of TRM reliability limits.
    Most complaints have related to transmission transfer capability 
that is set aside to provide for adequate generation. A vertically 
integrated public utility may have decided in the past that, to 
achieve adequate generation resources (including reserves), it was 
more economical to build stronger transmission interconnections with 
neighbors that could share their extra generation when needed than 
to build extra generation in its own service area. When Order No. 
888 was under consideration, such utilities argued that some 
transmission transfer capability should be set aside for this 
generation reliability function.\12\ They asserted that, if others 
were allowed to purchase firm rights to this transmission 
capability, it would not be available to the public utility when 
needed for the generation reliability purpose for which it was 
built.\13\ The term used for this type of transmission set aside is 
capacity benefit margin (CBM). Order No. 888 permitted utilities to 
have CBM if they fully explained and justified the amount set 
aside.\14\ The CBM set-aside practice is not used universally; some 
utilities do not claim a capacity benefit margin. Moreover, where it 
is used, there is regional variation in its implementation.
---------------------------------------------------------------------------

    \12\ See Order No. 888 at 31,693-94.
    \13\ See id.
    \14\ See id. at 31,694.
---------------------------------------------------------------------------

    Since Order No. 888 issued, at least two issues related to CBM 
have been controversial. One is whether all network transmission 
customers, including for example municipal utilities within the 
transmission owner's service territory, have an equal opportunity to 
set aside transmission for this purpose. The second is whether those 
who set aside transmission for CBM are reserving it and paying for 
it under the terms of the pro forma tariff.
    The second issue is best explained with an example. Suppose a 
transmission-owning public utility sets aside 100 MW of transfer 
capability at its interface with a neighboring utility to help 
ensure adequate generation for the public utility's native load 
customers. Suppose further that the public utility's native load is 
600 MW, and the collective amount of point-to-point transmission 
customer imports is 200 MW and the line's total capacity is 900 MW. 
Under the usual method of allocating transmission costs to 
customers, the point-to-point customer would pay for and receive 200 
MW of transmission service and the public utility would pay for 600 
MW of transmission system cost but receive 600 MW of transmission 
service and 100 MW of reserved capacity. In some cases, the 
transmission provider's merchant affiliate has used the CBM set-
aside on a non-firm basis to make sales without paying for the 
transmission capacity used.
    In 1998 the Commission received complaints alleging that some 
transmission-owning utilities were inappropriately reducing 
Available Transfer Capability to reflect transmission reliability 
requirements and capacity benefit margins.\15\ The Commission 
observed in WPPI that the determination of CBM was made differently 
in the Available Transfer Capability calculations of various 
utilities and was not explained in one tariff.\16\ The Commission 
stated that it was ``concerned that the exercise of this 
discretionary adjustment can turn on considerations (such as the 
reduction of power supply costs and limiting the generation supply 
options of competitors) that involve the transmission provider's 
merchant arm rather than its transmission function.'' \17\
---------------------------------------------------------------------------

    \15\ See Wisconsin Public Power Inc. SYSTEM. v. Wisconsin Public 
Service Corporation, et al., 83 FERC [para]61,198 (1998) 
[hereinafter WPPI].
    \16\ See id. at 61,857-58.
    \17\ Id. at 61,858.
---------------------------------------------------------------------------

    In 1999, the Commission initiated a generic inquiry into 
policies for transmission reliability set-asides. In particular, the 
Commission convened a conference in May 1999 in which it examined 
the practices of use, and the alleged abuses, of CBM.\18\ 
Transmitting utilities had been accused of using CBM designations to 
withhold transmission transfer capability from the wholesale 
electric transmission market. The Commission also requested comments 
on the subject. One commenter stated:
---------------------------------------------------------------------------

    \18\ See Capacity Benefit Margin in Computing Available 
Transmission Capacity, 64 Fed. Reg. 16730-31 (March 31, 1999), 86 
FERC [para]61,313 (1999), (hereinafter CBM Notice).

Even NERC acknowledges that there is a wide disparity in the 
magnitudes of TRM [transmission reliability margin] and CBM applied 
by transmission providers across an interconnection, especially in 
the quantification of CBM. The reason for this disparity is the 
absence of an enforceable industry standard--or more appropriately, 
a Commission rule--for the definition of CBM.\19\
---------------------------------------------------------------------------

    \19\ The Electricity Consumers Resource Council and the American 
Iron and Steel Institute (Industrial Consumers), Docket No. EL99-46-
000, written comments at 3 (footnote omitted).

---------------------------------------------------------------------------

[[Page 55575]]

    In July 1999, the Commission issued an order clarifying the 
method for computing ATC, including provisions dealing with CBM.\20\ 
There, the Commission stated that: ``[t]he measures that we are 
requiring transmission providers to take at this time consist of 
short-term solutions, which, for now, take no position on the 
transmission provider's ability to set aside CBM for generation 
reliability requirements.'' \21\ The Commission acknowledged that 
NERC had already started a process to establish a standardized 
methodology for deriving CBM, and directed public utility 
transmission providers, working through NERC, to complete this 
process by the end of 1999.\22\
---------------------------------------------------------------------------

    \20\ Capacity Benefit Margin in Computing Available Transmission 
Capacity, 88 FERC [para]61,099 (1999).
    \21\ Id. at 61,237. The order, among other things, also directed 
each transmission provider to post specific CBM information and 
practices on its OASIS site within 30 days of the order, and to 
reevaluate generation reliability needs periodically so as to make 
known the availability of CBM capacity to others. See id.
    \22\ See id. at 61,238.
---------------------------------------------------------------------------

    NERC called on each region to develop and document its own 
methodologies and guidelines for determining TRM and CBM.\23\ It 
reported that its ATC Working Group was continuing to develop CBM 
and TRM, and that the draft standards would require each region to 
develop a region-wide CBM methodology.\24\ It also noted that many 
methods for calculating CBM were used by transmission providers 
within each region.\25\ Although a single North American standard 
CBM method was called for by transmission customers, NERC reported 
that it was not able, at that time, to develop such a standard for 
CBM.\26\ NERC noted that the consideration of a standard CBM method 
would follow the completion of regional methods,\27\ a process that 
is still ongoing.
---------------------------------------------------------------------------

    \23\ See Response of the North American Electric Reliability 
Council to the CBM Order, Docket No. EL99-46-000 (Aug. 12, 1999), at 
3.
    \24\ See id. at 3-4.
    \25\ See id. at 5.
    \26\ See id.
    \27\ See Letter from Virginia C. Sulzberger, North American 
Electric Reliability Council, to David P. Boergers, FERC, Docket No. 
EL99-46-000 (Dec. 23, 1999), at 2. There have been no further 
Commission proceedings on a generic basis addressing CBM. Parties 
did raise the CBM issue in the proceedings leading to Order No. 
2000, but the Commission determined that ``[t]hese issues are too 
detailed for this proceeding and we will not address them at this 
time.'' Order No. 2000 at 31,146. Development of methods for 
calculating ATC and CBM at NERC are continuing.
---------------------------------------------------------------------------

    The lack of standards for TRM and CBM impedes the development of 
basic information required by Order Nos. 888 and 889 as a basis for 
eliminating undue discrimination in the provision of interstate 
transmission services. Further impeding competition is continued 
uncertainty about whether and how to account for CBM in determining 
ATC and how CBM costs should be allocated. The industry needs 
Commission guidance to achieve standardization in these areas.\28\
---------------------------------------------------------------------------

    \28\ Addressing the topic of ATC coordination, which includes 
the ``[p]roper quantification of transmission reliability margin 
(TRM)'' the NERC ATC Coordination Task Force concluded that:

    The existing definition of ATC coordination does not meet the 
needs of all members of the marketplace (all market participants) 
because there are too many diverse opinions that will not allow for 
consensus. * * * It is impossible to meet the existing definition of 
coordination due to differing market objectives, and regional 
business practices and transmission provider tariffs, and corporate 
objectives. Until these issues are resolved, coordination will not 
occur. Available Transfer Capability Coordination Task Force, ATC 
Coordination and Related Issues at 8-9 (July 12, 2000), available in 
ftp://www.nerc.com/pub/sys/all_upoll/pc/minutes/ac-0007m.pdf.

4. Transmission Curtailment Preference for Bundled Retail Load

    The Commission continues to receive complaints that transmission 
service to deliver power to bundled retail customers continues to be 
superior to transmission services for wholesale and unbundled retail 
transmission customers. In Northern States Power Company (NSP), the 
United States Court of Appeals for the Eighth Circuit held that the 
Commission had exceeded its authority when it rejected proposed 
transmission curtailment provisions, contained in a public utility's 
wholesale open access transmission tariff, that favored the 
utility's retail customers over its wholesale customers.\29\ On 
remand, the Commission permitted NSP to amend its open access 
transmission tariff to reflect its proposed transmission curtailment 
procedures to be effective in the ``rare circumstances'' where 
generation redispatch is inadequate or unavailable to fully relieve 
the transmission constraint.\30\ However, the Commission also told 
NSP that if it amends its tariff to reflect its proposed 
transmission curtailment procedures, ``NSP must revise its rates for 
firm point-to-point transmission service * * * to recognize the 
inferior quality of that service compared to the service provided by 
NSP to its native load and network customers. * * *'' \31\
---------------------------------------------------------------------------

    \29\ Northern States Power Company, et al. v. Federal Energy 
Regulatory Commission, 176 F.3d 1090, 1096 (8th Cir. 1999), cert. 
denied sub nom. Enron Power Marketing, Inc. v. Northern States Power 
Company, 528 U.S. 1182 (2000).
    \30\ See Northern States Power Company (Minnesota) and Northern 
States Power Company (Wisconsin), 89 FERC [para] 61,178 at 61,552-53 
(1999). Subsequently, the Commission has applied NSP narrowly and 
indicated that it continues to believe that it has the authority to 
treat such customers comparably. See North American Electric 
Reliability Council, et al., 96 FERC [para] 61,079 at 61,345 (2001).
    \31\ 89 FERC at 61,553.
---------------------------------------------------------------------------

    Although NSP later withdrew its objection to equal transmission 
curtailment treatment for all transmission customers, the case 
points out a difficulty the Commission has in ensuring transmission 
access that is not unduly discriminatory for all transmission 
customers--retail and wholesale--unless all transmission customers 
take service under the same tariff.
    Seams Problems. Even apparently minor differences in rules can 
create seams problems. The three Northeastern ISOs, which have 
substantially similar market designs and transmission congestion 
management systems, have struggled to coordinate their rules to 
lower trading barriers, but have achieved only limited success after 
several years. If each RTO in the Nation were to implement different 
rules, processes, and market mechanisms, these differences combined 
could produce and exacerbate significant barriers to transmission 
and electric power sales in interstate commerce.\32\
---------------------------------------------------------------------------

    \32\ For perspectives on this topic and its possible economic 
consequences, see Mirant Corporation, Northeast Power Markets: The 
Argument for a Unified Grid,  139 Public Utilities Fortnightly, at 
36-45, Sept. 1, 2001. See also Hartshorn, Andrew P. and Harvey, 
Scott M., Assessing the Short-Run Benefits from a Combined Northeast 
Market, LECG, LLC, October 23, 2001.
---------------------------------------------------------------------------

    As an example of a specific seams problem, incompatible ramping 
rules have made power sales among the ISO systems in the Northeast 
unnecessarily difficult and prevented some trades. Among the 
operating protocols of a transmission provider are rules for 
increasing and decreasing the power output of a generator (called 
``ramping'') connected to the transmission system. To implement a 
transaction between two systems, generation in the supplying system 
must be increased, or ``ramped'' up, and generation in the receiving 
system must be decreased, or ``ramped'' down. The ramping up and 
ramping down in the two systems should begin at the same time, last 
for the same length of time, and end at the same time. But different 
systems can have different rules about the timing and rate of 
ramping. For example, PJM allows ramping to occur every fifteen 
minutes; it can occur, for example, at 1 p.m., 1:15 p.m., 1:30 p.m, 
1:45 p.m., 2 p.m., and so forth. New York and New England require 
ramping to occur on the hour, at 1 p.m or 2 p.m. but not within an 
hour. Thus, PJM's ramping rules permit a sale from PJM to New York 
to begin on the half hour by ramping up generation in PJM, but New 
York's ramping rules do not allow a buyer in New York to receive the 
power because it cannot ramp down generation on the half hour. Also, 
systems may place different limits on the amount of ramping that may 
occur on the interface with a neighboring system. Then, one system 
may allow an amount to be exported that the neighbor will not allow 
to be imported.\33\ These differences must be reconciled to maximize 
opportunities for constructive trade at minimal transaction costs 
and obstacles.
---------------------------------------------------------------------------

    \33\ An extensive list of seams issues, ISO rule differences, 
and a discussion of efforts to reduce seams problems among the 
Northeast systems is available at the ISO Memorandum of 
Understanding Web site. See Seams Issues--High Priority Items http://www.isomou.com/working_ groups/business--practices/documents/
general/ bpwg--matrix.pdf. At the June 12, 2002 
Commission meeting, New York ISO presented a list of 40 seams issues 
in the Northeast and a time line for resolving these issues. See 
Transcripts of Commission Meetings, June 12, 2002, available in 
http:www.ferc.gov/calendar/commissionmeetings/transcripts.htm.
---------------------------------------------------------------------------

    Several efforts are underway at the Commission or within the 
industry to address seams problems and the

