#### SUMMARY OF STANDARD ELECTRICITY MARKET DESIGN

**Docket No. RM01-12-00**

**I. INTRODUCTION**

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 design that provides the right pricing
signals for investment in transmission and generation facilities, as
well as investment in demand reduction. (¶ 3)

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. (¶ 4)

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]{.underline} [forma]{.underline}
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. (¶ 6)

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. (¶ 7)

\[W\]e 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 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]{.underline}, 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.
(¶ 8)

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 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. (¶ 10)

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. (¶ 12)

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
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. (¶ 14)

In summary, in this proceeding, the Commission, pursuant to its
authority under sections 205 and 206 of the Federal Power Act, proposes
to:

(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.]{.underline}, 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;

(5) use LMP as the system for transmission congestion management and
    provide tradable financial rights -- Congestion Revenue Rights -- as
    a means to lock in a fixed price for transmission service;

(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 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.

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. (¶ 16)

We propose to allow certain regional variations, as described
[infra]{.underline}. (¶ 17)

\[T\]he 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. (¶ 18)

\[I\]n 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. (¶ 19)

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

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A.  **Order Nos. 888 and 888-A**

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. 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. 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. 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. (¶ 21)

# Order No. 2000

\[Order No. 2000\] 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. (¶ 24)

Order No. 2000 identified four specific areas of concerns \[regarding
item no. 2 above\]: (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]{.underline} 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]{.underline} [id.]{.underline} at 31,014. (Footnote 22)

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. (¶ 25)

The four RTO characteristics \[idenitified in Order No. 2000\] 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]{.underline} Order No. 2000 at 30,993-94.

## NEED FOR REFORM

A.  **Undue Discrimination and Impediments to Competition Remain**

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.

\[O\]pportunities 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). (¶ 32)

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)

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. (¶
35)

> **B. Specific Instances of Undue Discrimination and Impediments to
> Competition**
>
> **1. Transmission Market Power by Utilities that are Not Independent**

\[O\]nly limited portions of the country have moved beyond the basic
requirements of open access ([e.g.]{.underline}, 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. (¶ 38)

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. (¶ 39)

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. (¶ 40)

**a. Load Growth**

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. (¶ 42)

**b**. **Delays in Responding to Requests for Service**

Under Standard Market Design, \[delays in responding to request for
transmission or interconnection service\] are resolved through the
requirement for an independent entity, preferably an RTO, to perform
studies and calculate available transfer capability (ATC), since an
independent entity would have no incentive to favor one customer over
another. (¶ 44)

**c. Scheduling Advantages**

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. (¶ 47)

**d. Imbalance Resolution**

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. (¶ 49)

**e. Available Transfer Capability and Affiliates**

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

**f. OASIS Postings**

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. (¶ 54)

**g. Capacity Benefit Margin Manipulation**

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. (¶ 56)

**h. Discretionary Use of Transmission Loading Relief**

Several aspects of our proposed remedy address \[concerns regarding the
discretionary use of transmission loading relief\], 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**

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. (¶ 68)

Four prominent examples highlight the alleged advantages that a public
utility\'s bundled retail customers have over wholesale and unbundled
retail customers. . . . The first three of these were summarized above,
and a detailed discussion with examples is set forth in Appendix C. (¶
69)

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. (¶ 70)

**3. Congestion Management**

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. (¶ 78)

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. (¶ 79)

> **4. Seams Problems**

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. (¶ 84)

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. (¶
85)

**5. Market Design Flaws**

We set forth in Appendix C examples of specific \[market\] design flaws.
(¶ 88)

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. (¶ 89)

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

\[S\]mall distributed generation is becoming economic, and some
renewable energy resources, especially wind power generation, are also
on the verge of becoming competitive. In the right locations, wind
generating units can compete with the much larger coal, nuclear and
hydroelectric units. (¶ 91)

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. (¶ 94)

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. (¶ 99)

### D. Legal Authority and Findings

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. (¶ 103)

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. (¶
106)

**IV. THE PROPOSED REMEDY**

Section III and Appendix C provide numerous examples of ways that an
entity that owns both transmission and generation can discriminate in
favor of its own customers or generation under the current tariff. (¶
108)

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. We are proposing specific governance
requirements that must be met by the Independent Transmission Provider.
(¶ 109)

