Exhibit  10(d)(1)



PJM Interconnection, L.L.C.

Third Revised Rate Schedule FERC No. 24

---



AMENDED AND
RESTATED



OPERATING
AGREEMENT



OF



PJM INTERCONNECTION, L.L.C.



The following sheets reflect all revisions approved by FERC in orders
issued through January 25, 2005, and all revisions from compliance filings
submitted through January 27, 2005. Various sheets contain revisions that will
be made in a filing expected to be submitted by the end of January 2005 (the
“clean-up filing”). The revisions provide appropriate, updated designations.



---



---

PJM Interconnection, L.L.C.
    
    Sixth
      Revised Sheet No. 1Third Revised Rate Schedule FERC No.
      24
    
    Superseding Fifth Revised Sheet No. 1






OPERATING AGREEMENT



TABLE OF
CONTENTS



1.
    
    DEFINITIONS
    
    261.1
    
    Act
    
    261.2
    
    Affiliate
    
    261.2A
    
    Affected
      Member
    
    261.3
    
    Agreement
    
    261.4
    
    Annual Meeting of
      the Members
    
    261.4A
    
    Authorized
      Commission
    
    271.4B
    
    Authorized
      Person
    
    271.5
    
    Board
    Member
    
    271.5A
    
    Applicable Regional
      Reliability Council
    
    271.5B
    
    Behind The Meter
      Generation
    
    271.6
    
    Capacity
      Resource
    
    191.7
    
    Control
    Area
    
    191.7.01
    
    Control
    Zone
    
    191.7.02
    
    Default Allocation
      Assessment
    
    191.7A
    
    East Transmission
      Owner
    
    191.7B
    
    East Transmission
      Owners Agreement
    
    191.7C
    
    ECAR
    
    191.7D
    
    ECAR Control
      Zone
    
    19A1.8
    
    Electric
      Distributor
    
    19A1.9
    
    Effective
    Date
    
    201.10
    
    Emergency
    
    201.11
    
    End-Use
      Customer
    
    201.12
    
    FERC
    
    201.13
    
    Finance
      Committee
    
    201.14
    
    Generation
      Owner
    
    201.15
    
    Good Utility
      Practice
    
    201.16
    
    Information
      Request
    
    201.17
    
    LLC
    
    201.18
    
    Load Serving
      Entity
    
    211.19
    
    Locational Marginal
      Price
    
    211.20
    
    MAAC
    
    211.20A
    
    MAAC Control
      Zone
    
    211.20B
    
    MAIN
    
    211.20C
    
    MAIN Control
      Zone
    
    211.21
    
    Market
    Buyer
    
    211.22
    
    Market
      Participant
    
    21A1.23
    
    Market
    Seller
    
    21A1.24
    
    Member
    
    21A1.25
    
    Members
      Committee
    
    21A1.26
    
    NERC
    
    21A




Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2004Vice President, Government
    PolicyIssued On:
    
    November 1, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 1AThird Revised Rate Schedule FERC No.
      24




1.26A
    
    Non-Disclosure
      Agreement
    
    221.27
    
    Office of the
      Interconnection
    
    221.28
    
    Operating
      Reserve
    
    221.29
    
    Original PJM
      Agreement
    
    221.30
    
    Other
    Supplier
    
    221.31
    
    PJM Board
    
    221.31A
    
    PJM Capacity Credit
      Market
    
    22




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Fifth
      Revised Sheet No. 2Third Revised Rate Schedule FERC No.
      24
    
    Superseding Fourth Revised Sheet No. 2




1.32
    
    PJM Control
      Area
    
    221.33
    
    PJM Dispute
      Resolution Procedures
    
    221.34
    
    PJM Interchange
      Energy Market
    
    221.35
    
    PJM
Manuals
    
    231.35.01
    
    PJM Market
      Monitor
    
    231.35A
    
    PJM Region
    
    231.36
    
    PJM Tariff
    
    231.36A
    
    [Reserved.]
    
    231.36B
    
    PJM West
      Region
    
    231.37
    
    Planning
      Period
    
    231.38
    
    President
    
    231.38A
    
    Regulation
      Zone
    
    231.39
    
    Related
      Parties
    
    231.40
    
    Reliability
      Assurance Agreement
    
    23A1.40A
    
    Reliability
      Assurance Agreement-West
    
    23A1.41
    
    Sector
    Votes
    
    241.41A
    
    Senior Standing
      Committees
    
    241.41A.01
    
    Spinning Reserve
      Zone
    
    241.41B
    
    Standing
      Committees
    
    241.42
    
    State
    
    241.42.01
    
    State
      Certification
    
    241.42A
    
    State Consumer
      Advocate
    
    241.43
    
    System
    
    241.43A
    
    Third Party
      Request
    
    24A1.44
    
    Transmission
      Facilities
    
    24A1.45
    
    Transmission
      Owner
    
    24A1.46
    
    [Reserved.]
    
    24A1.47
    
    User Group
    
    24A1.48
    
    Voting
    Member
    
    251.49
    
    Weighted
      Interest
    
    251.50
    
    West Transmission
      Owner
    
    251.51
    
    West Transmission
      Owners Agreement
    
    251.52
    
    Zone
    
    252.
    
    FORMATION,
      NAME; PLACE OF BUSINESS
    
    262.1
    
    Formation of LLC;
      Certificate of Formation
    
    262.2
    
    Name of
LLC
    
    262.3
    
    Place of
      Business
    
    262.4
    
    Registered Office
      and Registered Agent
    
    263.
    
    PURPOSES
      AND POWERS OF LLC
    
    273.1
    
    Purposes
    
    273.2
    
    Powers
    
    27




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1,
      2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 2.01Third Revised Rate Schedule FERC No.
      24




4.
    
    EFFECTIVE
      DATE AND TERMINATION
    
    274.1
    
    Effective Date and Termination
    
    274.2
    
    Governing Law
    
    275.
    
    WORKING CAPITAL AND CAPITAL
      CONTRIBUTIONS
    
    285.1
    
    Funding of Working Capital and Capital
      Contributions
    
    285.2
    
    Contributions to Association
    
    29




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 2AThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 2A




6.
    
    TAX STATUS AND DISTRIBUTIONS
    
    296.1
    
    Tax Status
    
    296.2
    
    Return of Capital
Contributions
    
    296.3
    
    Liquidating Distribution
    
    29




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 3Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 3




7.
    
    PJM BOARD
    
    297.1
    
    Composition
    
    297.2
    
    Qualifications
    
    307.3
    
    Term of Office
    
    307.4
    
    Quorum
    
    317.5
    
    Operating and Capital Budgets
    
    317.5.1   Finance
      Committee
    
    317.5.2   Adoption of
      Budgets
    
    327.6
    
    By-laws
    
    327.7
    
    Duties and Responsibilities of the PJM
      Board
    
    328.
    
    MEMBERS COMMITTEE
    
    348.1
    
    Sectors
    
    348.1.1   Designation
    
    348.1.2   Related
    Parties
    
    348.2
    
    Representatives
    
    348.2.1   Appointment
    
    348.2.2   Regulatory
      Authorities
    
    358.2.3   State Offices of Consumer
      Advocate
    
    358.2.4   Initial
      Representatives
    
    358.2.5   Change of or Substitution
      for a Representative
    
    358.3
    
    Meetings
    
    368.3.1   Regular and Special
      Meetings
    
    368.3.2   Attendance
    
    368.3.3   Quorum
    
    368.4
    
    Manner of Acting
    
    368.5
    
    Chair and Vice Chair of the Members
      Committee
    
    378.5.1   Selection and
      Term
    
    378.5.2   Duties
    
    378.6
    
    Senior, Standing, and Other
      Committees
    
    37A8.6.1   Electricity Markets
      Committee
    
    37A8.6.2   Reliability
      Committee
    
    37B8.6.3   Other Committees and
      Bodies
    
    37C8.6.4   Alternate Dispute
      Resolution Committee
    
    388.7
    
    User Groups
    
    388.8
    
    Powers of the Members
Committee
    
    389.
    
    OFFICERS
    
    38A9.1
    
    Election and Term
    
    38A9.2
    
    President
    
    399.3
    
    Secretary
    
    399.4
    
    Treasurer
    
    399.5
    
    Renewal of Officers; Vacancies
    
    409.6
    
    Compensation
    
    40




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 3AThird Revised Rate Schedule FERC No.
      24




10.
    
    OFFICE OF THE INTERCONNECTION
    
    4010.1
    
    Establishment
    
    4010.2
    
    Processes and Organization
    
    4010.3
    
    Confidential Information
    
    40




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 4Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Original Sheet No.
4




10.4
    
    Duties and Responsibilities
    
    4011.
    
    MEMBERS
    
    4211.1
    
    Management Rights
    
    4211.2
    
    Other Activities
    
    4211.3
    
    Member Responsibilities
    
    4311.3.1   General
    
    4311.3.2   Facilities Planning and
      Operation
    
    4311.3.3   Electric
      Distributors
    
    4411.3.4   Reports to the Office of
      the Interconnection
    
    4611.4
    
    Regional Transmission Expansion Planning
      Protocol
    
    4611.5
    
    Member Right to Petition
    
    4611.6
    
    Membership Requirements
    
    4612.
    
    TRANSFERS OF MEMBERSHIP
    INTEREST
    
    4713.
    
    INTERCHANGE
    
    4713.1
    
    Interchange Arrangements with
      Non-Members
    
    4713.2
    
    Energy Market
    
    4814.
    
    METERING
    
    4814.1
    
    Installation, Maintenance and Reading of
      Meters
    
    4814.2
    
    Metering Procedures
    
    4814.3
    
    Integrated Megawatt-Hours
    
    4814.4
    
    Meter Locations
    
    4814.5
    
    Metering of Behind The Meter
      Generation
    
    4815.
    
    ENFORCEMENT OF OBLIGATIONS
    
    4915.1
    
    Failure to Meet Obligations
    
    4915.1.1   Termination of Market
      Buyer Rights
    
    4915.1.2   Termination of Market
      Seller Rights
    
    4915.1.3   Payment of
      Bills
    
    4915.2
    
    Enforcement of Obligations
    
    5015.2.1   Collection by the Office
      of the Interconnection
    
    5115.2.2   Default Allocation
      Assessment
    
    5115.3
    
    Obligations to a Member in
    Default
    
    51A15.4
    
    Obligations of a Member in
    Default
    
    51A15.5
    
    No Implied Waiver.
    
    51A16.
    
    LIABILITY AND INDEMNITY
    
    51A16.1
    
    Members
    
    51A16.2
    
    LLC Indemnified Parties
    
    5216.3
    
    Workers Compensation Claims
    
    5316.4
    
    Limitation of Liability
    
    5316.5
    
    Resolution of Disputes
    
    5316.6
    
    Gross Negligence or Willful
      Misconduct
    
    5416.7
    
    Insurance
    
    54




Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2005Vice President, Government
    PolicyIssued On:
    
    November 1, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 5Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 5






17.
    
    MEMBER REPRESENTATIONS, WARRANTIES AND
      COVENANTS
    
    5417.1
    
    Representations and Warranties
    
    5417.1.1  Organization and
      Existence
    
    5417.1.2  Power and
      Authority
    
    5417.1.3  Authorization and
      Enforceability
    
    5417.1.4  No Government
      Consents
    
    5517.1.5  No Conflict or
      Breach
    
    5517.1.6  No
    Proceedings
    
    5517.2
    
    Municipal Electric
      Systems
    
    5517.3
    
    Survival
    
    5518.
    
    MISCELLANEOUS PROVISIONS
    
    5618.1
    
    [Reserved.]
    
    5618.2
    
    Fiscal and Taxable Year
    
    5618.3
    
    Reports
    
    5618.4
    
    Bank Accounts; Checks, Notes and
      Drafts
    
    5618.5
    
    Books and Records
    
    5618.6
    
    Amendment
    
    5718.7
    
    Interpretation
    
    5718.8
    
    Severability
    
    5818.9
    
    Force Majeure
    
    5818.10
    
    Further Assurances
    
    5818.11
    
    Seal
    
    5818.12
    
    Counterparts
    
    5818.13
    
    Costs of Meetings
    
    5818.14
    
    Notice
    
    5918.15
    
    Headings
    
    5918.16
    
    No Third-Party Beneficiaries
    
    5918.17
    
    Confidentiality
    
    5918.17.1  Party Access
    
    5918.17.2  Required Disclosure
    
    6018.17.3  Disclosure to FERC
    
    6118.17.4  Disclosure to Authorized Persons
    
    6118.18
    
    Termination and
      Withdrawal
    
    61E18.18.1  Termination
    
    61E18.18.2  Withdrawal
    
    61F18.18.3  Winding Up
    
    61FRESOLUTION REGARDING ELECTION OF
      DIRECTORS
    
    63SCHEDULE 1 - PJM INTERCHANGE ENERGY
      MARKET
    
    641.
    
    MARKET OPERATIONS
    
    641.1
    
    Introduction
    
    641.2
    
    Cost-based Offers
    
    64




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 6Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 6




1.3
    
    Definitions
    
    641.3.1
    
    Auction Revenue Rights
    
    641.3.1A
    
    Auction Revenue Rights Credits
    
    641.3.1B
    
    Day-ahead Energy Market
    
    641.3.1C
    
    Day-ahead Prices
    
    641.3.1D
    
    Decrement Bid
    
    651.3.1E
    
    Dispatch Rate
    
    651.3.2
    
    Equivalent Load
    
    651.3.3
    
    External Market Buyer
    
    651.3.4
    
    External Resource
    
    651.3.5
    
    Financial Transmission Right
    
    651.3.5A
    
    Financial Transmission Right
      Obligation
    
    651.3.5B
    
    Financial Transmission Right
      Option
    
    651.3.6
    
    Generating Market Buyer
    
    651.3.7
    
    Generator Forced Outage
    
    661.3.8
    
    Generator Maintenance Outage
    
    661.3.9
    
    Generator Planned Outage
    
    661.3.9A
    
    Increment Bid
    
    661.3.10
    
    Internal Market Buyer
    
    661.3.11
    
    Inadvertent Interchange
    
    661.3.12
    
    Market Operations Center
    
    661.3.13
    
    Maximum Generation Emergency
    
    671.3.14
    
    Minimum Generation Emergency
    
    671.3.14A
    
    NERC Interchange Distribution
      Calculator
    
    671.3.15
    
    Network Resource
    
    671.3.16
    
    Network Service User
    
    671.3.17
    
    Network Transmission Service
    
    671.3.18
    
    Normal Maximum Generation
    
    671.3.19
    
    Normal Minimum Generation
    
    671.3.20
    
    Offer Data
    
    671.3.21
    
    Office of the Interconnection Control
      Center
    
    681.3.22
    
    Operating Day
    
    681.3.23
    
    Operating Margin
    
    681.3.24
    
    Operating Margin Customer
    
    681.3.25
    
    PJM Interchange
    
    681.3.26
    
    PJM Interchange Export
    
    681.3.27
    
    PJM Interchange Import
    
    691.3.28
    
    PJM Open Access Same-time Information
      System
    
    691.3.29
    
    Point-to-Point Transmission
      Service
    
    691.3.30
    
    Ramping Capability
    
    691.3.30A
    
    Real-time Prices
    
    691.3.30B
    
    Real-time Energy Market
    
    691.3.31
    
    Regulation
    
    69




Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 7, 2003Vice President, Governmental
      PolicyIssued On:
    
    November 6, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 7Third Revised Rate Schedule FERC No.
      24




1.3.31A
    
    Spinning Reserve
    
    701.3.31B
    
    Spinning Reserve Event
    
    701.3.32
    
    Spot Market Backup
    
    701.3.33
    
    Spot Market Energy
    
    701.3.33A
    
    State Estimator
    
    701.3.33B
    
    Station Power
    
    701.3.33C
    
    Target Allocation
    
    701.3.34
    
    Transmission Congestion Charge
    
    701.3.35
    
    Transmission Congestion Credit
    
    711.3.36
    
    Transmission Customer
    
    711.3.37
    
    Transmission Forced Outage
    
    711.3.37A
    
    Transmission Loading Relief
    
    711.3.37B
    
    Transmission Loading Relief
      Customer
    
    711.3.38
    
    Transmission Planned Outage
    
    711.4
    
    Market Buyers
    
    711.4.1
    
    Qualification
    
    711.4.2
    
    Submission of Information
    
    731.4.3
    
    Fees and Costs
    
    731.4.4
    
    Office of the Interconnection
      Determination
    
    731.4.5
    
    Existing Participants
    
    731.4.6
    
    Withdrawal
    
    731.5
    
    Market Sellers
    
    741.5.1
    
    Qualification
    
    741.5.2
    
    Withdrawal
    
    741.6
    
    Office of the Interconnection
    
    751.6.1
    
    Operation of the PJM Interchange Energy
      Market
    
    751.6.2
    
    Scope of Services
    
    751.6.3
    
    Records and Reports
    
    761.6.4
    
    PJM Manuals
    
    761.7
    
    General
    
    761.7.1
    
    Market Sellers
    
    761.7.2
    
    Market Buyers
    
    761.7.3
    
    Agents
    
    771.7.4
    
    General Obligations of the Market
      Participants
    
    771.7.5
    
    Market Operations Center
    
    781.7.6
    
    Scheduling and Dispatching
    
    791.7.7
    
    Pricing
    
    791.7.8
    
    Generating Market Buyer
    Resources
    
    791.7.9
    
    Delivery to an External Market
      Buyer
    
    801.7.10
    
    Other Transactions
    
    801.7.11
    
    Emergencies
    
    82




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Fourth
      Revised Sheet No. 8Third Revised Rate Schedule FERC No.
      24
    
    Superseding Third Revised Sheet No. 8




1.7.12
    
    Fees and Charges
    
    821.7.13
    
    Relationship to the PJM Region
    
    82A1.7.14
    
    PJM Manuals
    
    82A1.7.15
    
    Corrective Action
    
    831.7.16
    
    Recording
    
    831.7.17
    
    Operating Reserves
    
    831.7.18
    
    Regulation
    
    841.7.19
    
    Ramping
    
    841.7.19A
    
    Spinning Reserve
    
    841.7.20
    
    Communication and Operating
      Requirements
    
    851.8
    
    Selection,
      Scheduling and Dispatch Procedure Adjustment Process
    
    861.8.1
    
    PJM Dispute Resolution
    Agreement
    
    861.8.2
    
    Market or Control Area Hourly Operational
      Disputes
    
    861.9
    
    Prescheduling
    
    871.9.1
    
    Outage Scheduling
    
    871.9.2
    
    Planned Outages
    
    871.9.3
    
    Generator Maintenance Outages
    
    891.9.4
    
    Forced Outages
    
    891.9.5
    
    Market Participant
      Responsibilities
    
    891.9.6
    
    Internal Market Buyer
      Responsibilities
    
    901.9.7
    
    Market Seller Responsibilities
    
    901.9.8
    
    Transmission Owner
      Responsibilities
    
    901.9.9
    
    Office of the Interconnection
      Responsibilities
    
    911.10
    
    Scheduling
    
    911.10.1
    
    General
    
    911.10.1A
    
    Day-ahead Energy Market
    Scheduling
    
    921.10.2
    
    Pool-scheduled Resources
    
    951.10.3
    
    Self-scheduled Resources
    
    961.10.4
    
    Capacity Resources
    
    961.10.5
    
    External Resources
    
    971.10.6
    
    External Market Buyers
    
    971.10.6A
    
    Transmission Loading Relief
      Customers
    
    981.10.7
    
    Bilateral Transactions
    
    981.10.8
    
    Office of the Interconnection
      Responsibilities
    
    981.10.9
    
    Hourly Scheduling
    
    991.11
    
    Dispatch
    
    1001.11.1
    
    Resource Output
    
    1001.11.2
    
    Operating Basis
    
    1011.11.3
    
    Pool-dispatched Resources
    
    1011.11.3A
    
    Maximum Generation Emergency
    
    1011.11.4
    
    Regulation
    
    1011.11.4A
    
    Spinning Reserve
    
    1021.11.5
    
    PJM Open Access Same-time Information
      System
    
    103




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




---

PJM Interconnection, L.L.C.
    
    Fifth
      Revised Sheet No. 9Third Revised Rate Schedule FERC No.
      24
    
    Superseding Fourth Revised Sheet No. 9




1.12
    
    Dynamic
      Scheduling
    
    1032.
    
    CALCULATION OF LOCATIONAL MARGINAL PRICES
    
    1032.1
    
    Introduction
    
    1032.2
    
    General
    
    1032.3
    
    Determination of System Conditions Using the State
    Estimator
    
    1042.4
    
    Determination of Energy Offers Used in Calculating Real-time
      Prices
    
    1052.5
    
    Calculation of Real-time Prices
    
    1052.6
    
    Calculation of Day-ahead Prices
    
    1062.7
    
    Performance Evaluation
    
    1063.
    
    ACCOUNTING
      AND BILLING
    
    1063.1
    
    Introduction
    
    1063.2
    
    Market
      Buyers
    
    1073.2.1
    
    Spot Market Energy
    
    1073.2.2
    
    Regulation
    
    1093.2.3
    
    Operating Reserves
    
    1113.2.3A
    
    Spinning Reserve
    
    1143.2.3B
    
    Reactive Services
    
    1163.2.3C
    
    Synchronous Condensing for Post-Contingency
      Operation
    
    116D3.2.4
    
    Transmission Congestion
    
    116D.013.2.5
    
    Transmission Losses
    
    116D.013.2.6
    
    Emergency Energy
    
    1173.2.7
    
    Billing
    
    1173.3
    
    Market
      Sellers
    
    1183.3.1
    
    Spot Market Energy
    
    1183.3.2
    
    Regulation
    
    1193.3.3
    
    Operating Reserves
    
    1193.3.4
    
    Emergency Energy
    
    1193.3.5
    
    Spinning Reserve
    
    1193.3.6
    
    Billing
    
    1193.4
    
    Transmission Customers
    
    1203.4.1
    
    Transmission Congestion
    
    1203.4.2
    
    Transmission Losses
    
    1203.4.3
    
    Billing
    
    1203.5
    
    Other
      Control Areas
    
    1203.5.1
    
    Energy Sales
    
    1203.5.2
    
    Operating Margin Sales
    
    1213.5.3
    
    Transmission Congestion
    
    1213.5.4
    
    Billing
    
    1213.6
    
    Metering
      Reconciliation
    
    1213.6.1
    
    Meter Correction Billing
    
    1213.6.2
    
    Meter Corrections Between Market
      Participants
    
    1223.6.3
    
    500 kV Meter Errors
    
    1223.6.4
    
    Meter Corrections Between Control
      Areas
    
    122




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




---

PJM Interconnection, L.L.C.
    
    Sixth
      Revised Sheet No. 10Third Revised Rate Schedule FERC No.
      24
    
    Superseding Fifth Revised Sheet No. 10




3.6.5
    
    Meter Correction Data
    
    1223.6.6
    
    Correction Limits
    
    1224.
    
    RATE
      TABLE
    
    1234.1
    
    Offered
      Price Rates
    
    1234.2
    
    Transmission Losses
    
    1234.3
    
    Emergency
      Energy Purchases
    
    1235.
    
    CALCULATION OF TRANSMISSION CONGESTION CHARGES AND
CREDITS
    
    1235.1
    
    Transmission Congestion Charge Calculation
    
    1235.1.1
    
    Calculation by Office of the
      Interconnection
    
    1235.1.2
    
    General
    
    1235.1.3
    
    Network Service User
    Calculation
    
    1235.1.4
    
    Transmission Customer
    Calculation
    
    1245.1.5
    
    Operating Margin Customer
      Calculation
    
    1245.1.6
    
    Transmission Loading Relief Customer
      Calculation
    
    1255.1.7
    
    Total Transmission Congestion
      Charges
    
    1255.2
    
    Transmission Congestion Credit Calculation
    
    1255.2.1
    
    Eligibility
    
    1255.2.2
    
    Financial Transmission Rights
    
    1265.2.3
    
    Target Allocation of Transmission Congestion
      Credits
    
    127B5.2.4
    
    [Reserved.]
    
    1285.2.5
    
    Calculation of Transmission Congestion
      Credits
    
    1285.2.6
    
    Distribution of Excess Congestion
      Charges
    
    1285.3
    
    Unscheduled Transmission Service (Loop Flow)
    
    1296.
    
    “MUST-RUN”
      FOR RELIABILITY GENERATION
    
    1296.1
    
    Introduction
    
    1296.2
    
    Identification of Facility Outages
    
    1296.3
    
    Dispatch
      for Local Reliability
    
    1296.3.1
    
    Request and Dispatch
    
    1296.3.2
    
    Designation of Local Transmission
      Facilities
    
    1306.3.3
    
    Transition Procedures for Local Transmission
      Facilities under the Monitoring Responsibility and Dispatch Control of the
      Office of the Interconnection as of June 1, 2002
    
    1306.4
    
    Offer
      Price Caps
    
    1316.4.1
    
    Applicability
    
    1316.4.2
    
    Level
    
    131A7.
    
    FINANCIAL
      TRANSMISSION RIGHTS AUCTIONS
    
    1327.1
    
    Auctions
      of Financial Transmission Rights
    
    1327.1.1
    
    Auction Period and Scope of
      Auctions
    
    132.017.1.2
    
    Frequency and Time of Auctions
    
    132A7.1.3
    
    Duration of Financial Transmission
      Rights
    
    132A




Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 26, 2005Vice President, Government
    PolicyIssued On:
    
    November 2, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      EL03-236-000, issued May 6, 2004, 107 FERC ¶
61,112.




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 11Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 11




7.2
    
    Financial Transmission Rights
      Characteristics
    
    1337.2.1  Reconfiguration of
      Financial Transmission Rights
    
    1337.2.2  Specified Receipt and
      Delivery Points
    
    1337.2.3  Transmission Congestion
      Charges
    
    1337.3
    
    Auction Procedures
    
    1337.3.1  Role of the Office of the
      Interconnection
    
    1337.3.2  Notice of
    Offer
    
    1347.3.3  Pending Applications for
      Firm Service
    
    1347.3.4  On-Peak, Off-Peak and
      24-Hour Periods
    
    1347.3.5  Offers and
    Bids
    
    1347.3.6  Determination of Winning
      Bids and Clearing Price
    
    1357.3.7  Announcements of Winners
      and Prices
    
    1367.3.8  Auction
      Settlements
    
    1367.4
    
    Allocation of Auction Revenues
    
    1367.4.1  Eligibility
    
    1367.4.2  Auction Revenue
      Rights
    
    1367.4.3  Target Allocation of
      Auction Revenue Right Credits
    
    1387.4.4  Calculation of Auction
      Revenue Right Credits
    
    1387.5
    
    Simultaneous Feasibility
    
    1388.
    
    INTERREGIONAL TRANSMISSION
      CONGESTIONMANAGEMENT PILOT PROGRAM
    
    1398.1
    
    Introduction
    
    1398.2
    
    Identification of Transmission
      Constraints
    
    1398.3
    
    Redispatch Procedures
    
    1398.4
    
    Locational Marginal Price
    
    1408.5
    
    Generator Compensation
    
    1408.6
    
    Settlements
    
    1408.7
    
    Effective Date
    
    1419.
    
    COMMONWEALTH EDISON ZONE MARKET INTEGRATION
      DURINGTHE COMED INTEGRATION PHASE
    
    1419.1
    
    Introduction
    
    1419.2
    
    Generation Transfer Pathway
    
    1419.3
    
    Transmission Loss Recovery
    
    141B9.4
    
    Financial Transmission Rights
    
    141B9.5
    
    Ancillary Services
    
    141C10.
    