[[Page 55576]]

development of standards. The Commission issued a Notice of Proposed 
Rulemaking to standardize rules for interconnecting generators to 
the grid.\34\ The Commission also issued an Advanced Notice of 
Proposed Rulemaking to extend the standardization requirements of 
Order No. 889 to include electronic scheduling, among other 
matters.\35\ In response to the latter, the industry formed the 
Electronic Scheduling Collaborative (ESC) to develop recommendations 
for the proposed rule but reported that the diversity of business, 
operating and other practices around the country made it very 
difficult to develop standards and protocols for electronic 
scheduling that would apply to all public utility systems. In its 
October 5, 2001 report to the Commission, the Electronic Scheduling 
Collaborative identified ten key policy issues that would give 
significant impetus to standards development. All of these issues 
are addressed in this proposed rule. NERC is working to achieve more 
uniform and enforceable reliability rules, and the North American 
Energy Industry Standards Board was formed in the autumn of 2001 in 
part to develop standards for electric wholesale business practices 
and communications protocols. Regional groups have formed to address 
seams issues, including the Seams Steering Group for the Western 
Interconnection and a Memorandum of Understanding among the three 
Northeast ISOs and the Ontario Independent Market Operator to 
address seams issues. In the Midwest, over the last several years 
various groups have met to deal with seams issues between two or 
more proposed RTOs for the central United States. The Tennessee 
Valley Authority (TVA) has also negotiated memoranda of 
understanding with Midwest Independent System Operator, Entergy and 
Southern Companies to pursue development of a coordination agreement 
to address seams issues in the Southeast. In its RTO orders, the 
Commission has been concerned about seams between neighboring RTOs 
with different rules, and also about seams between entities that are 
part of one large RTO.\36\
---------------------------------------------------------------------------

    \34\ See Standardization of Generator Interconnection Agreements 
and Procedures, 62 Fed. Reg. 22,249 (May 2, 2002), FERC Stats. & 
Regs. [para] 32,560 (2002).
    \35\ Open Access Same-Time Information System (Phase II), Docket 
No. RM00-10-000, Advance Notice of Proposed Rulemaking, 92 FERC 
[para] 61,047 (July 14, 2000).
    \36\ See Alliance Companies, et al., 97 FERC [para] 61,327 at 
62,530 (2001).
---------------------------------------------------------------------------

    Many panelists at the Commission's seams conference urged us to 
develop standards for RTOs before they begin operating--indeed 
before they invest heavily in software development for a unique set 
of regional transmission rules and market designs.\37\ This urging 
played a significant role in the genesis of this rulemaking.
---------------------------------------------------------------------------

    \37\ Conference on RTO Interregional Coordination, Docket No. 
PL01-5-000, June 19, 2001.
---------------------------------------------------------------------------

    Another seams problem can arise from different market price 
mitigation rules in neighboring regions. When western electric power 
prices were high in 2001, for a short time the Commission applied 
price mitigation to certain generators in California for spot market 
sales of power within California.\38\ But these mitigation measures 
did not apply to sales from these generators to buyers outside 
California. As a result, some California generators sold power to 
parties outside California, that sold the power back into the state 
without facing the same price mitigation rule, a practice that was 
dubbed ``megawatt laundering.'' The Commission shortly thereafter 
applied uniform mitigation measures throughout the United States 
portion of the Western interconnection to remedy this problem. 
Uniformity of rules eliminated the seams problem in that 
circumstance.\39\
---------------------------------------------------------------------------

    \38\ See San Diego Gas & Electric Company v. Sellers of Energy 
and Ancillary Services into Markets Operated by the California 
Independent System Operator and the California Power Exchange, et 
al., 95 FERC [para] 61,115 (2001). The Commission's order on price 
mitigation provided in part that certain California generators that 
had not already sold their power were required to bid into the ISO's 
real-time market at a constrained bid price.
    \39\ See New York Independent System Operator, Inc., et al., 92 
FERC [para] 61,073 (2000); NSTAR Services Company v. New England 
Power Pool, et al., 92 FERC [para] 61,065 (2000); and PJM 
Interconnection, L.L.C., 96 FERC [para] 61,233 (2001) (orders 
accepting a uniform $1000 bid cap).
---------------------------------------------------------------------------

    Market Design Flaws. The ISO markets have experienced numerous 
design flaws. A few of the more fundamental flaws are detailed 
below:
    1. Transmission Congestion Pricing by Zones Rather than Nodes. 
On all single utility transmission systems, the cost of congestion 
is allocated to all users of the grid on a load ratio share basis. 
ISOs have tried various ways to allocate these costs to the customer 
or customers whose transactions caused the congestion. Several ISO 
markets attempted to price transmission congestion based on the 
average cost of congestion for transfers of power between defined 
zones on the system, rather than pricing the transmission congestion 
on a point-to-point basis. The zonal method tries to allocate 
congestion costs without too much pricing complexity. The theory of 
the method is that zones can be established within which little 
transmission congestion will occur (if any congestion does occur 
within the zone, all customers receiving power within the zone must 
share the cost of congestion). Variants of zonal pricing were tried 
in California, PJM, Texas (ERCOT) and New England.\40\ In all cases 
the methods contained a similar flaw: using the zonal price signal 
did not induce short-term efficiency in the region, and it spread 
the congestion costs too broadly to clearly identify the 
transactions causing the congestion or the location of the 
structural fixes necessary to resolve it. It has also been difficult 
to determine in advance the appropriate zones, as flows have changed 
after restructuring.\41\
---------------------------------------------------------------------------

    \40\ See New England Power Pool, 88 FERC [para] 61,147 (1999); 
PJM Interconnection, LLC, 81 FERC [para] 61,257 (1997), order on 
reh'g, 92 FERC [para] 61,282 (2000); Order Proposing Remedies for 
California Wholesale Electric Markets, 93 FERC [para] 61,121 (2000).
    \41\ This zonal cost allocation for congestion management is 
different from and should not be confused with proposals to 
aggregate energy prices at several points into hubs.
---------------------------------------------------------------------------

    2. Overly Restrictive Ancillary Service Market Designs. Although 
the specific designs were different, both the California ISO and ISO 
New England initially attempted to require sellers to separately bid 
into each of several ancillary services markets. The hope with this 
design was to establish vibrant markets for each of the various 
ancillary services. However, the market design did not allow the 
substitution of a higher quality product (operating reserve--
spinning) for a lower quality product (operating reserve--
supplemental), even if the higher quality product was available at a 
lower price. This resulted in thin markets for certain ancillary 
services because sellers had no incentive to offer in one market if 
another market paid more. The perverse result was that lesser 
quality product markets (such as operating reserve--supplemental) 
cleared at higher prices than higher quality products (operating 
reserve--spinning). Sellers had to guess, based on limited 
information, which service would be the most highly valued. The 
market design failed to recognize that certain ancillary services 
were substitutes, e.g., spinning reserves can ``provide'' 
supplemental reserves because operating reserves--spinning are more 
responsive to the ISO's dispatch signal. This design flaw created 
artificial barriers to entry for certain products, increasing market 
power and inefficiency, causing customers to pay prices higher than 
necessary for ancillary services.\42\
---------------------------------------------------------------------------

    \42\ See AES Redondo Beach, L.L.C., et al., 84 FERC [para] 
61,046 (1998); New England Power Pool, 85 FERC [para] 61,379 (1998).
---------------------------------------------------------------------------

    3. The Absence of a Day-Ahead Market. Certain ISO markets, 
including PJM and ISO New England, began operations with only real-
time energy markets. All prices for power sold through the balancing 
market and ancillary service markets were cleared based on schedules 
and actual purchases in real time. In all cases, ISOs with only a 
real-time market concluded that a day-ahead market settlement system 
was also needed so that transmission customers could better protect 
against congestion costs, and so buyers and sellers of energy too 
could better protect against energy price uncertainty.\43\ A day-
ahead market enhances reliability because it allows the system 
operator to assess the next day's likely load and available 
resources. The California ISO has had difficulty operating the 
system reliably since the California PX ceased operations. A 
financially binding day-ahead market serves a critical reliability 
function by facilitating planning, unit scheduling, and load 
balancing.
---------------------------------------------------------------------------

    \43\ See PJM Interconnection, LLC, 91 FERC [para] 61,148 (2000); 
New England Power Pool, et al., 96 FERC [para] 61,317 (2001).
---------------------------------------------------------------------------

Appendix D--Conversion of the Order No. 888--A Pro Forma Tariff to the 
Revised Standard Market Design Pro Forma Tariff

    The following outlines the Order No. 888-A pro forma tariff and 
indicates where the various sections appear in the SMD Tariff. Where 
there are modifications or additions, they are identified and 
described. In addition, throughout the SMD Tariff, we have revised 
our terminology to match the new NERC terminology.

[[Page 55577]]



------------------------------------------------------------------------
   Order No. 888--A Pro Forma Tariff
           Table of Contents                   SMD tariff location
------------------------------------------------------------------------
I.  COMMON SERVICE PROVISIONS.........  Part I
    1  Definitions....................  A.1
        [revised to include new
         transmission service, LMP,
         Congestion Revenue Rights,
         and market services]
    2  Initial Allocation and Renewal   revised
     Procedures.
        2.1  Initial Allocation of      deleted
         Available Transmission
         Capability.
            [the section was for the
             initial conversion to an
             open access tariff; it is
             no longer needed]
        2.2  Reservation Priority for   B.12
         Existing Firm Service
         Customers.
            [Revised to reflect
             transition to Congestion
             Revenue Rights. Ensures
             that existing customers
             keep the right to roll
             over long-term firm
             service until
             implementation of the
             Congestion Revenue Rights
             auction (B.12.1)]
    3  Ancillary Services.............  C
        [Slight modification to
         definitions to match best
         practices of the Northeast
         ISOs]
        3.1  Scheduling, System         C.1
         Control and Dispatch Service.
        3.2  Reactive Supply and        C.2
         Voltage Control From
         Generation Sources Service.
        3.3  Regulation and Frequency   C.3
         Response Service.
        3.4  Energy Imbalance Service.  C.4
            [imbalances will be priced
             at real-time LMP price,
             making deviation band and
             delayed (30 days)
             resolution unnecessary]
        3.5  Operating Reserve--        C.5
         Spinning Reserve Service.
        3.6  Operating Reserve--        C.5
         Supplemental Reserve Service.
    4  Open Access Same-Time            A.2
     Information System (OASIS).
    5  Local Furnishing Bonds.........  A.3
        5.1  Transmission Providers     A.3.1
         That Own Facilities Financed
         by Local Furnishing Bonds.
            [reflects that
             Transmission Owner will
             not be the Transmission
             Provider; also modified
             to define the applicable
             provisions of the
             Internal Revenue Code;
             and to add language from
             the preamble of Order No.
             888-A clarifying that
             this provision also
             applies if a customer
             requests service that
             would jeopardize the tax-
             exempt status of bonds
             used to finance the
             transmission provider's
             generation or
             distribution facilities,
             even if no transmission
             facilities were financed
             with such bonds]
        5.2  Alternative Procedures     A.3.2
         for Requesting Transmission
         Service.
            [modified to make
             transmission provider
             advise the customer of
             expected costs resulting
             from loss of tax-exempt
             status within thirty days
             of receipt of an
             application for service.
             Also modified to clarify
             that any Commission order
             issued pursuant to
             section 211 of the FPA
             would specify that
             service under this
             section is provided
             subject to the customer's
             payment of all costs
             deemed eligible for
             recovery]
    6  Reciprocity....................  A.4
    7  Billing and Payment............  A.5
        7.1  Billing Procedure........  A.5.1
        7.2  Interest on Unpaid         A.5.2
         Balances.
        7.3  Customer Default.........  A.5.3
    8  Accounting for the Transmission  deleted
     Provider's Use of the Tariff.
        [no longer needed as
         Transmission Provider is an
         independent entity--
         transmission owners that are
         load-serving entities will
         now take service under the
         revised tariff]
    9  Regulatory Filings.............  A.6
    10  Force Majeure and               A.7
     Indemnification.
        10.1  Force Majeure...........  A.7.1
        10.2  Indemnification.........  A.7.2
    11  Creditworthiness..............  A.8
    12  Dispute Resolution Procedures.  A.10
        12.1  Internal Dispute          A.10.1
         Resolution Procedures.
        12.2  External Arbitration      A.10.2
         Procedures.
        12.3  Arbitration Decisions...  A.10.3
        12.4  Costs...................  A.10.4
        12.5  Rights Under the Federal  A.10.5
         Power Act.
Additions to Part I of the Tariff
    (1.11)  Eligibility for             A.9
     Transmission Provider Services.
        [replaces definition of
         Eligible Customer so that
         ``Customer'' could apply to
         transmission and market
         services]
    --Data and Confidentiality          A.12
     Provisions.
        [ensures that Transmission
         Provider and market
         monitoring unit have access
         to operational and bid data;
         additional changes to ensure
         Commission access to data for
         investigations]
II.  POINT-TO-POINT TRANSMISSION
 SERVICE
    [PTP service replaced by Network
     Access Service. Section replaced
     entirely (except as noted) by
     Network Access Service--many
     provisions here that are
     comparable to Network Integration
     Transmission Service retained]
Preamble
    13  Nature of Firm Point-To-Point
     Transmission Service
        13.1  Term....................  B.2.2.1.(vi)
            [modified to be as short
             as one hour of service]
        13.2  Reservation Priority....  deleted
            [first-come, first served
             priority system replaced
             with LMP, ``who values it
             the most'' system of
             rationing capacity]
        13.3  Use of Firm Transmission  deleted
         Service by the Transmission
         Provider.
            [``Transmission Provider''
             will take service under a
             service agreement like
             all other customers]
        13.4  Service Agreements......  B.2.5
            [modified for Network
             Access Service]
        13.5  Transmission Customer
         Obligations for Facility
         Additions or Redispatch Costs.
        13.6  Curtailment of Firm       deleted
         Transmission Service.
            [use NITS procedures]

[[Page 55578]]