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. (¶ 110)

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. (¶
111)

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. (¶ 112)

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. . . . 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. (¶ 113)

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. (¶ 114)

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 form all or part of the Commission\'s regulations.
(¶ 115)

\[T\]his proposed rule does not include detailed business practices and
communication protocols that will be needed to administer Standard
Market Design. . . . \[W\]e 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 may cause cost-shifting would be resolved at the
Commission rather than through the standard setting body. (¶ 116)

**A. The Interim Tariff**

**1. Placing Bundled Retail Customers under the Interim Tariff**

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. (¶ 118)

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. . . . 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. (¶ 119)

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. (¶ 120)

**2. Additional Interim Revisions to the Pro Forma Tariff**

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). (¶ 121)

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. 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. (¶ 123)

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. (Footnote 81)

**B. Independent Transmission and Markets**

Another form of undue discrimination is the lack of independence of the
transmission provider in many regions of the country. (¶ 124)

**1. Independent Transmission Providers**

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. (¶ 125)

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. (¶ 127)

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. (¶ 128)

*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?* (¶ 131)

2.  **Role of Independent Transmission Companies in Standard Market**

> **Design**

*We seek comment on the functions that an \[Independent Transmission
Company\] should perform under Standard Market Design.* *Should the
Commission retain the same delegation of functions that was approved in
\[TRANSLink Transmission Company, L.L.C., et al., 99 FERC ¶ 61,106
(2002)\]? 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?* (¶ 134)

*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. . . . 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. . . . 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. . . .* *What is the
appropriate role for the ITC?* (¶ 135)

C.  **The New Transmission 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 that will expand their transmission options and enhance
competition in wholesale electric markets. (¶136)

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. (¶138)

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. (¶138)

1.  **Basic Rights**

Network Access Service. . . 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), (¶139)

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]{.underline} [forma]{.underline} tariff,
are secondary points that may be fully subscribed, by paying all
applicable congestion charges. (¶139)

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. (¶140)

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.]{.underline},
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.
(¶141)

Any customer using transmission service, whether a load-serving entity,
generator, or marketer, would take Network Access Service. . . 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.) (¶142)

2.  **Access to Transmission Service**

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).[^1] 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]{.underline} [forma]{.underline}
tariff\'s firm service. (¶144)

3.  **Service Limitations in the Existing [Pro]{.underline}
    [Forma]{.underline} Tariff**

The existing [pro]{.underline} [forma]{.underline} 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.( ¶147)

4.  **Conditions for Receiving Service**

To receive Network Access Service, a customer must meet the same
requirements as those under the existing [pro]{.underline}
[forma]{.underline} tariff for acquiring the right to schedule
transmission service. (¶148)

5.  **Scheduling Transmission Service and Acquiring Congestion Revenue
    Rights**

Transmission service will be scheduled through the day-ahead market with
deviations accounted for in the real-time market. . . 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.
(¶150)

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.[^2] Further, consistent with the
existing [pro]{.underline} [forma]{.underline} 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. (¶151)

6.  **Designating Resources and Loads**

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. (¶153)

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.*[^3] *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?*[^4] *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?
(*¶*153)*

7.  **Substituting Receipt and Delivery Points**

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.
Alternatively, the customer could request a \"reconfiguration\" of the
Congestion Revenue Rights it holds, [i.e.]{.underline}, 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. (*¶*156)*

8.  **System Impact and Facilities Studies**

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]{.underline}
[forma]{.underline} tariff addressing various studies will remain
largely unchanged. However. . . these studies are now required to be
performed by an Independent Transmission Provider. (¶157)

9.  **Load Shedding and Curtailments**

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]{.underline} [rata]{.underline} basis. 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?*
(¶159)

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.[^5] *We request comment on whether the Commission
should continue this practice*.(¶160)

.

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.[^6] Language has been added to Section 9.3,
Curtailments of Scheduled Deliveries, to reflect this change. (¶161)

> **10. Trading (Reassigning) Congestion Revenue Rights**

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. (¶162) (details in Section IV.E.3)

**D. Transmission Pricing**

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. (¶165)

1.  **Recovery of Embedded Costs**

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.]{.underline}, their load ratio shares.( ¶169)

We propose to eliminate rate pancaking both within an Independent
Transmission Provider\'s service area and between service areas. (¶170)

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.