    PJM-FE INTERREGIONAL TRANSMISSION CONGESTION
      MANAGEMENT
    
    141DPJM EMERGENCY LOAD RESPONSE
      PROGRAM
    
    142PJM ECONOMIC LOAD RESPONSE
    PROGRAM
    
    151SCHEDULE 2 - COMPONENTS OF
COST
    
    167SCHEDULE 2 - EXHIBIT A, EXPLANATION OF THE
      TREATMENT OF THE COSTS OF EMISSION ALLOWANCES
    
    168SCHEDULE 3 - ALLOCATION OF THE COST AND
      EXPENSES OF THE OFFICE OF THE INTERCONNECTION
    
    170




Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    June 30, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 11AThird Revised Rate Schedule FERC No.
      24




SCHEDULE 4 - STANDARD FORM OF AGREEMENT TO
      BECOME A MEMBER OF THE LLC.
    
    171SCHEDULE 5 - PJM DISPUTE RESOLUTION
      PROCEDURES
    
    1721.
    
    DEFINITIONS
    
    1721.1   Alternate Dispute Resolution
      Committee
    
    1721.2   MAAC Dispute Resolution
      Committee
    
    172




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 12Third Revised Rate Schedule FERC No.
      24




1.3
    
    Related PJM Agreements
    
    1722.
    
    PURPOSES AND OBJECTIVES
    
    1722.1
    
    Common and Uniform Procedures
    
    1722.2
    
    Interpretation
    
    1723.
    
    NEGOTIATION AND MEDIATION
    
    1733.1
    
    When Required
    
    1733.2
    
    Procedures
    
    1733.2.1  Initiation
    
    1733.2.2  Selection of
      Mediator
    
    1733.2.3  Advisory
    Mediator
    
    1733.2.4  Mediation
    Process
    
    1743.2.5  Mediator’s
      Assessment
    
    1743.3
    
    Costs
    
    1754.
    
    ARBITRATION
    
    1754.1
    
    When Required
    
    1754.2
    
    Binding Decision
    
    1754.3
    
    Initiation
    
    1754.4
    
    Selection of Arbitrator(s)
    
    1754.5
    
    Procedures
    
    1764.6
    
    Summary Disposition and Interim
      Measures
    
    1764.6.1  Lack of Good Faith
      Basis
    
    1764.6.2  Discovery
    Limits
    
    1764.6.3  Interim
    Decision
    
    1764.7
    
    Discovery of Facts
    
    1764.7.1  Discovery
      Procedures
    
    1764.7.2  Procedures
      Arbitrator
    
    1774.8
    
    Evidentiary Hearing
    
    1774.9
    
    Confidentiality
    
    1774.9.1  Designation
    
    1774.9.2  Compulsory
      Disclosure
    
    1784.9.3  Public
      Information
    
    1784.10
    
    Timetable
    
    1784.11
    
    Advisory Interpretations
    
    1784.12
    
    Decisions
    
    1794.13
    
    Costs
    
    1794.14
    
    Enforcement
    
    1795.
    
    ALTERNATE DISPUTE RESOLUTION
      COMMITTEE
    
    1795.1
    
    Membership
    
    1795.1.1  Representatives
    
    1795.1.2  Term
    
    1805.2
    
    Voting Requirements
    
    1805.3
    
    Officers
    
    180




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 13Third Revised Rate Schedule FERC No.
      24
    
    Superseding Substitute Original Sheet No.
13




5.4
    
    Meetings.
    
    1805.5
    
    Responsibilities.
    
    180SCHEDULE 6 -
      REGIONAL TRANSMISSION EXPANSION PLANNING PROTOCOL
    
    1821.
    
    REGIONAL TRANSMISSION EXPANSION PLANNING
      PROTOCOL
    
    1821.1
    
    Purpose
      and Objectives
    
    1821.2
    
    Conformity
      with NERC and Other Applicable Criteria
    
    1821.3
    
    Establishment of Committees
    
    182A1.4
    
    Contents
      of the Regional Transmission Expansion Plan
    
    1831.5
    
    Procedure
      for Development of the Regional Transmission Expansion Plan
    
    1831.5.1
    
    Commencement of the Process
    
    1831.5.2
    
    Development of Scope, Assumptions and
      Procedures
    
    1841.5.3
    
    Scope of Studies
    
    1841.5.4
    
    Supply of Data
    
    1841.5.5
    
    Coordination of the Regional Transmission
      Expansion Plan
    
    1851.5.6
    
    Development of the Recommended Regional
      Transmission Expansion Plan
    
    1851.5.7
    
    Development of Economic Transmission
      Enhancements and Expansions
    
    185B1.6
    
    Approval
      of the Final Regional Transmission Expansion Plan
    
    1861.7
    
    Obligation
      to Build
    
    1871.8
    
    Relationship to the PJM Open Access Transmission Tariff
    
    188SCHEDULE 7 -
      UNDERFREQUENCY RELAY OBLIGATIONS AND CHARGES
    
    1891.
    
    UNDERFREQUENCY RELAY
OBLIGATION
    
    1891.1
    
    Application.
    
    1891.2
    
    Obligations.
    
    1892.
    
    UNDERFREQUENCY RELAY CHARGES
    
    1893.
    
    DISTRIBUTION OF UNDERFREQUENCY RELAY
      CHARGES
    
    1903.1
    
    Share of
      Charges.
    
    1903.2
    
    Allocation
      by the Office of the Interconnection.
    
    190SCHEDULE 8 -
      DELEGATION OF PJM CONTROL AREA RELIABILITY RESPONSIBILITIES
    
    1911.
    
    DELEGATION
    
    1912.
    
    NEW PARTIES
    
    1913.
    
    IMPLEMENTATION OF RELIABILITY ASSURANCE
      AGREEMENT.
    
    191SCHEDULE 8A -
      DELEGATION OF PJM WEST REGION RELIABILITY RESPONSIBILITIES
    
    1931.
    
    DELEGATION
    
    1932.
    
    NEW PARTIES
    
    1933.
    
    IMPLEMENTATION OF RELIABILITY ASSURANCE
      AGREEMENT-WEST
    
    193SCHEDULE 9 -
      PJM CONTROL AREA EMERGENCY PROCEDURE CHARGES
    
    1951.
    
    EMERGENCY PROCEDURE CHARGE
    
    195




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 24, 2003Vice President, Government
    PolicyIssued On:
    
    August 31, 2004




---

PJM Interconnection, L.L.C.
    
    Fourth
      Revised Sheet No. 14Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 14




2.
    
    DISTRIBUTION OF EMERGENCY PROCEDURE CHARGES
    
    1952.1
    
    Complying
      Parties.
    
    1952.2
    
    All
      Parties.
    
    195SCHEDULE 9A -
      PJM WEST REGION EMERGENCY PROCEDURE CHARGES
    
    1961.
    
    EMERGENCY
      PROCEDURE CHARGE
    
    1962.
    
    DISTRIBUTION OF EMERGENCY PROCEDURE CHARGES
    
    1962.1
    
    Complying
      Parties
    
    1962.2
    
    All
      Parties
    
    196SCHEDULE 10 –
      FORM OF NON-DISCLOSURE AGREEMENT
    
    1971.
    
    DEFINITIONS
    
    197A1.1
    
    Affected
      Member.
    
    197A1.2
    
    Authorized
      Commission.
    
    197A1.3
    
    Authorized
      Person.
    
    197A1.4
    
    Confidential Information
    
    197A1.5
    
    FERC.
    
    197A1.6
    
    Information Request.
    
    197A1.7
    
    Operating
      Agreement.
    
    197A1.8
    
    PJM Market
      Monitor.
    
    197A1.9
    
    PJM
      Tariff.
    
    197A1.10
    
    Third
      Party Request.
    
    197A2.
    
    Protection
      of Confidentiality.
    
    197B2.1
    
    Duty to
      Not Disclose.
    
    197B2.2
    
    Conditions
      Precedent.
    
    197B2.3
    
    Discussion
      of Confidential Information with other Authorized Persons.
    
    197B2.4
    
    Defense
      Against Third Party Requests
    
    197C2.5
    
    Care and
      Use of Confidential Information
    
    197C2.5.1
    
    Control of
      Confidential Information.
    
    197C2.5.2
    
    Access to
      Confidential Information.
    
    197C2.5.3
    
    Schedule of
      Authorized Persons.
    
    197C2.5.4
    
    Use of Confidential
      Information.
    
    197D2.5.5
    
    Return of
      Confidential Information.
    
    197D2.5.6
    
    Notice of
      Disclosures.
    
    197D2.6
    
    Ownership
      and Privilege.
    
    197D3.
    
    Procedure
      for Information Requests
    
    197E3.1
    
    Written
      Requests.
    
    197E3.2
    
    Oral
      Disclosures by the PJM Market Monitor.
    
    197E3.3
    
    Response
      to Information Requests.
    
    197F4.
    
    Remedies.
    
    197G4.1
    
    Material
      Breach.
    
    197G4.2
    
    Judicial
      Recourse
    
    197G4.3
    
    Waiver of
      Monetary Damages
    
    197G5.
    
    Jurisdiction.
    
    197G6.
    
    Notices.
    
    197H7.
    
    Severability and Survival.
    
    197I




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 14AThird Revised Rate Schedule FERC No.
      24




8.
    
    Representations
    
    197I9.
    
    Third
      Party Beneficiaries
    
    197I10.
    
    Counterparts
    
    197I11.
    
    Amendment
    
    197ISCHEDULE 10A
      – FORM OF CERTIFICATION
    
    197J1.
    
    Definitions
    
    197J2.
    
    Requisite
      Authority
    
    197J3.
    
    Protection
      of Confidential Information
    
    197K4.
    
    Defense
      Against Requests for Disclosure
    
    197L5.
    
    Use and
      Destruction of Confidential Information
    
    197L6.
    
    Notice of
      Disclosure of Confidential Information
    
    197L7.
    
    Release of
      Claims
    
    197M8.
    
    Ownership
      and Privilege
    
    197MExhibit A
      Certification List of Authorized Persons
    
    197NSCHEDULE 11 -
      PJM CAPACITY CREDIT MARKETS IN PJM REGION
    
    1981.
    
    PURPOSES
      AND OBJECTIVES
    
    1981.1
    
    PJM Capacity Credit
      Markets in PJM Region
    
    1981.2
    
    [Reserved.]
    
    1981.3
    
    Use of Capacity
      Credits
    
    1982.
    
    DEFINITIONS
    
    1982.1
    
    Buy Bid
    
    1982.2
    
    Capacity
      Credit
    
    1982.2A
    
    ComEd Zone
    
    1982.3
    
    Capacity
      Resources
    
    1982.4
    
    Holiday
    
    198A2.4A
    
    Installed Capacity
      Credit Market
    
    198A2.4B
    
    Interim
    Period
    
    198A2.5
    
    PJM Capacity Credit
      Market
    
    198A2.6
    
    PJM Daily Capacity
      Credit Market
    
    1992.6A
    
    PJM Installed
      Capacity Credit Market
    
    1992.7
    
    PJM Monthly Capacity
      Credit Market
    
    1992.8
    
    Sell Offer
    
    1992.9
    
    Unforced
      Capacity
    
    1992.10
    
    Up-To
Block
    
    1993.
    
    PARTICIPATION IN THE PJM CAPACITY CREDIT MARKET
    
    1993.1
    
    Eligibility
    
    1993.2
    
    Effect of
      Withdrawal
    
    199A4.
    
    RESPONSIBILITIES OF THE OFFICE OF THE INTERCONNECTION
    
    2004.1
    
    Operation of the PJM
      Capacity Credit Market
    
    2004.2
    
    Records and
      Reports
    
    200




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 14BThird Revised Rate Schedule FERC No.
      24






5.
    
    GENERAL
      PROVISIONS
    
    2005.1
    
    Market
    Sellers
    
    2005.2
    
    Market
    Buyers
    
    2005.3
    
    Agents
    
    2015.4
    
    General Obligations
      of Market Participants
    
    2015.5
    
    Relationship of
      Capacity Credits to Capacity Obligations Imposed under the Reliability
      Assurance Agreement or Reliability Assurance Agreement-West
    
    201




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 15Third Revised Rate Schedule FERC No.
      24
    
    Superseding Substitute Original Sheet No.
15




5.6
    
    Deficiency
      Charges
    
    2015.7
    
    Financial
      Transmission Rights
    
    2015.8
    
    Confidentiality
    
    2016.
    
    OPERATION
      OF THE PJM CAPACITY CREDIT MARKETS
    
    2026.1
    
    Content of Sell
      Offers
    
    2026.1.1
      Specifications
    
    2026.1.2 Market-based
      Offers
    
    2026.1.3 Availability
      of Capacity Credits for Sale
    
    2026.2
    
    Content of Buy
      Bids
    
    2036.3
    
    Submission of Sell
      Offers and Buy Bids
    
    2036.4
    
    Conduct of PJM
      Capacity Credit Markets
    
    203A6.4.1 PJM Daily
      Capacity Credit Markets
    
    203A6.4.2 PJM Monthly
      Capacity Credit Markets
    
    2046.5
    
    Market Clearing
      Procedures
    
    2046.6
    
    Settlement
      Procedures
    
    2046.7
    
    Billing
    
    2056.8
    
    Time
    Standard
    
    205




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 16Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 16




SCHEDULE 12 - PJM MEMBER LIST
    
    215RESOLUTION TO AMEND THE
      PROCEDURES REQUIRING THE RETENTION OF AN INDEPENDENT CONSULTANT TO PROPOSE
      A LIST OF CANDIDATES FOR THE BOARD OF MANAGERS ELECTION FOR 2001
    
    220




Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 7, 2003Vice President, Governmental
      PolicyIssued On:
    
    November 6, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 17Third Revised Rate Schedule FERC No.
      24




AMENDED AND RESTATED

OPERATING
AGREEMENT



of



PJM INTERCONNECTION, L.L.C.



This Amended and Restated Operating Agreement of
PJM Interconnection, L.L.C., dated as of this 2ndday of June, 1997, amends and
restates as of the Effective Date the Operating Agreement of PJM
Interconnection, L.L.C. filed with the FERC on April 2, 1997, as amended.



WHEREAS, certain of the Members have
previously entered into an agreement, originally dated September 26, 1956, as
amended and supplemented up to and including December 31, 1996, stating “their
respective rights and obligations with respect to the coordinated operation of
their electric supply systems and the interchange of electric capacity and
energy among their systems” (such agreement as amended and supplemented being
referred to as the “Original PJM Agreement”), and which coordinated operations
and interchange came to be known as the PJM Interconnection; and



WHEREAS, pursuant to a resolution of June
16, 1993, an unincorporated association comprised of the parties to the Original
PJM Agreement was formed for the purpose of implementation of the Original PJM
Agreement as it then existed and as it subsequently has been amended and
supplemented, such association being known as the “PJM Interconnection
Association”; and



WHEREAS, because of changes in federal law
and policy, the Original PJM Agreement, together with other documents and
agreements, was amended, restated and submitted to FERC on December 31, 1996 to
restructure fundamental aspects of the operation of the Interconnection; and



WHEREAS, so that the provisions of the
Original PJM Agreement could be placed into effect consistent with a February
28, 1997 order of FERC, including those provisions related to the governance of
the Interconnection, the parties to the Original PJM Agreement, along with the
other interested parties, approved the conversion of the PJM Interconnection
Association into the LLC pursuant to the provisions of the Delaware Limited
Liability Company Act, as amended (the “Delaware LLC Act”), pursuant to a
Certificate of Formation (the “Certificate of Formation”) and a Certificate of
Conversion (the “Certificate of Conversion”), each filed with the Delaware
Secretary of State (the “Recording Office”) on March 31, 1997; and



WHEREAS, the Members wish to amend and
restate the Operating Agreement of PJM Interconnection, L.L.C. adopted in
connection with the formation of the LLC and as in effect immediately prior to
the Effective Date in the form set forth below; and



WHEREAS, the Members intend to form an
Independent System Operator in accordance with the regulations of the Federal
Energy Regulatory Commission; and



WHEREAS, the Members wish to amend and
restate the Operating Agreement to provide for expansion of the operations of
PJM Interconnection, L.L.C. into additional Control Areas.



Now, therefore, in consideration of the foregoing,
and of the covenants and agreements hereinafter set forth, the Members hereby
agree as follows:



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 18Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 18






1. DEFINITIONS



Unless the context otherwise specifies or
requires, capitalized terms used in this Agreement shall have the respective
meanings assigned herein or in the Schedules hereto for all purposes of this
Agreement (such definitions to be equally applicable to both the singular and
the plural forms of the terms defined). Unless otherwise specified, all
references herein to Sections, Schedules, Exhibits or Appendices are to
Sections, Schedules, Exhibits or Appendices of this Agreement. As used in this
Agreement:



1.1 Act.



“Act” shall mean the Delaware Limited Liability
Company Act, Title 6, §§ 18-101 to 18-1109 of the Delaware Code.



1.2 Affiliate.



“Affiliate” shall mean any two or more entities,
one of which controls the other or that are under common control. “Control”
shall mean the possession, directly or indirectly, of the power to direct the
management or policies of an entity. Ownership of publicly-traded equity
securities of another entity shall not result in control or affiliation for
purposes of this Agreement if the securities are held as an investment, the
holder owns (in its name or via intermediaries) less than 10 percent of the
outstanding securities of the entity, the holder does not have representation on
the entity’s board of directors (or equivalent managing entity) or vice versa,
and the holder does not in fact exercise influence over day-to-day management
decisions. Unless the contrary is demonstrated to the satisfaction of the
Members Committee, control shall be presumed to arise from the ownership of or
the power to vote, directly or indirectly, ten percent or more of the voting
securities of such entity.



1.2A Affected Member.



“Affected Member” shall mean a Member which as a
result of its participation in PJM’s markets or its membership in the LLC PJM
provided confidential information to the Office of the Interconnection, which
confidential information is requested by, or is disclosed to an Authorized
Person under a Non-Disclosure Agreement.



1.3 Agreement.



“Agreement” shall mean this Amended and Restated
Operating Agreement of PJM Interconnection, L.L.C., including all Schedules,
Exhibits, Appendices, addenda or supplements hereto, as amended from time to
time.



1.4 Annual Meeting of the Members.



“Annual Meeting of the Members” shall mean the
meeting specified in Section 8.3.1 of this Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 18AThird Revised Rate Schedule FERC No.
      24




1.4A Authorized Commission.



“Authorized Commission” shall mean (i) a State
public utility commission within the geographic limits of the PJM Region that
regulates the distribution or supply of electricity to retail customers and is
legally charged with monitoring the operation of wholesale or retail markets
serving retail suppliers or customers within its State or (ii) an association or
organization comprised exclusively of State public utility commissions described
in the immediately preceding clause (i).



1.4B Authorized Person.



“Authorized Person” shall mean a person who has
executed a Non-Disclosure Agreement, and is authorized in writing by an
Authorized Commission to receive and discuss confidential information.
Authorized Persons may include attorneys representing an Authorized Commission,
consultants and/or contractors directly employed by an Authorized Commission,
provided however that consultants or contractors may not initiate requests for
confidential information from the Office of the Interconnection or the PJM
Market Monitor.



1.5 Board Member.



“Board Member” shall mean a member of the PJM
Board.



1.5A Applicable Regional Reliability Council.



“Applicable Regional Reliability Council” shall
mean the reliability council for the region in which a Member operates.



1.5B Behind The Meter Generation: Behind
The Meter Generation refers to one or more generating units that are located
with load at a single electrical location such that no transmission or
distribution facilities owned or operated by any Transmission Owner or Electric
Distributor are used to deliver energy from the generating unit[s] to the load;
provided, however, that Behind The Meter Generation does not include (i) at any
time, any portion of such generating unit[s]’ capacity that is designated as a
Capacity Resource, or (ii) in any hour, any portion of the output of the
generating unit[s] that is sold to another entity for consumption at another
electrical location or into the PJM Interchange Energy Market.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




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    Substitute Sixth Revised Sheet No. 19Third Revised Rate Schedule FERC No.
      24
    
    Superseding Sixth Revised Sheet No. 19




1.6 Capacity Resource.



“Capacity Resource” shall mean the net capacity
from owned or contracted for generating facilities all of which (i) are
accredited to a Load Serving Entity pursuant to the procedures set forth in the
Reliability Assurance Agreement and (ii) are committed to satisfy that Load
Serving Entity’s obligations under the Reliability Assurance Agreement and this
Agreement.



1.7 Control Area.



“Control Area” shall mean an electric power system
or combination of electric power systems bounded by interconnection metering and
telemetry to which a common automatic generation control scheme is applied in
order to:



(a) match the power output of the generators
within the electric power system(s) and energy purchased from entities outside
the electric power system(s), with the load within the electric power system(s);



(b) maintain scheduled interchange with other
Control Areas, within the limits of Good Utility Practice;



(c) maintain the frequency of the electric power
system(s) within reasonable limits in accordance with Good Utility Practice and
the criteria of NERC and the applicable regional reliability council of NERC;



(d) maintain power flows on transmission
facilities within appropriate limits to preserve reliability; and



(e) provide sufficient generating capacity to
maintain operating reserves in accordance with Good Utility Practice.



1.7.01 Control Zone.



“Control Zone” shall mean any of the ECAR Control
Zone(s), MAAC Control Zone, or MAIN Control Zone(s).



1.7.02 Default Allocation Assessment.



“Default Allocation Assessment” shall mean the
assessment determined pursuant to section 15.2.2 of this Agreement.



1.7A East Transmission Owner.



“East Transmission Owner” shall mean a
Transmission Owner that has executed the East Transmission Owners’ Agreement.



1.7B East Transmission Owners Agreement.



“East Transmission Owners’ Agreement” shall mean
that certain agreement, dated June 2, 1997 and as amended from time to time, by
and among Transmission Owners in the PJM Control Area providing for an
open-access transmission tariff in the MAAC Control Zone, and for other
purposes.



1.7C ECAR.



“ECAR” shall mean the reliability council under
section 202 of the Federal Power Act, established pursuant to the ECAR
Coordination Agreement dated June 1, 1968, or any successor thereto.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2005Vice President, Government
    PolicyIssued On:
    
    January 27, 2005




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    First
      Revised Sheet No. 19AThird Revised Rate Schedule FERC No.
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    Superseding First Revised Sheet No. 19




1.7D ECAR Control Zone



“ECAR Control Zone” shall mean any one of the one
or more Control Zones comprised of the Transmission Facilities of one or more of
the Transmission Owners for which ECAR is the Applicable Regional Reliability
Council, as designated in the PJM Manuals.



1.8 Electric Distributor.



“Electric Distributor” shall mean a Member that
owns or leases with rights equivalent to ownership electric distribution
facilities that are used to provide electric distribution service to electric
load within the PJM Region.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Third
      Revised Sheet No. 20Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 20




1.9 Effective Date.



“Effective Date” shall mean August 1, 1997, or
such later date that FERC permits this Agreement to go into effect.



1.10 Emergency.



“Emergency” shall mean: (i) an abnormal system
condition requiring manual or automatic action to maintain system frequency, or
to prevent loss of firm load, equipment damage, or tripping of system elements
that could adversely affect the reliability of an electric system or the safety
of persons or property; or (ii) a fuel shortage requiring departure from normal
operating procedures in order to minimize the use of such scarce fuel; or (iii)
a condition that requires implementation of emergency procedures as defined in
the PJM Manuals.



1.11 End-Use Customer.



“End-Use Customer” shall mean a Member that is a
retail end-user of electricity within the PJM Region.



1.12 FERC.



“FERC” shall mean the Federal Energy Regulatory
Commission or any successor federal agency, commission or department exercising
jurisdiction over this Agreement.



1.13 Finance Committee.



“Finance Committee” shall mean the body formed
pursuant to Section 7.5.1 of this Agreement.



1.14 Generation Owner.



“Generation Owner” shall mean a Member that owns
or leases with rights equivalent to ownership facilities for the generation of
electric energy that are located within the PJM Region. Purchasing all or a
portion of the output of a generation facility shall not be sufficient to
qualify a Member as a Generation Owner.



1.15 Good Utility Practice.



“Good Utility Practice” shall mean any of the
practices, methods and acts engaged in or approved by a significant portion of
the electric utility industry during the relevant time period, or any of the
practices, methods and acts which, in the exercise of reasonable judgment in
light of the facts known at the time the decision was made, could have been
expected to accomplish the desired result at a reasonable cost consistent with
good business practices, reliability, safety and expedition. Good Utility
Practice is not intended to be limited to the optimum practice, method, or act
to the exclusion of all others, but rather is intended to include acceptable
practices, methods, or acts generally accepted in the region.



1.16 Information Request.



“Information Request” shall mean a written
request, in accordance with the terms of this Agreement for disclosure of
confidential information pursuant to Section 18.17.4 of this Agreement.



1.17 LLC.



“LLC” shall mean PJM Interconnection, L.L.C., a
Delaware limited liability company.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    August 31, 2004




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 21Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 21




1.18 Load Serving Entity.



“Load Serving Entity” shall mean an entity,
including a load aggregator or power marketer, (1) serving end-users within the
PJM Region, and (2) that has been granted the authority or has an obligation
pursuant to state or local law, regulation or franchise to sell electric energy
to end-users located within the PJM Region, or the duly designated agent of such
an entity.



1.19 Locational Marginal Price.



“Locational Marginal Price” shall mean the hourly
integrated market clearing marginal price for energy at the location the energy
is delivered or received, calculated as specified in Section 2 of Schedule 1 of
this Agreement.



1.20 MAAC.



“MAAC” shall mean the Mid-Atlantic Area Council, a
reliability council under § 202 of the Federal Power Act established pursuant to
the MAAC Agreement dated August 1, 1994 or any successor thereto.



1.20A MAAC Control Zone.



“MAAC Control Zone” shall mean the aggregate of
the Transmission Facilities of Atlantic City Electric Company, Baltimore Gas and
Electric Company, Delmarva Power and Light Company, Jersey Central Power and
Light Company, Metropolitan Edison Company, PECO Energy Company, Pennsylvania
Electric Company, PPL Electric Utilities Corporation, Potomac Electric Power
Company, Public Service Electric and Gas Company, and Rockland Electric Company.



1.20B MAIN.



“MAIN” shall mean the Mid-America Interconnected
Network, a reliability council under § 202 of the Federal Power Act established
pursuant to the Amended and Restated Bylaws of MAIN, dated January 8, 1998, or
any successor thereof.



1.20C MAIN Control Zone.



“MAIN Control Zone” shall mean any one of the one
or more Control Zones comprised of the Transmission Facilities of one or more of
the Transmission Owners for which MAIN is the Applicable Regional Reliability
Council, as designated in the PJM Manuals.



1.21 Market Buyer.



“Market Buyer” shall mean a Member that has met
reasonable creditworthiness standards established by the Office of the
Interconnection and that is otherwise able to make purchases in the PJM
Interchange Energy Market or PJM Capacity Credit.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 21AThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 21A




1.22 Market Participant.



“Market Participant” shall mean a Market Buyer or
a Market Seller, or both.



1.23 Market Seller.



“Market Seller” shall mean a Member that has met
reasonable creditworthiness standards established by the Office of the
Interconnection and that is otherwise able to make sales in the PJM Interchange
Energy Market or PJM Capacity Credit Market.



1.24 Member.



“Member” shall mean an entity that satisfies the
requirements of Section 11.6 of this Agreement and that (i) is a member of the
LLC immediately prior to the Effective Date, or (ii) has executed an Additional
Member Agreement in the form set forth in Schedule 4 hereof.



1.25 Members Committee.



“Members Committee” shall mean the committee
specified in Section 8 of this Agreement composed of representatives of all the
Members.



1.26 NERC.



“NERC” shall mean the North American Electric
Reliability Council, or any successor thereto.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 22Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 22




1.26A Non-Disclosure Agreement.



“Non-Disclosure Agreement” shall mean an agreement
between an Authorized Person and the Office of the Interconnection, pursuant to
Section 18 of this Agreement, the form of which is appended to this Agreement as
Schedule 10, wherein the Authorized Person is given access to otherwise
restricted confidential information, for the benefit of their respective
Authorized Commission.



1.27 Office of the Interconnection.



“Office of the Interconnection” shall mean the
employees and agents of the LLC engaged in implementation of this Agreement and
administration of the PJM Tariff, subject to the supervision and oversight of
the PJM Board acting pursuant to this Agreement.