 
        13.7  Classification of Firm
         Transmission Service.
        13.8  Scheduling of Firm Point- B.2.10
         To-Point Transmission Service.
            [revised to incorporate
             scheduling through the
             Day-Ahead and Real-Time
             markets]
    14  Nature of Non-Firm Point-To-    deleted
     Point Transmission Service.
            [all scheduled service is
             firm under Network Access
             Service]
    15  Service Availability
        15.1  General Conditions......  B.5.1
        15.2  Determination of          B.5.2
         Available Transmission
         Capability.
        15.3  Initiating Service in     B.2.9
         the Absence of an Executed
         Service Agreement.
        15.4  Obligation To Provide     B.5.9
         Transmission Service That
         Requires Expansion or
         Modification of the
         Transmission System.
        15.5  Deferral of Service.....
        15.6  Other Transmission        B.13
         Service Schedules.
            [modified to add service
             continues until contracts
             ``expire or'' are
             modified by the
             Commission]
        15.7  Real Power Losses.......  B.10.3.2
            [revised to reference
             markets and cost of
             marginal losses]
    16  Transmission Customer           B.8
     Responsibilities.
        16.1  Conditions Required of    B.8.1
         Transmission Customers.
        16.2  Transmission Customer     B.8.2
         Responsibility for Third-
         Party Arrangements.
    17  Procedures for Arranging Firm
     Point-To-Point Transmission
     Service.
        17.1  Application.............  deleted
            [Network Access Service
             will use comparable NITS
             procedures]
        17.2  Completed Application...  B.2.2.1
            [section retained with
             minor modifications in
             order and to establish
             minimum term of service
             of one hour; questions in
             preamble ask whether
             different procedures
             should be used by load-
             serving entity customers
             (who have load and/or
             generation and
             transmission facilities
             and need integration
             service) and non-load-
             serving entity
             transmission customers
             (who do not)]
        17.3  Deposit.................  B.2.2
        17.4  Notice of Deficient       B.2.6
         Application.
        17.5  Response to a Completed   B.2.7
         Application.
        17.6  Execution of Service      B.2.8
         Agreement.
        17.7  Extensions for            deleted
         Commencement of Service.
            [related to PTP
             reservations which will
             not be used by Network
             Access Service]
    18  Procedures for Arranging Non-   deleted
     Firm Point-To-Point Transmission
     Service.
        [all scheduled Network Access
         Service is firm]
    19  Additional Study Procedures
     for Firm Point-To-Point
     Transmission Service Requests
        19.1  Notice of Need for        B.5.3
         System Impact Study.
        19.2  System Impact Study       B.5.4
         Agreement and Cost
         Reimbursement.
        19.3  System Impact Study       B.5.5
         Procedures.
        19.4  Facilities Study          B.5.6
         Procedures.
        19.5  Facilities Study          B.5.7
         Modifications.
        19.6  Due Diligence in          B.5.8
         Completing New Facilities.
        19.7  Partial Interim Service.  B.5.10
        19.8  Expedited Procedures for  B.5.11
         New Facilities.
    20  Procedures if the Transmission  B.6
     Provider Is Unable To Complete
     New Transmission Facilities for
     Firm Point-To-Point Transmission
     Service.
        20.1  Delays in Construction    B.6.1
         of New Facilities.
        20.2  Alternatives to the       B.6.2
         Original Facility Additions.
        20.3  Refund Obligation for     B.6.3
         Unfinished Facility Additions.
    21  Provisions Relating to          B.7
     Transmission Construction and
     Services on the Systems of Other
     Utilities.
        21.1  Responsibility for Third- B.7.1
         Party System Additions.
        21.2  Coordination of Third-    B.7.2
         Party System Additions.
    22  Changes in Service
     Specifications
        22.1  Modifications On a Non-   deleted
         Firm Basis.
            [use NITS procedures]
        22.2  Modification On a Firm    deleted
         Basis.
            [use NITS procedures]
    23  Sale or Assignment of           D.3, 7, and 8
     Transmission Service.
        [revised--replaced with the
         resale of Congestion Revenue
         Rights]
    24  Metering and Power Factor       A.11
     Correction at Receipt and
     Delivery Points(s).
        24.1  Transmission Customer     A.11
         Obligations.
            [revised--additional
             detail added consistent
             with New York ISO Market
             Services Tariff]
        24.2  Transmission Provider     A.11
         Access to Metering Data.
            [revised--additional
             detail added consistent
             with New York ISO Market
             Services Tariff]
        24.3  Power Factor............  A.11
            [revised--additional
             detail added consistent
             with New York ISO Market
             Services Tariff]
    25  Compensation for Transmission   deleted
     Service.
        [charges based on NITS rates
         and charges instead (Section
         34)]
    26  Stranded Cost Recovery........  deleted
        [the Transmission Provider is
         now an independent entity;
         recovery of stranded costs
         remains permissible, but will
         no longer be part of the
         tariff]
    27  Compensation for New            deleted
     Facilities and Redispatch Costs.
        [assignment of redispatch
         costs replaced by LMP system]
III.  NETWORK INTEGRATION TRANSMISSION
 SERVICE

[[Page 55579]]

 
    [Replaced by Network Access
     Service; certain similar
     provisions retained and revised,
     as noted. Others added from PTP]
Preamble..............................  preamble
    28  Nature of Network Integration   B.1
     Transmission Service.
        [revised to become Network
         Access Service]
        28.1  Scope of Service........  B.1.1
        28.2  Transmission Provider     B.1.3
         Responsibilities.
        28.3  Network Integration       deleted
         Transmission Service.
            [requires OATT service to
             be comparable to native
             load service; all service
             now the same by
             definition]
        28.4  Secondary Service.......  B.1.4
            [revised to include
             Congestion Revenue
             Rights]
        28.5  Real Power Losses.......  B.10.3.2
            [revised--losses can also
             be provided through the
             market]
        28.6  Restrictions on Use of    deleted
         Service.
            [no restrictions on
             service--third part sales
             must be PTP; now one
             service for all]
    29  Initiating Service............  B.2
        29.1  Condition Precedent for   B.2.1
         Receiving Service.
        29.2  Application Procedures..  B.2.2.2
            [section retained with
             minor modifications to
             establish minimum term of
             service of one hour; but
             questions in preamble ask
             whether different
             procedures should be used
             by load-serving entity
             customers (who have load
             and/or generation and
             transmission facilities
             and need integration
             service) and non-load-
             serving entity
             transmission customers
             (who do not)]
        29.3  Technical Arrangements    B.2.3
         To Be Completed Prior to
         Commencement of Service.
        29.4  Network Customer          B.2.4
         Facilities.
        29.5  Filing of Service         B.2.5
         Agreement.
    30  Network Resources.............  B.3
        [section retained, but
         questions in preamble ask
         whether different procedures
         should be used by load-
         serving entity customers (who
         have load and/or generation
         and transmission facilities
         and need integration service)
         and non-load-serving entity
         transmission customers (who
         do not)]
        30.1  Designation of Network    B.3.1
         Resources.
        30.2  Designation of New        B.3.2
         Network Resources.
        30.3  Termination of Network    B.3.3
         Resources.
        30.4  Operation of Network      B.3.4
         Resources.
        30.5  Network Customer          B.3.6
         Redispatch Obligation.
            [redispatch obligation
             fulfilled through market
             structure--all generators
             will bid into market and
             follow Transmission
             Provider's dispatch
             instructions; section
             removes reference to
             Transmission Provider's
             own generation]
        30.6  Transmission              B.3.7
         Arrangements for Network
         Resources Not Physically
         Interconnected With the
         Transmission Provider.
        30.7  Limitation on             deleted
         Designation of Network
         Resources.
            [no limitations on amount
             of use of resources; any
             excess takes or
             deliveries priced at
             market clearing price]
        30.8  Use of Interface          deleted
         Capacity by the Network
         Customer.
            [customers can use as much
             interface capacity as
             they want as long as they
             are willing to pay
             congestion charges]
        30.9  Network Customer Owned    B.3.9
         Transmission Facilities.
    31  Designation of Network Load...  B.4
        [largely revised to remove the
         formal designation and
         replace with an
         identification of load and
         new loads]
        31.1  Network Load............  B.4.1
        31.2  New Network Loads         B.4.2
         Connected With the
         Transmission Provider.
        31.3  Network Load Not          deleted
         Physically Interconnected
         With the Transmission
         Provider.
            [required load on other
             systems to be counted as
             Network Load or served
             under PTP; now no charge
             for exports]
        31.4  New Interconnection       B.4.3
         Points.
        31.5  Changes in Service        B.4.4
         Requests.
        31.6  Annual Load and Resource  B.4.5
         Information Updates.
    32  Additional Study Procedures     B.5
     for Network Integration
     Transmission Service Requests.
        [now under Section 5, Service
         Availability. All sections
         modified to include requests
         for Congestion Revenue
         Rights]
        32.1  Notice of Need for        B.5.3
         System Impact Study.
        32.2  System Impact Study       B.5.4
         Agreement and Cost
         Reimbursement.
        32.3  System Impact Study       B.5.5
         Procedures.
        32.4  Facilities Study          B.5.6
         Procedures.
    33  Load Shedding and Curtailments  B.9
        33.1  Procedures..............  B.9.1
            [places curtailment
             procedures in the tariff
             rather than in Network
             Operating Agreements]
        33.2  Transmission Constraints  B.9.2
            [narrows focus of section
             to address only
             constraints not first
             resolved by the LMP
             system]
        33.3  Cost Responsibility for   deleted
         Relieving Transmission
         Constraints.
            [load ratio share
             allocation of redispatch
             costs is replaced by LMP
             system]
        33.4  Curtailments of           B.9.3
         Scheduled Deliveries.
            [narrows focus of section
             to address only
             constraints not first
             resolved by the LMP
             system; gives priority to
             customers with adequate
             resources who are also
             using Congestion Revenue
             Rights (question in
             preamble on whether we
             should grant this
             priority)]
        33.5  Allocation of             deleted
         Curtailments.

[[Page 55580]]

 
            [revised to no longer
             refer to sharing of
             curtailments between
             Transmission Provider and
             other customers--all load-
             serving entities will now
             be customers]
        33.6  Load Shedding...........  B.9.4
            [provision in tariff, not
             Network Operating
             Agreement; done on a non-
             discriminatory basis]
        33.7  System Reliability......  B.9.5
            [Transmission Provider can
             propose penalties for
             failure to follow a
             curtailment order]
    34  Rates and Charges.............  B.10
        34.1  Monthly Demand Charge...  B.10.1
            [revised to only apply the
             load ratio share Access
             Charge to deliveries to
             load located on the
             Transmission Provider's
             system; through and out
             service customers would
             not pay the Access Charge
             unless they wanted to
             receive a direct
             allocation of Congestion
             Revenue Rights]
        34.2  Determination of Network  B.10.2
         Customer's Monthly Network
         Load.
            [would only include load
             located on the
             Transmission Provider's
             system]
        34.3  Determination of          deleted
         Transmission Provider's
         Monthly Transmission System
         Load.
            [this section accounted
             for PTP service, which
             will no longer exist--may
             still need a transitional
             calculation]
        34.4  Redispatch Charge.......  B.10.3
            [revised to describe the
             Usage Charge, which
             consists of the
             congestion charge and the
             loss charge]
        34.5  Stranded Cost Recovery..  deleted
            [the Transmission Provider
             is now an independent
             entity; recovery of
             stranded costs remains
             permissible, but will no
             longer be part of the
             tariff]
    35  Operating Arrangements........  B.11
        35.1  Operation under the       B.11.1
         Network Operating Agreement.
        35.2  Network Operating         B.11.2
         Agreement.
        35.3  Network Operating         B.11.3
         Committee.
SCHEDULE 1
    Scheduling, System Control and      C.1
     Dispatch Service.
SCHEDULE 2
    Reactive Supply and Voltage         C.2
     Control From Generation Sources
     Service.
SCHEDULE 3
    Regulation and Frequency Response   C.3
     Service.
SCHEDULE 4
    Energy Imbalance Service..........  C.4
SCHEDULE 5
    Operating Reserve--Spinning         C.5
     Reserve Service.
SCHEDULE 6
    Operating Reserve--Supplemental     C.5
     Reserve Service.
SCHEDULE 7                              deleted
    Long-Term Firm and Short-Term Firm  deleted
     Point-To-Point Transmission
     Service.
        [all rates in Part VIII]
SCHEDULE 8                              deleted
    Non-Firm Point-To-Point             deleted
     Transmission Service.
        [no non-firm service]
ATTACHMENT A
    Form of Service Agreement for Firm  Part VI
     Point-To-Point Transmission
     Service.
        [name change for Network
         Access Service]
ATTACHMENT B
    Form of Service Agreement for Non-  deleted
     Firm Point-To-Point Transmission
     Service.
        [no non-firm service]
ATTACHMENT C
    Methodology To Assess Available     Attachment A
     Transmission Capability.
        [to be filed by Transmission
         Provider; must be done by an
         independent entity]
ATTACHMENT D
    Methodology for Completing a        Attachment B
     System Impact Study.
        [to be filed by Transmission
         Provider]
ATTACHMENT E
    Index of Point-To-Point             Attachment D
     Transmission Service Customers.
        [name change for Network
         Access Service]
ATTACHMENT F
    Service Agreement for Network       deleted
     Integration Transmission Service.
        [one for all Network Access
         Service Customers--Part VI]
ATTACHMENT G
    Network Operating Agreement.......  Attachment C
        [to be filed by Transmission
         Provider]
ATTACHMENT H
    Annual Transmission Revenue         Part VIII
     Requirement for Network
     Integration Transmission Service.
        [all rates addressed in Part
         VIII]
ATTACHMENT I
    Index of Network Integration        deleted
     Transmission Service Customers.
        [one for all Network Access
         Service Customers--Attachment
         D]
New Sections of the Pro Forma Tariff:
    Part II.D.  Congestion Revenue
     Rights
    Part III.  Day-Ahead and Real-Time
     Market Services
    Part IV.  Market Monitoring
    Part V.  Generation
     Interconnection Procedures

[[Page 55581]]

 
        [will be the outcome of the
         Standardization of Generator
         Interconnection Agreements
         and Procedures, Notice of
         Proposed Rulemaking, 99 FERC
         [para]61,086 (2002)]
    Part VI.  Transmission Planning
     and Expansion
    Part VIII.  Appendices (Details
     for calculation of rates and
     market clearing prices)
------------------------------------------------------------------------

Appendix E

Standard Market Design and Trading Strategies Encountered in the 
Independent System Operators

    Currently, five ISOs operate organized markets for energy and 
ancillary services, California ISO, PJM, New York ISO, ISO-New 
England and ERCOT. This appendix discusses how Standard Market 
Design would handle various trading strategies that were allegedly 
used for market manipulation in these ISOs, including those 
described by Enron Corporation in two memoranda as being used in the 
California wholesale markets. Standard Market Design incorporates 
lessons we have learned from experience in these organized markets. 
In many cases the proposed market rules have been designed to avoid 
the market design flaws that were the basis for these trading 
strategies. For others, Standard Market Design relies on strong 
market monitoring by the Independent Transmission Provider's Market 
Monitoring Unit and the Commission Office of Market Oversight and 
Investigation to ensure compliance with the market rules and to 
detect new market manipulation strategies.