(¶171)

*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]{.underline} 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.* (¶172)

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. . (¶173) (More details in
Appendix F)

2.  **Rates for Bundled Retail Customers**

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. (¶178)

3.  **Inter-Regional Transfers**

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.. .
However, the transaction would still be responsible for applicable
congestion charges and transmission losses in the originating and any
intermediate transmission systems. (¶180)

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. 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
. . . Alternatively, under a revenue crediting approach, inter-regional
transfers could be priced at the load ratio share charge (or a similar
transmission charge)[^7] and the inter-regional transaction charges
would be netted out over some time period ([e.g.]{.underline}, one month
or one year). . . 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.. . . (¶185-8) (More in
Appendix F )

We seek comment on how to assign Congestion Revenue Rights to the
customers of the importing region. (¶189)

4.  **Application of Inter-Regional Pricing to Parallel Path Flows**

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?. . . We seek comment as
to how cost impacts of parallel path flows across regional borders
should be addressed. (¶190)

> **5. Pricing of New Transmission Capacity**

Our preference is to allow recovery of the costs of expansion through
participant funding, [i.e.]{.underline}, those who benefit from a
particular project (such as a generator building to export power or load
building to reduce congestion) pay for it. . (¶197)

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.]{.underline}, 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. (¶200)

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. (¶201)

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. (¶202)

**E. The New Congestion Management System**

we propose to require that all Independent Transmission Providers manage
congestion using a system of LMP and Congestion Revenue Rights. (¶203)

1.  **Locational Marginal Pricing**

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. (¶204)

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. (See footnote 118 for explanation of
why the Commission selected the market clearing price instead of
individual bid prices) (¶204)

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. 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. 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. (¶205)

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. (¶206)

LMP uses a financial instrument called a Congestion Revenue Right to
provide customers with price certainty for transmission service. 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 against
congestion costs for the transmission service covered by that right in
the day-ahead market. 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. (¶208)

No congestion revenues are paid to Congestion Revenue Rights holders for
transactions made in real-time market. (¶209)

The proposed SMD Tariff lays out the general framework and the basic
rules for LMP.. . *We seek comment on how best to recognize this need
for regional variation and the need for continued refinement in the
rules.* (¶211)

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. (¶213)

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 optional. . . 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. . . 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. (¶215)

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. (¶216)

*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.*
(¶219)

**2. LMP and Energy Markets**

We propose to require that the Independent Transmission Provider operate
both a day-ahead and a real-time energy market to manage congestion
(¶221)

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.]{.underline}, 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.(¶222)

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. (¶223)

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). . .. Buyers also submit bids indicating the quantities they
desire to purchase in each hour of the day. Buyers may also indicate the
maximum price they are willing to pay for those quantities.. (¶224)

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.(¶225)

. 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. (¶226)

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.]{.underline}, 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. (¶227)

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. . .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 (¶228).

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.]{.underline}, a
security-constrained dispatch).[^8] 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. (¶229)

The day-ahead market would be financially binding(¶230)

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. (¶231)

The Independent Transmission Provider will consider the bids for energy,
transmission service and ancillary services simultaneously. (¶234)

3.  **Congestion Revenue Rights**

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(¶235)

a.  **General Features**

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. . . Part II.D., Congestion Revenue Rights. (¶237)

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. 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?* (¶238)

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. (¶239)

We propose that Congestion Revenue Rights be made available first in the
form of receipt point-to-delivery point [obligation rights]{.underline},
which we propose to mandate now, and later in the form of receipt
point-to-delivery point [option rights]{.underline} and [flowgate
rights]{.underline}. (¶240)

b.  **Types of Congestion Revenue Rights**

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

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.]{.underline}, one hour). . . The right
is direction-specific. (¶242)

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. In addition, during any period
when the demand for transmission service cannot be met with Available
Transfer Capability ([i.e.]{.underline}, 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(¶243)

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. (¶244)

(2) **Obligations and Options**

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. (¶245)

(3) **Flowgate Rights**

A flowgate is a particular transmission facility or group of facilities
([e.g.]{.underline}, an interface). A flowgate right specifies a portion
of the transmission capacity over that flowgate in a specified
direction. . (¶246)