1.28 Operating Reserve.



“Operating Reserve” shall mean the amount of
generating capacity scheduled to be available for a specified period of an
Operating Day to ensure the reliable operation of a Control Zone, as specified
in the PJM Manuals.



1.29 Original PJM Agreement.



“Original PJM Agreement” shall mean that certain
agreement between certain of the Members, originally dated September 26, 1956,
and as amended and supplemented up to and including December 31, 1996, relating
to the coordinated operation of their electric supply systems and the
interchange of electric capacity and energy among their systems.



1.30 Other Supplier.



“Other Supplier” shall mean a Member that is (i)
engaged in buying, selling or transmitting electric energy in or through the
Interconnection or has a good faith intent to do so, and (ii) is not a
Generation Owner, Electric Distributor, Transmission Owner or End-Use Customer.



1.31 PJM Board.



“PJM Board” shall mean the Board of Managers of
the LLC, acting pursuant to this Agreement.



1.31A PJM Capacity Credit Market.



“PJM Capacity Credit Market” shall be as defined
in Schedule 11 to this Agreement.



1.32 PJM Control Area.



“PJM Control Area” shall mean the Control Area
recognized by NERC as the PJM Control Area.



1.33 PJM Dispute Resolution Procedures.



“PJM Dispute Resolution Procedures” shall mean the
procedures for the resolution of disputes set forth in Schedule 5 of this
Agreement.



1.34 PJM Interchange Energy Market.



“PJM Interchange Energy Market” shall mean the
regional competitive market administered by the Office of the Interconnection
for the purchase and sale of spot electric energy at wholesale in interstate
commerce and related services established pursuant to Schedule 1 to this
Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    August 31, 2004




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    First
      Revised Fourth Revised Sheet No. 23Third Revised Rate Schedule FERC No.
      24
    
    Superseding Fourth Revised Sheet No. 23




1.35 PJM Manuals.



“PJM Manuals” shall mean the instructions, rules,
procedures and guidelines established by the Office of the Interconnection for
the operation, planning, and accounting requirements of the PJM Region and the
PJM Interchange Energy Market.



1.35.01 PJM Market Monitor.



“PJM Market Monitor” shall mean the Market
Monitoring Unit established under Attachment M to the PJM Tariff.



1.35A PJM Region.



“PJM Region” shall mean the aggregate of the MAAC
Control Zone and the PJM West Region.



1.36 PJM Tariff.



“PJM Tariff” shall mean the PJM Open Access
Transmission Tariff providing transmission service within the PJM Region,
including any schedules, appendices, or exhibits attached thereto, as in effect
from time to time.



1.36A [Reserved.]



1.36B PJM West Region.



“PJM West Region” shall mean the aggregate of the
ECAR Control Zone(s) and MAIN Control Zone(s).



1.37 Planning Period.



“Planning Period” shall initially mean the 12
months beginning June 1 and extending through May 31 of the following year, or
such other period established under the procedures of, as applicable, the
Reliability Assurance Agreement or the Reliability Assurance Agreement-West.



1.38 President.



“President” shall have the meaning specified in
Section 9.2.



1.38A Regulation Zone.



“Regulation Zone” shall mean any of those one or
more geographic areas, each consisting of a combination of one or more Control
Zone(s) as designated by the Office of the Interconnection in the PJM Manuals,
relevant to provision of, and requirements for, regulation service.



1.39 Related Parties.



“Related Parties” shall mean, solely for purposes
of the governance provisions of this Agreement: (i) any generation and
transmission cooperative and one of its distribution cooperative members; and
(ii) any joint municipal agency and one of its members. For purposes of this
Agreement, representatives of state or federal government agencies shall not be
deemed Related Parties with respect to each other, and a public body’s
regulatory authority, if any, over a Member shall not be deemed to make it a
Related Party with respect to that Member.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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    First
      Revised Sheet No. 23AThird Revised Rate Schedule FERC No.
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    Superseding Fourth Revised Sheet No. 23




1.40 Reliability Assurance Agreement.



“Reliability Assurance Agreement” shall mean that
certain agreement, dated June 2, 1997 and as amended from time to time,
establishing obligations, standards and procedures for maintaining the reliable
operation of the PJM Control Area.



1.40A Reliability Assurance Agreement-West.



“Reliability Assurance Agreement-West” shall mean
that certain agreement, dated March 13, 2001 and as amended from time to time,
establishing obligations, standards and procedures for maintaining the reliable
operation of the PJM West Region.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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    First
      Revised Third Revised Sheet No. 24Third Revised Rate Schedule FERC No.
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    Superseding Third Revised Sheet No. 24




1.41 Sector Votes.



“Sector Votes” shall mean the affirmative and
negative votes of each sector of a Senior Standing Committee, as specified in
Section 8.4.



1.41A Senior Standing Committees.



“Senior Standing Committees” shall mean the
Members Committee, Electricity Markets Committee, and Reliability Committee, as
established in Sections 8.1 and 8.6.



1.41A.01 Spinning Reserve Zone.



“Spinning Reserve Zone” shall mean the MAAC
Control Zone or any of those geographic areas consisting of a combination of one
or more of the Control Zone(s) in the PJM West Region as designated by the
Office of the Interconnection in the PJM Manuals, relevant to provision of, and
requirement for, spinning reserve service.



1.41B Standing Committees.



“Standing Committees” shall mean the Members
Committee, the committees established and maintained under Section 8.6, and such
other committees as the Members Committee may establish and maintain from time
to time.



1.42 State.



“State” shall mean the District of Columbia and
any State or Commonwealth of the United States.



1.42.01 State Certification.



“State Certification” shall mean the Certification
of an Authorized Commission, pursuant to Section 18 of this Agreement, the form
of which is appended to this Agreement as Schedule 10A, wherein the Authorized
Commission identifies all Authorized Persons employed or retained by such
Authorized Commission, a copy of which shall be filed with FERC.



1.42A State Consumer Advocate.



“State Consumer Advocate” shall mean a
legislatively created office from any State, all or any part of the territory of
which is within the PJM Region, and the District of Columbia established,
inter alia, for the purpose of representing the interests of energy
consumers before the utility regulatory commissions of such states and the
District of Columbia and the FERC.



1.43 System.



“System” shall mean the interconnected electric
supply system of a Member and its interconnected subsidiaries exclusive of
facilities which it may own or control outside of the PJM Region. Each Member
may include in its system the electric supply systems of any party or parties
other than Members which are within the PJM Region, provided its interconnection
agreements with such other party or parties do not conflict with such inclusion.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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    First
      Revised Original Sheet No. 24AThird Revised Rate Schedule FERC No.
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    Superseding Original Sheet No. 24A




1.43A Third Party Request.



“Third Party Request” shall mean any request or
demand by any entity upon an Authorized Person or an Authorized Commission for
release or disclosure of confidential information provided to the Authorized
Person or Authorized Commission by the Office of the Interconnection or PJM
Market Monitor. A Third Party Request shall include, but shall not be limited
to, any subpoena, discovery request, or other request for confidential
information made by any: (i) federal, state, or local governmental subdivision,
department, official, agency or court, or (ii) arbitration panel, business,
company, entity or individual.



1.44 Transmission Facilities.



“Transmission Facilities” shall mean facilities
that: (i) are within the PJM Region; (ii) meet the definition of transmission
facilities pursuant to FERC’s Uniform System of Accounts or have been classified
as transmission facilities in a ruling by FERC addressing such facilities; and
(iii) have been demonstrated to the satisfaction of the Office of the
Interconnection to be integrated with the transmission system of the PJM Region
and integrated into the planning and operation of such to serve all of the power
and transmission customers within such region.



1.45 Transmission Owner.



“Transmission Owner” shall mean a Member that owns
or leases with rights equivalent to ownership Transmission Facilities. Taking
transmission service shall not be sufficient to qualify a Member as a
Transmission Owner.



1.46 [Reserved.]



1.47 User Group.



“User Group” shall mean a group formed pursuant to
Section 8.7 of this Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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    Third
      Revised Sheet No. 25Third Revised Rate Schedule FERC No.
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    Superseding First Revised Sheet No. 25




1.48 Voting Member.



“Voting Member” shall mean (i) a Member as to
which no other Member is an Affiliate or Related Party, or (ii) a Member
together with any other Members as to which it is an Affiliate or Related Party.



1.49 Weighted Interest.



“Weighted Interest” shall be equal to (0.1(1/N) +
0.5(B/C) + 0.2(D/E) + 0.2(F/G)), where:



N =
    the total
      number of Members excluding ex officio Members and State Consumer
      Advocates (which, for purposes of Section 15.2 of this agreement, shall be
      calculated as of five o’clock p.m. Eastern Time on the date PJM declares a
      Member in default)




B =
    the Member’s
      internal peak demand for the previous calendar year (which, for Load
      Serving Entities under the Reliability Assurance Agreement, shall be that
      used to calculate Accounted For Obligation as determined by the Office of
      the Interconnection pursuant to Schedule 7 of the Reliability Assurance
      Agreement averaged over the previous calendar year)




C =
    the sum of
      factor B for all Members




D =
    the Member’s
      generating capability from Capacity Resources located in the PJM Region as
      of January 1 of the current calendar year, determined by the Office of the
      Interconnection pursuant to Schedule 9 of the Reliability Assurance
      Agreement or Schedule 9 of the West Reliability Assurance Agreement,
      respectively




E =
    the sum of
      factor D for all Members




F =
    the sum of
      the Member’s circuit miles of transmission facilities multiplied by the
      respective operating voltage for facilities 100 kV and above as of January
      1 of the current calendar year




G =
    the sum of
      factor F for all Members




1.50 West Transmission Owner.



“West Transmission Owner” shall mean a
Transmission Owner that has executed the West Transmission Owners Agreement.



1.51 West Transmission Owners Agreement.



“West Transmission Owners’ Agreement” shall mean
that certain “West Transmission Owners’ Agreement,” dated March 13, 2001, as it
may be amended hereafter.



1.52 Zone



“Zone” shall mean an area within the PJM Region,
as set forth in Attachment J to the PJM Tariff.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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2. FORMATION, NAME; PLACE OF BUSINESS



2.1 Formation of LLC; Certificate of Formation.



The Members of the LLC hereby:



(a) acknowledge the conversion of the PJM
Interconnection Association into the LLC, a limited liability company pursuant
to the Act, by virtue of the filing of both the Certificate of Formation and the
Certificate of Conversion with the Recording Office, effective as of March 31,
1997;



(b) confirm and agree to their status as Members
of the LLC;



(c) enter into this Agreement for the purpose of
amending and restating the rights, duties, and relationship of the Members; and



(d) agree that if the laws of any jurisdiction in
which the LLC transacts business so require, the PJM Board also shall file, with
the appropriate office in that jurisdiction, any documents necessary for the LLC
to qualify to transact business under such laws; and (ii) agree and obligate
themselves to execute, acknowledge, and cause to be filed for record, in the
place or places and manner prescribed by law, any amendments to the Certificate
of Formation as may be required, either by the Act, by the laws of any
jurisdiction in which the LLC transacts business, or by this Agreement, to
reflect changes in the information contained therein or otherwise to comply with
the requirements of law for the continuation, preservation, and operation of the
LLC as a limited liability company under the Act.



2.2 Name of LLC.



The name under which the LLC shall conduct its
business is “PJM Interconnection, L.L.C.”



2.3 Place of Business.



The location of the principal place of business of
the LLC shall be 955 Jefferson Avenue, Valley Forge Corporate Center,
Norristown, Pennsylvania 19403-2497. The LLC may also have offices at such other
places both within and without the State of Delaware as the PJM Board may from
time to time determine or the business of the LLC may require.



2.4 Registered Office and Registered Agent.



The street address of the initial registered
office of the LLC shall be 1209 Orange Street, Wilmington, Delaware 19801, and
the LLC’s registered agent at such address shall be The Corporation Trust
Company. The registered office and registered agent may be changed by resolution
of the PJM Board.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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    Third
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    Superseding Second Revised Sheet No. 27




3. PURPOSES AND POWERS OF LLC



3.1 Purposes.



The purposes of the LLC shall be:



(a) to operate in accordance with FERC
requirements as an Independent System Operator, comprised of the PJM Board, the
Office of the Interconnection, and the Members Committee, with the authorities
and responsibilities set forth in this Agreement;



(b) as necessary for the operation of the PJM
Region as specified above: (i) to acquire and obtain licenses, permits and
approvals, (ii) to own or lease property, equipment and facilities, and (iii) to
contract with third parties to obtain goods and services, provided that, the LLC
may procure goods and services from a Member only after open and competitive
bidding; and



(c) to engage in any lawful business permitted by
the Act or the laws of any jurisdiction in which the LLC may do business and to
enter into any lawful transaction and engage in any lawful activities in
furtherance of the foregoing purposes and as may be necessary, incidental or
convenient to carry out the business of the LLC as contemplated by this
Agreement.



3.2 Powers.



The LLC shall have the power to do any and all
acts and things necessary, appropriate, advisable, or convenient for the
furtherance and accomplishment of the purposes of the LLC, including, without
limitation, to engage in any kind of activity and to enter into and perform
obligations of any kind necessary to or in connection with, or incidental to,
the accomplishment of the purposes of the LLC, so long as said activities and
obligations may be lawfully engaged in or performed by a limited liability
company under the Act.



4. EFFECTIVE DATE AND TERMINATION



4.1
    Effective
      Date and Termination.




(a) The existence of the LLC commenced on March
31, 1997, as provided in the Certificate of Formation and Certificate of
Conversion which were filed with the Recording Office on March 31, 1997. This
Agreement shall amend and restate the Operating Agreement of PJM
Interconnection, LLC as of the Effective Date.



(b) The LLC shall continue in existence until
terminated in accordance with the terms of this Agreement. The withdrawal or
termination of any Member is subject to the provisions of Section 18.18 of this
Agreement.



(c) Any termination of this Agreement or
withdrawal of any Member from the Agreement shall be filed with the FERC
pursuant to Section 205 of the Federal Power Act and shall become effective only
upon the FERC’s approval, acceptance without suspension, or, if suspended, the
expiration of the suspension period before the FERC has issued an order on the
merits of the filing.



4.2
    Governing
      Law.




This Agreement and all questions with respect to
the rights and obligations of the Members, the construction, enforcement and
interpretation hereof, and the formation, administration and



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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termination of the LLC shall be governed by the provisions of the Act and
other applicable laws of the State of Delaware, and the Federal Power Act.



5. WORKING CAPITAL AND CAPITAL CONTRIBUTIONS



5.1
    Funding
      of Working Capital and Capital Contributions.




(a) The Office of the Interconnection shall
attempt to obtain financing of up to twenty-five percent (25%) of the approved
annual operating budget of the LLC adopted by the PJM Board pursuant to Section
7.5.2 of this Agreement to meet the working capital needs of the LLC, which
shall be limited to such working capital needs that arise from timing in cash
flows from interchange accounting, tariff administration and payment of the
operating costs of the Office of the Interconnection. Such financing, which
shall be non-recourse to the Members of the LLC and which shall be for a stated
term without penalty for prepayment, may be obtained by borrowing the amount
required at market-based interest rates, negotiated on an arm’s length basis,
(i) from a Member or Members or (ii) from a commercial lender, supported, if
necessary, by credit enhancements provided by a Member or Members; provided,
however, no Member shall be obligated to provide such financing or credit
enhancements. The LLC shall make such filings and seek such approvals as
necessary in order for the principal, interest and fees related to any such
borrowing to be repaid through charges under the PJM Tariff as appropriate under
Schedule 3 of this Agreement.



(b) In the event financing of the working capital
needs of the Office of the Interconnection is unavailable on commercially
reasonable terms, the PJM Board may require the Members to contribute capital in
the aggregate up to five million two hundred thousand dollars ($5,200,000) for
the working capital needs that could not be financed; provided that in such
event each Member’s obligation to contribute additional capital shall be in
proportion to its Weighted Interest, multiplied by the amount so requested by
the PJM Board. Each Member that contributes such capital shall be entitled to
earn a return on the contribution to the extent such contribution has not been
repaid, which return shall be at a fair market rate as determined by the PJM
Board but in no event less than the current interest rate established pursuant
to 18 C.F.R. § 35.19a(a)(2)(iii); provided further, that any Member not
wanting to contribute the requested capital contribution may withdraw from the
LLC upon 90 days written notice as provided in Section 18.18.2 of this
Agreement.



(c) Authority to borrow capital for LLC
Operations. Nothing in Section 5.1(a) and (b) shall be construed to restrict the
authority of the PJM Board to authorize the LLC to borrow or raise capital in
excess of twenty-five percent of the approved annual operating budget of the
LLC, for working capital or otherwise, as the PJM Board deems appropriate to
fund the operations of the LLC, in accordance with the general powers of the LLC
under Section 3.2 to enter into obligations of any kind to accomplish the
purposes of the LLC. Nor shall anything in Section 5.1(a) and (b) in any way
restrict the authority of the PJM Board to authorize the LLC to grant to lenders
such security interests or other rights in assets or revenues received under the
PJM Tariff with respect to the costs of operating the LLC and the Office of the
Interconnection and to take such other actions as it deems necessary and
appropriate to obtain such financing in accordance with such general powers of
the LLC under Section 3.2.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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    Original
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      24




5.2 Contributions to Association.



All contributions prior to the Effective Date of
the original Operating Agreement of PJM Interconnection, L.L.C. of cash or other
assets to the PJM Interconnection Association by persons who are now or in the
future may become Members of the LLC shall be deemed contributions by such
Members to the LLC.



6. TAX STATUS AND DISTRIBUTIONS



6.1
    Tax
      Status.




The LLC shall make all necessary filings under the
applicable Treasury Regulations to have the LLC taxed as a corporation.



6.2
    Return of
      Capital Contributions.




(a) In the event Members are required to
contribute capital to the LLC in accordance with Section 5.1 herein, the LLC
shall request the Transmission Owners to recover such working capital through
charges under the PJM Tariff as provided in Schedule 3 of this Agreement. In the
event all or a portion of the working capital is recovered pursuant to the PJM
Tariff, such amount(s) shall be returned to the Members in accordance with their
actual contributions.



(b) Except for return of capital contributions and
liquidating distributions as provided in the foregoing section and Section 6.3
herein, respectively, the LLC does not intend to make any distributions of cash
or other assets to its Members.



6.3
    Liquidating Distribution.




Upon termination or liquidation of the LLC, the
cash or other assets of the LLC shall be distributed as follows:



(a) first, in the event the LLC has any
liabilities at the time of its termination or dissolution, the LLC shall
liquidate such of its assets as is necessary to satisfy such liabilities;



(b) second, any capital contribution in cash or in
kind by any Member of the PJM Interconnection Association prior to the Effective
Date shall be distributed by the LLC back to such Member in the form received by
the PJM Interconnection Association; and



(c) third, any remaining assets of the LLC shall
be distributed to the Members in proportion to their Weighted Interests.



7. PJM BOARD



7.1
    Composition.




There shall be an LLC Board of Managers, referred
to herein as the “PJM Board,” composed of nine voting members, with the
President as a non-voting member. The nine voting Board Members shall be elected
by the Members Committee. A Nominating Committee, consisting of one
representative elected annually from each sector of the Members Committee



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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    First
      Revised Sheet No. 30Third Revised Rate Schedule FERC No.
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    Superseding Original Sheet No. 30




established under Section 8.1 and three voting Board Members (provided
that one such Board Member shall serve only as a non-voting member of the
Nominating Committee), shall retain an independent consultant, which shall be
directed to prepare a list of persons qualified and willing to serve on the PJM
Board. Not later than 30 days prior to each Annual Meeting of the Members, the
Nominating Committee shall distribute to the representatives on the Members
Committee one nominee from among the list proposed by the independent consultant
for each vacancy or expiring term on the PJM Board, along with information on
the background and experience of the nominees appropriate to evaluating their
fitness for service on the PJM Board; provided, however, that the Nominating
Committee in its discretion may nominate, without retaining an independent
consultant, a Board member whose term is expiring and who desires to serve an
additional term. Elections for the PJM Board shall be held at each Annual
Meeting of the Members, for the purpose of selecting the initial PJM Board in
accordance with the provisions of Section 7.3(a), or selecting a person to fill
the seat of a Board Member whose term is expiring. Should the Members Committee
fail to elect a full PJM Board from the nominees proposed by the Nominating
Committee, then the Nominating Committee shall propose a further nominee from
the list prepared by the independent consultant (or a replacement consultant)
for each remaining vacancy on the PJM Board for consideration by the Members at
the next regular meeting of the Members Committee.



7.2 Qualifications.



A Board Member shall not be, and shall not have
been at any time within five years of election to the PJM Board, a director,
officer or employee of a Member or of an Affiliate or Related Party of a Member.
Except as provided in the LLC’s Standards of Conduct filed with the FERC, at any
time while serving on the PJM Board, a Board Member shall have no direct
business relationship or other affiliation with any Member or its Affiliates or
Related Parties. Of the nine Board Members, four shall have expertise and
experience in the areas of corporate leadership at the senior management or
board of directors level, or in the professional disciplines of finance or
accounting, engineering, or utility laws and regulation, one shall have
expertise and experience in the operation or concerns of transmission dependent
utilities, one shall have expertise and experience in the operation or planning
of transmission systems, and one shall have expertise and experience in the area
of commercial markets and trading and associated risk management.



7.3 Term of Office.



(a) The persons serving as the Board of Managers
of the LLC immediately prior to the Effective Date shall continue in office
until the first Annual Meeting of the Members. At the first Annual Meeting of
the Members, the then current members of the PJM Board who desire to continue in
office shall be elected by the Members to serve until the second Annual Meeting
of the Members or until their successors are elected, along with such additional
persons as necessary to meet the composition requirements of Section 7.1 and the
qualification requirements of Section 7.2.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    Original
      Sheet No. 30AThird Revised Rate Schedule FERC No.
      24




(b) A Board Member shall serve for a term of three
years commencing with the Annual Meeting of the Members at which the Board
Member was elected; provided, however, that two of the Board Members elected at
the first Annual Meeting of the Members following the Effective Date shall be
chosen by lot to serve a term of one year, three of such Board Members shall be
chosen by lot to serve a term of two years and the final two such Board Members
shall serve a term of three years; provided further, however, that the initial
term of one of the two Board Members elected to fill one of the two new Board
seats added in 2003 shall be chosen by lot to serve a term



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    First
      Revised Sheet No. 31Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 31




of four years and the initial term of the other Board Member elected to
fill the other new Board seat added in 2003 shall serve a term of five years.



(c) Vacancies on the PJM Board occurring between
Annual Meetings of the Members shall be filled by vote of the then remaining
Board Members; a Board Member so selected shall serve until the next Annual
Meeting at which time a person shall be elected to serve the balance of the term
of the vacant Board Seat. Removal of a Board Member shall require the approval
of the Members Committee.



7.4 Quorum.



The presence in person or by telephone or other
authorized electronic means of a majority of the voting Board Members shall
constitute a quorum at all meetings of the PJM Board for the transaction of
business except as otherwise provided by statute. If a quorum shall not be
present, the Board Members then present shall have the power to adjourn the
meeting from time to time, until a quorum shall be present. Provided a quorum is
present at a meeting, the PJM Board shall act by majority vote of the Board
Members present.



7.5
    Operating
      and Capital Budgets.




7.5.1 Finance Committee.



Not later than June 1 of each year, the entities
specified below shall select the members of a Finance Committee. The Finance
Committee shall be composed of one representative elected annually from each
sector of the Members Committee as defined in section 8.1, one representative of
the Office of the Interconnection selected by the President, and two Board
Members selected by the PJM Board. The Office of the Interconnection shall
prepare annual operating and capital budgets in accordance with processes and
procedures established by the PJM Board, and shall timely submit its budgets to
the Finance Committee for review. The Finance Committee shall submit its
analysis of and recommendations on the budgets to the PJM Board, with copies to
the Members Committee. The Finance Committee shall also review and comment upon
any additional or amended budgets prepared by the Office of the Interconnection
at the request of the PJM Board or the Members Committee.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    Second
      Revised Sheet No. 32Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 32




7.5.2  Adoption of Budgets.



The PJM Board shall adopt, upon consideration of
the advice and recommendations of the Finance Committee, operating and capital
budgets for the LLC, and shall distribute to the Members for their information
final annual budgets for the following fiscal year not later than 60 days prior
to the beginning of each fiscal year of the LLC.



7.6 By-laws.



To the extent not inconsistent with any provision
of this Agreement, the PJM Board shall adopt such by-laws establishing
procedures for the implementation of this Agreement as it may deem appropriate,
including but not limited to by-laws governing the scheduling, noticing and
conduct of meetings of the PJM Board, selection of a Chair and Vice Chair of the
PJM Board, action by the PJM Board without a meeting, and the organization and
responsibilities of standing and special committees of the PJM Board. Such
by-laws shall not modify or be inconsistent with any of the rights or
obligations established by this Agreement.



7.7 Duties and Responsibilities of the PJM
Board.



In accordance with this Agreement, the PJM Board
shall supervise and oversee all matters pertaining to the PJM Region and the
LLC, and carry out such other duties as are herein specified, including but not
limited to the following duties and responsibilities:



i)
    As its
      primary responsibility, ensure that the President, the other officers of
      the LLC, and Office of the Interconnection perform the duties and
      responsibilities set forth in this Agreement, including but not limited to
      those set forth in Sections 9.2 through 9.4 and Section 10.4 in a manner
      consistent with (A) the safe and reliable operation of the PJM Region, (B)
      the creation and operation of a robust, competitive, and
      non-discriminatory electric power market in the PJM Region, and (C) the
      principle that a Member or group of Members shall not have undue influence
      over the operation of the PJM Region;




ii)
    Select the
      Officers of the LLC;




iii)
    Adopt
      budgets for the LLC;




iv)
    Approve the
      Regional Transmission Expansion Plan in accordance with the provisions of
      the Regional Transmission Expansion Planning Protocol set forth in
      Schedule 6 of this Agreement;




v)
    On its own
      initiative or at the request of a User Group as specified herein, submit
      to the Members Committee such proposed amendments to this Agreement or any
      Schedule hereto, or a proposed new Schedule, as it may deem appropriate;




vi)
    Petition FERC to modify
      any provision of this Agreement or any Schedule or practice hereunder that
      the PJM Board believes to be unjust, unreasonable, or unduly
      discriminatory under section 206 of the Federal




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Fifth
      Revised Sheet No. 33Third Revised Rate Schedule FERC No.
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    Superseding Fourth Revised Sheet No. 33




Power Act, subject to the right of
      any Member or the Members to intervene in any resulting proceedings;




vii)
    Review for
      consistency with the creation and operation of a robust, competitive and
      non-discriminatory electric power market in the PJM Region any change to
      rate design or to non-rate terms and conditions proposed by Transmission
      Owners for filing under section 205 of the Federal Power Act;




viii)
    If and to
      the extent it shall deem appropriate, intervene in any proceeding at FERC
      initiated by the Members in accordance with Section 11.5(b), and
      participate in other state and federal regulatory proceedings relating to
      the interests of the LLC;




ix)
    Review, in
      accordance with Section 15.1.3, determinations of the Office of the
      Interconnection with respect to events of default;




x)
    Assess
      against the other Members in proportion to their Default Allocation
      Assessment an amount equal to any payment to the Office of the
      Interconnection, including interest thereon, as to which a Member is in
      default;




xi)
    Establish
      reasonable sanctions for failure of a Member to comply with its
      obligations under this Agreement;




xii)
    Direct the
      Office of the Interconnection on behalf of the LLC to take appropriate
      legal or regulatory action against a Member (A) to recover any unpaid
      amounts due from the Member to the Office of the Interconnection under
      this Agreement and to make whole any Members subject to an assessment as a
      result of such unpaid amount, or (B) as may otherwise be necessary to
      enforce the obligations of this Agreement;




xiii)
    [Reserved.]




xiv)
    [Reserved.]




xv)
    Solicit the views of
      Members on, and commission from time to time as it shall deem appropriate
      independent reviews of, (a) the performance of the PJM Interchange Energy
      Market, (b) compliance by Market Participants with the rules and
      requirements of the PJM Interchange Energy Market, and




Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2005Vice President, Government
    PolicyIssued On:
    
    November 1, 2004




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    Superseding Original Sheet No. 34




(c) the performance of the Office of the
      Interconnection under performance criteria proposed by the Members
      Committee and approved by the PJM Board; and




xvi)
    Terminate a
      Member as may be appropriate under the terms of this Agreement.