Enron Strategies and Standard Market Design

    In memoranda dated December 6, 2000 and December 8, 2000, 
attorneys for Enron detailed various trading strategies that were 
being used in California wholesale markets. The strategies discussed 
in the Enron memoranda were mainly tailored to take advantage of 
flaws in the California market design, particularly its congestion 
management system. Standard Market Design uses a different 
congestion management system that would make most of these 
strategies infeasible.
    Most of the strategies described in the Enron memoranda depended 
on the development of a day-ahead schedule for power sales that was 
developed without determining whether that day-ahead schedule was 
physically feasible. In real time, the California ISO made payments 
to entities to relieve congestion. This created an incentive for an 
entity to create congestion in the day-ahead schedule at no cost so 
that the same entity would be paid to relieve that congestion in 
real time.
    Standard Market Design uses a nodal congestion management 
system, Locational Marginal Pricing (LMP) together with a physically 
feasible and financially binding day-ahead schedule. The use of a 
nodal congestion management system ensures that all transmission 
constraints are considered in developing day-ahead schedules and any 
congestion is reflected in the prices for energy and transmission 
services.\1\ Thus, there is no need to make separate payments in 
real time to relieve congestion in the day-ahead schedule, as there 
was in California. The day-ahead schedules under Standard Market 
Design would also be financially binding so that a marketer that 
changed its schedule in real time would still be financially liable 
for its day-ahead schedule. This also reduces the opportunities and 
incentives for market manipulation strategies that rely on 
differences between day-ahead and real-time prices.
---------------------------------------------------------------------------

    \1\ California used a zonal congestion management system that 
was designed to manage congestion between zones, but not within a 
zone. A nodal congestion management system is designed to manage 
congestion between any locations or nodes within the transmission 
system. In California, the day-ahead schedule for energy sales was 
developed by the PX and there was no requirement that this schedule 
be physically feasible
---------------------------------------------------------------------------

    A few of the strategies in the Enron memoranda appear to depend 
on the marketer providing false information to the ISO. Thus, these 
strategies rely on evading or violating the market rules rather than 
on market design flaws. Standard Market Design addresses these types 
of strategies by requiring an active market monitoring program that 
will detect violations of market rules and take appropriate action 
against entities that violate the market rules.
    The specific strategies in the Enron memoranda are discussed 
below.

A. The Big Picture

    1. ``Inc-ing Load'' (Fat Boy)--artificially increasing load on 
schedules submitted to the Cal PX; dispatching the generation as 
scheduled, which was in excess of actual load; being paid by the 
California ISO for the excess generation at the market clearing 
price.
    This strategy appears to be designed to evade the requirement 
for balanced day-ahead schedules by the California ISO. Standard 
Market Design does not require load or generation to submit balanced 
day-ahead schedules. Therefore, such a strategy is not necessary to 
offer excess generation to the market. The market rules provide 
sellers with varying methods to do this. However, there are 
scheduling requirements and entities that do not follow them may be 
subject to penalties.
    2. Relieving Congestion--creating congestion in the PX market 
(i.e., the energy scheduled for delivery exceeds the capacity of the 
transmission path) and ``relieving'' such congestion in the real-
time market. Accomplished by reducing schedules or scheduling 
transmission in the opposite direction, for which congestion payment 
is made by the ISO.
    This strategy appears designed to exploit a flaw in the 
California market design that is not present in Standard Market 
Design. The day-ahead schedule for energy developed by the PX market 
did not take into account transmission constraints. As such, the 
schedule that was developed was often not physically feasible. 
Second, entities were then paid to relieve the congestion in real-
time that resulted from the infeasible day-ahead schedule. In 
contrast, Standard Market Design uses a security constrained day-
ahead schedule for energy. This means the day-ahead schedule 
accounts for all transmission system constraints needed for reliable 
system operations. Thus, the day-ahead schedules in the Standard 
Market Design will not have the type of manufactured congestion 
discussed in the Enron memoranda. Standard Market Design also uses a 
more efficient congestion management system, LMP, than that used by 
the California ISO. Under LMP, the entities that cause congestion 
are charged for that congestion. Thus, there would be no need for 
separate payments by the ISO to relieve congestion as occurred in 
California.

B. Representative Trading Strategies

    1. Exports of California Power--buying energy for export and 
then importing that energy to evade the price caps in California.
    The strategy was designed to take advantage of the fact that 
there was a price cap in effect in only part of the market. This 
problem was eliminated in California when West-wide mitigation 
measures were imposed. Standard Market Design will apply consistent 
market mitigation measures across all regions. Thus, the incentive 
for this type of strategy is significantly reduced. Also, Standard 
Market Design includes a resource adequacy requirement for load 
serving entities that avoids or minimizes the energy shortage 
conditions that made this strategy possible.
    2. Non-firm Export--scheduling non-firm energy from a point in 
California to a control area outside of California and then cutting 
the non-firm energy after it receives payment for relieving 
congestion.
    This strategy appears to exploit a loophole in the California 
congestion management system that allowed an entity to get a payment 
for shipping power that wasn't actually shipped. In contrast, under 
Standard Market Design the day-ahead schedule would be financially 
binding so a marketer could not cancel the arrangement without a 
financial penalty. Also, Standard Market Design uses LMP to manage 
congestion rather than separate payments to relieve congestion.
    3. Death Star--scheduling energy in the opposite direction of 
congestion (counterflow) without putting energy onto or taking it 
off of the grid, yet still receiving congestion payments.
    This strategy appears designed to exploit a flaw in the way that 
congestion charges were paid in California. Under LMP, the entity 
would only be paid in real time for power

[[Page 55582]]

that actually flowed. Congestion charges would be computed as the 
difference between two locational energy prices under a LMP system 
rather than a separate charge as in California. This particular 
strategy also appears to depend on different congestion management 
systems being in effect in contiguous areas. That is, the California 
ISO's congestion charges did not reflect the availability of 
additional transmission capacity along a parallel path in an 
adjacent system. As long as that happens there likely are some 
opportunities for market manipulation. The long-term fix for this 
type of problem is a standard market design that applies to all 
areas within the market. Also, large regional organizations that 
cover natural markets will fix this problem. In Order No. 2000, the 
Commission encouraged the formation of these types of regional 
organizations.
    4. Load Shift--submitting artificial schedules in order to 
receive inter-zonal congestion payments. Shifting load to receive 
congestion payments.
    The strategy relies on the flaws in the congestion management 
system in California. The zonal congestion system used in California 
provides more opportunities to game congestion than the nodal 
congestion system under LMP. Because of the separation of the day-
ahead market (formerly administered by the PX) and the real-time 
balancing market (administered by the ISO), there are numerous ways 
that market participants can create artificial congestion in the 
day-ahead market and then be paid to relieve the congestion in real 
time. Under LMP, the entity that caused the congestion would pay for 
the congestion.
    5. ``Get Shorty''--paper trading of ancillary services. Enron 
has to submit false information to the CA ISO on the location of the 
plants to sell the ancillary services.
    Standard Market Design proposes a day-ahead and real-time market 
for ancillary services. Financial bids for ancillary services are 
not permitted. Bidders would be required to identify specific units 
that would be used to provide the ancillary services. Market 
monitoring would be used to ensure that ancillary service bids are 
backed by real resources.
    This strategy is also based on virtual bidding, something that 
is allowed under Standard Market Design for energy markets. Virtual 
bidding should cause the prices in the day-ahead and real-time 
markets to converge. This by itself does not harm customers. It 
means that a customer that buys power in real time will pay 
approximately the same as a customer that buys power day ahead. 
However, under Standard Market Design, bidders would be required to 
specifically identify energy bids that are not backed by physical 
resources. This is important for reliability purposes, to ensure 
that the transmission provider can ensure that sufficient physical 
resources are committed to meet the projected load. In contrast, 
Enron apparently indicated the ancillary bids were backed by 
physical resources when they were not. This could have affected 
reliability if Enron was actually called on to supply the ancillary 
services.
    6. Wheel Out--scheduling a transmission flow while knowing that 
an intertie is completely constrained or that a line is out of 
service. Even though no energy is delivered, the trader will be paid 
a congestion charge for cutting the transaction.
    This strategy appears designed to exploit two flaws in the 
California system that do not exist in Standard Market Design. 
First, because Standard Market Design uses security-constrained unit 
commitment and dispatch procedures in operating their energy 
markets, market participants could not schedule transactions day-
ahead or real-time that are physically impossible. Second, the 
congestion management system under Standard Market Design is fully 
integrated with the energy markets and therefore would not provide 
separate payments for relieving congestion as in California. Under 
LMP, if more entities were trying to schedule an export than the 
physical capacity of the line, this excess would be reflected in the 
market clearing prices for the energy exports, which in turn would 
be used to compute appropriate congestion charges. Thus, there would 
be nothing to gain in using this strategy.
    7. Ricochet--Buying energy from the Cal PX and exporting it to 
another entity which charges a small fee. The energy is resold in 
the real-time market.
    The main purpose of this strategy is to evade California's price 
caps which apply to in-state generation, but not to external 
generation purchased ``out of market.'' Under Standard Market Design 
there would be consistent market mitigation measures across the 
country. Therefore, there would not be the opportunity to take 
advantage of the differences in market rules. In California, the 
``Ricochet'' strategy ended when consistent West-wide mitigation 
rules went into effect.
    8. Selling non-firm as firm--selling or reselling what is 
actually non-firm energy to the Cal PX but claiming that it is firm 
energy.
    The reason for this strategy is that Enron would get paid for 
ancillary services if the energy was labeled as firm, but would not 
get paid for ancillary services if it was labeled as non-firm. Under 
Standard Market Design all transmission service would be under 
Network Access Service so there would be no difference in the 
ancillary service requirements. Thus, there would be no reason for 
this strategy.
    9. Scheduling energy to collect congestion charge--scheduling a 
counterflow even though a company does not have any available 
generation. The entity is charged the real-time price for energy 
that it is short but receives a congestion payment for the scheduled 
counterflow. This activity is profitable whenever the congestion 
payment is greater than the charge associated with the energy that 
was not delivered.
    This strategy exploited a loophole in the CA ISO congestion 
management system that does not exist under the LMP system used in 
Standard Market Design. As the memorandum notes, CA ISO paid 
congestion charges whether any power flowed or not. Under Standard 
Market Design if an entity sold energy in the day-ahead market it 
would either have to provide the energy in real time or buy back its 
position (it would be charged the real-time price for the energy). 
Also, the strategy may be related to the fact that the day-ahead 
schedule for energy developed by the Cal PX did not account for 
transmission constraints. CA ISO then paid congestion charges to 
entities to relieve the congestion they had created through their 
scheduling. The security constrained day-ahead schedules required in 
Standard Market Design takes into account transmission constraints. 
So, there is not the same opportunity for this type of market 
manipulation.

Market Manipulation in the Eastern ISO Markets: Implications for 
Standard Market Design

    Because several components of Standard Market Design are based 
on market designs in effect in the Eastern ISOs markets--PJM, New 
York and New England--it is important to turn to these markets to 
verify that the Standard Market Design rules protect against market 
manipulation. In this regard, the following points are important. 
First, the Eastern ISO markets have recognized almost from the start 
of market operations that no market design can protect against 
market power due to structural conditions, such as the high 
concentration of firms in a region or load pocket and/or the lack of 
price-sensitive demand. For this reason, the Standard Market Design 
includes market power mitigation rules.
    Second, there have been several years of learning in the Eastern 
ISO markets on market design. Small details of market design can 
turn out to have major effects on market performance. We have used 
this experience in developing the market rules for Standard Market 
Design.
    Like the California markets, the Eastern ISO markets have been 
alleged to be subject periodically to physical and economic 
withholding of capacity by firms and other measures employed as a 
means to increase market prices for energy, ancillary services and 
installed capacity, and to manipulate the prices for transmission 
rights. However, these attempts have been more sporadic and have had 
a far less significant economic impact than California. This is due 
in part to the fact that approximately 85 percent of demand is 
covered under long-term contracts and therefore is unaffected by 
spot price volatility. In general, the Eastern markets are 
considered relatively competitive and have a range of measures in 
place to monitor and mitigate locational market power.\2\ Several 
problematic markets, especially for installed capacity, have been 
eliminated or substantially modified. In addition, at least some 
types of market manipulation that have occurred in the New England 
market are associated with its interim market design,

[[Page 55583]]

and will not recur under the Standard Market Design. Similarly, in 
New York, many initial poor design decisions and software choices 
made within a framework similar to the proposed Standard Market 
Design have been modified and improved, yielding some lessons for 
future attempts to implement Standard Market Design markets.\3\
---------------------------------------------------------------------------

    \2\ Each of the Eastern ISOs produces reports on market 
performance and on market power monitoring and mitigation. These 
reports are available on the ISO Web-sites; particular reports 
referenced in this section will be cited. In addition, filings 
before the Commission and Commission orders address these issues and 
will also be cited when referenced. See also FERC, ``Investigation 
of Bulk Power Markets: Northeast Region,'' November 1, 2000, 
available on the FERC web-site; State of New York Department of 
Public Service, ``Interim Pricing Report On New York State's 
Independent System Operator,'' Department of Public Service Pricing 
Team, December 2000.
    \3\ David B. Patton and Michael T. Wander, ``2001 Annual Report 
on The New York Electric Markets,'' Independent Market Advisor to 
the New York ISO, June 2002.
---------------------------------------------------------------------------