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:

North Flowgate

A
o\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\--o

\| \|

o\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\--o
B

South Flowgate

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.]{.underline}, 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 (footnote 136 in ¶246)

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 . . 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.( ¶247)

c.  **Requirement for Offering Rights**

    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. . 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. (¶248)

    *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*. (¶249)

d.  **Funding for the Congestion Revenue Rights**

    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. (¶250)

    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.
    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. . . *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.*
    (¶251)

e.  **Auctions and Resales of Congestion Revenue Right**

    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. (¶252)

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

    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.. (¶254)

**F.** **Day-Ahead and Real-Time Market Services**

1.  **Design of the Day-Ahead Markets**

    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. (¶257)

> **a. Scheduling Transmission Service Day Ahead**

(1) **General Features**

    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.. . 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; (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. (¶258)

    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. . . *We seek
    comments on its merit and any implementation difficulties*. (¶259)

    *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. (¶263) last
    sentence a repeat? -- delete one

> **(2) Transmission Service Across Borders**

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. . . *We would prefer
\"one-stop shopping\" with Independent Transmission Provider
coordination; we seek comment on whether this can be done?* (¶265)

Recently we accepted a prescheduling option for service across borders
that was proposed by the New York ISO. . . *We seek comment on whether a
similar prescheduling option should be included in Standard Market*
Design. (¶266)

b.  **Transmission Losses**

    *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.* (¶267)

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1.  *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.* (¶268)

**c. Day-Ahead Energy Market**

(1) **General Features**

    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.. . .
    \"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. . . \"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. *.*
    (¶269)

(2) **Bidding and Scheduling Rules**

    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.. . . 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. (¶271)

    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
    . . (¶272)

    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 *We
    seek comment on whether other scheduling options or regional
    variations should be included for energy-limited resources in the
    tariff.* (¶274)

    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*(¶275)

    *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*.
    (¶276)

(3) **Price Determination and Settlement**

    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.
    (¶277)

    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. . . . Nodal pricing would be used for both buyers
    and sellers in the day-ahead market (¶278)

    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. . . Energy may not be injected or
    withdrawn from the grid at a trading hub, since a hub does not exist
    at a physical location. . . 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. (¶279)

    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.]{.underline}, an
    \"uplift\" payment) for the net revenue shortfall for the day.. . .
    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. (¶280)

    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.(¶281)

    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... . *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?* .(¶283)

> **d. Day-Ahead Ancillary Service Markets**

(1) **General Features**

    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. . . 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.
    .(¶285)

**(2) Bidding and Scheduling Rules**

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.(¶287)

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.(¶288)

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.
(¶292)

Although suppliers bid to provide these ancillary services in the
day-ahead market, customers pay for them based on real-time load. (¶295)

*In Order No. 888, exports are not charged for these ancillary services.
We ask for comments on whether they should be charged here*.. (¶296)

> **2. Scheduling After the Close of the Day-Ahead Market**
>
> **a. Replacement Reserves**

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 the extent necessary to ensure that
sufficient generation will be available to meet load. (¶299)

Generators selected to provide replacement reserves would be paid the
applicable real-time energy price for energy that they produce. (New
Section g.2 in Tariff) (¶301)

> **b. Changes to Transmission Schedules**

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. (¶304)

3.  **Design of the Real-Time Markets**

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a.  **Real-time Energy Markets**

**(1) General Features**

Real time energy markets would be used to provide the imbalance energy
service of Order No. 888 [pro]{.underline} [forma]{.underline} tariff
and self provision would be allowed. (¶306)

> **(2) Bidding and Scheduling Rules**

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. (¶309)

> **(3) Price Determination and Settlement**

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. (¶310)

**[Ex Post versus Ex Ante Prices]{.underline}**

This Section discusses how to determine real-time energy prices. The
options are to set the prices using near real-time estimates
([ex]{.underline} [ante]{.underline}), or base the price on the price of
the actual marginal resource clearing the market in real time
([ex]{.underline} [post]{.underline}). . . We propose to adopt the
[ex]{.underline} [post]{.underline} rule because it creates incentives
for bidders to act consistent with their bids. *We seek comment on the
choice between [ex]{.underline} [post]{.underline} and [ex]{.underline}
[ante]{.underline} pricing.* (¶315)