8. MEMBERS COMMITTEE



8.1 Sectors.



8.1.1
    Designation.




Voting on the Senior Standing Committees shall be
by sectors. The Senior Standing Committee shall be composed of five sectors, one
for Generation Owners, one for Other Suppliers, one for Transmission Owners, one
for Electric Distributors, and one for End-Use Customers, provided that there
are at least five Members in each Sector. Except as specified in Section 8.1.2,
each Voting Member shall have one vote. Each Voting Member shall, within thirty
(30) days after the Effective Date or, if later, thirty (30) days after becoming
a Member, and thereafter not later than 10 days prior to the Annual Meeting of
the Members for each annual period beginning with the Annual Meeting of the
Members, submit to the President a sealed notice of the sector in which it is
qualified to vote or, if qualified to participate in more than one sector, its
rank order preference of the sectors in which it wishes to vote, and shall be
assigned to its highest-ranked sector that has the minimum number of Members
specified above. If a Member is assigned to a sector other than its
highest-ranked sector in accordance with the preceding sentence, its higher
sector preference or preferences shall be honored as soon as a higher-ranked
sector has five or more Members. A Voting Member may designate as its voting
sector any sector for which it or its Affiliate or Related Party Members is
qualified. The sector designations of the Voting Members shall be announced by
the Office of the Interconnection at the Annual Meeting and shall apply to all
Senior Standing Committees.



8.1.2
    Related
      Parties.




The Members in a group of Related Parties shall
each be entitled to a vote, provided that all the Members in a group of Related
Parties that chooses to exercise such rights shall be assigned to the Electric
Distributor sector.



8.2 Representatives.



8.2.1
    Appointment.




Each Member may appoint one representative to
serve on each of the Standing Committees, potentially a different person for
each committee, with authority to act for that Member with respect to actions or
decisions thereof. Each Member may appoint up to three alternate representatives
to each such committee to act for that Member at meetings thereof in the absence
of the representative. A Member participating in the PJM Interchange Energy
Market through an agent may be represented on the Standing Committee by that
agent. A Member shall appoint its representatives and alternates by giving
written notice thereof to the Office of the Interconnection. Members that are
Affiliates or Related Parties may each appoint a representative and alternate
representatives to each of the Standing Committees, but shall vote on Senior
Standing Committees as specified in Section 8.1.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    Superseding First Revised Sheet No. 35




8.2.2 Regulatory Authorities.



FERC and any other federal agency with regulatory
authority over a Member and each State electric utility regulatory commission
with regulatory jurisdiction within the PJM Region, may nominate one
representative to serve as an ex officio non-voting member on each of the
Standing Committees.



8.2.3 State Offices of Consumer Advocate.



(a) Each State Consumer Advocate may nominate one
representative to serve as an ex officio member on each of the Standing
Committees. Upon a written request by a State Consumer Advocate to the Office of
the Interconnection, and upon the payment of the fee prescribed by section (b)
of Schedule 3 to this Agreement, a State Consumer Advocate may designate a
representative to each of the Standing Committees who, subject to subparagraph
b, shall be entitled to cast one (1) non-divisible vote in the End-Use Customer
Sector in Senior Standing Committees. As an ex officio member, a State
Consumer Advocate shall have no liability under this Agreement, other than the
annual fee required by Schedule 3. The State Consumer Advocates shall not be
entitled to indemnification by the other Members under any provisions of this
Agreement. Additionally, the State Consumer Advocates shall not be eligible to
participate in any markets managed by PJM under the terms contained in this
Agreement.



(b) Each State Consumer Advocate shall be entitled
to cast only one (1) vote in the Senior Standing Committees per State or the
District of Columbia. If more than one representative from a given state has
been nominated to be a voting member of the Senior Standing Committees, all
State Offices of Consumer Advocate from such state that have nominated
representatives to vote at the Senior Standing Committees shall designate to the
Office of the Interconnection one (1) representative who shall be entitled to
vote on all of their behalf’s, prior to being permitted to vote at any meetings
of the Senior Standing Committees.



8.2.4 Initial Representatives.



Initial representatives to the Members Committee
shall be appointed no later than 30 days after the Effective Date; provided,
however, that each representative to the Management Committee under the
Operating Agreement of PJM Interconnection, L.L.C. as in effect immediately
prior to the Effective Date shall automatically become a representative to the
Members Committee on the Effective Date unless replaced as specified in Section
8.2.5. An entity becoming a Member shall appoint a representative to each
Standing Committee no later than 30 days after becoming a Member.



8.2.5 Change of or Substitution for a
Representative.



Any Member may change its representative or
alternate on the Standing Committees at any time by providing written notice to
the Office of the Interconnection identifying its replacement representative or
alternate. Any representative to the Standing Committees may, by written notice
to the applicable Chair, designate a substitute representative from that Member
to act for him or her with respect to any matter specified in such notice.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 36Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 36




8.3 Meetings.



8.3.1 Regular and Special Meetings.



The Standing Committees shall hold regular
meetings, no less frequently than once each calendar quarter at such time and at
such place as shall be fixed by the Chair thereof. The Members Committee may
adopt bylaws, including rules of procedure, governing its meetings and
activities and the meetings and activities of the other Standing Committees, and
other committees, subcommittees, task forces, working groups and other bodies
under its auspices. The Members Committee shall hold an Annual Meeting of the
Members each calendar year at such time and place as shall be specified by the
Chair. At the Annual Meeting of the Members, Board Members as necessary shall be
elected. The Standing Committees may hold special meetings for one or more
designated purposes within the scope of the authority of the applicable
committee when called by the Chair on the Chair’s own initiative, or at the
request of five or more representatives on the applicable committee. The notice
of a regular or special meeting shall be distributed to the representatives as
specified in Section 18.14 of this Agreement not later than seven days prior to
the meeting, shall state the time and place of the meeting, and shall include an
agenda sufficient to notify the representatives of the substance of matters to
be considered at the meeting; provided, however, that meetings may be called on
shorter notice at the discretion of the Chair as the Chair shall deem necessary
to deal with an emergency or to meet a deadline for action.



8.3.2 Attendance.



Regular and special meetings may be conducted in
person or by telephone, or other electronic means as authorized by the Members
Committee. The attendance in person or by telephone or other electronic means of
a representative or a duly designated substitute shall be required in order to
vote.



8.3.3 Quorum.



The attendance as specified in Section 8.3.2 of a
majority of the Voting Members from each of at least three sectors that each
have at least five Members shall constitute a quorum at any meeting of the
Members Committee; however, a quorum shall only require one-third of the Voting
Members, but not less than ten, from any sector that has more than 20 Voting
Members. No action may be taken by the Members Committee at a meeting unless a
quorum is present; provided, however, that if a quorum is not present, the
Voting Members then present shall have the power to adjourn the meeting from
time to time until a quorum shall be present. A quorum shall not be required to
conduct a meeting of any Committee other than the Members Committee; however,
the Chair of any committee other than the Members Committee, in his discretion,
may declare adjourned any meeting which fewer than ten Members attend.



8.4 Manner of Acting.



(a) The procedures for the conduct of meetings of
the Standing Committees may be stated in bylaws adopted by the Members
Committee.



(b) In a Senior Standing Committee, each Sector
shall be entitled to cast one and zero one-hundredths (1.00) Sector Votes. Each
Voting Member shall be entitled to cast one (1) non-divisible vote in its
sector. In the case of a Voting Member comprised of Affiliates or Related
Parties, any representative, alternate or substitute of any of the Affiliated or
Related Parties may cast the vote of the Voting Member. The Sector Vote of each
sector shall be split into an affirmative component based on votes for the
pending motion, and a negative component based on votes against the pending
motion, in direct



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    First
      Revised Sheet No. 37Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 37




proportion to the votes cast within the sector for and against the
pending motion, rounded to two decimal places.



(c) The sum of affirmative Sector Votes necessary
to pass a pending motion in a Senior Standing Committee shall be greater than
(but not merely equal to) the product of .667 multiplied by the number of
sectors that have at least five Members and that participated in the vote;
provided, however, that the sum of the affirmative Sector Votes necessary to
pass a motion to elect a Board Member or to elect the Chair or Vice Chair of the
Members Committee shall be greater than (but not merely equal to) the product of
..5 multiplied by the number of sectors that have at least five Members and that
participated in the vote.



(d) Voting Members not in attendance at the
meeting as specified in Section 8.3.2 of this Agreement or abstaining shall not
be counted as affirmative or negative votes.



8.5 Chair and Vice Chair of the Members
Committee.



8.5.1 Selection and Term.



The representatives or their alternates or
substitutes on the Members Committee shall elect from among the representatives
a Chair and a Vice Chair. The offices of Chair and Vice Chair shall be held for
a term of one year. The terms shall commence at the last regular meeting of the
Members Committee each calendar year and end at the last regular meeting of the
Members Committee of the following calendar year or until succession to the
office occurs as specified herein. Except as specified below, at the last
regular meeting of the Members Committee each calendar year, the Vice Chair
shall succeed to the office of Chair, and a new Vice Chair shall be elected. If
the office of Chair becomes vacant, or the Chair leaves the employment of the
Member for whom the Chair is the representative, or the Chair is no longer the
representative of such Member, the Vice Chair shall succeed to the office of
Chair, and a new Vice Chair shall be elected at the next regular or special
meeting of the Members Committee, both such officers to serve until the last
regular meeting of the Members Committee of the calendar year following such
succession or election to a vacant office. If the office of Vice Chair becomes
vacant, or the Vice Chair leaves the employment of the Member for whom the Vice
Chair is the representative, or the Vice Chair is no longer the representative
of such Member, a new Vice Chair shall be elected at the next regular or special
meeting of the Members Committee.



Notwithstanding the foregoing, the Chair and Vice
Chair whose terms commenced on May 1, 2003, shall hold their offices until the
last regular meeting of the Members Committee in 2004, and there shall not be an
election of a new Vice Chair at the last regular meeting of the Members
Committee in 2003.



8.5.2 Duties.



The Chair shall call and preside at meetings of
the Members Committee, and shall carry out such other responsibilities as the
Members Committee shall assign. The Chair shall cause minutes of each meeting of
the Members Committee to be taken and maintained, and shall cause notices of
meetings of the Members Committee to be distributed. The Vice Chair shall
preside at meetings of the Members Committee in the absence of the Chair, and
shall otherwise act for the Chair at the Chair’s request.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    First
      Revised Sheet No. 37AThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 37A




8.6 Senior, Standing, and Other Committees.



The Members Committee shall establish and maintain
the Electricity Markets Committee and Reliability Committee as Senior Standing
Committees. The Members Committee also shall establish and maintain the Market
Implementation Committee (under the Electricity Markets Committee), and Planning
Committee and Operating Committee (both under the Reliability Committee) as
Standing Committees. The Members Committee may establish or dissolve other
Standing Committees from time to time. The President shall appoint the Chair and
Vice Chair of each Senior Standing Committee and Standing Committee and, after
consultation with the Chair of a Standing Committee, the President shall appoint
the Chair and Vice Chair of any other committees.



8.6.1Electricity Markets Committee.
The Electricity Markets Committee shall provide advice and recommendations
concerning the operation of the PJM Interchange Energy Market and Ancillary
Services markets and otherwise as directed by the Members Committee. Voting on
the Electricity Markets Committee shall be by sectors in accordance with
Sections 8.1 and 8.4 of this Agreement. The responsibilities of the Electricity
Markets Committee shall, more specifically, include, but not be limited to, the
following:



(a) The Electricity Markets Committee shall
develop and approve an annual plan including prioritization of planned
activities and initiation of activities supporting the approved plan.



(b) The Electricity Markets Committee shall
provide advice and recommendations concerning issues pertaining to the operation
and administration of the PJM markets, including but not limited to amendments
to this Agreement, the PJM Tariff, or market rules and procedures as necessary
or appropriate to foster competition and assure the fair, reliable and efficient
operation and administration of the PJM markets.



(c) The Electricity Markets Committee shall
provide advice and recommendations as are necessary or appropriate to assure a
high level of economy of service in the operation of the PJM Interchange Energy
Market and other markets, in accordance with established market operation
principles, practices and procedures, recognizing individual participant
requirements for services, contractual obligations and other pertinent factors.



(d) The Electricity Markets Committee shall
provide advice and recommendations concerning studies and analyses relating to
the overall efficacy of the PJM Interchange Energy Market and in carrying out
actions as may be initiated as a result thereof.



(e) The Electricity Markets Committee shall
provide direction to the Market Implementation Committee, which committee shall
report to the Electricity Markets Committee. The Market Implementation Committee
shall provide advice and recommendations to the Electricity Markets Committee
directed to the advancement and promotion of competitive wholesale electricity
markets in the PJM Region, and perform such other functions as the Electricity
Markets Committee may direct from time to time.



(f) The Electricity Markets Committee shall
perform such other functions, directly or through delegation to a Standing
Committee, subcommittee, working group or task force reporting thereto, as the
Members Committee may direct.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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      Sheet No. 37BThird Revised Rate Schedule FERC No.
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(g) The Electricity Markets Committee shall create
subcommittees, working groups or task forces as and when necessary to assist in
performing the duties of the Electricity Markets Committee.



8.6.2 Reliability Committee.



The Reliability Committee addresses matters
related to the reliable and secure operation of the PJM system and planning
strategies to assure the continued ability of the Members to operate reliably
and economically, consistent with applicable reliability principles and
standards. The Reliability Committee coordinates with the Electricity Markets
Committee on mechanisms to provide an efficient marketplace for products needed
for resource adequacy and operating security. Voting on the Reliability
Committee shall be by sectors in accordance with Sections 8.1 and 8.4 of this
Agreement. Neither the Reliability Committee nor the Members Committee shall
have authority to control or direct the actions of the PJM Board or the Office
of the Interconnection with regard to the short-term reliability of grid
operations within the PJM Region. The responsibilities of the Reliability
Committee shall, more specifically, include, but not be limited to, the
following:



(a) The Reliability Committee shall develop and
approve an annual plan including prioritization of planned activities and
initiation of activities supporting the approved plan.



(b) The Reliability Committee shall provide advice
and recommendations concerning revisions to this Agreement, the Reliability
Assurance Agreement, the Reliability Assurance Agreement-West, and the PJM
Tariff that pertain to its areas of responsibility.



(c) The Reliability Committee shall make annual
and timely recommendations concerning the generating capacity reserve
requirement and related demand-side valuation factors for consideration by the
Members Committee, in order to assist the Members Committee in making
recommendations to the PJM Board.



(d) The Reliability Committee shall provide
direction to the Operating Committee and Planning Committee, which committees
shall report to the Reliability Committee. The Operating Committee shall advise
the Reliability Committee and the Office of the Interconnection on matters
pertaining to the reliable and secure operation of the PJM Region and other
matters as the Reliability Committee may request. The Planning Committee shall
advise the Reliability Committee and the Office of the Interconnection on
matters pertaining to system reliability, security, economy of service, and
planning strategies and policies and other matters as the Reliability Committee
may request.



(e) The Reliability Committee shall perform such
other functions, directly or through delegation to a Standing Committee,
subcommittee, working group or task force reporting thereto, as the Members
Committee may direct.



(f) The Reliability Committee shall create
subcommittees, working groups or task forces as and when appropriate to assist
in performing the duties of the Reliability Committee.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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      24




8.6.3 Other Committees and Bodies. The
Standing Committees may form, select the membership, and oversee the activities,
of such other committees, subcommittees, task forces, working groups or other
bodies as it shall deem appropriate, to provide advice and recommendations to
the Standing Committees or Office of the Interconnection. Each such group shall
terminate automatically upon completion of its assigned tasks and, if not
terminated, shall terminate two years after formation unless reauthorized by the
Standing Committee that directed its formation.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    First
      Revised Sheet No. 38Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 38




8.6.4 Alternate Dispute Resolution Committee.The Members Committee shall elect representatives to the Alternate Dispute
Resolution Committee as specified in the PJM Dispute Resolution Procedures.



8.7 User Groups.



(a) Any five or more Members sharing a common
interest may form a User Group, and may invite such other Members to join the
User Group as the User Group shall deem appropriate. Notification of the
formation of a User Group shall be provided to all members of the Members
Committee.



(b) The Members Committee shall create a User
Group composed of representatives of bona fide public interest and
environmental organizations that are interested in the activities of the LLC and
are willing and able to participate in such a User Group.



(c) Meetings of User Groups shall be open to all
Members and the Office of the Interconnection. Notices and agendas of meetings
of a User Group shall be provided to all Members that ask to receive them.



(d) Any recommendation or proposal for action
adopted by affirmative vote of three-fourths or more of the members of a User
Group shall be submitted to the Chair of the Members Committee. The Chairman
shall refer the matter for consideration by the applicable Standing Committee as
appropriate for consideration at that Committee’s next regular meeting,
occurring not earlier than 30 days after the referral, for a recommendation to
the Members Committee for consideration at its next regular meeting.



(e) If the Members Committee does not adopt a
recommendation or proposal submitted by a User Group, upon vote of nine-tenths
or more of the members of the User Group the recommendation or proposal may be
submitted to the PJM Board for its consideration in accordance with Section
7.7(v).



8.8 Powers of the Members Committee.



The Members Committee, acting by adoption of a
motion as specified in Section 8.4, shall have the power to take the actions
specified in this Agreement, including:



i)
    Elect the
      members of the PJM Board;




ii)
    In
      accordance with the provisions of Section 18.6 of this Agreement, amend
      any portion of this Agreement, including the Schedules hereto, or create
      new Schedules, and file any such amendments or new Schedules with FERC or
      other regulatory body of competent jurisdiction;




iii)
    Adopt bylaws
      that are consistent with this Agreement, as amended or restated from time
      to time;




Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    Original
      Sheet No. 38AThird Revised Rate Schedule FERC No.
      24




iv)
    Terminate
      this Agreement; and




v)
    Provide
      advice and recommendations to the PJM Board and the Office of the
      Interconnection.




9. OFFICERS



9.1 Election and Term.



The officers of the LLC shall consist of a
President, a Secretary and a Treasurer. The PJM Board may elect such other
officers as it deems necessary to carry out the business of the LLC. All
officers shall be elected by the PJM Board and shall hold office until the next
annual meeting of the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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    Original
      Sheet No. 39Third Revised Rate Schedule FERC No.
      24




PJM Board and until their successors are elected. Any number of offices
may be held by the same person, except that the offices of the President and
Treasurer may not be held by the same person.



9.2 President.



The PJM Board shall appoint a President and Chief
Executive Officer of the LLC (the “President”). The President shall direct and
supervise the day-to-day operation of the LLC, and shall report to the PJM
Board. The President shall be responsible for directing and supervising the
Office of the Interconnection in the performance of the duties and
responsibilities specified in Section 10.4. The President shall execute bonds,
mortgages and other contracts requiring a seal, under the seal of the LLC,
except where required or permitted by law to be otherwise signed and executed
and except where the signing and execution thereof shall be expressly delegated
by the board to some other officer or agent of the LLC. In the absence of the
President or in the event of his or her inability or refusal to act, and if a
vice president has been appointed by the PJM Board, the Vice President (or in
the event there be more than one Vice President, the Vice Presidents in the
order designated by the PJM Board in its Minutes) shall perform the duties of
the President, and when so acting, shall have all the powers of and be subject
to all the restrictions upon the President. The Vice President shall perform
such other duties and have such other powers as the PJM Board may from time to
time prescribe.



9.3 Secretary.



The Secretary shall attend all meetings of the PJM
Board and record all the proceedings of the meetings of the PJM Board in a
minute book to be kept for that purpose and shall perform like duties for the
standing committees or special committees when required. He or she shall give,
or cause to be given, notice of all special meetings of the PJM Board, and shall
perform such other duties as may be prescribed by the PJM Board or President,
under whose supervision he or she shall be. He or she shall have custody of the
corporate seal of the LLC, and he or she, or an assistant secretary, shall have
authority to affix the same to any instrument requiring it and, when so affixed,
it may be attested by his or her signature or by the signature of such assistant
secretary. The PJM Board may give general authority to any other officer to
affix the seal of the LLC and to attest the affixing by his or her signature.



9.4 Treasurer.



The Treasurer shall have or arrange for the
custody of the LLC’s funds and securities and shall keep full and accurate
accounts of receipts and disbursements in books belongings to the LLC and shall
deposit all moneys and other valuable effects in the name and to the credit of
the LLC in such depositories as may be designated by the PJM Board. The
Treasurer shall disburse the funds of the LLC as may be ordered by the PJM
Board, taking proper vouchers for such disbursements, and shall render to the
President and PJM Board at its regular meetings, or when the PJM Board so
requires, an account of his or her transactions as Treasurer and of the
financial condition of the LLC. If required by the Board, the Treasurer shall
give the LLC a bond (which shall be renewed periodically) in such sum and with
such surety or sureties as shall be satisfactory to the PJM Board for the
faithful performance of the duties of his office and of the restoration to the
LLC, in case of his or her death, resignation, retirement or removal from
office, of all books, papers, vouchers, money and other property of whatever
kind in his or her possession or under his or her control belonging to the LLC.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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    Second
      Revised Sheet No. 40Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 40




9.5 Renewal of Officers; Vacancies.



Any officer elected or appointed by the PJM Board
may be removed at any time by the affirmative vote of a majority of the PJM
Board eligible to vote. Any vacancy occurring in any office of the LLC shall be
filled by the PJM Board.



9.6 Compensation.



The salaries of all officers and agents of the
LLC, and the reasonable compensation of the PJM Board, shall be fixed by the PJM
Board.



10. OFFICE OF THE INTERCONNECTION



10.1 Establishment.



The Office of the Interconnection shall implement
this Agreement, administer the PJM Tariff, and undertake such other
responsibilities as set forth herein. All personnel of the Office of the
Interconnection shall be employees of the LLC or under contract thereto. The
cost of the Office of the Interconnection and expenses associated therewith,
including salaries and expenses of said personnel, space and any necessary
facilities or other capital expenditures, shall be recovered in accordance with
Schedule 3. The Office of the Interconnection shall adopt, publish and comply
with standards of conduct that satisfy the regulations of FERC.



10.2 Processes and Organization.



In order to carry out the responsibilities of the
Office of the Interconnection for the safe and reliable operation of the PJM
Region, the President may establish processes and organization for operating
personnel and facilities as the President shall deem appropriate, and shall
request such Members as the President shall deem appropriate to participate in
such processes and organization. All such processes and organization shall be
carried out in accordance with all applicable code of conduct or other
functional separation requirements of FERC.



10.3 Confidential Information.



The Office of the Interconnection shall comply
with the requirements of Section 18.17 with respect to any proprietary or
confidential information received from or about any Member.



10.4 Duties and Responsibilities.



The Office of the Interconnection, under the
direction of the President as supervised and overseen by the PJM Board, shall
carry out the following duties and responsibilities, in accordance with the
provisions of this Agreement:



i)
    Administer
      and implement this Agreement;




ii)
    Perform such
      functions in furtherance of this Agreement as the PJM Board, acting within
      the scope of its duties and responsibilities under this Agreement, may
      direct;




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Substitute Fifth Revised Sheet No. 41Third Revised Rate Schedule FERC No.
      24
    
    
    
    Superseding Fifth Revised Sheet No. 41




iii)
    Prepare,
      maintain, update and disseminate the PJM Manuals;




iv)
    Comply with
      NERC, and Applicable Regional Reliability Council operation and planning
      standards, principles and guidelines;




v)
    Maintain an
      appropriately trained workforce, and such equipment and facilities,
      including computer hardware and software and backup power supplies, as
      necessary or appropriate to implement or administer this Agreement;




vi)
    Direct the
      operation and coordinate the maintenance of the facilities of the PJM
      Region used for both load and reactive supply, so as to maintain
      reliability of service and obtain the benefits of pooling and interchange
      consistent with this Agreement, the Reliability Assurance Agreement, and
      the Reliability Assurance Agreement-West;




vii)
    Direct the
      operation and coordinate the maintenance of the bulk power supply
      facilities of the PJM Region with such facilities and systems of others
      not party to this Agreement in accordance with agreements between the LLC
      and such other systems to secure reliability and continuity of service and
      other advantages of pooling on a regional basis;




viii)
    Perform
      interchange accounting and maintain records pertaining to the operation of
      the PJM Interchange Energy Market and the PJM Region;




ix)
    Notify the
      Members of the receipt of any application to become a Member, and of the
      action of the Office of the Interconnection on such application, including
      but not limited to the completion of integration of a new Member’s system
      into the PJM Region, as specified in Section 11.6(f);




x)
    Calculate
      the Weighted Interest and Default Allocation Assessment of each Member;




xi)
    Maintain
      accurate records of the sectors in which each Voting Member is entitled to
      vote, and calculate the results of any vote taken in the Members
      Committee;




xii)
    Furnish
      appropriate information and reports as are required to keep the Members
      regularly informed of the outlook for, the functioning of, and results
      achieved by the PJM Region;




xiii)
    File with
      FERC on behalf of the Members any amendments to this Agreement or the
      Schedules hereto, any new Schedules hereto, and make any other regulatory
      filings on behalf of the Members or the LLC necessary to implement this
      Agreement;




xiv)
    At the
      direction of the PJM Board, submit comments to regulatory authorities on
      matters pertinent to the PJM Region;




Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2005Vice President, Governmental
      PolicyIssued On:
    
    January 27, 2005




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    Second
      Revised Sheet No. 42Third Revised Rate Schedule FERC No.
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    Superseding Fifth Revised Sheet No. 42




xv)
    Consult with
      the standing or other committees established pursuant to Section 8.6(a) on
      matters within the responsibility of the committee;




xvi)
    Perform
      operating studies of the bulk power supply facilities of the PJM Region
      and make such recommendations and initiate such actions as may be
      necessary to maintain reliable operation of the PJM Region;




xvii)
    Accept, on
      behalf of the Members, notices served under this Agreement;




xviii)
    Perform those functions and undertake those responsibilities
      transferred to it under the East Transmission Owners Agreement and West
      Transmission Owners Agreement, including (A) direct the operation of the
      transmission facilities of the parties to the East Transmission Owners
      Agreement (B) direct the operation of the transmission facilities of the
      Parties to the West Transmission Owners Agreement, (C) administer the PJM
      Tariff, and (D) administer the Regional Transmission Expansion Planning
      Protocol set forth as Schedule 6 to this Agreement;




xix)
    Perform
      those functions and undertake those responsibilities transferred to it
      under the Reliability Assurance Agreement, as specified in Schedule 8 of
      this Agreement, and those functions and responsibilities transferred to it
      under the Reliability Assurance Agreement-West, as specified in Schedule
      8A of this Agreement;




xx)
    Monitor the
      operation of the PJM Region, ensure that appropriate Emergency plans are
      in place and appropriate Emergency drills are conducted, declare the
      existence of an Emergency, and direct the operations of the Members as
      necessary to manage, alleviate or end an Emergency;




xxi)
    Incorporate
      the grid reliability requirements applicable to nuclear generating units
      in the PJM Region planning and operating principles and practices; and




xxii)
    Initiate
      such legal or regulatory proceedings as directed by the PJM Board to
      enforce the obligations of this Agreement.




11. MEMBERS



11.1 Management Rights.



The Members or any of them shall not take part in
the management of the business of, and shall not transact any business for, the
LLC in their capacity as Members, nor shall they have power to sign for or to
bind the LLC.