    The previous section examined whether the Enron strategies in 
California could be used to manipulate prices under the Standard 
Market Design. This section reviews some of the publicly known 
examples of market manipulation in the Eastern ISO markets and 
discusses whether and how the Standard Market Design would prevent 
such activity.\4\ The ISO market monitoring reports and filings 
before the Commission provide many further examples of market 
manipulation in the Eastern ISO markets that concern either minor 
events, transitory problems, or market rule changes made in 
anticipation of potential market manipulation. The Standard Market 
Design may not specifically require many of those rules, but the 
Commission will review Standard Market Design compliance filings to 
evaluate whether proposed market rules are susceptible to 
manipulation.
---------------------------------------------------------------------------

    \4\ Some paragraphs in this section are excerpted from FERC, 
``Investigation of Bulk Power Markets: Northeast Region,'' November 
1, 2000.
---------------------------------------------------------------------------

A. Energy Markets

    The Eastern ISO energy markets have been subject to forms of 
market manipulation and market power, including both economic and 
physical withholding. Most exercise of market power in the energy 
markets occurs in two types of system conditions: (1) The existence 
of persistent transmission constraints in some locations and (2) 
periods of system-wide shortage of energy, such as exists on peak-
load days or during emergencies. Locations that are on the import 
side of persistently congested transmission lines (sometimes called 
``load pockets'') present the most opportunity for exercise of 
market power due to the high concentration that occurs in these 
locations. Generators in these locations are typically closely 
monitored and/or placed under contract to prevent bid price 
increases. Hence, this section will not consider market power in 
these locations.
    During capacity shortages or system emergencies, market power is 
more diffuse, reflecting the possibility that all generation will 
have to be dispatched. For example, the PJM market monitor believes 
that high energy prices in the summer of 1999 were the result of the 
interaction of high demand levels with supply curves that exhibited 
steep slopes over very narrow ranges of output. Some firms appear to 
have withheld capacity and changed bid parameters during peak hours 
as a means to drive up prices (see discussion below). However, these 
prices also appear to have attracted imports into PJM. The market 
monitor thus concluded that the high prices were due both to 
scarcity and to the exercise of market power, but that the relative 
importance of the two factors could not be determined.\5\
---------------------------------------------------------------------------

    \5\ PJM Market Monitoring Unit (MMU), ``PJM Interconnection 
State of the Market Report 1999,'' June 2000. The report explains 
that long-term net revenue results indicate that prices were 
competitive in 1999.
---------------------------------------------------------------------------

    During periods of shortage, interactions between the energy 
markets and the markets for ancillary services and installed 
capacity are also more significant. Market power in each type of 
market can affect the other. Price increases in the energy markets 
will lead to higher prices for ancillary services, since the prices 
in the latter markets reflect the opportunity costs associated with 
forgone energy sales.\6\ Maintenance of the operating reserve 
requirement can also drive up prices in the energy market, because 
the ISO markets require that all energy should be taken to preserve 
the reserve margins prior to having to reduce them (see example 
1(a), below); hence withholding of reserves could drive up not just 
reserve prices but also energy prices.\7\
---------------------------------------------------------------------------

    \6\ The standard pricing rule for regulation and operating 
reserves is to compensate generators that would have been scheduled 
for energy but are withheld for regulation or reserves for the 
forgone energy revenues. This pricing rule is continued in the 
Standard Market Design.
    \7\ In addition to the example in 1(a), there are some 
significant instances in which the reliability rules that require 
ISOs to purchase energy from any external or internal source to 
maintain the reserve margin can increase the energy price. For 
example, prior to the imposition of the $1000 energy bid cap in the 
Eastern ISOs, ISO New England experienced an $6000/MWh energy 
clearing price for four hours in May 2000 due to an import purchase 
that was taken to avoid degrading the internal reserve margin. 
However, this case was not deemed to be exercise of market power. 
See FERC, ``Investigation of Bulk Power Markets: Northeast Region,'' 
November 1, 2000.
---------------------------------------------------------------------------

    1. Manipulation of physical bid parameters to extend the 
operating time or increase the output level of a generator and 
increase the market price--Several ISO markets have experienced 
firms' use of the bid-in physical parameters of generators, such as 
minimum run times and low operating levels, to extend the operating 
time and/or output of the generator and possibly set a higher market 
clearing price than was economically necessary. Typically, these 
problems are combined with specific market rules that allow the 
change in physical bid parameters to impact the price (under a 
purely competitive market assumption, changes in these parameters 
should not affect the price in the market). Two specific cases 
follow.
    (a) In PJM, certain generators were increasing their minimum run 
times to the full 24 hours of the day and submitting high price 
bids. Under the PJM energy market rules, the bids were evaluated 
over the full day; hence, under normal conditions, high price bids 
would be rejected. However, in Maximum Generation Emergencies, PJM 
was required to take all economic offers, regardless of the number 
of hours of the day in which such offers were economic, prior to 
taking other emergency measures, such as recalling capacity 
resources. This allowed these generators to run at a high price all 
day and set LMPs higher than the $1,000 bid cap. PJM estimated that 
in 1999, excess energy payments to just one plant of $8 million 
resulted from this bidding technique. The Commission approved PJM's 
market rule revision to address this problem, which restricted the 
bid sufficiency guarantee only to the hours in which the generator 
bid was economic during the emergency.\8\
---------------------------------------------------------------------------

    \8\ See PJM Interconnection, L.L.C., 92 FERC [para] 61,013 
(2000).
---------------------------------------------------------------------------

    Under the proposed Standard Market Design market rules, as in 
PJM, a generator's bid offer must be considered over the full day. 
Hence in normal circumstances, as in PJM, changing the generator's 
minimum run time should not confer any competitive advantage. The 
Standard Market Design rules explicitly require that the 
Transmission Provider must evaluate how emergency conditions affect 
market prices. In complying with this requirement, the Commission 
will evaluate whether the rules prevent market manipulation, whether 
by adopting the PJM rules or some other measures.
    (b) In New England, generators were bidding very high low 
operating levels--that is, setting a high minimum output level. By 
the existing rules in New England, these generators were not 
eligible to set the Energy Clearing Price but were eligible for 
uplift payments based on their bid. The ISO proposed, and the 
Commission accepted, that generators would be required to bid their 
physical low operating levels, subject to adjustment for emissions 
or economic efficiency reasons.\9\ This kind of problem would be 
less likely in an LMP-based system with a revenue sufficiency 
guarantee.
---------------------------------------------------------------------------

    \9\ See ISO New England, Inc., 99 FERC [para] 61,124 (2002).
---------------------------------------------------------------------------

    Under Standard Market Design, the Transmission Provider is given 
authority to put limits on the frequency with which physical bid 
parameters can be changed, and other limits on how the operating 
characteristics of the generators are bid. These potential bid 
restrictions can be used to address any evidence of market 
manipulation or to anticipate such behavior.

B. Ancillary Service Markets

    Bid-based ancillary service markets typically have fewer 
eligible suppliers (particularly until demand-side resources 
participate) than the energy markets as well as inelastic demand 
(unless demand curves for reserves are established). Locational 
reserve requirements may narrow the markets further. Finally, as 
noted above, market power in the energy markets is transferred to 
the ancillary service markets through opportunity cost payments and 
other market rules.\10\ These factors make monitoring of these 
markets important. Under normal conditions, it is expected that 
regulation and operating reserves should account for under 10 
percent of total market costs, and in the Eastern ISO markets are 
often under 5 percent. In contrast, in a few cases, poorly designed 
ancillary service markets and/or exercise of market power in these 
markets have resulted in ancillary services

[[Page 55584]]

temporarily accounting for a much higher percentage of total 
electricity costs.\11\
---------------------------------------------------------------------------

    \10\ PJM Market Monitoring Unit (MMU), ``PJM Interconnection 
State of the Market Report 2001,'' PJM Interconnection, L.L.C., June 
2002, p. 108.
    \11\ For example, New York ISO experienced one month, February 
2000, in which regulation and operating reserves accounted for 
almost 30 percent of total market costs. This was an aberration due 
to the market power in the reserves markets discussed in example 
(1); following market power mitigation measures, the costs of these 
ancillary services dropped to under 5 percent of total market costs. 
See Patton, David B., ``New York Market Advisor Annual Report on The 
New York Electric Markets for Calendar Year 2000,'' ISO New York, 
April 2001, p. ix.
---------------------------------------------------------------------------

    1. Withholding of Operating Reserves--The New York ISO markets 
for operating reserves experienced withholding of operating reserves 
in the Spring of 2000, resulting in substantially higher prices for 
these products for several months.\12\ In particular, ten-minute 
non-spinning reserves were both withheld from the market physically 
or bid in at a high level by the three major suppliers. The high 
price for this reserve in turn drove up prices for regulation and 
the other operating reserves. In response, the Commission approved a 
bid cap on ten-minute non-spinning reserves and the New York ISO 
took additional measures to increase supply.\13\ The Commission 
subsequently imposed a bid cap on non-spinning reserves in the ISO 
New England markets for similar reasons.\14\ PJM delayed the start 
of a ten-minute spinning reserve market in part due to concerns 
about the potential for limited sellers of the product.
---------------------------------------------------------------------------

    \12\ See id.
    \13\ New York Independent System Operator, Inc., et al., 91 FERC 
[para] 61,218 (2000).
    \14\ See ISO New England, Inc., 99 FERC [para] 61,124 (2002).
---------------------------------------------------------------------------

    As in the energy markets, Standard Market Design auctions alone 
cannot solve structural sources of market power in the regulation 
and operating reserves markets. Rather, these problems must be 
addressed through a combination of market power mitigation measures, 
such as bid caps, and structural solutions, such as encouraging 
entry into these markets by generators with flexible start-times.

C. Congestion Management Systems and Transmission Rights

    The congestion management system based on LMP and financial 
transmission rights proposed in the Standard Market Design and in 
use in PJM and New York presents a clear advantage over the 
transmission line-loading relief (TLR) methods used in other parts 
of the country. The LMP-based method has caused far fewer instances 
of transmission curtailments.\15\ At the same time, any transmission 
network with congestion pricing and financial transmission rights is 
susceptible to some degree to market manipulation.\16\ Heretofore, 
there has been some evidence of manipulation of these design 
elements in the Eastern ISO markets, although nothing that has 
disrupted the markets. Nevertheless, under Standard Market Design, 
such behavior will be monitored for and mitigated if found.
---------------------------------------------------------------------------

    \15\ See, e.g., FERC, ``Investigation of Bulk Power Markets: 
Southeast Region,'' November 1, 2000; and FERC, ``Investigation of 
Bulk Power Markets: Midwest Region,'' November 1, 2000.
    \16\ Although electricity flows in complex patterns determined 
by physical laws and subject to the simultaneous interaction of all 
injections and withdrawals on the systems, the ways in which 
generators load certain lines can be calculated (through so-called 
``generation shift factors'') or understood through experience.
---------------------------------------------------------------------------

    Care must be taken to discriminate between legitimate 
transactions and those aiming to favor owners of certain generation 
or transmission assets. Increasing congestion is not necessarily a 
sign of intentional activity to congest; all the Eastern ISOs report 
increasing congestion as market trading increases simply because 
there is more demand for distant resources and associated 
transmission. In addition, changes in congestion accounting may 
increase the amount of apparent congestion\17\ and transmission 
maintenance or outages can also have a major effect.
---------------------------------------------------------------------------

    \17\ For example, PJM reports a notable increase in congestion 
over low-voltage facilities, which is at least in part associated 
with PJM assuming monitoring and control of these facilities from 
transmission owners. See PJM Market Monitoring Unit (MMU), ``PJM 
Interconnection State of the Market Report 2001,'' PJM 
Interconnection, L.L.C., June 2002, p. 126.
---------------------------------------------------------------------------

    An important financial linkage in the Standard Market Design is 
between the congestion management system and the holding of 
Congestion Revenue Rights. The Standard Market Design rules aim to 
find a method of allocation, trade and settlement of such rights 
that is equitable, transparent, provides appropriate incentives for 
maintenance of and investment in transmission assets, and is 
resistant to manipulation. The following example shows how market 
manipulation can occur.
    1. Sharing of information about Transmission Maintenance by 
Transmission Owners to affect the value of affiliates holdings of 
Transmission Rights--In PJM, information acquired during a non-
public investigation suggested that subsidiaries of Exelon, may have 
shared information that gave the marketing subsidiary an 
informational advantage in its bidding for Fixed Transmission Rights 
(FTRs) in the monthly FTR auctions. After the bidding closed in 
three auctions held in September, October, and November 1999, PECO 
announced maintenance outages on transmission facilities within PJM. 
The Commission directed Exelon, PECO and Exelon Power Team to show 
cause whether they violated section 205(b) of the Federal Power Act 
(FPA) and the standards of conduct and the Commission's regulations 
by operating PECO's transmission system in an unduly preferential 
manner or sharing non-public information regarding the timing and 
location of maintenance outages in PJM's system or both. The 
Commission also directed PJM to report, to the Commission on its 
current transmission oversight processes and procedures regarding 
maintenance and de-rating decisions.\18\ PJM subsequently modified 
its transmission oversight procedures to eliminate incentives for 
such behavior.\19\
---------------------------------------------------------------------------

    \18\ See PJM Interconnection, L.L.C., 97 FERC [para] 61,010 
(2001).
    \19\ See PJM Interconnection, L.L.C. ``Report of PJM 
Interconnection, L.L.C. on Transmission Oversight Procedures, Docket 
No. EL01-122-000 (November 2, 2001).
---------------------------------------------------------------------------

    This problem is generic to electricity markets with transmission 
rights. The rights established under Standard Market Design, which 
include financial rights analogous to FTRs in PJM, are susceptible 
under some conditions to manipulation by transmission owners and 
their affiliates. The Standard Market Design requires market 
monitoring and appropriate transmission maintenance oversight and 
incentives to mitigate such problems.