**[Other Charges for Uninstructed Deviations from
Schedules]{.underline}**

*We seek comment on whether market participants should face additional
charges for "uninstructed" deviations in real time from their schedules,
[i.e.]{.underline}, for producing or taking a different amount of energy
in real time than was scheduled without permission or direction from the
Independent Transmission Provider.* . . 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 . . . We seek comment on whether and how to establish
market prices for ramping capability. . . 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*. (¶316)

> **[What Bids Should be Eligible to Set the Energy Price]{.underline}**

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..
. 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.]{.underline}, the difference between the applicable energy
price and their energy bids) for the amount of the output reduction. . .
*We seek comment on whether such lumpy generators should also be
eligible to set the energy price in the day-ahead market.* . (¶316)

> **b. Real-Time Ancillary Services Markets**

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. . . 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. . (¶321)

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(¶322)

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. (¶324)

4.  **Market Rules for Shortages or Emergencies**

    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. . . . . The existing [pro]{.underline}
    [forma]{.underline} 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.* (¶324)

**IV. THE PROPOSED REMEDY**

> **G. Other Changes to Remove Undue Discrimination and Improve the
> Efficiency**
>
> **of the Markets under Standard Market Design**

\[T\]he following revisions must be made to the pro forma tariff to
change the market rules in ways that will improve the efficiency of
wholesale electric markets. (¶ 329)

**1. Capacity Benefit Margin**

We propose to standardize the treatment of Capacity Benefit Margin to
ensure that (1) only customers benefiting 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. (¶ 331)

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 . . . . (¶ 332)

2.  **Regional and Independent Calculation of Available Transfer**

> **Capability, Performance of Facilities Studies and 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. (¶ 333)

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. (¶ 334)

**3. Regional Planning Process**

The policy relies primarily on a \"ground-up\" planning process that
encourages construction by private companies yet also recognizes the
need for of 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. (¶
337)

Given the need for transmission investment in much of the country and
the time it will take to implement Standard Market Design and for
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. (¶ 338)

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 US energy markets, we encourage participation by Canadian
entities and provincial authorities in the regional planning process. (¶
340)

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. (¶ 341)

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. (¶ 342)

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. (¶ 345)

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. (¶ 347)

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 implement demand
response. 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. (¶ 348)

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. (¶ 349)

> **4. Modular Software Design**

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. (¶
352)

To instill confidence in the software, testing, validation and
evaluation should be a part of an open process. (¶ 353)

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. (¶ 354)

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 \[July 18, 2002 SMD software\] 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?* (¶ 358)

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 the industry to develop such a
suite of benchmark or test problems. (¶ 359)

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; and how
to proceed with the development of test problems for evaluating and
comparing software modules. (¶ 360)

5.  **Transmission Facilities That Must be Under the Control of an**

> **Independent Transmission Provider**

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. (¶
361)

**a. Before Order No. 888**

\[Transmission and distribution rate treatment\] 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
as 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). (¶ 364)

**b. After Order No. 888**

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.
(¶ 365)

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. 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. (¶ 366)

> **c. Test for Transmission Facilities**

Order No. 888\'s seven factor test was designed to determine the local
distribution component of an unbundled retail sale. . . . \[T\]he 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 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. (¶ 367)

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. We note that the
determination of which facilities are under the operational control of
the Independent Transmission Provider does not dictate transmission
pricing. (¶ 368)

*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.* (¶ 369)

**H. Transition to Single Transmission Tariff**

This section discusses the transition process that will be used to move
from the existing pro forma tariff to the SMD Tariff. (¶ 370)

**1. Treatment of Customers under Existing Wholesale Contracts**

\[W\]e 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. 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. (¶ 373)

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 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. 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. (¶ 374)

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.* (¶ 375)

> **2. Allocation of Congestion Revenue Rights**

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. This would include firm Point-to-Point
Transmission Service under an open access transmission tariff, 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. (¶ 376)

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.
(Footnote 180)

Next, the catalogue of firm obligations would be subject to a
simultaneous feasibility test. 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, 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. (¶ 377)

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.
(Footnote 184)

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. 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 100MW 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. 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.* (¶ 378)