11.2 Other Activities.



Except as otherwise expressly provided herein, any
Member may engage in or possess any interest in another business or venture of
any nature and description, independently or with others, even if such
activities compete directly with the business of the LLC, and neither the LLC
nor any Member hereof shall have any rights in or to any such independent
ventures or the income or profits derived therefrom.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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    First
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      24
    
    Superseding Second Revised Sheet No. 43




11.3 Member Responsibilities.



11.3.1 General.



To facilitate and provide for the work of the
Office of the Interconnection and of the several committees appointed by the
Members Committee, each Member shall, to the extent applicable;



(a) Maintain adequate records and, subject to the
provisions of this Agreement for the protection of the confidentiality of
proprietary or commercially sensitive information, provide data required for (i)
coordination of operations, (ii) accounting for all interchange transactions,
(iii) preparation of required reports, (iv) coordination of planning, including
those data required for capacity accounting under the Reliability Assurance
Agreement and Reliability Assurance Agreement-West; (v) preparation of
maintenance schedules, (vi) analysis of system disturbances, and (vii) such
other purposes, including those set forth in Schedule 2, as will contribute to
the reliable and economic operation of the PJM Region;



(b) Provide such recording, telemetering, revenue
quality metering, communication and control facilities as are required for the
coordination of its operations with the Office of the Interconnection and those
of the other Members and to enable the Office of the Interconnection to operate
the PJM Region and otherwise implement and administer this Agreement, including
equipment required in normal and Emergency operations and for the recording and
analysis of system disturbances;



(c) Provide adequate and properly trained
personnel to (i) permit participation in the coordinated operation of the PJM
Region, (ii) meet its obligation on a timely basis for supply of records and
data, (iii) serve on committees and participate in their investigations, and
(iv) share in the representation of the Interconnection in inter-regional and
national reliability activities;



(d) Share in the costs of committee activities and
investigations (including costs of consultants, computer time and other
appropriate items), communication facilities used by all the Members (in
addition to those provided in the Office of the Interconnection), and such other
expenses as are approved for payment by the PJM Board, such costs to be
recovered as provided in Schedule 3;



(e) Comply with the requirements of the PJM
Manuals and all directives of the Office of the Interconnection to take any
action for the purpose of managing, alleviating or ending an Emergency, and
authorize the Office of the Interconnection to direct the transfer or
interruption of the delivery of energy on their behalf to meet an Emergency and
to implement agreements with other Control Areas interconnected with the PJM
Region for the mutual provision of service to meet an Emergency, and be subject
to the emergency procedure charges specified in Schedule 9 of this Agreement for
any failure to follow the Emergency instructions of the Office of the
Interconnection.



11.3.2 Facilities Planning and Operation.



Consistent with and subject to the requirements of
this Agreement, the PJM Tariff, the governing agreements of the Applicable
Regional Reliability Councils, the Reliability Assurance Agreement, the
Reliability Assurance Agreement-West, the West Transmission Owners Agreement,
the East Transmission Owners Agreement, and the PJM Manuals, each Member shall



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1,
    2004Vice President, Government
    PolicyIssued On:
    
    August 31,
      2004




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    Third
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    Superseding First Revised Sheet No. 44




cooperate with the other Members in the
coordinated planning and operation of the facilities of its System within the
PJM Region so as to obtain the greatest practicable degree of reliability,
compatible economy and other advantages from such coordinated planning and
operation. In furtherance of such cooperation each Member shall, as applicable:



(a) Consult with the other Members and the Office
of the Interconnection, and coordinate the installation of its electric
generation and Transmission Facilities with those of such other Members so as to
maintain reliable service in the PJM Region;



(b) Coordinate with the other Members, the Office
of the Interconnection and with others in the planning and operation of the
regional facilities to secure a high level of reliability and continuity of
service and other advantages;



(c) Cooperate with the other Members and the
Office of the Interconnection in the implementation of all policies and
procedures established pursuant to this Agreement for dealing with Emergencies,
including but not limited to policies and procedures for maintaining or
arranging for a portion of a Member’s Capacity Resources, at least equal to the
applicable levels established from time to time by the Office of the
Interconnection, to have the ability to go from a shutdown condition to an
operating condition and start delivering power without assistance from the power
system;



(d) Cooperate with the members of Applicable
Regional Reliability Councils to augment the reliability of the bulk power
supply facilities of the region and comply with Applicable Regional Reliability
Councils and NERC operating and planning standards, principles and guidelines
and the PJM Manuals;



(e) Obtain or arrange for transmission service as
appropriate to carry out this Agreement;



(f) Cooperate with the Office of the
Interconnection’s coordination of the operating and maintenance schedules of the
Member’s generating and Transmission Facilities with the facilities of other
Members to maintain reliable service to its own customers and those of the other
Members and to obtain economic efficiencies consistent therewith;



(g) Cooperate with the other Members and the
Office of the Interconnection in the analysis, formulation and implementation of
plans to prevent or eliminate conditions that impair the reliability of the PJM
Region; and



(h) Adopt and apply standards adopted pursuant to
this Agreement and conforming to NERC, and Applicable Regional Reliability
Council standards, principles and guidelines and the PJM Manuals, for system
design, equipment ratings, operating practices and maintenance practices.



11.3.3 Electric Distributors.



In addition to any of the foregoing
responsibilities that may be applicable, each Member that is an Electric
Distributor, whether or not that Member votes in the Members Committee in the
Electric Distributor sector or meets the eligibility requirements for any other
sector of the Members Committee, shall:



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1,
  2004Vice President, Government
    PolicyIssued On:
    
    April 30,
    2004




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 45Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 45




(a) Accept, comply with or be compatible with all
standards applicable within the PJM Region with respect to system design,
equipment ratings, operating practices and maintenance practices as set forth in
the PJM Manuals, or be subject to an interconnected Member’s requirements
relating to the foregoing, so that sufficient electrical equipment, control
capability, information and communication are available to the Office of the
Interconnection for planning and operation of the PJM Region;



(b) Assure the continued compatibility of its
local system energy management system monitoring and telecommunications systems
to satisfy the technical requirements of interacting automatically or manually
with the Office of the Interconnection as it directs the operation of the PJM
Region;



(c) Maintain or arrange for a portion of its
connected load to be subject to control by automatic underfrequency,
under-voltage, or other load-shedding devices at least equal to the levels
established pursuant to the Reliability Assurance Agreement and Reliability
Assurance Agreement-West, as applicable, or be subject to another Member’s
control for these purposes;



(d) Provide or arrange for sufficient reactive
capability and voltage control facilities to conform to Good Utility Practice
and (i) to meet the reactive requirements of its system and customers and (ii)
to maintain adequate voltage levels and the stability required by the bulk power
supply facilities of the PJM Region;



(e) Shed connected load, share Capacity Resources,
initiate active load management programs, and take such other coordination
actions as may be necessary in accordance with the directions of the Office of
the Interconnection in Emergencies;



(f) Maintain or arrange for a portion of its
Capacity Resources at least equal to the level established pursuant to the
Reliability Assurance Agreement to have the ability to go from a shutdown
condition to an operating condition and start delivering power without
assistance from the power system;



(g) Provide or arrange through another Member for
the services of a 24-hour local control center to coordinate with the Office of
the Interconnection, each such control center to be furnished with appropriate
telemetry equipment as specified in the PJM Manuals, and to be staffed by system
operators trained and delegated sufficient authority to take any action
necessary to assure that the system for which the operator is responsible is
operated in a stable and reliable manner;



(h) Provide to the Office of the Interconnection
all System, accounting, customer tracking, load forecasting (including all load
to be served from its System) and other data necessary or appropriate to
implement or administer this Agreement, the Reliability Assurance Agreement and
the Reliability Assurance Agreement-West; and



(i) Comply with the underfrequency relay
obligations and charges specified in Schedule 7 of this Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1,
  2004Vice President, Government
    PolicyIssued On:
    
    April 30,
    2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 46Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 46




11.3.4 Reports to the Office of the
Interconnection.



Each Member shall report as promptly as possible
to the Office of the Interconnection any changes in its operating practices and
procedures relating to the reliability of the bulk power supply facilities of
the PJM Region. The Office of the Interconnection shall review such reports, and
if any change in an operating practice or procedure of the Member is not in
accord with the established operating principles, practices and procedures for
the PJM Region and such change adversely affects such region and regional
reliability, it shall so inform such Member, and the other Members through their
representative on the Operating Committee, and shall direct that such change be
modified to conform to the established operating principles, practices and
procedures.



11.4 Regional Transmission Expansion Planning
Protocol.



The Members shall participate in regional
transmission expansion planning in accordance with the Regional Transmission
Expansion Planning Protocol set forth in Schedule 6 to this Agreement.



11.5 Member Right to Petition.



(a) Nothing herein shall deprive any Member of the
right to petition FERC to modify any provision of this Agreement or any Schedule
or practice hereunder that the petitioning Member believes to be unjust,
unreasonable, or unduly discriminatory under section 206 of the Federal Power
Act, subject to the right of any other Member (a) to oppose said proposal, or
(b) to withdraw from the LLC pursuant to Section 4.1.



(b) Nothing herein shall be construed as affecting
in any way the right of the Members, acting pursuant to a vote of the Members
Committee as specified in Section 8.4, unilaterally to make an application to
FERC for a change in any rate, charge, classification, tariff or service, or any
rule or regulation related thereto, under section 205 of the Federal Power Act
and pursuant to the rules and regulations promulgated by FERC thereunder,
subject to the right of any Member that voted against such change in any rate,
charge, classification, tariff or service, or any rule or regulation related
thereto, in intervene in opposition to any such application.



11.6 Membership Requirements.



(a) To qualify as a Member, an entity shall:



i) Be a Transmission Owner a Generation Owner, an
Other Supplier, an Electric Distributor, or an End-Use Customer; and



ii) Accept the obligations set forth in this
Agreement.



(b) Certain Members that are Load Serving Entities
are parties to the Reliability Assurance Agreement or Reliability Assurance
Agreement-West. Upon becoming a Member, any entity that is a Load Serving Entity
in the PJM Control Area and that wishes to become a Market Buyer shall also
simultaneously execute the Reliability Assurance Agreement. Any entity that is a



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 47Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 47




Load Serving Entity in the PJM West Region and that wishes to become a
Market Buyer shall also simultaneously execute the Reliability Assurance
Agreement-West.



(c) An entity that wishes to become a party to
this Agreement shall apply, in writing, to the President setting forth its
request, its qualifications for membership, its agreement to supply data as
specified in this Agreement, its agreement to pay all costs and expenses in
accordance with Schedule 3, and providing all information specified pursuant to
the Schedules to this Agreement for entities that wish to become Market
Participants. Any such application that meets all applicable requirements shall
be approved by the President within sixty (60) days.



(d) Nothing in this Section 11 is intended to
remove, in any respect, the choice of participation by other utility companies
or organizations in the operation of the PJM Region through inclusion in the
System of a Member.



(e) An entity whose application is accepted by the
President pursuant to Section 11.6(c) shall execute a supplement to this
Agreement in substantially the form prescribed in Schedule 4, which supplement
shall be countersigned by the President. The entity shall become a Member
effective on the date the supplement is countersigned by the President.



(f) Entities whose applications contemplate
expansion or rearrangement of the PJM Region may become Members promptly as
described in Sections 11.6(c) and 11.6(e) above, but the integration of the
applicant’s system into all of the operation and accounting provisions of this
Agreement and the Reliability Assurance Agreement, or, as applicable, the
Reliability Assurance Agreement-West, shall occur only after completion of all
required installations and modifications of metering, communications, computer
programming, and other necessary and appropriate facilities and procedures, as
determined by the Office of the Interconnection. The Office of the
Interconnection shall notify the other Members when such integration has
occurred.



(g) Entities that become Members will be listed in
Schedule 12 of this Agreement.



(h) In accordance with the MAAC Agreement, a
Member serving load in the MAAC Control Zone shall be a member of MAAC and any
other Member may be a member of MAAC.



12. TRANSFERS OF MEMBERSHIP INTEREST



The rights and obligations created by this
Agreement shall inure to and bind the successors and assigns of such Member;
provided, however, that the rights and obligations of any Member hereunder shall
not be assigned without the approval of the Members Committee except as to a
successor in operation of a Member’s electric operating properties by reason of
a merger, consolidation, reorganization, sale, spinoff, or foreclosure, as a
result of which substantially all such electric operating properties are
acquired by such a successor, and such successor becomes a Member.



13. INTERCHANGE



13.1 Interchange Arrangements with Non-Members.



Any Member may enter into interchange arrangements
with others that are not Members with respect to the delivery or receipt of
capacity and energy to fulfill its obligations hereunder or for any other
purpose, subject to the standards and requirements established in or pursuant to
this Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 48Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 48




13.2 Energy Market.



The Office of the Interconnection shall administer
an efficient energy market within the PJM Region, to be known as the PJM
Interchange Energy Market, in which Members may buy and sell energy. The Office
of the Interconnection will schedule in advance and dispatch generation on the
basis of least-cost, security-constrained dispatch and the prices and operating
characteristics offered by sellers within and into the PJM Region, continuing
until sufficient generation is dispatched to serve the energy purchase
requirements of such region and buyers out of such region, as well as the
requirements of the PJM Region for ancillary services provided by such
generation. Scheduling and dispatch shall be conducted in accordance with
applicable schedules to the PJM Tariff and the Schedules to this Agreement.



14. METERING



14.1 Installation, Maintenance and Reading of
Meters.



The quantities of electric energy involved in
determination of the amounts of the billing rendered hereunder shall be
ascertained by means of meters installed, maintained and read either at the
expense of the party on whose premises the meters are located or as otherwise
provided for by agreement between the parties concerned.



14.2 Metering Procedures.



Procedures with respect to maintenance, testing,
calibrating, correction and registration records, and precision tolerance of all
metering equipment shall be in accordance with Good Utility Practice. The
expense of testing any meter shall be borne by the party owning such meter,
except that when a meter tested upon request of another party is found to
register within the established tolerance the party making the request shall
bear the expense of such test.



14.3 Integrated Megawatt-Hours.



All metering of energy required herein shall be
the integration of megawatt hours in the clock hour, and the quantities thus
obtained shall constitute the megawatt load for such clock hour; provided,
however, that adjustment shall be made for other contractual obligations of any
Member as may be required to determine the quantity to be accounted for
hereunder, and for transmission losses.



14.4 Meter Locations.



The meter locations to be used by the Members in
determining their energy transactions on the PJM Region shall be as reasonably
determined from time to time by the Member or the Office of the Interconnection.



14.5 Metering of Behind The Meter Generation.



Behind The Meter Generation consisting of one or
more generating units individually rated at ten megawatts or greater or that
otherwise have been identified by the Office of the Interconnection as requiring
metering for operational security reasons must have both revenue quality
metering and telemetry equipment for operational security purposes. Behind The
Meter Generation consisting of multiple generating units that are individually
rated less than ten megawatts but together total more than ten megawatts and are
identified by the Office of the Interconnection as requiring revenue quality
metering and telemetry equipment may meet these metering requirements by being
metered as a single unit.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2004Vice President, Government
    PolicyIssued On:
    
    March 1, 2004




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    First
      Revised Sheet No. 49Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 49




15. ENFORCEMENT OF OBLIGATIONS



15.1 Failure to Meet Obligations.



15.1.1 Termination of Market Buyer Rights.



The Office of the Interconnection shall terminate
a Market Buyer’s right to make purchases from the PJM Interchange Energy Market,
the PJM Capacity Credit Market or any other market operated by PJM if it
determines that the Market Buyer does not continue to meet the obligations set
forth in this Agreement, including but not limited to the obligation to be in
compliance with PJM’s creditworthiness requirements and the obligation to make
timely payment, provided that the Office of the Interconnection has notified the
Market Buyer of any such deficiency and afforded the Market Buyer a reasonable
opportunity to cure pursuant to Section 15.1.3. The Office of the
Interconnection shall reinstate a Market Buyer’s right to make purchases from
the PJM Interchange Energy Market and PJM Capacity Credit Market upon
demonstration by the Market Buyer that it has come into compliance with the
obligations set forth in this Agreement.



15.1.2 Termination of Market Seller Rights.



The Office of the Interconnection shall not accept
offers from a Market Seller that has not complied with the prices, terms, or
operating characteristics of any of its prior scheduled transactions in the PJM
Interchange Energy Market, unless such Market Seller has taken appropriate
measures to the satisfaction of the Office of the Interconnection to ensure
future compliance.



15.1.3 Payment of Bills.



(a) A Member shall make full and timely payment,
in accordance with the terms specified by the Office of the Interconnection, of
all bills rendered in connection with or arising under or from this Agreement,
any service or rate schedule, any tariff, or any services performed by the
Office of the Interconnection, notwithstanding any disputed amount, but any such
payment shall not be deemed a waiver of any right with respect to such dispute.
With respect to any payment that the LLC is required to make to a Member in
connection with or arising under this Agreement, any service or rate schedule,
or any tariff, the LLC shall have a right of setoff equal to any amount that the
Member is required to pay the LLC in connection with or arising under or from
this Agreement, any service or rate schedule, any tariff, or any services
performed by the Office of the Interconnection. Any Member that fails to make
full and timely payment to the LLC, or otherwise fails to meet its financial or
other obligations to a Member, the Office of the Interconnection or the LLC
under this Agreement, shall, in addition to any requirement set forth in
Sections 15.1.1 and 15.1.2 and upon expiration of the 3-day period specified
below be in default. If the Office of the Interconnection concludes, upon its
own initiative or the recommendation of or complaint by the Members Committee or
any Member, that a Member is in breach of any obligation under this Agreement,
including, but not limited to, the obligation to make timely payment and the
obligation to meet PJM’s creditworthiness standards and to otherwise comply with
PJM’s credit policies, the Office of the Interconnection shall so notify such
Member and inform all other Members. The



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




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    Third
      Revised Sheet No. 50Third Revised Rate Schedule FERC No.
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    Superseding First Revised Sheet No. 50




notified Member may remedy such asserted breach
by: (i) paying all amounts assertedly due, along with interest on such amounts
calculated in accordance with the methodology specified for interest on refunds
in FERC’s regulations at 18 C.F.R. § 35.19a(a)(2)(iii); and (ii) demonstration
to the satisfaction of the Office of the Interconnection that the Member has
taken appropriate measures to meet any other obligation of which it was deemed
to be in breach; provided, however, that any such payment or demonstration may
be subject to a reservation of rights, if any, to subject such matter to the PJM
Dispute Resolution Procedures; and provided, further, that any such
determination by the Office of the Interconnection may be subject to review by
the PJM Board upon request of the Member involved or the Office of the
Interconnection. If a Member has not remedied a breach by the 3rd business day
following receipt of the Office of the Interconnection’s notice, or receipt of
the PJM Board’s decision on review, if applicable, then the Member shall be in
default and, in addition to such other remedies as may be available to the LLC:



i)
    A defaulting
      Market Participant shall be precluded from buying or selling in the PJM
      Interchange Energy Market, the PJM Capacity Credit Market, or any other
      market operated by PJM until the default is remedied as set forth above;




ii)
    A defaulting
      Member shall not be entitled to participate in the activities of any
      committee or other body established by the Members Committee or the Office
      of the Interconnection; and




iii)
    A defaulting
      Member shall not be entitled to vote on the Members Committee or any other
      committee or other body established pursuant to this Agreement.




15.2 Enforcement of Obligations.



If the Office of the Interconnection sends a
notice to the PJM Board that a Member has failed to perform an obligation under
this Agreement, the PJM Board shall initiate such action against such Member to
enforce such obligation as the PJM Board shall deem appropriate. Subject to the
procedures specified in Section 15.1, a Member’s failure to perform such
obligation shall be deemed to be a default under this Agreement. In order to
remedy a default, but without limiting any rights the LLC may have against the
defaulting Member, the PJM Board may assess against, and collect from, the
Members not in default, in proportion to their Default Allocation Assessment, an
amount equal to the amount that the defaulting Member has failed to pay to the
Office of the Interconnection, along with appropriate interest. Such assessment
shall in no way relieve the defaulting Member of its obligations. A Member that
has paid such an assessment to the LLC shall have an independent right to seek
and obtain payment and recovery from the defaulting Member of the amount of the
assessment the Member paid to the LLC. In addition to any amounts in default,
the defaulting Member shall be liable to the LLC for all reasonable costs
incurred in enforcing the defaulting Member’s obligations.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2005Vice President, Government
    PolicyIssued On:
    
    November 1, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 51Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 51




15.2.1 Collection by the Office of the
Interconnection.



By vote at any Members Committee meeting, a
majority of the Members that have paid a Default Allocation Assessment may
request and appoint the Office of the Interconnection to act as agent on behalf
of the Members that have paid a Default Allocation Assessment, solely for the
purpose of pursuing and collecting any amounts so assessed; provided, however,
that any Member that does not desire for the Office of the Interconnection to
act on their behalf with regard to such collection shall so inform the Office of
the Interconnection. In the event that the Office of the Interconnection is
appointed as agent for the Members, the Office of the Interconnection shall be
authorized to pursue collection through such actions, legal or otherwise, as it
reasonably deems appropriate, including but not limited to the prosecution of
legal actions and assertion of claims on behalf of the affected Members in the
state and federal courts as well as under the United States Bankruptcy Code;
provided, however, that the Office of the Interconnection shall take no action
on behalf of those Members that have requested that the Office of the
Interconnection not act on their behalf. After deducting the costs of
collection, any amounts recovered by the Office of the Interconnection on behalf
of the affected Members shall be distributed to the Members who have paid their
Default Allocation Assessment in proportion to the Default Allocation Assessment
paid by each Member except those Members who informed the Office of the
Interconnection that it should not act as their agent.



15.2.2 Default Allocation Assessment.



(a) “Default Allocation Assessment” shall be equal
to (0.1(1/N) + 0.9(A/Z)), where:



N = the total number of Members, calculated as of
five o’clock p.m. eastern prevailing time on the date PJM declares a Member in
default, excluding ex officioMembers, State Consumer Advocates,
Emergency and Economic Load Response Program Special Members, and municipal
electric system Members that have been granted a waiver under section 17.2 of
this Agreement.



A = for Members comprising factor “N” above, the
Member’s gross activity as determined by summing the absolute values of the
charges and credits for each of the Activity Line Items identified in section
15.2.2(b) of this Agreement as accounted for and billed pursuant to section 3 of
Schedule 1 of this Agreement for the month of default and the two previous
months.



Z = the sum of factor A for all Members excluding
ex officioMembers, State Consumer Advocates, Emergency and Economic Load
Response Program Special Members, and municipal electric system Members that
have been granted a waiver under section 17.2 of this Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2005Vice President, Government
    PolicyIssued On:
    
    November 1, 2004




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PJM Interconnection, L.L.C.
    
    Substitute First Revised Sheet No. 51AThird Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 51A




The assessment value of (0.1(1/N)) shall not
exceed $10,000 per Member per calendar year, cumulative of all defaults. If one
or more defaults arise that cause the value to exceed $10,000 per Member, then
the excess shall be reallocated through the gross activity factor.



(b) Activity Line Items shall be each of the line
items on the PJM monthly bills net of load reconciliation adjustments and
adjustments applicable to activity for the current billing month appearing on
the same bill.



15.3 Obligations to a Member in Default.



The Members have no continuing obligation to
provide the benefits of interconnected operations to a Member in default.



15.4 Obligations of a Member in Default.



A Member found to be in default shall take all
possible measures to mitigate the continued impact of the default on the Members
not in default, including, but not limited to, loading its own generation to
supply its own load to the maximum extent possible.



15.5 No Implied Waiver.



A failure of a Member, the PJM Board, or the LLC
to insist upon or enforce strict performance of any of the provisions of this
Agreement shall not be construed as a waiver or relinquishment to any extent of
such entity’s right to assert or rely upon any such provisions, rights and
remedies in that or any other instance; rather, the same shall be and remain in
full force and effect.



16. LIABILITY AND INDEMNITY



16.1 Members.



(a) As between the Members, except as may be
otherwise agreed upon between individual Members with respect to specified
interconnections, each Member will indemnify and hold harmless each of the other
Members, and its directors, officers, employees, agents, or representatives, of
and from any and all damages, losses, claims, demands, suits, recoveries, costs
and expenses (including all court costs and reasonable attorneys’ fees), caused
by reason of bodily injury, death or damage to property of any third party,
resulting from or attributable to the fault,



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2005Vice President, Government
    PolicyIssued On:
    
    January 27, 2005Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER05-120-000, issued December 28, 2004, 109 FERC ¶
61,366.




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    Original
      Sheet No. 52Third Revised Rate Schedule FERC No.
      24




negligence or willful misconduct of such Member, its directors, officers,
employees, agents, or representatives, or resulting from, arising out of, or in
any way connected with the performance of its obligations under this Agreement,
excepting only, and to the extent, such cost, expense, damage, liability or loss
may be caused by the fault, negligence or willful misconduct of any other
Member. The duty to indemnify under this Agreement will continue in full force
and effect notwithstanding the expiration or termination of this Agreement or
the withdrawal of a Member from this Agreement, with respect to any loss,
liability, damage or other expense based on facts or conditions which occurred
prior to such termination or withdrawal.



(b) The amount of any indemnity payment arising
hereunder shall be reduced (including, without limitation, retroactively) by any
insurance proceeds or other amounts actually recovered by the Member seeking
indemnification in respect of the indemnified action, claim, demand, costs,
damage or liability. If any Member shall have received an indemnity payment for
an action, claim, demand, cost, damage or liability and shall subsequently
actually receive insurance proceeds or other amounts for such action, claim,
demand, cost, damage or liability, then such Member shall pay to the Member that
made such indemnity payment the lesser of the amount of such insurance proceeds
or other amounts actually received and retained or the net amount of the
indemnity payments actually received previously.



16.2 LLC Indemnified Parties.



(a) The LLC will indemnify and hold harmless the
PJM Board, the LLC’s officers, employees and agents, and any representatives of
the Members serving on the Members Committee and any other committee created
under Section 8 of this Agreement (all such Board Members, officers, employees,
agents and representatives for purposes of this Section 16 being referred to as
“LLC Indemnified Parties”), of and from any and all actions, claims, demands,
costs (including consequential or indirect damages, economic losses and all
court costs and reasonable attorneys’ fees) and liabilities to any third
parties, arising from, or in any way connected with, the performance of the LLC
under this Agreement, or the fact that such LLC Indemnified Party was serving in
such capacity, except to the extent that such action, claim, demand, cost or
liability results from the willful misconduct of any LLC Indemnified Party with
respect to participation in the misconduct. To the extent any dispute arises
between any Member and the LLC arising from, or in any way connected with, the
performance of the LLC under this Agreement, the Member and the LLC shall follow
the PJM Dispute Resolution Procedures. To the extent that any such action,
claim, demand, cost or liability arises from a Member’s contractual or other
obligation to provide electric service directly or indirectly to said third
party, which obligation to provide service is limited by the terms of any
tariff, service agreement, franchise, statute, regulatory requirement, court
decision or other limiting provision, the Member designates the LLC and each LLC
Indemnified Party a beneficiary of said limitation.



(b) An LLC Indemnified Party shall not be
personally liable for monetary damages for any breach of fiduciary duty by such
LLC Indemnified Party, except that an LLC Indemnified Party shall be liable to
the extent provided by applicable law (i) for acts or omissions not in good
faith or that involve intentional misconduct or a knowing violation of law, or
(ii) for any transaction from which the LLC Indemnified Party derived an
improper personal benefit. Notwithstanding (i) and (ii), indemnification shall
be made in respect of any claim, issue or matter as to which such person shall
have been adjudged to be liable to the LLC if and to the extent that the court
in which such action or suit was brought shall determine upon application that,
despite the adjudication of liability



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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    Superseding Original Sheet No. 53




but in view of all the circumstances of the case, such person is fairly
and reasonably entitled to indemnity for such expenses that such court shall
deem proper. If applicable law is hereafter construed or amended to authorize
the further elimination or limitation of the liability of LLC Indemnified
Parties, then the liability of the LLC Indemnified Parties, in addition to the
limitation on personal liability provided herein, shall be limited to the
fullest extent permitted by law. No amendment to or repeal of this section shall
apply to or have any effect on the liability or alleged liability of any LLC
Indemnified Party or with respect to any acts or omissions occurring prior to
such amendment or repeal. The termination of any action, suit or proceeding by
judgment, order, settlement, conviction, or upon a plea of nolo
contendere or its equivalent, shall not, of itself, create a presumption
that the person did not act in good faith and in a manner which such person
reasonably believed to be in or not opposed to the best interests of the LLC,
and with respect to any criminal action or proceeding, had reasonable cause to
believe that his or her conduct was unlawful.