D. Installed Capacity Markets

    Each of the Eastern ISO markets has an installed capacity 
requirement and an ISO-operated capacity market (with the exception 
of New England, in which the market was terminated). The design of 
these markets is different in each ISO, as is the market structure 
(that is, the degree of firm concentration in the market); hence, 
the problems experienced in each market have also been different. As 
discussed in this proposed rule preamble (Section H), for various 
reasons the proposed Standard Market Design includes a resource 
adequacy requirement similar in purpose to what is called here 
``installed capacity'' but does not include either specific rules 
for a tradable capacity product or a centralized market to provide 
such adequacy. However, regions may choose to establish such 
markets. This section discusses some of the market manipulation that 
has been experienced in the existing ICAP markets. The Commission 
will evaluate any proposals for new markets for resource adequacy on 
the basis that they do not result in a repeat of the flaws detected 
in the existing ISO installed capacity markets.
    1. Bid Manipulation of poorly defined ICAP products (New 
England)--The original ISO New England ICAP market was recognized as 
a flawed market almost from its inception (along with other aspects 
of the New England markets),\20\ but the true problems and attempts 
at market manipulation did not emerge until several months into 
operations. The basic flaw was that the ICAP product did not have 
any recall obligations or deliverability requirements and had only 
seasonal availability requirements. Hence, its value in the monthly 
auction was determined not by the value of ICAP but by the ability 
to manipulate the price. The auction clearing price tended to swing 
between $0/MW and very high prices. In early 2000, the ISO 
determined that the ICAP price was due to

[[Page 55585]]

market power and revised the price for several months.
---------------------------------------------------------------------------

    \20\ The preliminary New England market design was developed by 
NEPOOL committees over the course of 1998. Problems with this design 
were suggested by independent experts under contract to the ISO (See 
Peter Cramton and Robert Wilson, ``A Review of ISO New England's 
Proposed Market Rules,'' Report to ISO New England, Market Design 
Inc., September 1998). However, these experts, the ISO and NEPOOL 
supported beginning market operations and addressing market design 
problems with the markets in progress. NEPOOL proposed a phased 
implementation which was approved by the Commission. Market trials 
were run in January 1999 and the markets were started on May 1, 
1999.
---------------------------------------------------------------------------

    The subsequent modifications of the New England ICAP 
requirements and markets will not be reviewed here. In a June 28, 
2000, order, the Commission agreed with the ISO that the existing 
installed capability auction market was not useful and that it could 
produce inflated prices unrelated to the actual harm created by 
installed capability deficiencies.\21\ The Commission permitted the 
elimination of the auction market effective August 1, 2000, and 
required the ISO to revert to administratively-determined deficiency 
charge for failure to meet installed capability requirements.
---------------------------------------------------------------------------

    \21\ See ISO New England, Inc., et al., 91 FERC [para] 61,311 
(2000).
---------------------------------------------------------------------------

    2. Withholding of ICAP (PJM)--In the ICAP markets in PJM and New 
York, both structural problems and market design issues have 
resulted in ongoing refinement of market design and measures to 
limit the exercise of market power. An in-depth explanation of the 
designs of these markets is beyond the scope of this section; 
rather, the focus will be on the exercise of market power in the PJM 
daily capacity credit market in early 2001. The PJM market monitor 
has noted potentially high concentration and design flaws in this 
market since its inception on January 1, 1999, and there have been 
modifications of the market rules several times.
    In PJM, each load-serving entity has the obligation to own 
capacity, have a bilateral contract for capacity, or purchase 
capacity credits through a centralized market equal to its peak load 
plus a reserve margin. To qualify as a capacity resource, a 
generating unit must pass tests regarding overall capability and the 
ability to deliver energy to PJM load, which requires adequate 
transmission capability. Load-serving entities can use their 
capacity resources to produce energy for export from the PJM control 
area, but such transactions are subject to recall by PJM in 
emergencies. If a load-serving entity's capacity resources are less 
than its obligation, then it is considered deficient and subject to 
a penalty. In 2001, the capacity credit market was operated on a 
daily, monthly and multi-monthly basis as well as on an ``interval'' 
basis defined by seasons (the daily market serves residual demand 
after the markets for longer-term credits close).
    Between January and April 2001, a single firm raised the price 
in the daily capacity credit market for a sustained period of time 
by essentially being in a position that required all buyers that 
were short of capacity to have to purchase some or all of their 
capacity from it. The determination that this price increase was the 
exercise of market power through economic withholding was made on 
the basis of the excess capacity available at the time as well as 
calculation of the opportunity cost of that capacity, which is the 
sale of the firm energy output forward into a neighboring market. 
Effective June 2001, the Commission approved market rule changes 
that diminished the incentive to economically withhold by spreading 
the revenues accruing to owners of excess capacity to all compliant 
load-serving entities rather than to the single firm.\22\
---------------------------------------------------------------------------

    \22\ See PJM Interconnection, L.L.C., 95 FERC [para] 61,175 
(2001).
---------------------------------------------------------------------------

Appendix F

Access Charges and Congestion Revenue Rights

Allocation of Congestion Revenue Rights

Phase I (Initial Allocation)--Through Direct Assignment Based on 
Historical Use

    All existing customers using transmission service, whether 
through bundled contracts, service agreements under the pro forma 
tariff, or pre-Order No. 888 transmission contracts, pay the 
transmission rate, i.e., the access charge, which enables the 
transmission owner to recover the fixed, or embedded, costs of its 
transmission system. Moreover, the existing pro forma tariff grants 
priority for transmission capacity to existing long-term firm 
customers.
    This proposed rule gives the region a choice between an initial 
allocation or an auction of Congestion Revenue Rights. The first 
portion, ``Phase I,'' deals with regions that start with an 
allocation of Congestion Revenue Rights to existing long-term 
customers based on their historical use of the system. In this sense 
there is a link between paying the access charge and receiving 
Congestion Revenue Rights. However, this is not a one-to-one link, 
i.e., not all customers paying the access charge will receive 
Congestion Revenue Rights--customers with short-term or non-firm 
service under the existing pro forma tariff currently pay an access 
charge but would receive no Congestion Revenue Rights through the 
initial allocation process. This is consistent with Section 2.2 of 
the existing pro forma tariff, which grants rollover rights (which 
guarantee access to firm service) only to longer-term contracts.

Phase I: Specific Examples--What the Customer Pays and What the 
Customer Gets

    The following answers the question of whether and how the 
following customers currently receiving various services will pay 
access charges or receive Congestion Revenue Rights. All service in 
the following examples would be performed under Network Access 
Service upon implementation of Standard Market Design.

A. Short-Term and Non-Firm Contracts (less than one year in duration)

    These customers would receive no Congestion Revenue Rights 
(however, transactions under which power is taken off the grid pay 
an access charge; those under which power is not taken off the grid 
do not pay an access charge). These contracts would be converted to 
Network Access Service at the time Standard Market Design is 
implemented through the SMD Tariff.

B. Long-Term Contracts (one year or longer)

    1. Existing Network Integration Transmission Service--These 
customers currently pay and would continue to pay the access charge, 
and would receive a direct allocation of Congestion Revenue Rights.
    2. Existing Point-to-Point Service.
    a. Load-Serving Entity (service to load within a single 
Transmission Provider's area)--These customers currently pay and 
would continue to pay the access charge, and would receive a direct 
allocation of Congestion Revenue Rights.
    b. Internal, Non-Load Serving Transactions (service within a 
single Transmission Provider's area from generator to hub, hub-to-
hub, or to support sales to the spot market)--The customer currently 
has specific rights to capacity between stated points and, for this, 
pays the access charge. Under Standard Market Design, it would be 
permitted to retain its priority rights, albeit in the form of 
Congestion Revenue Rights rather than firm transmission capacity 
rights through Phase I. For this continued right, however, the 
customer must continue to pay the access charge to receive a direct 
allocation of Congestion Revenue Rights. In other words, it could 
choose to either (1) continue the point-to-point contract, including 
paying the access charge, and for that would receive a direct 
allocation of Congestion Revenue Rights; or (2) terminate the 
contract, meaning the customer would no longer pay the access 
charge, no longer receive specific transmission capacity rights 
between points, and, therefore, would not receive a direct 
allocation of Congestion Revenue Rights. Under the second choice, 
the customer would instead schedule service in the day-ahead and 
real-time markets and pay the applicable congestion and loss 
charges.
    c. Through and Out (export by generator or marketer)--Consistent 
with internal, load-serving transactions (above), the customer 
currently has specific rights to capacity between stated points and, 
for this, pays the access charge, but would no longer be required to 
pay the access charge to export power to another region. It would be 
permitted to retain its priority rights, albeit in the form of 
Congestion Revenue Rights rather than firm transmission capacity 
rights through Phase I so long as it continued to pay an access 
charge on the source Transmission Provider's system. In addition, 
the access (or scheduling) charge paid by all load-serving entities 
taking power off of the grid on the sink side of a transaction 
involving two Transmission Providers' systems would include a 
portion of the transmission costs from the source side of the 
transaction, as explained below.
    3. Existing Pre-888 Transmission Contract--These contracts are 
not standard and may have characteristics of Network Integration 
Transmission Service or Point-to-Point Transmission Service. 
Customers currently pay an access charge (though likely a different 
charge than under the pro forma tariff). In either case, the load-
serving entity (the transmission owning public utility who currently 
is the transmission provider), would pay the Transmission Provider 
the access charge on behalf of the pre-888 customer, and would 
receive any direct allocation of the Congestion Revenue Rights 
associated with the contracts, unless the customer converted its 
contract to Network Access Service. Continued payment of the access 
charge and direct allocation of Congestion Revenue Rights would be 
based

[[Page 55586]]

on the nature of the service and would be determined consistent with 
the pattern established above.
    4. Bundled Wholesale Contract--Like pre-888 transmission 
contracts, these contracts are not standard and may have 
characteristics of Network Integration Transmission Service or 
Point-to-Point Transmission Service. Customers currently pay an 
access charge (though likely a different charge than under the pro 
forma tariff). Like the pre-888 contracts, the load-serving entity 
(the transmission owning public utility who currently is the 
transmission provider), would pay the Transmission Provider the 
access charge on behalf of the bundled wholesale customer, and would 
receive any direct allocation of the Congestion Revenue Rights 
associated with the contracts, unless the customer converted its 
contract to Network Access Service. Continued payment of the access 
charge and direct allocation of Congestion Revenue Rights would be 
based on the nature of the service and would be determined 
consistent with the pattern established above.
    5. Bundled Retail Customers--There is no specific contract 
defining transmission rights for this type of service. Customers 
currently pay an access charge through the bundled rate. The load-
serving entity, often the transmission owning public utility who 
currently is the transmission provider, would pay the Transmission 
Provider the access charge on behalf of the bundled retail customer, 
and would receive a direct allocation of the Congestion Revenue 
Rights.
    6. Retail Choice--Customers in states with retail choice are 
either transmission customers under the pro forma tariff, or they 
are buying power from a supplier who is acting as the transmission 
customer on their behalf. They currently directly (or indirectly 
through the supplier) pay the access charge. The transmission 
customer in these transactions would receive the direct allocation 
of Congestion Revenue Rights. However, if the retail customer 
switched suppliers, this proposed rule establishes the principle 
that the Congestion Revenue Rights move with the load (i.e., the 
Transmission Provider would have to periodically reallocate the 
Congestion Revenue Rights based on each load-serving entities' load 
ratio share).

Phase II (within four years of adoption of Standard Market Design)--
Through an Auction

    Under Phase II, Congestion Revenue Rights (other than those 
assigned to an entity on a ``life of the facility'' basis as a 
result of the customer paying for the network upgrades) will be 
auctioned off rather than allocated to particular customers. The 
link between paying the access charge and receiving Congestion 
Revenue Rights will no longer exist once we move to a full auction, 
since any entity can acquire Congestion Revenue Rights through the 
auction, with no requirement to pay an access charge to get them. 
Instead, the link moves to the revenue side, i.e., the auction 
revenues would be returned to those customers paying the embedded 
costs of the system through an access charge.

Are There Differences in the Allocation of Congestion Revenue Rights 
Based on How the Rates Are Paid?