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. (¶ 379)

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. (¶ 380)

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.*
(¶ 382)

**3. Reciprocity Provision**

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. 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. (¶ 383)

We propose to continue \[Order No. 888's\] 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.* (¶ 384)

> **4. Force Majeure and Indemnification Provisions**

*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.
(¶ 389)

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. (Footnote 194)

**I. Market Power Mitigation and Monitoring In Markets Operated By The**

> **Independent Transmission Provider**
>
> **1. Principles and Objectives**

\[A\]t 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. (¶ 390)

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. (¶ 392)

Market power is the ability to raise price above the competitive level.
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). 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. (¶ 393)

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 suppliers'
bids alone, so we cannot rely on market prices to ration scarce supplies
in all situations. (¶ 394)

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.
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. (¶ 395)

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. (¶ 396)

\[T\]he 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. (¶ 397)

**2. Overview of the Market Power Mitigation Measures**

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. (¶ 398)

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. (¶ 399)

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. (¶ 400)

The third component of the market power mitigation plan is the resource
adequacy requirement discussed in Section J. (¶ 401)

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). (¶ 402)

**3. Market Power Mitigation For Local Market Power**

Under the Standard Market Design pro forma tariff all generators
dispatched by the Independent Transmission Provider would enter into a
participating generator agreement. Standard Market Design will require
these participating generator agreements to include provisions to
mitigate local market power. (¶ 407)

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. The capped bid could also set the market clearing price.
(¶ 408)

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. . . .
Bilateral contracts are an effective way for a buyer to mitigate the
market power of a seller. 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. (¶ 409)

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. (¶ 410)

*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.* (¶ 411)

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.* (¶ 412)

**4. The Safety-Net Bid Cap**

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. . . . \[I\]n 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. . . . *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.* (¶ 413)

*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. (¶ 414)

> **5. Mitigation Triggered by Market Conditions**

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.* (¶ 415)

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. (¶ 417)

> **6. Establishing Bid Caps or Competitive Reference Bids**

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. (¶ 418)

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. 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.* (¶ 420)

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.* (¶ 421)

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.* (¶ 422)

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.* (¶ 423)

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.* (¶ 424)

Several approaches could be used for establishing bid caps for
\[start-up and no-load bids and certain operating parameters\]. 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. 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.* (¶ 426)

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 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.* (¶
427)

7.  **Exemptions**

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. . . . *\[T\]he Commission requests comment whether any
other sellers should be exempt from the mitigation because they have
insufficient incentives to withhold.* (¶ 428)

8.  **Monitoring**

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. (¶ 429)

The market monitor will be expected to report directly to the
Commission, and the independent governing board of the Independent
Transmission Provider. (¶ 430)

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. . . . 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. (¶ 431)

*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?* (¶ 432)

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. (¶ 433)

The work and findings of the market monitor must be integrated into the
regional planning process. (¶ 434)

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. (¶ 435)

a.  **Framework for analyzing market structure and market**

> **Conduct**

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. (¶ 436)

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. (¶ 439)

In addition, the Commission proposes to require an annual assessment of
the performance of the markets operated by the Independent Transmission
Provider. (¶ 440)

*Comment is requested on how the monitor should address these and other
topics, to develop useful measures that permit inter-regional
comparisons.* (¶ 441)

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. (¶ 442)

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. (¶ 443)

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; (2) Economic Withholding; (3)
Availability Reporting; (4) Factual Accuracy; (5) Information
Obligation; (6) Cooperation; and (7) Physical Feasibility. (¶ 445)

**b. Data Requirements and Data Collection**

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. (¶ 447)

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. (¶ 448)

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. . . . 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. (¶ 449)

All information obtained by the monitor that is specific to a market
participant would be treated confidentially. (¶ 450)

**c. Reporting Requirements**

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.
(¶ 451)

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. (¶
452)

*The Commission requests comment whether additional reporting
requirements are needed.* (¶ 453)

**d. Enforcement of the Tariff Rules**

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 of the
tariff rules. (¶ 454)

*The Commission requests comment on the conditions that would justify
mitigation of the penalty.* (¶ 456)

#  J. Long-Term Resource Adequacy

We propose a resource adequacy requirement to provide for sufficient
supply and demand resources to avert such shortages. (¶ 459)