(c) The LLC may pay expenses incurred by an LLC
Indemnified Party in defending a civil, criminal, administrative or
investigative action, suit or proceeding in advance of the final disposition of
such action, suit or proceeding upon receipt of an undertaking by or on behalf
of such LLC Indemnified Party to repay such amount if it shall ultimately be
determined that such LLC Indemnified Party is not entitled to be indemnified by
the LLC as authorized in this Section.



(d) In the event the LLC incurs liability under
this Section 16.2 that is not adequately covered by insurance, such amounts
shall be recovered pursuant to the PJM Tariff as provided in Schedule 3 of this
Agreement.



16.3 Workers Compensation Claims.



Each Member shall be solely responsible for all
claims of its own employees, agents and servants growing out of any Workers’
Compensation Law.



16.4 Limitation of Liability.



No Member or its directors, officers, employees,
agents, or representatives shall be liable to any other Member or its directors,
officers, employees, agents, or representatives, whether liability arises out of
contract, tort (including negligence), strict liability, or any other cause of
or form of action whatsoever, for any indirect, incidental, consequential,
special or punitive cost, expense, damage or loss, including but not limited to
loss of profits or revenues, cost of capital of financing, loss of goodwill or
cost of replacement power, arising from such Member’s performance or failure to
perform any of its obligations under this Agreement or the ownership,
maintenance or operation of its System; provided, however, that nothing herein
shall be deemed to reduce or limit the obligations of any Member with respect to
the claims of persons or entities that are not parties to this Agreement.



16.5 Resolution of Disputes.



To the extent any dispute arises between one or
more Members regarding any issue covered by this Agreement, the Members shall
follow the dispute resolution procedures set forth in the PJM Dispute Resolution
Procedures.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Original
      Sheet No. 54Third Revised Rate Schedule FERC No.
      24




16.6 Gross Negligence or Willful Misconduct.



Neither the LLC nor the LLC Indemnified Parties
shall be liable to the Members or any of them for any claims, demands or costs
arising from, or in any way connected with, the performance of the LLC under
this Agreement other than actions, claims or demands based on gross negligence
or willful misconduct; provided, however, that nothing herein shall limit or
reduce the obligations of the LLC to the Members or any of them under the
express terms of this Agreement or the PJM Tariff, including, but not limited
to, those set forth in Sections 6.2 and 6.3 of this Agreement.



16.7 Insurance.



The PJM Board shall be authorized to procure
insurance against the risks borne by the LLC and the LLC Indemnified Parties,
the cost of which shall be treated as a cost and expense of the LLC.



17. MEMBER REPRESENTATIONS, WARRANTIES AND
COVENANTS



17.1 Representations and Warranties.



Each Member makes the following representations
and warranties to the LLC and each other Member, as of the Effective Date or
such later date as such Member shall become admitted as a Member of the LLC.



17.1.1 Organization and Existence.



Such Member is an entity duly organized, validly
existing and in good standing under the laws of the state of its organization.



17.1.2 Power and Authority.



Such Member has the full power and authority to
execute, deliver and perform this Agreement and to carry out the transactions
contemplated hereby.



17.1.3 Authorization and Enforceability.



The execution and delivery of this Agreement by
such Member and the performance of its obligations hereunder have been duly
authorized by all requisite action on the part of the Member, and do not
conflict with any applicable law or with any other agreement binding upon the
Member. The Agreement has been duly executed and delivered by such Member and
constitutes the legal, valid and binding obligation of such Member, enforceable
against it in accordance with the terms thereof, except insofar as such
enforceability may be limited by applicable bankruptcy, insolvency,
reorganization, fraudulent conveyance, moratorium or other similar laws
affecting the enforcement of creditors’ rights generally, and to general
principles of equity whether such principles are considered in proceedings in
law or in equity.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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      24




17.1.4 No Government Consents.



No authorization, consent, approval or order of,
notice to or registration, qualification, declaration or filing with, any
governmental authority is required for the execution, delivery and performance
by such Member of this Agreement or the carrying out by such Member of the
transactions contemplated hereby other than such authorization, consent,
approval or order of, notice to or registration, qualification, declaration or
filing that is pending before such governmental authority.



17.1.5 No Conflict or Breach.



None of the execution, delivery and performance by
such Member of this Agreement, the compliance with the terms and provisions
hereof and the carrying out of the transactions contemplated hereby, conflicts
or will conflict with or will result in a breach or violation of any of the
terms, conditions or provisions of any law, governmental rule or regulation or
the charter documents or bylaws of such Member or any applicable order, writ,
injunction, judgment or decree of any court or governmental authority against
such Member or by which it or any of its properties, is bound, or any loan
agreement, indenture, mortgage, bond, note, resolution, contract or other
agreement or instrument to which such Member is a party or by which it or any of
its properties is bound, or constitutes or will constitute a default thereunder
or will result in the imposition of any lien upon any of its properties.



17.1.6 No Proceedings.



There are no actions at law, suits in equity,
proceedings or claims pending or, to the knowledge of the Member, threatened
against the Member before any federal, state, foreign or local court, tribunal
or government agency or authority that might materially delay, prevent or hinder
the performance by the Member of its obligations hereunder.



17.2 Municipal Electric Systems.



Any provisions of Section 17.1 notwithstanding, if
any Member that is a municipal electric system believes in good faith that the
provisions of Sections 5.1(b) and 16.1 of this Agreement may not lawfully be
applied to that Member under applicable state law governing municipal
activities, the Member may request a waiver of the pertinent provisions of the
Agreement. Any such request for waiver shall be supported by an opinion of
counsel for the Member to the effect that the provision of the Agreement as to
which waiver is sought may not lawfully be applied to the Member under
applicable state law. The PJM Board shall have the right to have the opinion of
the Member’s counsel reviewed by counsel to the LLC. If the PJM Board concludes
that either or both of Sections 5.1(b) and 16.1 of this Agreement may not
lawfully be applied to a municipal electric system Member, it shall waive the
application of the affected provision or provisions to such municipal Member.
Any Member not permitted by law to indemnify the other Members shall not be
indemnified by the other Members.



17.3 Survival.



All representations and warranties contained in
this Section 17 shall survive the execution and delivery of this Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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    Superseding Original Sheet No. 56




18. MISCELLANEOUS PROVISIONS



18.1 [Reserved.]



18.2 Fiscal and Taxable Year.



The fiscal year and taxable year of the LLC shall
be the calendar year.



18.3 Reports.



Each year prior to the Annual Meeting of the
Members, the PJM Board shall cause to be prepared and distributed to the Members
a report of the LLC’s activities since the prior report.



18.4 Bank Accounts; Checks, Notes and Drafts.



(a) Funds of the LLC shall be deposited in an
account or accounts of a type, in form and name and in a bank(s) or other
financial institution(s) which are participants in federal insurance programs as
selected by the PJM Board. The PJM Board shall arrange for the appropriate
conduct of such accounts. Funds may be withdrawn from such accounts only for
bona fide and legitimate LLC purposes and may from time to time be
invested in such short-term securities, money market funds, certificates of
deposit or other liquid assets as the PJM Board deems appropriate. All checks or
demands for money and notes of the LLC shall be signed by any officer or by any
other person designated by the PJM Board.



(b) The Members acknowledge that the PJM Board may
maintain LLC funds in accounts, money market funds, certificates of deposit,
other liquid assets in excess of the insurance provided by the Federal Deposit
Insurance Corporation, or other depository insurance institutions and that the
PJM Board shall not be accountable or liable for any loss of such funds
resulting from failure or insolvency of the depository institution.



(c) Checks, notes, drafts and other orders for the
payment of money shall be signed by such persons as the PJM Board from time to
time may authorize. When the PJM Board so authorizes, the signature of any such
person may be a facsimile.



18.5 Books and Records.



(a) At all times during the term of the LLC, the
PJM Board shall keep, or cause to be kept, full and accurate books of account,
records and supporting documents, which shall reflect, completely, accurately
and in reasonable detail, each transaction of the LLC. The books of account
shall be maintained and tax returns prepared and filed on the method of
accounting determined by the PJM Board. The books of account, records and all
documents and other writings of the LLC shall be kept and maintained at the
principal office of the Interconnection.



(b) The PJM Board shall cause the Office of the
Interconnection to keep at its principal office the following:



i)
    A current
      list in alphabetical order of the full name and last known business
      address of each Member and the Members Committee sector of each Voting
      Member;




Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 1, 2005Vice President, Government
    PolicyIssued On:
    
    November 1, 2004




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ii)
    A copy of
      the Certificate of Formation and the Certificate of Conversion, and all
      Certificates of Amendment thereto;




iii)
    Copies of
      the LLC’s federal, state, and local income tax returns and reports, if
      any, for the three most recent years; and




iv)
    Copies of
      the Operating Agreement, as amended, and of any financial statements of
      the LLC for the three most recent years.




18.6 Amendment.



(a) Except as provided by law or otherwise set
forth herein, this Agreement, including any Schedule hereto, may be amended, or
a new Schedule may be created, only upon: (i) submission of the proposed
amendment to the PJM Board for its review and comments; (ii) approval of the
amendment or new Schedule by the Members Committee, after consideration of the
comments of the PJM Board, in accordance with Section 8.4, or written agreement
to an amendment of all Members not in default at the time the amendment is
agreed upon; and (iii) approval and/or acceptance for filing of the amendment by
FERC and any other regulatory body with jurisdiction thereof as may be required
by law. If and as necessary, the Members Committee may file with FERC or other
regulatory body of competent jurisdiction any amendment to this Agreement or to
its Schedules or a new Schedule not filed by the Office of the Interconnection.



(b) Notwithstanding the foregoing, an applicant
eligible to become a Member in accordance with the procedures specified in this
Agreement shall become a Member by executing a counterpart of this Agreement
without the need for amendment of this Agreement or execution of such
counterpart by any other Member.



(c) Each of the following fundamental changes to
the LLC shall require or be deemed to require an amendment to this Agreement and
shall require the prior approval of FERC:



i)
    Adoption of
      any plan of merger or consolidation;




ii)
    Adoption of
      any plan of sale, lease or exchange of assets relating to all, or
      substantially all, of the property and assets of the LLC;




iii)
    Adoption of
      any plan of division relating to the division of the LLC into two or more
      corporations or other legal entities;




iv)
    Adoption of
      any plan relating to the conversion of the LLC into a stock corporation;




v)
    Adoption of
      any proposal of voluntary dissolution; or




vi)
    Taking any
      action which has the purpose or effect of the adoption of any plan or
      proposal described in items (i), (ii), (iii), (iv) or (v) above.




18.7 Interpretation.



Wherever the context may require, any noun or
pronoun used herein shall include the corresponding masculine, feminine or
neuter forms. The singular form of nouns, pronouns and verbs shall include the
plural and vice versa.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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      Sheet No. 58Third Revised Rate Schedule FERC No.
      24




18.8 Severability.



Each provision of this Agreement shall be
considered severable and if for any reason any provision is determined by a
court or regulatory authority of competent jurisdiction to be invalid, void or
unenforceable, the remaining provisions of this Agreement shall continue in full
force and effect and shall in no way be affected, impaired or invalidated, and
such invalid, void or unenforceable provision shall be replaced with valid and
enforceable provision or provisions which otherwise give effect to the original
intent of the invalid, void or unenforceable provision.



18.9 Force Majeure.



No Member shall be liable to any other Member for
damages or otherwise be in breach of this Agreement to the extent and during the
period such Member’s performance is prevented by any cause or causes beyond such
Member’s control and without such Member’s fault or negligence, including but
not limited to any act, omission, or circumstance occasioned by or in
consequence of any act of God, labor disturbance, act of the public enemy, war,
insurrection, riot, fire, storm or flood, explosion, breakage or accident to
machinery or equipment, or curtailment, order, regulation or restriction imposed
by governmental, military or lawfully established civilian authorities;
provided, however, that any such foregoing event shall not excuse any payment
obligation. Upon the occurrence of an event considered by a Member to constitute
a force majeure event, such Member shall use due diligence to endeavor to
continue to perform its obligations as far as reasonably practicable and to
remedy the event, provided that no Member shall be required by this provision to
settle any strike or labor dispute.



18.10 Further Assurances.



Each Member hereby agrees that it shall hereafter
execute and deliver such further instruments, provide all information and take
or forbear such further acts and things as may be reasonably required or useful
to carry out the intent and purpose of this Agreement and as are not
inconsistent with the terms hereof.



18.11 Seal.



The seal of the LLC shall have inscribed thereon
the name of the LLC, the year of its organization and the words “Corporate Seal,
Delaware.” The seal may be used by causing it or a facsimile thereof to be
impressed or affixed or reproduced or otherwise.



18.12 Counterparts.



This Agreement may be executed in any number of
counterparts, each of which shall be an original but all of which together will
constitute one instrument, binding upon all parties hereto, notwithstanding that
all of such parties may not have executed the same counterpart.



18.13 Costs of Meetings.



Each Member shall be responsible for all costs of
its representative, alternate or substitute in attending any meeting. The Office
of the Interconnection shall pay the other reasonable costs of meetings of the
PJM Board and the Members Committee, and such other committees, subcommittees,
task forces, working groups, User Groups or other bodies as determined to be
appropriate by the Office of the Interconnection, which costs otherwise shall be
paid by the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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    First
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    Superseding Original Sheet No. 59




Members attending. The Office of the Interconnection shall reimburse all
Board Members for their reasonable costs of attending meetings.



18.14 Notice.



(a) Except as otherwise expressly provided herein,
notices required under this Agreement shall be in writing and shall be sent to a
Member by overnight courier, hand delivery, telecopier or other reliable
electronic means to the representative on the Members Committee of such Member
at the address for such Member previously provided by such Member to the Office
of the Interconnection. Any such notice so sent shall be deemed to have been
given (i) upon delivery if given by overnight couriers or hand delivery, or (ii)
upon confirmation if given by telecopier or other reliable electronic means.
Notices of meetings of the Members Committee or committees, subcommittees, task
forces, working groups and other bodies under its auspices may be given as
provided in the Members Committee by-laws.



(b) Notices, as well as copies of the agenda and
minutes of all meetings of committees, subcommittees, task forces, working
groups, User Groups, or other bodies formed under this Agreement, shall be
posted in a timely fashion on and made available for downloading from the PJM
website.



18.15 Headings.



The section headings used in this Agreement are
for convenience only and shall not affect the construction or interpretation of
any of the provisions of this Agreement.



18.16 No Third-Party Beneficiaries.



This Agreement is intended to be solely for the
benefit of the Members and their respective successors and permitted assigns
and, unless expressly stated herein, is not intended to and shall not confer any
rights or benefits on any third party (other than successors and permitted
assigns) not a signatory hereto.



18.17 Confidentiality.



18.17.1 Party Access.



(a) No Member shall have a right hereunder to
receive or review any documents, data or other information of another Member,
including documents, data or other information provided to the Office of the
Interconnection, to the extent such documents, data or information have been
designated as confidential pursuant to the procedures adopted by the Office of
the Interconnection or to the extent that they have been designated as
confidential by such other Member; provided, however, a Member may receive and
review any composite documents, data and other information that may be developed
based on such confidential documents, data or information if the composite does
not disclose any individual Member’s confidential data or information.



(b) Except as may be provided in this Agreement or
in the PJM Open Access Transmission Tariff, the Office of the Interconnection
shall not disclose to its Members or to third parties, any documents, data, or
other information of a Member or entity applying for Membership, to the extent
such documents, data, or other information has been designated confidential
pursuant to the procedures adopted by the Office of the Interconnection or by
such Member or entity



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    July 31, 2003




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applying for membership; provided that nothing
contained herein shall prohibit the Office of the Interconnection from providing
any such confidential information to its agents, representatives, or contractors
to the extent that such person or entity is bound by an obligation to maintain
such confidentiality; provided further that nothing contained herein shall
prohibit the Office of the Interconnection from providing Member confidential
information to the North American Electric Reliability Council or any of its
regional reliability councils to the extent that (i) the Office of the
Interconnection determines in its reasonable discretion that the exchange of
such information is required to enhance and/or maintain reliability within MAAC
and its neighboring reliability councils, (ii) such entity is bound by a written
agreement to maintain such confidentiality, and (iii) the Office of the
Interconnection has notified the affected party of its intention to release such
information no less than five business days prior to the release. The Office of
the Interconnection shall collect and use confidential information only in
connection with its authority under this Agreement and the Open Access
Transmission Tariff and the retention of such information shall be in accordance
with PJM’s data retention policies.



(c) Nothing contained herein shall prevent the
Office of the Interconnection from releasing a Member’s confidential data or
information to a third party provided that the Member has delivered to the
Office of the Interconnection specific, written authorization for such release
setting forth the data or information to be released, to whom such release is
authorized, and the period of time for which such release shall be authorized.
The Office of the Interconnection shall limit the release of a Member’s
confidential data or information to that specific authorization received from
the Member. Nothing herein shall prohibit a Member from withdrawing such
authorization upon written notice to the Office of the Interconnection who shall
cease such release as soon as practicable after receipt of such withdrawal
notice.



18.17.2 Required Disclosure.



(a) Notwithstanding anything in the foregoing
Section to the contrary, and subject to the provisions of Section 18.17.3, if a
Member or the Office of the Interconnection is required by applicable law, or in
the course of administrative or judicial proceedings other than FERC proceedings
or investigations, to disclose to third parties other than the FERC or its
staff, information that is otherwise required to be maintained in confidence
pursuant to this Agreement, that Member or the Office of the Interconnection may
make disclosure of such information; provided, however, that as soon as the
Member or the Office of the Interconnection learns of the disclosure requirement
and prior to making disclosure, that Member or the Office of the Interconnection
shall notify the affected Member or Members of the requirement and the terms
thereof and the affected Member or Members may direct, at their sole discretion
and cost, any challenge to or defense against the disclosure requirement. The
disclosing Member and the Office of the Interconnection shall cooperate with
such affected Members to the maximum extent practicable to minimize the
disclosure of the information consistent with applicable law. Each Member and
the Office of the Interconnection shall cooperate with the affected Members to
obtain proprietary or confidential treatment of such information by the person
to whom such information is disclosed prior to any such disclosure.



(b) Nothing in this Section 18.17 shall prohibit
or otherwise limit the Office of the Interconnection’s use of information
covered herein if such information was: (i) previously



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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known to the Office of the Interconnection without
an obligation of confidentiality; (ii) independently developed by or for the
Office of the Interconnection using nonconfidential information; (iii) acquired
by the Office of the Interconnection from a third party which is not, to the
Office of the Interconnection’s knowledge, under an obligation of confidence
with respect to such information; (iv) which is or becomes publicly available
other than through a manner inconsistent with this Section 18.17.



(c) The Office of the Interconnection shall impose
on any contractors retained to provide technical support or otherwise to assist
with the implementation or administration of this Agreement or of the Open
Access Transmission Tariff a contractual duty of confidentiality consistent with
this Agreement. A Member shall not be obligated to provide confidential or
proprietary information to any contractor that does not assume such a duty of
confidentiality, and the Office of the Interconnection shall not provide any
such information to any such contractor without the express written permission
of the Member providing the information.



(d) Section 18.17.2(a) does not apply to
disclosure of information to the FERC or its staff.



18.17.3 Disclosure to FERC.



Notwithstanding anything in this Section to the
contrary, if the FERC or its staff, during the course of an investigation or
otherwise, requests information from the Office of the Interconnection that is
otherwise required to be maintained in confidence pursuant to this Agreement,
the Office of the Interconnection shall provide the requested information to the
FERC or its staff, within the time provided for in the request for information.
In providing the information to the FERC or its staff, the Office of the
Interconnection may, consistent with 18 C.F.R. § 388.112, request that the
information be treated as confidential and non-public by the FERC and its staff
and that the information be withheld from public disclosure. The Office of the
Interconnection shall notify any affected Member(s) when it is notified by FERC
or its staff, that a request for disclosure of, or decision to disclose,
confidential information has been received, at which time the Office of
Interconnection and the affected Member may respond before such information
would be made public, pursuant to 18 C.F.R. § 388.112.



18.17.4 Disclosure to Authorized Persons



(a)
    Notwithstanding anything in this section to the contrary, the
      Office of the Interconnection and/or the PJM Market Monitor shall disclose
      confidential information, otherwise required to be maintained in
      confidence pursuant to this Agreement, to an Authorized Person under the
      following conditions:




i)
    The Authorized Person
      has executed a Non-Disclosure Agreement with the Office of the
      Interconnection, representing and warranting that he or she: (i) is an
      Authorized Person; (ii) is duly authorized to enter into and perform the
      obligations of the Non-Disclosure Agreement; (iii) has adequate procedures
      to protect against the release of any confidential information received,
      (iv) is familiar with, and will comply with any applicable procedures of
      the Authorized Commission which the Authorized Person represents, (v)
      covenants and agrees on behalf of himself or herself to deny any Third
      Party Requests and defend against any legal process which seeks the
      release of any confidential information that would be released in
      contravention of the




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    June 28, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




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      24




terms of the Non-Disclosure Agreement, and
      (vi) is not in breach of any Non-Disclosure Agreement entered into with
      the Office of the Interconnection.




ii)
    The
      Authorized Commission employing or retaining the Authorized Person has
      provided the Office of the Interconnection with: (a) a final order of FERC
      prohibiting the release by the Authorized Person or the Authorized
      Commission of confidential information in accordance with the terms of
      this Agreement and the Non-Disclosure Agreement; and (b) either an order
      of such Authorized Commission or a certification from counsel to such
      Authorized Commission, confirming that the Authorized Commission (i) has
      statutory authority to protect the confidentiality of any confidential
      information received from public release or disclosure and from release or
      disclosure to any other entity, (ii) will defend against any disclosure of
      Confidential Information pursuant to any Third Party Request through all
      available legal process, including, but not limited to, obtaining any
      necessary protective orders, (iii) will provide the Office of the
      Interconnection with prompt notice of any such Third Party Request or
      legal proceedings and will consult with the Office of the Interconnection
      and/or any Affected Member in its efforts to deny the Third Party Request
      or defend against such legal process, (iv) in the event a protective order
      or other remedy is denied, will direct Authorized Persons authorized by it
      to furnish only that portion of the confidential information which their
      legal counsel advises the Office of the Interconnection in writing is
      legally required to be furnished, (v) will exercise its best efforts to
      obtain assurance that confidential treatment will be accorded to such
      confidential information and (vi) has adequate procedures to protect
      against the release of such confidential information; and (c) confirmation
      in writing that the Authorized Person is authorized by the Commission to
      enter into the Non-Disclosure Agreement and to receive confidential
      information under this Agreement.




iii)
    The
      Authorized Commission employing or retaining the Authorized Person has
      provided the Office of the Interconnection with a State Certification.




iv)
    The Office
      of the Interconnection and the PJM Market Monitor shall be expressly
      entitled to rely upon such FERC and Authorized Commission orders, the
      State Certification and/or certifications of counsel in providing
      confidential information to the Authorized Person, and shall in no event
      be liable, or subject to damages or claims of any kind or nature hereunder
      due to the ineffectiveness of the FERC and/or Commission orders, or the
      inaccuracy of such certification of counsel.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




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PJM Interconnection, L.L.C.
    
    Substitute Original Sheet No. 61BThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 61B




v)
    The
      Authorized Person may discuss confidential information with other
      Authorized Persons who are parties to Non-Disclosure Agreements; provided,
      however, that the Office of the Interconnection shall have confirmed in
      advance and in writing that it has previously released the confidential
      information in question to such Authorized Persons. The Office of the
      Interconnection shall respond to any written request for confirmation
      within two (2) business days of its receipt.




vi)
    The Office
      of the Interconnection shall maintain a schedule of all Authorized Persons
      and the Authorized Commissions they represent, which shall be made
      publicly available on its website, or by written request. Such schedule
      shall be compiled by the Office of the Interconnection, based on
      information provided by any Authorized Person and/or Authorized
      Commission. The Office of the Interconnection shall update the schedule
      promptly upon receipt of information from an Authorized Person or
      Authorized Commission, but shall have no obligation to verify or
      corroborate any such information, and shall not be liable or otherwise
      responsible for any inaccuracies in the schedule due to incomplete or
      erroneous information conveyed to and relied upon by the Office of the
      Interconnection in the compilation and/or maintenance of the schedule.




(b)
    The PJM Market Monitor
      or other designated representative of the Office of the Interconnection
      may, in the course of discussions with an Authorized Person, orally
      disclose information otherwise required to be maintained in confidence,
      without the need for a prior Information Request. Such oral disclosures
      shall provide enough information to enable the Authorized Person or their
      Authorized Commission to determine whether additional Information Requests
      for information are appropriate. The PJM Market Monitor or other
      representative of the Office of the Interconnection will not make any
      written or electronic disclosures of confidential information to the
      Authorized Person pursuant to this section. In any such discussions, the
      PJM Market Monitor or other representative of the Office of the
      Interconnection shall ensure that the individual or individuals receiving
      such confidential information are Authorized Persons as defined herein,
      orally designate confidential information that is disclosed, and refrain
      from identifying any specific Affected Member whose information is
      disclosed. The PJM Market Monitor or other representative of the Office of
      the Interconnection shall also be authorized to assist Authorized Persons
      in interpreting confidential information that is disclosed. The PJM Market
      Monitor or representative of the Office of the Interconnection shall
      provide any Affected Member with oral notice of any oral disclosure
      immediately, but not later than one (1) business day after the oral
      disclosure. Such oral notice to the Affected




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    July 28, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 61CThird Revised Rate Schedule FERC No.
      24




Member shall include the substance of the
      oral disclosure, but shall not reveal any confidential information of any
      other Member and must be received by the Affected Member before the name
      of the Affected Member is released to the Authorized Person; provided
      however, the identity of the Affected Party must be made to the Authorized
      Person within two (2) business days of the initial oral disclosure.




(c)
    As regards
      Information Requests:




(i)
    Information
      Requests to the Office of the Interconnection shall be in writing, which
      shall include electronic communications, addressed to the PJM Market
      Monitor or other designated representative of the Office of the
      Interconnection, and shall: (a) describe with particularity the
      information sought; (b) provide a description of the purpose of the
      Information Request; (c) state the time period for which confidential
      information is requested; and (d) re-affirm that only the Authorized
      Person shall have access to the confidential information requested. The
      Office of the Interconnection shall provide an Affected Member with
      written notice, which shall include electronic communication, of an
      Information Request of the Authorized Person as soon as possible, but not
      later than two (2) business days after the receipt of the Information
      Request.