    1. Service with rate based on open access tariff's embedded cost 
charge.
    a. At the time of direct allocation--this is defined above 
(long-term customers pay the access charge and get the direct 
allocation of Congestion Revenue Rights)
    b. At the time of the auction--this is defined above for various 
categories of customers (some customers will continue to pay the 
access charge, which will be reduced by auction revenues, but all 
Congestion Revenue Rights will be auctioned)
    2. Service with rate based on incremental cost of new 
transmission facilities.
    a. At the time of direct allocation--When a customer requests 
firm service under the existing pro forma tariff and network 
upgrades must, on occasion, be built to accommodate the service. The 
Commission has historically allowed rates for transmission service 
to be set at the higher of the incremental cost or the average 
embedded cost. Thus, the allocation of Congestion Revenue Rights for 
customers who are currently paying an incremental rate for 
transmission service will, therefore, be the same as for customers 
paying the embedded cost charge under the pro forma tariff for 
transmission service.
    b. At the time of the auction--Under Standard Market Design, 
customers generally will no longer request to build facilities to 
receive ``firm'' service, since all service will be allocated based 
on the customer's willingness to pay congestion costs. Rather, 
customers will request an economic expansion in order to avoid 
paying the cost of congestion. For economic expansions that are not 
rolled in to the embedded cost charge, the customer will pay the 
Transmission Provider the cost of the new facilities in order to 
acquire the Congestion Revenue Rights, and will continue to pay the 
access charge to receive Network Access Service.
    3. Economic Expansions--once an Independent Transmission 
Provider is in place, it (with state participation) would make a 
decision on pricing. Most likely, the beneficiary(ies) of the 
economic expansion of the network would pay for the cost of the new 
facilities in return for any Congestion Revenue Rights created by an 
increase in transfer capability, and will continue to pay the access 
charge to receive Network Access Service. Otherwise, all network 
expansions would be rolled in either regionally or to a license 
plate zone and, therefore, all newly created Congestion Revenue 
Rights would be auctioned.
    4. Reliability Expansions.
    a. At the time of direct allocation--reliability expansions 
benefit all users of the grid; therefore, the costs are rolled-in to 
the access charge either regionally or to a license plate zone. 
Accordingly, any newly created Congestion Revenue Rights associated 
with the expansion will be auctioned.
    b. At the time of the auction--the introduction of the full 
auction would have no impact on reliability expansions, which will 
continue to be rolled-in either regionally or to a license plate 
zone with any newly created Congestion Revenue Rights associated 
with the expansion offered in an auction.
    5. Generator that receives credits for network upgrades.
    a. At the time of direct allocation--currently, the 
interconnecting generator pre-pays for transmission service and 
receives credits against the monthly cost of transmission service, 
whether the generator is the customer or it is chosen as a network 
resource by a load-serving entity. To the extent the generator is a 
long-term transmission customer, it would receive Congestion Revenue 
Rights associated with its transmission service (otherwise the 
network customer that chose the generator as a network resource 
would receive the Congestion Revenue Rights).\1\ If participant 
funding is adopted, the customer would receive the Congestion 
Revenue Rights associated with the additional transfer capability 
made possible by the transmission expansion. This pricing is subject 
to the outcome of the Generator Interconnection proposed rule in 
Docket No. RM02-1-000.
---------------------------------------------------------------------------

    \1\ There could be situations where the transition to Network 
Access Service occurs prior to a customer receiving transmission 
credits it is entitled to. To the extent that such a customer would 
no longer be required to pay the access charge, we would expect the 
RTO or Independent Transmission Provider to return the remaining 
amounts to the customer at the same rate as if the current 
transmission charge were still in place until the balance is 
returned.
---------------------------------------------------------------------------

    b. At the time of the auction--a generator would be treated in 
the same fashion as other customers under the pro forma tariff both 
with respect to payment of the access charge and receipt of 
Congestion Revenue Rights. If participant funding is adopted, the 
customer would receive the Congestion Revenue Rights associated with 
the additional transfer capability made possible by the transmission 
expansion. This pricing is subject to the outcome of the Generator 
Interconnection proposed rule in [Docket No. RM02-1-000.
    6. Merchant transmission owner.
    a. At the time of direct allocation--A merchant transmission 
owner does not receive service, but rather is a transmission owner. 
A customer using this facility would also have to pay for service 
across the RTO plus a rate for service on the merchant facility. 
Accordingly, the merchant transmission owner would pay for the full 
cost of constructing the new facilities and would receive the 
Congestion Revenue Rights associated with its facility for the 
economic life of the facility. The full amount of those rights may 
be subject to change based on changes in the overall grid over time 
(e.g., changes in flow patterns or deterioration of transfer 
capability of other lines may diminish the amount of Congestion 
Revenue Rights associated with the merchant facility).
    b. At the time of the auction--the introduction of the full 
auction will not change the way merchant facilities are addressed--
the merchant transmission owner would pay for the full cost of 
constructing the new facilities and would receive the Congestion 
Revenue Rights associated with its facility for the economic life of 
the facility.

[[Page 55587]]

Cost Shifts Due to Eliminating the Access Charge for Inter-Regional 
Transfers

    This rulemaking proposes to eliminate transaction fees (the 
access charge) on through and out transactions. This, by definition, 
raises the possibility of cost shifts, resulting in winners and 
losers. This scenario has been previously faced and resolved within 
a Transmission Provider's service area, with the result being the 
elimination of pancaked rates, and can be resolved across multiple 
service areas as well.
    Currently, all transmission customers pay a share of the 
embedded costs of the transmission system. Under Standard Market 
Design, only load-serving entities (i.e., customers taking load off 
of the grid) will pay a share of the embedded costs of the system 
through an access charge.\2\ This means that the portion of embedded 
costs currently paid by customers transmitting power through or out 
of a Transmission Provider's service area must be picked up by load-
serving entities. However, while this may seem like a rate increase, 
the benefits from the elimination of the interregional access charge 
should exceed the costs. Specifically, this occurs through the 
reduction in generation costs across the region, as we will explain 
below.
---------------------------------------------------------------------------

    \2\ This may also include point-to-point customers who continue 
to pay the access charge to receive Congestion Revenue Rights.
---------------------------------------------------------------------------

    Current situation on a hypothetical RTO (or transmission 
provider's system): 90 percent of the embedded costs are paid for by 
bundled retail customers, network customers, and point-to-point 
customers who serve load within the RTO. 10 percent of the embedded 
costs are paid for by point-to-point customers exporting power to 
another RTO or moving power within the RTO but not to load.
    Standard Market Design will have two transmission rate impacts: 
First, the non-load serving transactions will no longer pay the 
access charge. Second, the inter-regional transfers will be netted 
across RTOs and the load-serving entities on the net importing RTO 
will pay a load ratio share of the embedded costs of the exporting 
RTO. On first blush, it would appear that the load-serving entities 
on both RTOs will pay more of the embedded costs to make up for the 
fact that exporting generators will no longer pay an access charge. 
While this is true with respect to transmission costs, it ignores 
the intended benefit of this rate change--lower generation costs.
    First, access charges paid by generators for the first leg of a 
transaction, whether to serve load in the same or a neighboring RTO, 
are ultimately paid by the purchaser of the power. So, recovering 
these costs directly from the load-serving entities will not 
increase the overall cost of delivered power.\3\
---------------------------------------------------------------------------

    \3\ It is possible that there will be instances where a bundled 
purchase contract, if not reformed to reflect this change in 
transmission rate design, will result in the customer paying twice 
for transmission service. Affected customers could file under 
section 206 of the FPA to seek reformation of their contracts.
---------------------------------------------------------------------------

    More importantly, removing this additional transaction fee 
reduces the cost of reaching generation on a neighboring RTO. The 
removal of the transaction cost makes cheaper generation available 
across a broader area, which leads to a more optimal dispatch and 
lower generation cost for all customers.
    For example, assume load is served at a particular location in 
RTO A at an LMP of $25, and that there is a generator on neighboring 
RTO B willing and able to sell at $24 (i.e., it has available 
capacity and there is no transmission constraint between the sink 
and source). However, RTO B has an access charge of $2, making the 
competing generator's delivered cost non-competitive at $26. 
Removing the $2 transaction fee reduces the generator's delivered 
cost to $24, saving all customers at that location $1, since the LMP 
is reduced from $25 to $24. Moreover, to the extent that other load 
within RTO A is served with generation cost in excess of $25, the 
$25 generator in RTO A that was displaced by the $24 generator in 
RTO B is now available to meet this load, providing greater 
generation savings across RTO A. Given that generation costs far 
exceed access charges, customers' overall savings (generation plus 
transmission costs) can be reduced far below the increase in 
transmission costs resulting from the elimination of the access 
charge on inter-regional transactions. There could be additional 
savings to the load-serving entities in that they would receive 
additional Congestion Revenue Rights (or the associated auction 
revenues) that would otherwise be held by the point-to-point 
customers.
    The precise details of how current contracts will be 
transitioned and how embedded transmission costs associated with 
inter-regional transactions will be netted across regions should be 
left to regions to work out in compliance filings.

Appendix G

Security Standards for Electric Market Participants

Purpose

    Wholesale electric grid operations are highly interdependent, 
and a failure of one part of the generation, transmission or grid 
management system can compromise the reliable operation of a major 
portion of the regional grid. Similarly, the wholesale electric 
market--as a network of economic transactions and interdependencies-
-relies on the continuing reliable operation of not only physical 
grid resources, but also the operational infrastructure of 
monitoring, dispatch and market software and systems. Because of 
this mutual vulnerability and interdependence, it is necessary to 
safeguard the electric grid and market resources and systems by 
establishing minimum standards for all market participants, to 
assure that a lack of security for one resource does not compromise 
security and risk grid and market failure for the market or grid as 
a whole.
    The purpose of these standards is to ensure that electric market 
participants have a basic Security Program protecting the electric 
grid and market from the impacts of acts, either accidental or 
malicious, that aren't authentic or could cause wide-ranging, 
harmful impacts on grid operations and market resources. A basic 
Security Program for electric grid and market resources (hereafter 
referred to as market resources) shall cover governance, planning, 
prevention, operations, incident response, and business continuity.
    Security standards for market resources will primarily focus on 
electronic systems, which include hardware, software, data, related 
communications networks, control systems as they impact the grid or 
market, and personnel (hereafter the word cyber shall refer to all 
of these aspects). In addition, physical security will be addressed 
to the extent that it is necessary to assure a secure physical 
environment for cyber resources.
    This initial set of security standards represent a minimum set 
of measures derived from commonly accepted industry standards and 
practices, such as the Common Criteria, CTSEC, ITSEC, IPSEC, ISO 
17799, NIST Guidelines, and the NERC Security Guidelines. Market 
participants are encouraged to review their individual situation and 
tolerance for risk and implement a Security Program that goes beyond 
these basic security standards herein.

Application

    These standards are intended to ensure that appropriate 
mitigating plans and actions are in place, recognizing the role of 
the participant in the marketplace and the risks being managed. For 
the purpose of these security standards, participants are defined 
as, and the standards shall apply to:
     The market operations of RTO's and ISO's, and their 
market connections to Control Areas,
     Marketers,
     Transmission Owners,
     Power Producers,
     Load-serving entities and other power purchasers,
     NERC and the Reliability Authorities, and
     Tagging (or other similar dispatching) Organizations.
    Further, if a power-generating unit participates directly in the 
grid (i.e., it is electronically dispatched by control centers), the 
plant control system shall comply with these security standards. If 
a power-generating unit participates directly in the electric market 
(i.e., submits tagging requests), its market systems shall also 
comply with these security standards.

Compliance

    These security standards shall become effective on January 1, 
2004. Beginning 2004, on January 1 of each year, every participant 
shall file with FERC a self-certification signed by an officer of 
the company indicating compliance with these standards and 
identifying any areas of non-compliance. Failure to comply with 
these security standards will result in loss of direct access 
privileges to the electric market.
    Malicious acts directed against the electric market, shall be 
prosecuted by FERC and law enforcement agencies to the full extent 
of the law, including the recovery of damages.

Security Standards

Governance

    Participant senior management shall designate a management 
official to be

[[Page 55588]]

responsible for establishing and managing a basic Security Program 
for electric market functions and resources.

Security Scope

    Participants shall define their security perimeter and identify 
the boundaries and defenses for physical and cyber security that 
delineate and protect the critical resources under their control. 
The security perimeter shall identify all entry and exit points and 
the requirements for access controls.
    A Security Program and policy based on these security standards 
shall be developed to protect critical electric grid and market 
functions and resources within the security perimeter and at entry 
and exit points where personnel, supplies or communications may come 
and go. Additionally, related procedures shall be created that guide 
implementation and enforcement of the security standards. Policy and 
procedures shall be reviewed for appropriateness (due to changes in 
personnel, technology, equipment configuration, vulnerabilities and 
threats) as necessary, and at least annually.

Asset Classification and Control

    Electric market assets within the security perimeter shall be 
classified as to their criticality in maintaining and protecting 
electric market functions. A classification system shall further 
define appropriate levels of protection for each level of 
criticality, and access rights that will be granted for each level 
of criticality. All critical assets within the perimeter (computers, 
networks, doorways, etc.) shall have a custodian who ensures that 
those assets are handled in accordance with their assigned 
classification scheme.

Personnel

    Any personnel who are authorized access within the security 
perimeter, or are authorized access to administer, operate or 
maintain assets within the security perimeter shall be trained on 
the Security Program and security standards related to their 
respective positions. This training shall start upon employment, be 
repeated annually and at career points where significant 
responsibilities change. Security awareness training shall be 
provided to all staff.
    To the extent permitted by law, personnel required to administer 
or operate assets classified as critical (according to the 
participant's classification system) shall undergo background 
investigation conducted prior to employment, upon promotion to such 
positions (if not a new hire), and at periodic intervals (not to 
exceed five years). The participant shall review the results of the 
background checks and take appropriate action. Individuals shall be 
disqualified from administering, operating or accessing critical 
assets if the individual meets any disqualifying criteria specified 
by the Federal Bureau of Investigation, Office of Homeland Security, 
RCMP, or other federal agency.

Access Control

    A process such as transaction logs shall be in place to identify 
individual users of critical systems and their time of access. 
Procedures for critical electric grid and market resources within 
the security perimeter shall be developed that establish and monitor 
controls for:
    (1) The assignment of both logical and physical access rights 
(as defined in the classification system);
    (2) The prompt disabling of access rights when positions are 
terminated or job responsibilities no longer require access; and
    (3) The annual re-evaluation of assigned access rights.
    Such authorized personnel--including visitors and service 
vendors--shall only have access (whether logical or physical) to 
electric market resources within the security perimeter that they 
are authorized for. Any and all unauthorized personnel allowed 
temporary access within the security perimeter shall be escorted at 
all times.