**1. The Reason for the Requirement**

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. (¶ 461)

a.  **Spot Market Prices Alone Will Not Signal the Need to Begin**

> **Development of New Resources in Time to Avert a Shortage**

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. (¶ 462)

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. (¶ 465)

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. (¶ 466)

b.  **Spot Market Prices That are Subject to Mitigation Measures**

> **May Not Produce an Adequate Level of Investment When a Shortage
> Occurs**

\[M\]arket power mitigation may tend to suppress the scarcity price that
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. (¶ 468)

c.  **Load-serving Entities Will Underinvest in Resources Needed**

> **for Reliability if They Can Depend on the Resource Development
> Investments of Others**

\[A\] 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. (¶ 470)

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. (¶ 472)

These arguments persuade us to propose a long-term resource adequacy
requirement in the Standard Market Design rule. (¶ 473)

**2. Basic Features of the Requirement**

**a. Demand Forecast**

A 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. (¶ 485)

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. (¶ 486)

A load-serving entity has an incentive to underestimate its future load
if doing so would reduce its share of the resource adequacy requirement.
(Footnote 221)

**b. Level of Resource Adequacy**

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. (¶ 487)

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.* (¶ 489)

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. (¶ 490)

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

*\[W\]e 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.* (¶ 491)

\[W\]e propose to adopt a 12 percent reserve margin 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. (¶ 493)

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. (Footnote 223)

**c. Load-serving Entities**

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. (¶ 494)

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

> **Requirement**

Once the future regional requirement is determined, each load-serving
entity\'s share of the regional requirement must be determined. (¶ 497)

*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. (¶ 498)

The other method is to allocate the future adequacy requirement to loads
based on each load\'s most recently documented load ratio share. (¶ 499)

*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.* (¶ 500)

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. (¶ 501)

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.* (¶ 502)

e.  **Resources That Can Satisfy the Resource Needs**

Each region\'s resource adequacy requirement could be satisfied by a
combination of generation, transmission, and demand response
infrastructure. (¶ 503)

(1) **Generation and Transmission**

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). (¶ 504)

In any of these cases, the generator must be committed to supply power
to the load-serving entity, at least under certain conditions. (¶ 505)

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. (¶ 506)

**(2) Demand Response**

Biddable and interruptible load can satisfy the resource adequacy
requirement as well as generation. (¶ 508)

**3. Resource Standards**

The Independent Transmission Provider must determine if each
load-serving entity\'s planned resources meet certain standards. (¶ 509)

*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.* (¶ 510)

**a. Generation Standards**

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. (¶ 511)

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?* (¶ 512)

\[A\] contract with a marketer to deliver power at a future time from
unspecified sources cannot satisfy the requirement. . . . \[A\] 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.* (¶ 513)

b.  **Transmission Standards**

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?* (¶ 514)

We believe . . . that planned transmission with full siting approval and
completion expected within the planning horizon should satisfy the
adequacy requirement. (¶ 516)

**c. Demand Response Standards**

Demand response must also be verifiable to satisfy the adequacy
requirement. . . . 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. (¶ 517)

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. (¶ 519)

**4. Planning Horizon**

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. (¶
520)

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. (¶ 523)

We propose to have the Regional State Advisory Committee determine the
planning horizon for the region. . . . *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.* (¶
524)

**5. Enforcement**

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. (¶ 527)

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. (¶ 528)

\[W\]e 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. (¶ 529)

The penalty price would increase in stages as the shortage becomes more
severe. . . . *We ask for comment on having such a graduated penalty and
the appropriate penalty rates.* (¶ 530)

The second enforcement mechanism is applied when the operating reserve
level decreases to the point that some load must be curtailed. 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. (¶ 532)

\[W\]e will require the Independent Transmission Provider to inform the
load-serving entity\'s state regulatory authority 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. (¶ 533)

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. *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.* (¶ 534)

\[U\]nder 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. . . . *\[W\]e ask
for comments on the merits of this alternative approach.* (¶ 536)

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?* (¶ 537)

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.* (¶ 538)

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. 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. (¶ 539)

*What is the effect of these alternate enforcement mechanisms on the
incentives and business risks of the load serving entities in the
region? Is there another enforcement mechanism that is both appropriate
and effective?* (¶ 541)