(ii)
    Subject to
      the provisions of section (c)(iii), the Office of the Interconnection
      shall supply confidential information to the Authorized Person in response
      to any Information Request within five (5) business days of the receipt of
      the Information Request, to the extent that the requested confidential
      information can be made available within such period; provided however,
      that in no event shall confidential information be released prior to the
      end of the fourth (4th) business day without the express consent of the Affected Member.
      To the extent that the Office of the Interconnection can not reasonably
      prepare and deliver the requested confidential information within such
      five (5) day period, it shall, within such period, provide the Authorized
      Person with a written schedule for the provision of such remaining
      confidential information. Upon providing confidential information to the
      Authorized Person, the Office of the Interconnection shall either provide
      a copy of the confidential information to the Affected Member(s), or
      provide a listing of the confidential information disclosed; provided,
      however, that the Office of the Interconnection shall not reveal any
      Member’s confidential information to any other Member.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




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    Original
      Sheet No. 61DThird Revised Rate Schedule FERC No.
      24




(iii)
    Notwithstanding section (c)(ii), above, should the Office of the
      Interconnection or an Affected Member object to an Information Request or
      any portion thereof, either of them may, within four (4) business days
      following the Office of the Interconnection’s receipt of the Information
      Request, request, in writing, a conference with the Authorized Commission
      or the Authorized Commission’s authorized designee to resolve differences
      concerning the scope or timing of the Information Request; provided,
      however, nothing herein shall require the Authorized Commission to
      participate in any conference. Any party to the conference may seek
      assistance from FERC staff in resolution of the dispute. Should such
      conference be refused by any participant, or not resolve the dispute, then
      the Office of the Interconnection, the Affected Member or the Authorized
      Commission may initiate appropriate legal action at FERC within three (3)
      business days following receipt of written notice from any conference
      participant terminating such conference. Any complaints filed at FERC
      objecting to a particular Information Request shall be designated by the
      party as a “fast track” complaint and each party shall bear its own costs
      in connection with such FERC proceeding. If no FERC proceeding regarding
      the Information Request is commenced within such three day period, the
      Office of the Interconnection shall utilize its best efforts to respond to
      the Information Request promptly.




(d)
    In the event
      of any breach of a Non-Disclosure Agreement:




(i)
    The
      Authorized Person and/or their respective Authorized Commission shall
      promptly notify the Office of the Interconnection, who shall, in turn,
      promptly notify any Affected Member of any inadvertent or intentional
      release, or possible release, of confidential information provided
      pursuant to any Non-Disclosure Agreement.




(ii)
    The Office
      of the Interconnection shall terminate such Non-Disclosure Agreement upon
      written notice to the Authorized Person and his or her Authorized
      Commission, and all rights of the Authorized Person thereunder shall
      thereupon terminate; provided, however, that the Office of the
      Interconnection may restore an individual’s status as an Authorized Person
      after consulting with the Affected Member and to the extent that: (i) the
      Office of the Interconnection determines that the disclosure was not due
      to the intentional, reckless or negligent action or omission of the
      Authorized Person; (ii) there were no harm or damages suffered by the
      Affected Member; or (iii) similar good cause shown. Any appeal of the
      Office of the Interconnection’s actions under this section shall be to
      FERC.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




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    Substitute Original Sheet No. 61EThird Revised Rate
      Schedule FERC No. 24
    
    Superseding Original Sheet No. 61E




(iii)
    The Office
      of the Interconnection and/or the Affected Member shall have the right to
      seek and obtain at least the following types of relief: (a) an order from
      FERC requiring any breach to cease and preventing any future breaches; (b)
      temporary, preliminary, and/or permanent injunctive relief with respect to
      any breach; and (c) the immediate return of all confidential information
      to the Office of the Interconnection.




(iv)
    No
      Authorized Person shall have responsibility or liability whatsoever under
      the Non-Disclosure Agreement or this Agreement for any and all
      liabilities, losses, damages, demands, fines, monetary judgments,
      penalties, costs and expenses caused by, resulting from, or arising out of
      or in connection with the release of confidential information to persons
      not authorized to receive it, provided that such Authorized Person is an
      employee or member of an Authorized Commission at the time of such
      unauthorized release. Nothing in this Section (d)(iv) is intended to limit
      the liability of any person who is not an employee of or a member of an
      Authorized Commission at the time of such unauthorized release for any and
      all economic losses, damages, demands, fines, monetary judgments,
      penalties, costs and expenses caused by, resulting from, or arising out of
      or in connection with such unauthorized release.




(v)
    Any dispute
      or conflict requesting the relief in section (d)(ii) or (d)(iii)(a) above,
      shall be submitted to FERC for hearing and resolution. Any dispute or
      conflict requesting the relief in section (d)(iii)(c) above may be
      submitted to FERC or any court of competent jurisdiction for hearing and
      resolution.




18.18 Termination and Withdrawal.



18.18.1 Termination.



Upon termination of this Agreement, final
settlement for obligations under this Agreement shall include the accounting for
the period ending with the last day of the last month for which the Agreement
was effective.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    July 28,
    2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




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    Original
      Sheet No. 61FThird Revised Rate
      Schedule FERC No. 24




18.18.2 Withdrawal.



Subject to the requirements of Section 4.1(c) of
this Agreement and Section 1.4.6 of the Schedule 1 to this Agreement, any Member
may withdraw from this Agreement upon 90 days notice to the Office of the
Interconnection.



18.18.3 Winding Up.



Any provision of this Agreement that expressly or
by implication comes into or remains in force following the termination or
expiration of this Agreement shall survive such



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29,
    2004Vice President, Government
    PolicyIssued On:
    
    April 29,
    2004




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    Original
      Sheet No. 62Third Revised Rate
      Schedule FERC No. 24




termination or expiration. The surviving
provisions shall include, but shall not be limited to: (i) those provisions
necessary to permit the orderly conclusion, or continuation pursuant to another
agreement, of transactions entered into prior to the decision to terminate this
Agreement, (ii) those provisions necessary to conduct final billing, collection,
and accounting with respect to all matters arising hereunder, and (iii) the
indemnification provisions as applicable to periods prior to such termination or
expiration.



IN WITNESS whereof, the Members have caused this
Agreement to be executed by their duly authorized representatives.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20,
      2003Vice President, Governmental
      PolicyIssued On:
    
    March 20,
    2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 63Third Revised Rate Schedule FERC No.
      24




RESOLUTION REGARDING ELECTION OF DIRECTORS



1.
    Subject to
      the approval of the Federal Energy Regulatory Commission, the provisions
      of Section 7.1 of the Amended and Restated Operating Agreement of PJM
      Interconnection, L.L.C. (the “Operating Agreement”), to the extent that
      such section requires that the election of members to the PJM Board of
      Managers be held at the Annual Meeting of the Members, be, and they hereby
      are, waived, solely for election to those positions on the PJM Board of
      Managers that expire in the year 2001; and




2.
    An election
      of members of the PJM Board of Managers from the slate approved by the
      independent consultant retained by the Office of the Interconnection, is,
      and hereby shall be, authorized by the PJM Members Committee to occur at
      its meeting held on August 30, 2001; and




3.
    The Office
      of the Interconnection is, and hereby shall be, authorized to file such
      documents and make such pleadings before the Federal Energy Regulatory
      Commission as the Office of the Interconnection determines to be
      reasonably necessary seeking such waivers and authorizations as may be
      required to assure the validity of the aforementioned election of members
      to the PJM Board of Managers.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 64Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 64




SCHEDULE 1



PJM INTERCHANGE ENERGY MARKET



1. MARKET OPERATIONS



1.1 Introduction.



This Schedule sets forth the scheduling, other
procedures, and certain general provisions applicable to the operation of the
PJM Interchange Energy Market within the PJM Region. This Schedule addresses
each of the three time-frames pertinent to the daily operation of the PJM
Interchange Energy Market: Prescheduling, Scheduling, and Dispatch.



1.2 Cost-based Offers.



Unless and until the FERC shall authorize the use
of market-based prices in the PJM Interchange Energy Market, all offers for
energy or other services to be sold on the PJM Interchange Energy Market from
generating resources located within the PJM Region shall not exceed the variable
cost of producing such energy or other service, as determined in accordance with
Schedule 2 to this Agreement and applicable regulatory standards, requirements
and determinations; provided that, a Market Seller may offer to the PJM
Interchange Energy Market the right to call on energy from a resource the output
of which has been sold on a bilateral basis, with the rate for such energy if
called equal to the curtailment rate specified in the bilateral contract.



1.3 Definitions.



1.3.1 Auction Revenue Rights.



“Auction Revenue Rights” shall mean the right to
receive the revenue from the Financial Transmission Right auction, as further
described in Section 7.4 of this Schedule.



1.3.1A Auction Revenue Rights Credits.



“Auction Revenue Rights Credits” shall mean the
allocated share of total FTR auction revenues or costs credited to each holder
of Auction Revenue Rights, calculated and allocated as specified in Section
7.4.3 of this Schedule.



1.3.1B Day-ahead Energy Market.



“Day-ahead Energy Market” shall mean the schedule
of commitments for the purchase or sale of energy and payment of Transmission
Congestion Charges developed by the Office of the Interconnection as a result of
the offers and specifications submitted in accordance with Section 1.10 of this
Schedule.



1.3.1C Day-ahead Prices.



“Day-ahead Prices” shall mean the Locational
Marginal Prices resulting from the Day-ahead Energy Market.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Second
      Revised Sheet No. 65Third Revised Rate Schedule FERC No.
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    Superseding Original Sheet No. 65




1.3.1D Decrement Bid.



“Decrement Bid” shall mean a bid to purchase
energy at a specified location in the Day-ahead Energy Market. An accepted
Decrement Bid results in scheduled load at the specified location in the
Day-ahead Energy Market.



1.3.1E Dispatch Rate.



“Dispatch Rate” shall mean the control signal,
expressed in dollars per megawatt-hour, calculated and transmitted continuously
and dynamically to direct the output level of all generation resources
dispatched by the Office of the Interconnection in accordance with the Offer
Data.



1.3.2 Equivalent Load.



“Equivalent Load” shall mean the sum of a Market
Participant’s net system requirements to serve its customer load in the PJM
Region, if any, plus its net bilateral transactions.



1.3.3 External Market Buyer.



“External Market Buyer” shall mean a Market Buyer
making purchases of energy from the PJM Interchange Energy Market for
consumption by end-users outside the PJM Region, or for load in the PJM Region
that is not served by Network Transmission Service.



1.3.4 External Resource.



“External Resource” shall mean a generation
resource located outside the metered boundaries of the PJM Region.



1.3.5 Financial Transmission Right.



“Financial Transmission Right” or “FTR” shall mean
a right to receive Transmission Congestion Credits as specified in Section 5.2.2
of this Schedule.



1.3.5A Financial Transmission Right Obligation.



“Financial Transmission Right Obligation” shall
mean a right to receive Transmission Congestion Credits as specified in Section
5.2.2(b) of this Schedule.



1.3.5B Financial Transmission Right Option.



“Financial Transmission Right Option” shall mean a
right to receive Transmission Congestion Credits as specified in Section
5.2.2(c) of this Schedule.



1.3.6 Generating Market Buyer.



“Generating Market Buyer” shall mean an Internal
Market Buyer that is a Load Serving Entity that owns or has contractual rights
to the output of generation resources capable of serving the Market Buyer’s load
in the PJM Region, or of selling energy or related services in the PJM
Interchange Energy Market or elsewhere.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Second
      Revised Sheet No. 66Third Revised Rate Schedule FERC No.
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    Superseding Original Sheet No. 66




1.3.7 Generator Forced Outage.



“Generator Forced Outage” shall mean an immediate
reduction in output or capacity or removal from service, in whole or in part, of
a generating unit by reason of an Emergency or threatened Emergency,
unanticipated failure, or other cause beyond the control of the owner or
operator of the facility, as specified in the relevant portions of the PJM
Manuals. A reduction in output or removal from service of a generating unit in
response to changes in market conditions shall not constitute a Generator Forced
Outage.



1.3.8 Generator Maintenance Outage.



“Generator Maintenance Outage” shall mean the
scheduled removal from service, in whole or in part, of a generating unit in
order to perform necessary repairs on specific components of the facility, if
removal of the facility meets the guidelines specified in the PJM Manuals.



1.3.9 Generator Planned Outage.



“Generator Planned Outage” shall mean the
scheduled removal from service, in whole or in part, of a generating unit for
inspection, maintenance or repair with the approval of the Office of the
Interconnection in accordance with the PJM Manuals.



1.3.9A Increment Bid.



“Increment Bid” shall mean an offer to sell energy
at a specified location in the Day-ahead Energy Market. An accepted Increment
Bid results in scheduled generation at the specified location in the Day-ahead
Energy Market.



1.3.10 Internal Market Buyer.



“Internal Market Buyer” shall mean a Market Buyer
making purchases of energy from the PJM Interchange Energy Market for ultimate
consumption by end-users inside the PJM Region that are served by Network
Transmission Service.



1.3.11 Inadvertent Interchange.



“Inadvertent Interchange” shall mean the
difference between net actual energy flow and net scheduled energy flow into or
out of the individual Control Areas operated by PJM, as determined and allocated
each hour by the Office of the Interconnection in accordance with the procedures
set forth in the PJM Manuals to each Electric Distributor that reports to the
Office of the Interconnection its hourly net energy flows from metered tie
lines.



1.3.12 Market Operations Center.



“Market Operations Center” shall mean the
equipment, facilities and personnel used by or on behalf of a Market Participant
to communicate and coordinate with the Office of the Interconnection in
connection with transactions in the PJM Interchange Energy Market or the
operation of the PJM Region.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    First
      Revised Sheet No. 67Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 67




1.3.13 Maximum Generation Emergency.



“Maximum Generation Emergency” shall mean an
Emergency declared by the Office of the Interconnection in which the Office of
the Interconnection anticipates requesting one or more Capacity Resources or
Available Capacity Resources to operate at its maximum net or gross electrical
power output, subject to the equipment stress limits for such Capacity Resource,
in order to manage, alleviate, or end the Emergency.



1.3.14 Minimum Generation Emergency.



“Minimum Generation Emergency” shall mean an
Emergency declared by the Office of the Interconnection in which the Office of
the Interconnection anticipates requesting one or more generating resources to
operate at or below Normal Minimum Generation, in order to manage, alleviate, or
end the Emergency.



1.3.14A NERC Interchange Distribution
Calculator.



“NERC Interchange Distribution Calculator” shall
mean the NERC mechanism that is in effect and being used to calculate the
distribution of energy, over specific transmission interfaces, from energy
transactions.



1.3.15 Network Resource.



“Network Resource” shall have the meaning
specified in the PJM Tariff.



1.3.16 Network Service User.



“Network Service User” shall mean an entity using
Network Transmission Service.



1.3.17 Network Transmission Service.



“Network Transmission Service” shall mean
transmission service provided pursuant to the rates, terms and conditions set
forth in Part III of the PJM Tariff, or transmission service comparable to such
service that is provided to a Load Serving Entity that is also a West
Transmission Owner or an East Transmission Owner.



1.3.18 Normal Maximum Generation.



“Normal Maximum Generation” shall mean the highest
output level of a generating resource under normal operating conditions.



1.3.19 Normal Minimum Generation.



“Normal Minimum Generation” shall mean the lowest
output level of a generating resource under normal operating conditions.



1.3.20 Offer Data.



“Offer Data” shall mean the scheduling, operations
planning, dispatch, new resource, and other data and information necessary to
schedule and dispatch generation resources



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 7, 2003Vice President, Governmental
      PolicyIssued On:
    
    November 6, 2003




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    Second
      Revised Sheet No. 68Third Revised Rate Schedule FERC No.
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    Superseding Original Sheet No. 68




for the provision of energy and other services and
the maintenance of the reliability and security of the transmission system in
the PJM Region, and specified for submission to the PJM Interchange Energy
Market for such purposes by the Office of the Interconnection.



1.3.21 Office of the Interconnection Control
Center.



“Office of the Interconnection Control Center”
shall mean the equipment, facilities and personnel used by the Office of the
Interconnection to coordinate and direct the operation of the PJM Region and to
administer the PJM Interchange Energy Market, including facilities and equipment
used to communicate and coordinate with the Market Participants in connection
with transactions in the PJM Interchange Energy Market or the operation of the
PJM Region.



1.3.22 Operating Day.



“Operating Day” shall mean the daily 24 hour
period beginning at midnight for which transactions on the PJM Interchange
Energy Market are scheduled.



1.3.23 Operating Margin.



“Operating Margin” shall mean the incremental
adjustments, measured in megawatts, required in PJM Region operations in order
to accommodate, on a first contingency basis, an operating contingency in the
PJM Region resulting from operations in an interconnected Control Area. Such
adjustments may result in constraints causing Transmission Congestion Charges,
or may result in Ancillary Services charges pursuant to the PJM Tariff.



1.3.24 Operating Margin Customer.



“Operating Margin Customer” shall mean a Control
Area purchasing Operating Margin pursuant to an agreement between such other
Control Area and the LLC.



1.3.25 PJM Interchange.



“PJM Interchange” shall mean the following, as
determined in accordance with the Schedules to this Agreement: (a) for a Market
Participant that is a Network Service User, the amount by which its hourly
Equivalent Load exceeds, or is exceeded by, the sum of the hourly outputs of its
operating generating resources; or (b) for a Market Participant that is not a
Network Service User, the amount of its Spot Market Backup; or (c) the hourly
scheduled deliveries of Spot Market Energy by a Market Seller from an External
Resource; or (d) the hourly net metered output of any other Market Seller; or
(e) the hourly scheduled deliveries of Spot Market Energy to an External Market
Buyer; or (f) the hourly scheduled deliveries to an Internal Market Buyer that
is not a Network Service User.



1.3.26 PJM Interchange Export.



“PJM Interchange Export” shall mean the following,
as determined in accordance with the Schedules to this Agreement: (a) for a
Market Participant that is a Network Service User, the amount by which its
hourly Equivalent Load is exceeded by the sum of the hourly outputs of its



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Second
      Revised Sheet No. 69Third Revised Rate Schedule FERC No.
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    Superseding Original Sheet No. 69




operating generating resources; or (b) for a
Market Participant that is not a Network Service User, the amount of its Spot
Market Backup sales; or (c) the hourly scheduled deliveries of Spot Market
Energy by a Market Seller from an External Resource; or (d) the hourly net
metered output of any other Market Seller.



1.3.27 PJM Interchange Import.



“PJM Interchange Import” shall mean the following,
as determined in accordance with the Schedules to this Agreement: (a) for a
Market Participant that is a Network Service User, the amount by which its
hourly Equivalent Load exceeds the sum of the hourly outputs of its operating
generating resources; or (b) for a Market Participant that is not a Network
Service User, the amount of its Spot Market Backup purchases; or (c) the hourly
scheduled deliveries of Spot Market Energy to an External Market Buyer; or (d)
the hourly scheduled deliveries to an Internal Market Buyer that is not a
Network Service User.



1.3.28 PJM Open Access Same-time Information
System.



“PJM Open Access Same-time Information System”
shall mean the electronic communication system for the collection and
dissemination of information about transmission services in the PJM Region,
established and operated by the Office of the Interconnection in accordance with
FERC standards and requirements.



1.3.29 Point-to-Point Transmission Service.



“Point-to-Point Transmission Service” shall mean
transmission service provided pursuant to the rates, terms and conditions set
forth in Part II of the PJM Tariff.



1.3.30 Ramping Capability.



“Ramping Capability” shall mean the sustained rate
of change of generator output, in megawatts per minute.



1.3.30A Real-time Prices.



“Real-time Prices” shall mean the Locational
Marginal Prices resulting from the Office of the Interconnection’s dispatch of
the PJM Interchange Energy Market in the Operating Day.



1.3.30B Real-time Energy Market.



“Real-time Energy Market” shall mean the purchase
or sale of energy and payment of Transmission Congestion Charges for quantity
deviations from the Day-ahead Energy Market in the Operating Day.



1.3.31 Regulation.



“Regulation” shall mean the capability of a
specific generating unit with appropriate telecommunications, control and
response capability to increase or decrease its output in response to a
regulating control signal, in accordance with the specifications in the PJM
Manuals.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 70Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 70




1.3.31A Spinning Reserve.



“Spinning Reserve” shall mean the reserve
capability that can be converted fully into energy within ten minutes from the
request of the Office of the Interconnection dispatcher, and is provided by
equipment electrically synchronized to the Transmission System.



1.3.31B Spinning Reserve Event.



“Spinning Reserve Event” shall mean a request from
the Office of the Interconnection to those generation resources able, assigned
or self-scheduled to provide Spinning Reserve to increase, within ten minutes,
the energy output from those resources by the amount of assigned or
self-scheduled Spinning Reserve capability.



1.3.32 Spot Market Backup.



“Spot Market Backup” shall mean the purchase of
energy from, or the delivery of energy to, the PJM Interchange Energy Market in
quantities sufficient to complete the delivery or receipt obligations of a
bilateral contract that has been curtailed or interrupted for any reason.



1.3.33 Spot Market Energy.



“Spot Market Energy” shall mean energy bought or
sold by Market Participants through the PJM Interchange Energy Market at
Locational Marginal Prices determined as specified in Section 2 of this
Schedule.



1.3.33A State Estimator.



“State Estimator” shall mean the computer model of
power flows specified in Section 2.3 of this Schedule.



1.3.33B Station Power.



“Station Power” shall mean energy used for
operating the electric equipment on the site of a generation facility located in
the PJM Region or for the heating, lighting, air-conditioning and office
equipment needs of buildings on the site of such a generation facility that are
used in the operation, maintenance, or repair of the facility. Station Power
does not include any energy used to power synchronous condensers, used for
pumping at a pumped storage facility, or used in association with restoration or
black start service.



1.3.33C Target Allocation.



Shall mean the allocation of Transmission
Congestion Credits as set forth in Section 5.2.3 of this Schedule or the
allocation of Auction Revenue Rights Credits as set forth in Section 7.4.3 of
this Schedule.



1.3.34 Transmission Congestion Charge.



“Transmission Congestion Charge” shall mean a
charge attributable to the increased cost of energy delivered at a given load
bus when the transmission system serving that load bus is operating under
constrained conditions, or as necessary to provide energy for third-party
transmission losses in accordance with Section 9.3, which shall be calculated
and allocated as specified in Section 5.1 of this Schedule.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 71Third Revised Rate Schedule FERC No.
      24
    
    Superseding Substitute Original Sheet No.
71




1.3.35 Transmission Congestion Credit.



“Transmission Congestion Credit” shall mean the
allocated share of total Transmission Congestion Charges credited to each holder
of Financial Transmission Rights, calculated and allocated as specified in
Section 5.2 of this Schedule.



1.3.36 Transmission Customer.



“Transmission Customer” shall mean an entity using
Point-to-Point Transmission Service.



1.3.37 Transmission Forced Outage.



“Transmission Forced Outage” shall mean an
immediate removal from service of a transmission facility by reason of an
Emergency or threatened Emergency, unanticipated failure, or other cause beyond
the control of the owner or operator of the transmission facility, as specified
in the relevant portions of the PJM Manuals. A removal from service of a
transmission facility at the request of the Office of the Interconnection to
improve transmission capability shall not constitute a Forced Transmission
Outage.



1.3.37A Transmission Loading Relief.



“Transmission Loading Relief” shall mean NERC’s
procedures for preventing operating security limit violations, as implemented by
PJM as the security coordinator responsible for maintaining transmission
security for the PJM Region.



1.3.37B Transmission Loading Relief Customer.



“Transmission Loading Relief Customer” shall mean
an entity that, in accordance with Section 1.10.6A, has elected to pay
Transmission Congestion Charges during Transmission Loading Relief in order to
continue energy schedules over contract paths outside the PJM Region that are
increasing the cost of energy in the PJM Region.



1.3.38 Transmission Planned Outage.



“Transmission Planned Outage” shall mean any
transmission outage scheduled in advance for a pre-determined duration and which
meets the notification requirements for such outages specified in this Agreement
or the PJM Manuals.



1.4 Market Buyers.



1.4.1 Qualification.



(a) To become a Market Buyer, an entity shall
submit an application to the Office of the Interconnection, in such form as
shall be established by the Office of the Interconnection.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 72Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 72




(b) An applicant that is a Load Serving Entity or
that will purchase on behalf of or for ultimate delivery to a Load Serving
Entity shall establish to the satisfaction of the Office of the Interconnection
that the end-users that will be served through energy and related services
purchased in the PJM Interchange Energy Market, are located electrically within
the PJM Region, or will be brought within the PJM Region prior to any purchases
from the PJM Interchange Energy Market. Such applicant shall further demonstrate
that:



i)
    The Load
      Serving Entity for the end users is obligated to meet the requirements of
      the Reliability Assurance Agreement; or Reliability Assurance
      Agreement-West, as applicable, and




ii)
    The Load
      Serving Entity for the end users has arrangements in place for Network
      Transmission Service or Point-To-Point Transmission Service for all PJM
      Interchange Energy Market purchases.




(c) An applicant that is not a Load Serving Entity
or purchasing on behalf of or for ultimate delivery to a Load Serving Entity
shall demonstrate that:



i)
    The
      applicant has obtained or will obtain Network Transmission Service or
      Point-to-Point Transmission Service for all PJM Interchange Energy Market
      purchases; and




ii)
    The
      applicant’s PJM Interchange Energy Market purchases will ultimately be
      delivered to a load in another Control Area that is recognized by NERC and
      that complies with NERC’s standards for operating and planning reliable
      bulk electric systems.




(d) An applicant shall not be required to obtain
transmission service for purchases from the PJM Interchange Energy Market to
cover quantity deviations from its sales in the Day-ahead Energy Market.



(e) All applicants shall demonstrate that:



i)
    The
      applicant is capable of complying with all applicable metering, data
      storage and transmission, and other reliability, operation, planning and
      accounting standards and requirements for the operation of the PJM Region
      and the PJM Interchange Energy Market;




ii)
    The
      applicant meets the creditworthiness standards established by the Office
      of the Interconnection, or has provided a letter of credit or other form
      of security acceptable to the Office of the Interconnection; and




iii)
    The
      applicant has paid all applicable fees and reimbursed the Office of the
      Interconnection for all unusual or extraordinary costs of processing and
      evaluating its application to become a Market Buyer, and has agreed in its
      application to subject any disputes arising from its application to the
      PJM Dispute Resolution Procedures.




(f) The applicant shall become a Market Buyer upon
a final favorable determination on its application by the Office of the
Interconnection as specified below, and execution by the applicant of
counterparts of this Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 73Third Revised Rate Schedule FERC No.
      24




1.4.2 Submission of Information.



The applicant shall furnish all information
reasonably requested by the Office of the Interconnection in order to determine
the applicant’s qualification to be a Market Buyer. The Office of the
Interconnection may waive the submission of information relating to any of the
foregoing criteria, to the extent the information in the Office of the
Interconnection’s possession is sufficient to evaluate the application against
such criteria.



1.4.3 Fees and Costs.



The Office of the Interconnection shall require
all applicants to become a Market Buyer to pay a uniform application fee,
initially in the amount of $1,500, to defray the ordinary costs of processing
such applications. The application fee shall be revised from time to time as the
Office of the Interconnection shall determine to be necessary to recover its
ordinary costs of processing applications. Any unusual or extraordinary costs
incurred by the Office of the Interconnection in processing an application shall
be reimbursed by the applicant.



1.4.4 Office of the Interconnection
Determination.



Upon submission of the information specified
above, and such other information as shall reasonably be requested by the Office
of the Interconnection, the Office of the Interconnection shall undertake an
evaluation and investigation to determine whether the applicant meets the
criteria specified above. As soon as practicable, but in any event not later
than 60 days after submission of the foregoing information, or such later date
as may be necessary to satisfy the requirements of the Reliability Assurance
Agreement, the Office of the Interconnection shall notify the applicant and the
members of the Members Committee of its determination, along with a written
summary of the basis for the determination. The Office of the Interconnection
shall respond promptly to any reasonable and timely request by a Member for
additional information regarding the basis for the Office of the
Interconnection’s determination, and shall take such action as it shall deem
appropriate in response to any request for reconsideration or other action
submitted to the Office of the Interconnection not later than 30 days from the
initial notification to the Members Committee.



1.4.5 Existing Participants.



Any entity that was qualified to participate as a
Market Buyer in the PJM Interchange Energy Market under the Operating Agreement
of PJM Interconnection L.L.C. in effect immediately prior to the Effective Date
shall continue to be qualified to participate as a Market Buyer in the PJM
Interchange Energy Market under this Agreement.