Systems Management

    Procedures for critical electric market resources within the 
security perimeter shall be developed to monitor and protect cyber 
assets, such as:

     Computers
     Software
     Data, as stored and transmitted
     Servers
     Routers
     Modems
     Communications channels, whether owned or leased

    At a minimum, these procedures shall address:
    (1) The use of effective password routines that periodically 
require changing of passwords, including the replacement of default 
passwords on newly installed equipment;
    (2) Authorization and re-validation of computer accounts;
    (3) Disabling of unauthorized (invalidated, expired) or unused 
computer accounts;
    (4) Disabling of unused network services and ports;
    (5) Secure dial-up modem connections;
    (6) Firewall software (for routed Internet access);
    (7) Intrusion Detection Systems (for networked routers and 
firewalls);
    (8) Patch management;
    (9) Installation and update of anti-virus software checkers.
    For critical electric systems, operator logs and Intrusion 
Detection System logs shall be maintained for the purpose of 
checking system anomalies and for evidence of suspected unauthorized 
activity. Appropriate procedures for securing control systems that 
are critical to the grid or market shall be developed and employed. 
The procedures shall address:
    (1) Remote access including modems and other means;
    (2) Security patch management, as appropriate;
    (3) Assurance that communication channels are adequate so as not 
to impact the performance of the control system and its critical 
functions; and
    (4) Assurance that system procedures do not impact the 
performance of the control system and its critical functions.
    Procedures for critical electric resources within the security 
perimeter shall be established to monitor and control physical 
features, such as:
     Doors,
     Windows,
     Floor space,
     Environmental systems,
     Backup power systems--whether owned or leased.
    At a minimum, these procedures shall address:
    (1) Appropriate security barriers and entry controls;
    (2) Mechanical and electronic key and badge programs;
    (3) Access locking of unattended assets; and,
    (4) Protection from environmental threats and hazards (e.g., 
loss of cooling).
    Critical electric facilities shall restrict the distribution of 
maps, floor plans and equipment layouts pertaining to those 
facilities, and restrict the use of signage indicating critical 
facility locations.

Planning

    Security requirements for critical electric systems within the 
security perimeter shall be identified, documented and agreed upon 
prior to development, procurement, enhancement to, installation of 
and acceptance testing for cyber resources or related physical 
features. For critical control systems, this means developing cyber 
security procedures to augment existing test and/or acceptance 
procedures.
    Development and testing of critical electric market systems 
shall be conducted in system environments that are not 
interconnected with operational system environments.

Incident Response

    Organizations with critical electric market resources shall have 
incident response procedures, which define roles, responsibilities 
and actions to rapidly detect and protect electric resources in the 
event of harmful or unusual incidents, whether accidental or 
malicious.
    Organizations with critical electric market resources shall 
report incidents to the Electricity Sector--Information Sharing and 
Analysis Center (ES-ISAC) and use reporting criteria, thresholds and 
procedures contained in NERC's Indications, Analysis and Warning 
(IAW) Program.

Business Continuity

    Every participant operating a critical electric resource shall 
have contingency plans that define roles, responsibilities and 
actions for protecting the rest of the electric grid and market from 
the failure of its own critical resources. Those plans should 
further define the roles, responsibilities and actions needed to 
quickly recover or reestablish electric grid and market functions, 
processes and systems, in the event that a critical physical or 
cyber resource fails or suffers harm or attack. Such plans shall be 
tested or exercised regularly.

References

    The North American Electric Reliability Council (NERC) has 
established and maintains Security Guidelines for the Electricity 
Sector. NERC also provides a list of additional sources for security 
best practices. These references shall be helpful in developing 
organization-specific security

[[Page 55589]]

standards and procedures for critical market resources.
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[GRAPHIC] [TIFF OMITTED] TP29AU02.002

BILLING CODE 6717-01-C
Electricity Market Design and Structure
Breathitt, Commissioner, concurring:
    I am writing separately on the Notice of Proposed Rulemaking 
(NOPR) on Standard Market Design (SMD) to express some of my 
thoughts on certain of its provisions and design elements. We have 
been discussing the broad contours of the SMD NOPR with interested 
parties for months through the staff white paper, the options paper 
and technical conferences. Many of the NOPR's features have been 
welcomed and embraced by various entities, associations, company 
representatives and academics. Just as many participants have 
cautioned us to make sure that the procedures, protocols and 
standards that we wish to impose on the industry we regulate are 
practical in implementation, fair to consumers and respectful of 
state jurisdiction. They have also asked us to recognize that not 
all regions of the country are the same or have the same historical 
ways of providing electricity to retail and wholesale customers.
    For example, the way the Northeast has evolved with their power 
pools is vastly different from how the Southeast and the Southwest 
has traded bulk power. The northwest has a heavy reliance on 
hydroelectric generated power. Even with these differences, all the 
regions have provided reliable and steady service especially in 
times of extreme weather conditions.
    People will be pouring over this NOPR to see if it is practical 
and if it is doable. During the October SMD/RTO week we were advised 
to keep it simple. This is anything but simple. It is a 
comprehensive proposal and it's very complicated. Over time it will 
result in a sophisticated market. Parties are going to need time to 
understand its complexities and implement its many features. The 
Commission is going to need patience and flexibility. We have not 
assigned a cost to this proposal but we know that each FERC 
jurisdictional entity is required to hire an independent 
transmission provider (ITP) if they are not already in an RTO. The 
ITPs must set up locational marginal pricing (LMP), day-ahead and 
real time energy

[[Page 55591]]

markets, as well as ancillary services markets.
    In Order 2000 we paired a voluntary rule with very tight 
compliance deadlines, deadlines that I believe we all knew at the 
time would be difficult to meet. Today's proposed rule pairs many 
complicated and mandatory requirements with short implementation 
time lines. For example, the LMP system paired with energy and 
ancillary services markets has not been proven outside of the tight 
power pools in the Northeast. Also, allocation of initial Congestion 
Revenue Rights will be complicated, if not problematic for some 
areas of the country. But, I am pleased that today's order 
recognizes that not all areas of the country will be able to move 
ahead with all requirements of SMD at lightning speed. The 
Commission intends to be flexible in some compliance dates and while 
it is the objective to have SMD in place within two years of the 
effective date of the Final Rule, the Commission will consider 
requests to extend that date.
    The fundamental goal of SMD requirements in conjunction with the 
standardized transmission service is to create ``seamless'' 
wholesale power markets that allow sellers to transact easily across 
transmission grid boundaries. Once the final rule is in place and 
implemented my hope is that the squabbling over which entities 
belong in what RTO will end. We should be able to put our magic 
markers away for good.
    Today's NOPR puts forward a detailed vision of the roles that 
ITPs, this commission and states will play in planning for expansion 
of the transmission grid. I am pleased that the governors have 
requested a significant role in transmission planning through the 
formation of Multi State Entities (or MSEs). I am also pleased that 
we propose to give MSEs a role in both overseeing the plans 
developed by the ITPs and in developing a fair pricing methodology 
for these expansions. I feel very positive about the bottom up 
approach that is described in the planning section of this NOPR. 
This approach allows merchant transmission companies and utilities, 
as well as generators and demand resources, to bring economic 
solutions to the table to solve the problems of under-built 
infrastructure. These projects must be vetted by the ITP to 
determine their impact on the grid in terms of loop flows and other 
regional impacts, but the real tests will be the demand for the 
projects much as we see in gas pipeline certificates.
    I do have concerns about the planning protocols that would be 
enacted by the ITP once it is determined that economic projects 
cannot fulfill all of the reliability requirements of the grid. My 
concern is that this ``central planning'' aspect may direct projects 
that are uneconomic with costs socialized to all users of the grid. 
It is hard to imagine gold plating of the transmission grid when we 
are in an era of under-built infrastructure, but I believe that once 
we get the incentives right for building needed infrastructure there 
will be no need for the ITP to direct the construction of possibly 
``uneconomic'' projects.
    Getting the incentives right in grid expansion has been on my 
top ten list through this NOPR process and in my tenure here at the 
Commission. To this end, I have continued to be a proponent of 
Independent Transmission Companies (ITCs) and continue to believe 
that ITCs show great promise to address grid problems through profit 
driven activities. I am pleased that the NOPR proposes to adopt a 
form of participant funding once independent transmission entities 
are in place. I am also pleased that the Commission is willing to 
consider proposals submitted by Regional State Advisory Committees 
for participant funding prior to nation-wide adoption. This order 
gives a push to state and regional entities that already have 
significant momentum and I hope to see the fruit of the Regional-
State groups efforts in the form of actionable plans for cost 
allocation of expanded transmission. However, if these groups have 
difficulty getting organized and implemented, there is a default 
mechanism that would allocate the costs of expanded transmission 
locally if the facilities are below 138 kV and regionally if the 
facilities are above the 138 kV level. I urge the parties, 
especially the states, to carefully consider this section of the 
NOPR and comment on this. I still have some uncertainty whether we 
reached the right balance here.
    Furthermore, the states have been asking for some time for 
certain responsibilities in RTOs, particularly in the area of 
reliability and planning. In SMD it is envisioned that they will 
play important roles in developing the resource adequacy standards 
and transmission expansion pricing methods. We will give deference 
to areas that are not as far along in standardizing markets, 
allowing states to manage the pace of the required changes. 
Additionally, the proposed rule, while it asserts jurisdiction over 
native load, does not abrogate either actual or implicit contracts. 
I am not so Pollyanna as to believe that everyone will be happy with 
our assertion of jurisdiction over native load, in fact this is 
likely to be a big bone of contention. But take a look at the rule, 
as I think states will find that it tries to be balanced and allows 
them significant say in determining outcomes.
    Another area that I have focused on in this process is cost 
shifts. I agree that embedded costs charges for wheel through and 
export transactions should be eliminated or minimized while at the 
same time assuring recovery of the transmission owner's revenue 
requirement. My concern with respect to cost shifts resulting from 
this removal of inter-regional rates is two-fold.
    First, I fear that areas with low-cost energy, such as my state 
of Kentucky, will see those resources flow to high-cost areas 
located several states or regions away. It is a mathematical fact 
that when costs are averaged that someone's costs will go up. This 
particular concern is in part alleviated by the ability for those in 
low-cost areas to lock up their low-cost power resources in long 
term contracts. I also note that these transactions which will flow 
over greater distances, now that they no longer face the fixed cost 
of the transmission system, will be subject to marginal losses and 
congestion charges. I believe that marginal losses in excess of 
actual losses should be credited back to the areas where the power 
originated.
    My second concern with cost shifts relates to the determination 
of how these costs will be apportioned among different types of 
customers. Even if costs are allocated to import zones instead of to 
each ITP, one customer in the zone that relies solely on generation 
within the zone could subsidize a customer that imports all of its 
requirements. This is due to the fact that the embedded costs for 
imports would be spread across all load within the zone. My hope is 
that parties will comment on these and other costs shifts giving us 
concrete examples of the kind and level of shifts that may occur. I 
would also ask for recommendations on how best to address cost 
shifts, especially if they have a significant impact on retail 
customers.
    In Order 888, Imbalance service was an ancillary service that 
could be provided by the transmission provider or it could be self-
supplied. In staff's initial thinking on SMD as expressed in their 
concept paper, the markets for both real-time and day ahead energy 
would only require voluntary participation. As we worked through the 
details of SMD, this idea morphed a bit to now require imbalance 
service to be taken through the real-time energy market set up by 
the ITP. Participation in the day-ahead market is still left to the 
buyer's discretion and bilateral contracts are encouraged. But, the 
requirement for load to buy their imbalance service through the 
real-time market is a significant change. Loads will be subject to 
spot prices for that small portion of their load that varies from 
their load forecasts. I hope that parties will comment on this 
change to imbalance service.
    I believe that one of the fundamental underpinnings of this rule 
is to give equal access to the transmission grid to all and I 
support that notion. However, I recognize that giving everyone equal 
access means that decisions will be made based on each party's 
willingness to pay. This means that the price certainty that we gave 
through Order 888 will disappear. But, this does not mean that all 
price certainty will disappear because SMD provides mechanisms for 
customers to use to hedge the volatility in transmission markets and 
in real-time markets. My concern is that both small players and less 
sophisticated players will have increased transaction costs and 
steep learning curves in finding their way through these markets and 
in hedging these price risks. I don't want this rule to result in 
two classes of SMD participants--those that know how to participate 
effectively and those that have difficulty and incur higher costs 
without competitive benefits.
    Also, after consulting several economic textbooks, we have 
defined market power for the first time in an electric order as 
``the ability to raise price above the competitive level''. We 
caveat that definition by stating that the determination of when to 
intervene in a market, i.e. when the price is significantly raised 
for a sustained period, will be incorporated into our triggers for 
intervention rather that the definition. I am not positive that we 
have the definition right and I hope that parties will let us know 
if they think we have used the right definition.
    The three prongs of mitigation proposed in this NOPR, local 
market mitigation, a safety-

[[Page 55592]]

net bid cap, and the resource adequacy requirement, along with the 
requirement for an active independent market monitor should protect 
these markets during what could be a rocky inception. My hope is 
that over time there will be less reliance on mitigation measures as 
the structural problems in these markets subside. Further, I believe 
this proposed rule holds promise for solving the disagreements that 
we have today on the ability to exercise market power under our 
current methods for granting market-based rates. With these 
stringent new mitigation measures in place the Commission should 
reassess its reliance on the Supply Margin Assessment test and study 
the need for the 206 refund obligation.
    With respect to governance, I do not agree with the level of 
prescription that we are imposing on certain governance proposals. I 
don't think the Commission should be dictating with such specificity 
so many rules concerning the explicit makeup of stakeholder 
committees, who can sit on which committees, and exactly how boards 
should be selected. This could have the effect of disbanding boards 
of RTOs that are in the formative stages and boards that might have 
met our Order 2000 independence requirements.
    And last, but definitely not least, I am pleased that today's 
proposed rule keeps the same provisions for reciprocity as that of 
the OATT. Entities that already have waivers of the reciprocity 
provision will not have to come in again and request additional 
waiver from the SMD provisions. Today's proposed rule also would 
allow reciprocal OATTs to be grandfathered and require no further 
changes to those tariffs to meet the new SMD requirements. This 
provides necessary relief to small transmission owners, including 
municipalities and cooperatives.
    I urge my colleagues to carefully consider the comments and not 
be shy about considering changes to the proposal. We are asking over 
seventy-five questions which indicates that we still need industry's 
and the public's advice on a number of issues. I will be anxiously 
awaiting the comments and look forward to what parties have to say 
on these and other issues.

Linda K. Breathitt,
Commissioner.

[FR Doc. 02-21479 Filed 8-28-02; 8:45 am]
BILLING CODE 6717-01-P