**6. Regional Flexibility**

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. (¶ 542)

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*. (¶
549)

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?* (¶ 550)

K.  **State Participation in RTO Operations**

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. (¶551)

The institution we propose here appears complementary to the National
Governors Association\'s recommendation. . . *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.]{.underline}, whether
the governor should select them or some other process should be used).*
(¶553)

L.  **Governance for Independent Transmission Providers**

we are proposing to require that all Independent Transmission Providers
satisfy specific governance requirements. (¶557)

**1. Responsibilities of the Board of Directors**

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. . . . In order to carry
out the functions required by Standard Market Design, the board must be
fully independent of any market participants. Further, the board should
be composed of members that are not part of the management of the
Independent Transmission Provider. . .(¶558)

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. .(¶559)

> **2. Stakeholder Participation**

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. .(¶560)

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, (4) public interest groups
([e.g.]{.underline}, consumer advocates, environmental groups, citizen
participation), (5) alternative energy providers ([e.g.]{.underline},
distributed generation, demand response technologies, renewable energy),
and (6) end-users and retail energy providers ([i.e.]{.underline},
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. . . .
Also, we propose that a company (including all of its affiliates) may
have a representative in only one stakeholder sector. . . . *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.* .(¶561)

> **3. Initial Selection Process for Board of Directors**

First, the qualifications of the board members should be established. .
. Second, a nationally recognized search firm should be retained by the
nominating committee to identify candidates that satisfy these criteria.
. . . 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. . . 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.

Board seats are filled by a simple majority.(¶564-7)

*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*.(¶568)

> **4. Succession of Board Members**

we propose that the board members have staggered terms. . . *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.(¶570)

The same process that was used to select the initial Board of Directors
would be used in the selection process for subsequent board
members.(¶571)

**M. System Security**

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. .(¶576)

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 . . .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. (¶577)

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.(¶578)

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.(¶579)

**V. IMPLEMENTATION**

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. . . 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.(¶580)

**July 31, 2003** --

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. .(¶582)

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 (¶583)

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 . . 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. (¶587)

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. . (¶588)

Finally, the public utility must cooperate with others in its region to
have a Regional State Advisory Committee in place by July 31, 2003.
(¶589)

**[Six Months After Effective Date of Final Rule]{.underline}**

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. . . The Independent Transmission
Provider will take over this process when it becomes operational.(¶590)

**[December 1, 2003]{.underline}**

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. .(¶591)

VI. **PUBLIC COMMENT PROCEDURES**

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.
. . The Commission must receive all comments no later than 75 days after
the issuance of this notice of proposed rulemaking .(¶596)

VII. **ENVIRONMENTAL STATEMENT**

the Commission will prepare an environmental assessment (EA) that will
consider the environmental mpacts 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. .(¶603)

VIII. **PUBLIC REPORTING BURDEN AND INFORMATION COLLECTION STATEMENT**

*the Commission seeks comments on the anticipated costs for IT
development associated with this proposed rule*. .(¶607)

We have estimated for purposes of this analysis that RTOs and ITPs may
number from 5 to 12 entities in the lower 48 states. .(¶609)

***Regulatory Text***

\(d\) 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*

*(2) 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*

[^1]: 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.

[^2]: Further, consistent with the existing [pro]{.underline}
    [forma]{.underline} 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]{.underline} Coalition Against Private Tariffs, 83 FERC
    ¶ 61,015 at 61,040, [reh\'g denied]{.underline}, 84 FERC ¶ 61,050
    (1998).

[^3]: 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.

[^4]: [See]{.underline} Sections B.2.2.1(iv) and (v), and Sections
    B.2.2.2(iii) through (vi) of the SMD Tariff.

[^5]: [See]{.underline} Allegheny Power System, Inc., 80 FERC ¶ 61,143
    at 61,546 (1997), [order on reh\'g]{.underline}, 85 FERC ¶ 61,235
    (1998)..

[^6]: Such procedures may need to be refined in light of Standard Market
    Design.

[^7]: An explanation of how this charge may be calculated is contained
    in Appendix F.

[^8]: It is important that the schedule developed through the day-ahead
    market be physically feasible, [i.e.]{.underline}, 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.