[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
[[Page 55452]]
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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
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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
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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
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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.
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\11\ See Order No. 888 at 31,652.
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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.
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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).
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[[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.
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[[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.
---------------------------------------------------------------------------
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.
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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.
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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.
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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.
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\89\ All services, including firm service, can be curtailed for
reliability reasons.
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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.
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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.
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\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.
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\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.
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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.
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\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).
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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.
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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?
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\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).
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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.
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\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).
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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.
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\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.
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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.
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\121\ Transmission losses will also be recovered through the
transmission usage charge and included in the energy prices under
LMP.
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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.
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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.
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\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.
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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.
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\126\ The market power mitigation measures would be developed on
a regional basis and would take into account the special
characteristics of hydropower.
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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.
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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.
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\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.
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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.
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\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.
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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.
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\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.
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\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.
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\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.
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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.
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\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\
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\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.
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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.
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\140\ New York Independent System Operator, Inc., 99 FERC [para]
61,292 (2002).
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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.
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(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.
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\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.
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\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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\
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\151\ Because prices are determined hourly, an opportunity cost
expressed in dollars per MWh converts to an equivalent dollar-per-MW
basis.
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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.
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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.
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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\
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\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.
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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.
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\161\ See Section III and Appendix C.
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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.
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\162\ See Interstate Strategies for Transmission Planning and
Expansion, National Governors' Association, posted on July 18, 2002,
available in .
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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.
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\163\ Northeast Power Coordinating Council Collaborative
Planning Initiative Phase I issued March 13, 2002.
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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.
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\166\ See http://www.oeb.gov.on.ca/english/electronic_business_standards.htm last visited July 30, 2002.
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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.
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\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).
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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
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\168\ Order 888 at 31,771.
\169\ New York v. FERC, 122 S. Ct. 1012.
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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:
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\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).
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We note that the determination of which facilities are under the
operational control of the Independent Transmission Provider does not
dictate transmission pricing.\177\
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\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.
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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.
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\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.
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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.
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\179\ To the extent that there are contractual limitations, the
customer could seek modification of the contract through a filing
with the Commission.
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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.
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\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.
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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.
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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.
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\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.
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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\
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\188\ See Order No. 888 at 31,760; Order No. 888-A at 30,285.
\189\ Id. at 31,761.
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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.
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\190\ Order No. 888 at 31,765.
\191\ See Sections 10.1 and 10.2 of the pro forma tariff.
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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.
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\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.
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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\
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\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.
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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.
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\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.
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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.
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\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.
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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.
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\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.
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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.
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\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.
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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).
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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.
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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.
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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.
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\207\ These same considerations would apply if the Commission
adopted an AMP-like mechanism with bid caps or competitive reference
bids.
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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.
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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.
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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.
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\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.
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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\
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\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.
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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\
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\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.''
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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.
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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.
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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.
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\222\ See the following section, State Participation in RTO
Operations, for a discussion of the composition of the advisory
committee.
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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.
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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\
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\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.
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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.
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\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.
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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.
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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.
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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.
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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.
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\235\ See SMD Tariff, Appendix B, Section I.5.
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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\
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\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.
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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\
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\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.
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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).
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\239\ Available in http://www.ng.org/center/divisions/1,1188,C--
ISSUE--BRIEF[caret]D--4110,00.html.
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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.
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\241\ See Avista Corporation, et al.., 95 FERC [para]61,114
(2001).
\242\ See Carolina Power & Light Company, 94 FERC [para]61,273
(2001).
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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.
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\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.
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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.
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\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.
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\248\ 18 CFR 35.34(k)(7) (2002).
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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:--------------------------------------------
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8.2 System Impact and/or Facilities Study Charge(s):------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
8.3 Direct Assignment Facilities Charge:------------------------------
-----------------------------------------------------------------------
8.4 Ancillary Services Charges:---------------------------------------
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-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------
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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.
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\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\
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\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
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standards and procedures for critical market resources.
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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