1.4.6 Withdrawal.



(a) An Internal Market Buyer that is a Load
Serving Entity may withdraw from this Agreement by giving written notice to the
Office of the Interconnection specifying an effective date of withdrawal not
earlier than the effective date of (i) its withdrawal from the Reliability
Assurance Agreement or Reliability Assurance Agreement-West, or (ii) the
assumption of its obligations under the Reliability Assurance Agreement or
Reliability Assurance Agreement-West by an agent that is a Market Buyer.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 74Third Revised Rate Schedule FERC No.
      24




(b) An External Market Buyer or an Internal Market
Buyer that is not a Load Serving Entity may withdraw from this Agreement by
giving written notice to the Office of the Interconnection specifying an
effective date of withdrawal at least one day after the date of the notice.



(c) Withdrawal from this Agreement shall not
relieve a Market Buyer of any obligation to pay for electric energy or related
services purchased from the PJM Interchange Energy Market prior to such
withdrawal, to pay its share of any fees and charges incurred or assessed by the
Office of the Interconnection prior to the date of such withdrawal, or to
fulfill any obligation to provide indemnification for the consequences of acts,
omissions or events occurring prior to such withdrawal; and provided, further,
that withdrawal from this Agreement shall not relieve any Market Buyer of any
obligations it may have under, or constitute withdrawal from, any other Related
PJM Agreement.



(d) A Market Buyer that has withdrawn from this
Agreement may reapply to become a Market Buyer in accordance with the provisions
of this Section 1.4, provided it is not in default of any obligation incurred
under this Agreement.



1.5 Market Sellers.



1.5.1 Qualification.



A Member that demonstrates to the Office of the
Interconnection that the Member meets the standards for the issuance of an order
mandating the provision of transmission service under section 211 of the Federal
Power Act, as amended by the Energy Policy Act of 1992, may become a Market
Seller upon execution of this Agreement and submission to the Office of the
Interconnection of the applicable Offer Data in accordance with the provisions
of this Schedule. All Members that are Market Buyers shall become Market Sellers
upon submission to the Office of the Interconnection of the applicable Offer
Data in accordance with the provisions of this Schedule.



1.5.2 Withdrawal.



(a) A Market Seller may withdraw from this
Agreement by giving written notice to the Office of the Interconnection
specifying an effective date of withdrawal at least one day after the date of
the notice; provided, however, that withdrawal shall not relieve a Market Seller
of any obligation to deliver electric energy or related services to the PJM
Interchange Energy Market pursuant to an offer made prior to such withdrawal, to
pay its share of any fees and charges incurred or assessed by the Office of the
Interconnection prior to the date of such withdrawal, or to fulfill any
obligation to provide indemnification for the consequences of acts, omissions,
or events occurring prior to such withdrawal; and provided, further, that
withdrawal shall not relieve any entity that is a Market Seller and is also a
Market Buyer of any obligations it may have as a Market Buyer under, or
constitute withdrawal as a Market Buyer from, this Agreement or any other
Related PJM Agreement.



(b) A Market Seller that has withdrawn from this
Agreement may reapply to become a Market Seller at any time, provided it is not
in default with respect to any obligation incurred under this Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 75Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 75




1.6 Office of the Interconnection.



1.6.1 Operation of the PJM Interchange Energy
Market.



The Office of the Interconnection shall operate
the PJM Interchange Energy Market in accordance with this Agreement.



1.6.2 Scope of Services.



The Office of the Interconnection shall, on behalf
of the Market Participants, perform the services pertaining to the PJM
Interchange Energy Market specified in this Agreement, including but not limited
to the following:



i)
    Administer
      the PJM Interchange Energy Market as part of the PJM Region, including
      scheduling and dispatching of generation resources, accounting for
      transactions, rendering bills to the Market Participants, receiving
      payments from and disbursing payments to the Market Participants,
      maintaining appropriate records, and monitoring the compliance of Market
      Participants with the provisions of this Agreement, all in accordance with
      applicable provisions of the Office of the Interconnection Agreement, and
      the Schedules to this Agreement;




ii)
    Review and
      evaluate the qualification of entities to be Market Buyers or Market
      Sellers under applicable provisions of this Agreement;




iii)
    Coordinate,
      in accordance with applicable provisions of this Agreement, the
      Reliability Assurance Agreement, the Reliability Assurance Agreement-West,
      the West Transmission Owners Agreement and the East Transmission Owners
      Agreement, maintenance schedules for generation and transmission resources
      operated as part of the PJM Region;




iv)
    Provide or
      coordinate the provision of ancillary services necessary for the operation
      of the PJM Region or the PJM Interchange Energy Market;




v)
    Determine
      and declare that an Emergency is expected to exist, exists, or has ceased
      to exist, in all or any part of the PJM Region, or in another directly or
      indirectly interconnected Control Area and serve as a primary point of
      contact for interested state or federal agencies;




vi)
    Enter into
      (a) agreements for the transfer of energy in conditions constituting an
      Emergency in the PJM Region or in an interconnected Control Area, and the
      mutual provision of other support in such Emergency conditions with other
      interconnected Control Areas, and (b) purchases of Emergency energy
      offered by Members from resources that are not Capacity Resources in
      conditions constituting an Emergency in the PJM Region;




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 76Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 76




vii)
    Coordinate
      the curtailment or shedding of load, or other measures appropriate to
      alleviate an Emergency, in order to preserve reliability in accordance
      with NERC, or Applicable Regional Reliability Council principles,
      guidelines and standards, and to ensure the operation of the PJM Region in
      accordance with Good Utility Practice and this Agreement;




viii)
    Protect
      confidential information as specified in this Agreement; and




ix)
    Send a
      representative to meetings of the Members Committee or other Committees,
      subcommittees, or working groups specified in this Agreement or formed by
      the Members Committee when requested to do so by the chair or other head
      of such committee or other group.




1.6.3 Records and Reports.



The Office of the Interconnection shall prepare
and maintain such records and prepare such reports, including, but not limited
to quarterly budget reports, as are required to document the performance of its
obligations to the Market Participants hereunder in a form adopted by the Office
of the Interconnection upon consideration of the advice and recommendations of
the Members Committee. The Office of the Interconnection shall also produce
special reports reasonably requested by the Members Committee and consistent
with FERC’s standards of conduct; provided, however, the Market Participants
shall reimburse the Office of the Interconnection for the costs of producing any
such report. Notwithstanding the foregoing, the Office of the Interconnection
shall not be required to disclose confidential or commercially sensitive
information in any such report.



1.6.4 PJM Manuals.



The Office of the Interconnection shall prepare,
maintain and update the PJM Manuals consistent with this Agreement. The PJM
Manuals shall be available for inspection by the Market Participants, regulatory
authorities with jurisdiction over the LLC or any Member, and the public.



1.7 General.



1.7.1 Market Sellers.



Only Market Sellers shall be eligible to submit
offers to the Office of the Interconnection for the sale of electric energy or
related services in the PJM Interchange Energy Market. Market Sellers shall
comply with the prices, terms, and operating characteristics of all Offer Data
submitted to and accepted by the PJM Interchange Energy Market.



1.7.2 Market Buyers.



Only Market Buyers shall be eligible to purchase
energy or related services in the PJM Interchange Energy Market. Market Buyers
shall comply with all requirements for making purchases from the PJM Interchange
Energy Market.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 77Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 77




1.7.3 Agents.



A Market Participant may participate in the PJM
Interchange Energy Market through an agent, provided that the Market Participant
informs the Office of the Interconnection in advance in writing of the
appointment of such agent. A Market Participant participating in the PJM
Interchange Energy Market through an agent shall be bound by all of the acts or
representations of such agent with respect to transactions in the PJM
Interchange Energy Market, and shall ensure that any such agent complies with
the requirements of this Agreement.



1.7.4 General Obligations of the Market
Participants.



(a) In performing its obligations to the Office of
the Interconnection hereunder, each Market Participant shall at all times (i)
follow Good Utility Practice, (ii) comply with all applicable laws and
regulations, (iii) comply with the applicable principles, guidelines, standards
and requirements of FERC, NERC and Applicable Regional Reliability Councils,
(iv) comply with the procedures established for operation of the PJM Interchange
Energy Market and PJM Region and (v) cooperate with the Office of the
Interconnection as necessary for the operation of the PJM Region in a safe,
reliable manner consistent with Good Utility Practice.



(b) Market Participants shall undertake all
operations in or affecting the PJM Interchange Energy Market and the PJM Region
including but not limited to compliance with all Emergency procedures, in
accordance with the power and authority of the Office of the Interconnection
with respect to the operation of the PJM Interchange Energy Market and the PJM
Region as established in this Agreement, and as specified in the Schedules to
this Agreement and the PJM Manuals. Failure to comply with the foregoing
operational requirements shall subject a Market Participant to such reasonable
charges or other remedies or sanctions for non-compliance as may be established
by the PJM Board, including legal or regulatory proceedings as authorized by the
PJM Board to enforce the obligations of this Agreement.



(c) The Office of the Interconnection may
establish such committees with a representative of each Market Participant, and
the Market Participants agree to provide appropriately qualified personnel for
such committees, as may be necessary for the Office of the Interconnection to
perform its obligations hereunder.



(d) All Market Participants shall provide to the
Office of the Interconnection the scheduling and other information specified in
the Schedules to this Agreement, and such other information as the Office of the
Interconnection may reasonably require for the reliable and efficient operation
of the PJM Region and PJM Interchange Energy Market, and for compliance with
applicable regulatory requirements for posting market and related information.
Such information shall be provided as much in advance as possible, but in no
event later than the deadlines established by the Schedules to this Agreement,
or by the Office of the Interconnection in conformance with such Schedules. Such
information shall include, but not be limited to, maintenance and other
anticipated outages of generation or transmission facilities, scheduling and
related information on bilateral transactions and self-scheduled resources, and



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 78Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 78




implementation of active load management,
interruption of load, and other load reduction measures. The Office of the
Interconnection shall abide by appropriate requirements for the non-disclosure
and protection of any confidential or proprietary information given to the
Office of the Interconnection by a Market Participant. Each Market Participant
shall maintain or cause to be maintained compatible information and
communications systems, as specified by the Office of the Interconnection,
required to transmit scheduling, dispatch, or other time-sensitive information
to the Office of the Interconnection in a timely manner.



(e) Each Market Participant shall install and
operate, or shall otherwise arrange for, metering and related equipment capable
of recording and transmitting all voice and data communications reasonably
necessary for the Office of the Interconnection to perform the services
specified in this Agreement. A Market Participant that elects to be separately
billed for its PJM Interchange shall, to the extent necessary, be individually
metered in accordance with Section 14 of this Agreement, or shall agree upon an
allocation of PJM Interchange between it and the Market Participant through
whose meters the unmetered Market Participant’s PJM Interchange is delivered.
The Office of the Interconnection shall be notified of the allocation by the
foregoing Market Participants.



(f) Each Market Participant shall operate, or
shall cause to be operated, any generating resources owned or controlled by such
Market Participant that are within the PJM Region or otherwise supplying energy
to or through the PJM Region in a manner that is consistent with the standards,
requirements or directions of the Office of the Interconnection and that will
permit the Office of the Interconnection to perform its obligations under this
Agreement; provided, however, no Market Participant shall be required to take
any action that is inconsistent with Good Utility Practice or applicable law.



(g) Each Market Participant shall follow the
directions of the Office of the Interconnection to take actions to prevent,
manage, alleviate or end an Emergency in a manner consistent with this Agreement
and the procedures of the PJM Region as specified in the PJM Manuals.



(h) Each Market Participant shall obtain and
maintain all permits, licenses or approvals required for the Market Participant
to participate in the PJM Interchange Energy Market in the manner contemplated
by this Agreement.



1.7.5 Market Operations Center.



Each Market Participant shall maintain a Market
Operations Center, or shall make appropriate arrangements for the performance of
such services on its behalf. A Market Operations Center shall meet the
performance, equipment, communications, staffing and training standards and
requirements specified in this Agreement for the scheduling and completion of
transactions in the PJM Interchange Energy Market and the maintenance of the
reliable operation of the PJM Region, and shall be sufficient to enable (i) a
Market Seller to perform all terms and conditions of its offers to the PJM
Interchange Energy Market, and (ii) a Market Buyer to conform to the
requirements for purchasing from the PJM Interchange Energy Market.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 79Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 79




1.7.6 Scheduling and Dispatching.



(a) The Office of the Interconnection shall
schedule and dispatch in real-time generation economically on the basis of
least-cost, security-constrained dispatch and the prices and operating
characteristics offered by Market Sellers, continuing until sufficient
generation is dispatched to serve the PJM Interchange Energy Market energy
purchase requirements under normal system conditions of the Market Buyers, as
well as the requirements of the PJM Region for ancillary services provided by
such generation, in accordance with this Agreement. Such scheduling and dispatch
shall recognize transmission constraints on coordinated flowgates external to
the Transmission System in accordance with Appendix A to the Joint Operating
Agreement between the Midwest Independent Transmission System Operator, Inc. and
PJM Interconnection, L.L.C. (PJM Rate Schedule FERC No. 38). Scheduling and
dispatch shall be conducted in accordance with this Agreement.



(b) The Office of the Interconnection shall
undertake to identify any conflict or incompatibility between the scheduling or
other deadlines or specifications applicable to the PJM Interchange Energy
Market, and any relevant procedures of another Control Area, or any tariff
(including the PJM Tariff). Upon determining that any such conflict or
incompatibility exists, the Office of the Interconnection shall propose tariff
or procedural changes, and undertake such other efforts as may be appropriate,
to resolve any such conflict or incompatibility.



(c) To protect its generation or distribution
facilities, or local Transmission Facilities not under the monitoring
responsibility and dispatch control of the Office of the Interconnection, an
entity may request that the Office of the Interconnection schedule and dispatch
generation to meet a limit on Transmission Facilities different from that which
the Office of the Interconnection has determined to be required for reliable
operation of the Transmission System. To the extent consistent with its other
obligations under this Agreement, the Office of the Interconnection shall
schedule and dispatch generation in accordance with such request. An entity that
makes a request pursuant to this section 1.7.6(c) shall be responsible for all
generation and other costs resulting from its request that would not have been
incurred by operating the Transmission System and scheduling and dispatching
generation in the manner that the Office of the Interconnection otherwise has
determined to be required for reliable operation of the Transmission System.



1.7.7 Pricing.



The price paid for energy bought and sold in the
PJM Interchange Energy Market will reflect the hourly Locational Marginal Price
at each load and generation bus, determined by the Office of the Interconnection
in accordance with this Agreement. Transmission Congestion Charges, which shall
be determined by differences in Locational Marginal Prices in an hour caused by
transmission constraints, shall be calculated and collected, and the revenues
therefrom shall be disbursed, by the Office of the Interconnection in accordance
with this Schedule.



1.7.8 Generating Market Buyer Resources.



A Generating Market Buyer may elect to
self-schedule its generation resources up to that Generating Market Buyer’s
Equivalent Load, in accordance with and subject to the procedures specified in
this Schedule, and the accounting and billing requirements specified in Section
3 to this Schedule.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 80Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Sheet No. 80




1.7.9 Delivery to an External Market Buyer.



A purchase of Spot Market Energy by an External
Market Buyer shall be delivered to a bus or buses at the electrical boundaries
of the PJM Region specified by the Office of the Interconnection, or to load in
such area that is not served by Network Transmission Service, using
Point-to-Point Transmission Service paid for by the External Market Buyer.
Further delivery of such energy shall be the responsibility of the External
Market Buyer.



1.7.10 Other Transactions.



(a) Market Participants may enter into bilateral
contracts for the purchase or sale of electric energy to or from each other or
any other entity, subject to the obligations of Market Participants to make
Capacity Resources available for dispatch by the Office of the Interconnection.
Bilateral arrangements that contemplate the physical transfer of energy to or
from a Market Participant shall be reported to and coordinated with the Office
of the Interconnection in accordance with this Schedule.



(b) Market Participants shall have Spot Market
Backup with respect to all bilateral transactions that are not dynamically
scheduled pursuant to Section 1.12 and that are curtailed or interrupted for any
reason (except for curtailments or interruptions through active load management
for load located within the PJM Region).



(c) To the extent the Office of the
Interconnection dispatches a Generating Market Buyer’s generation resources,
such Generating Market Buyer may elect to net the output of such resources
against its hourly Equivalent Load. Such a Generating Market Buyer shall be
deemed a buyer from the PJM Interchange Energy Market to the extent of its PJM
Interchange Imports, and shall be deemed a seller to the PJM Interchange Energy
Market to the extent of its PJM Interchange Exports.



(d) A Market Seller may self-supply Station Power
for its generation facility in accordance with the following provisions:



(i)
    A Market Seller may
      self-supply Station Power for its generation facility during any month (1)
      when the net output of such facility is positive, or (2) when the net
      output of such facility is negative and the Market Seller during the same
      month has available at other of its generation facilities positive net
      output in an amount at least sufficient to offset fully such negative net
      output. For purposes of this subsection (d), “net output” of a generation
      facility during any month means the facility’s gross energy output, less
      the Station Power requirements of such facility, during that month. The
      determination of a generation facility’s or a Market Seller’s monthly net
      output under this subsection (d) will apply only to determine whether the
      Market Seller self-supplied Station Power during the month and will not
      affect the price of energy sold or consumed by the Market Seller at any
      bus during any hour during the month. For




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 81Third Revised Rate
      Schedule FERC No. 24
    
    Superseding First Revised Sheet No. 81




each hour when a Market Seller has
      positive net output and delivers energy into the Transmission System, it
      will be paid the locational marginal price (“LMP”) at its bus for that
      hour for all of the energy delivered. Conversely, for each hour when a
      Market Seller has negative net output and has received Station Power from
      the Transmission System, it will pay the LMP at its bus for that hour for
      all of the energy consumed.




(ii)
    Transmission
      Provider will determine the extent to which each affected Market Seller
      during the month self-supplied its Station Power requirements or obtained
      Station Power from third-party providers (including affiliates) and will
      incorporate that determination in its accounting and billing for the
      month. In the event that a Market Seller self-supplies Station Power
      during any month in the manner described in clause (1) of paragraph (d)(i)
      above, Market Seller will not use, and will not incur any charges for,
      transmission service. In the event, and to the extent, that a Market
      Seller self-supplies Station Power during any month in the manner
      described in clause (2) of paragraph (d)(i) above (hereafter referred to
      as “remote self-supply of Station Power”), Market Seller shall use and pay
      for transmission service for the transmission of energy in an amount equal
      to the facility’s negative net output from Market Seller’s generation
      facility(ies) having positive net output. Unless the Market Seller makes
      other arrangements with Transmission Provider in advance, such
      transmission service shall be provided under Part II of the PJM Tariff and
      shall be charged the hourly rate under Schedule 8 of the PJM Tariff for
      non-firm point-to-point transmission service with an election to pay
      congestion charges, provided, however, that no reservation shall be
      necessary for such transmission service and the terms and charges under
      Schedules 1, 1A, 2 through 6, 9 and 10 of the PJM Tariff shall not apply
      to such service. The amount of energy that a Market Seller transmits in
      conjunction with remote self-supply of Station Power will not be affected
      by any other sales, purchases, or transmission of capacity or energy by or
      for such Market Seller under any other provisions of the PJM Tariff.




(iii)
    A Market
      Seller may self-supply Station Power from its generation facilities
      located outside of the PJM Region during any month only if such generation
      facilities in fact run during such month and Market Seller separately has
      reserved transmission service and scheduled delivery of the energy from
      such resource in advance into the PJM Region.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1,
  2004Vice President, Government
    PolicyIssued On:
    
    April 30,
    2004




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PJM Interconnection, L.L.C.
    
    First
      Revised Second Revised Sheet No. 82Third Revised Rate
      Schedule FERC No. 24
    
    Superseding Second Revised Sheet No. 82




1.7.11 Emergencies.



(a)
    The Office
      of the Interconnection, with the assistance of the Members’ dispatchers as
      it may request, shall be responsible for monitoring the operation of the
      PJM Region, for declaring the existence of an Emergency, and for directing
      the operations of Market Participants as necessary to manage, alleviate or
      end an Emergency. The standards, policies and procedures of the Office of
      the Interconnection for declaring the existence of an Emergency, including
      but not limited to a Minimum Generation Emergency, and for managing,
      alleviating or ending an Emergency, shall apply to all Members on a
      non-discriminatory basis. Actions by the Office of the Interconnection and
      the Market Participants shall be carried out in accordance with this
      Agreement, the NERC Operating Policies, Applicable Regional Reliability
      Council reliability principles and standards, Good Utility Practice, and
      the PJM Manuals. A declaration that an Emergency exists or is likely to
      exist by the Office of the Interconnection shall be binding on all Market
      Participants until the Office of the Interconnection announces that the
      actual or threatened Emergency no longer exists. Consistent with existing
      contracts, all Market Participants shall comply with all directions from
      the Office of the Interconnection for the purpose of managing, alleviating
      or ending an Emergency. The Market Participants shall authorize the Office
      of the Interconnection to purchase or sell energy on their behalf to meet
      an Emergency, and otherwise to implement agreements with other Control
      Areas interconnected with the PJM Region for the mutual provision of
      service to meet an Emergency, in accordance with this Agreement.




(b)
    To the
      extent load must be shed to alleviate an Emergency in a Control Zone, the
      Office of the Interconnection shall, to the maximum extent practicable,
      direct the shedding of load within such Control Zone. The Office of the
      Interconnection may shed load in one Control Zone to alleviate an
      Emergency in another Control Zone under its control only as necessary
      after having first shed load to the maximum extent practicable in the
      Control Zone experiencing the Emergency and only to the extent that PJM
      supports other control areas (not under its control) in those situations
      where load shedding would be necessary, such as to prevent isolation of
      facilities within the Eastern Interconnection, to prevent voltage
      collapse, or to restore system frequency following a system collapse;
      provided, however, that the Office of the Interconnection may not order a
      manual load dump in a Control Zone solely to address capacity deficiencies
      in another Control Zone. This paragraph shall be implemented consistent
      with North American Electic Reliability Council and applicable reliability
      council standards.




1.7.12 Fees and Charges.



Each Market Participant shall pay all fees and
charges of the Office of the Interconnection for operation of the PJM
Interchange Energy Market as determined by and allocated to the Market
Participant by the Office of the Interconnection in accordance with Schedule 3.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1,
      2004




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 82AThird Revised Rate
      Schedule FERC No. 24




1.7.13 Relationship to the PJM Region.



The PJM Interchange Energy Market operates within
and subject to the requirements for the operation of the PJM Region.



1.7.14 PJM Manuals.



The Office of the Interconnection shall be
responsible for maintaining, updating, and promulgating the PJM Manuals as they
relate to the operation of the PJM Interchange Energy



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1,
      2004Vice President, Government
    PolicyIssued On:
    
    September 1,
      2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 83Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 83




Market. The PJM Manuals, as they relate to the
operation of the PJM Interchange Energy Market, shall conform and comply with
this Agreement, NERC operating policies, and Applicable Regional Reliability
Council reliability principles, guidelines and standards, and shall be designed
to facilitate administration of an efficient energy market within industry
reliability standards and the physical capabilities of the PJM Region.



1.7.15 Corrective Action.



Consistent with Good Utility Practice, the Office
of the Interconnection shall be authorized to direct or coordinate corrective
action, whether or not specified in the PJM Manuals, as necessary to alleviate
unusual conditions that threaten the integrity or reliability of the PJM Region,
or the regional power system.



1.7.16 Recording.



Subject to the requirements of applicable State or
federal law, all voice communications with the Office of the Interconnection
Control Center may be recorded by the Office of the Interconnection and any
Market Participant communicating with the Office of the Interconnection Control
Center, and each Market Participant hereby consents to such recording.



1.7.17 Operating Reserves.



(a) The following procedures shall apply to any
generation unit subject to the dispatch of the Office of the Interconnection for
which construction commenced before July 9, 1996.



(b) The Office of the Interconnection shall
schedule to the Operating Reserve and load-following objectives of the Control
Zones of the PJM Region and the PJM Interchange Energy Market in scheduling
resources pursuant to this Schedule. A table of Operating Reserve objectives for
each Control Zone is calculated seasonally for various peak load levels and
eight weekly periods and is published in the PJM Manuals. Reserve levels are
probabilistically determined based on the season’s historical load forecasting
error and expected generation mix (including typical Planned and
Forced/Unplanned Outages). Operating Reserve objectives will be determined for
the ECAR Control Zone(s) and MAIN Control Zone(s), in accordance with ECAR and
MAIN requirements, respectively. Generating Units with quick start capability,
as specified in the PJM Manuals, that are dispatched to maintain reliability by
providing load following capability shall receive energy payments at the levels
specified below. The energy payments specified below shall be considered the
offered price for Spot Market Energy for purposes of Section 3.2.3(b) of this
Schedule. The price offered or paid for the energy of units so dispatched shall
not be considered in determining Locational Marginal Prices.



(c) Payments for energy produced by a quick start
generating unit dispatched as specified above shall be at the higher of the
applicable Locational Marginal Price or one of the amounts specified below, as
specified in advance by the Market Seller for the affected unit:



(i)
    The weighted average
      Locational Marginal Price at the generation bus at which energy from the
      capped resource was delivered during a specified number of hours during
      which the resource was dispatched for energy in economic merit order, the
      specified number of hours to be determined by the Office of the
      Interconnection and to be a number of hours sufficient to result




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 84Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 84




in a price cap that reflects
      reasonably contemporaneous competitive market conditions for that unit;




(ii)
    The
      incremental operating cost of the generation resource as determined in
      accordance with Schedule 2 of this Agreement and the PJM Manuals, plus 10%
      of such costs; or




(iii)
    An amount
      determined by agreement between the Office of the Interconnection and the
      Market Seller.




1.7.18 Regulation.



(a) Regulation to meet the Regulation objective of
each Regulation Zone shall be supplied from generators located within the
metered electrical boundaries of such Regulation Zone. Generating Market Buyers,
and Market Sellers offering Regulation, shall comply with applicable standards
and requirements for Regulation capability and dispatch specified in the PJM
Manuals.



(b) The Office of the Interconnection shall obtain
and maintain for each Regulation Zone an amount of Regulation equal to the
Regulation objective for such Regulation Zone as specified in the PJM Manuals.



(c) The Regulation range of a unit shall be at
least twice the amount of Regulation assigned.



(d) A unit capable of automatic energy dispatch
that is also providing Regulation shall have its energy dispatch range reduced
by twice the amount of the Regulation provided. The amount of Regulation
provided by a unit shall serve to redefine the Normal Minimum Generation and
Normal Maximum Generation energy limits of that unit, in that the amount of
Regulation shall be added to the unit’s Normal Minimum Generation energy limit,
and subtracted from its Normal Maximum Generation energy limit.



(e) Qualified Regulation must satisfy the
verification tests described in the PJM Manuals.



1.7.19 Ramping.



A generator dispatched by the Office of the
Interconnection pursuant to a control signal appropriate to increase or decrease
the generator’s megawatt output level shall be able to change output at the
ramping rate specified in the Offer Data submitted to the Office of the
Interconnection for that generator.



1.7.19A Spinning Reserve.



a) Spinning Reserve shall be supplied from
generators located within the metered boundaries of the PJM Region. Generating
Market Buyers, and Market Sellers offering Spinning Reserve shall comply with
applicable standards and requirements for Spinning Reserve capability and
dispatch specified in the PJM Manuals.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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PJM Interconnection, L.L.C.
    
    First
      Revised Fourth Revised Sheet No. 85Third Revised Rate Schedule FERC No.
      24
    
    Superseding Fourth Revised Sheet No. 85




b) The Office of the Interconnection shall obtain
and maintain for each Spinning Reserve Zone an amount of Spinning Reserve equal
to the Spinning Reserve objective for such Spinning Reserve Zone, as specified
in the PJM Manuals.



c) The Spinning Reserve capability of a unit shall
be the increase in energy output achievable by the unit within a continuous
10-minute period.



d) A unit capable of automatic energy dispatch
that also is providing Spinning Reserve shall have its energy dispatch range
reduced by the amount of the Spinning Reserve provided. The amount of Spinning
Reserve provided by a unit shall serve to redefine the Normal Maximum Generation
energy limit of that unit in that the amount of Spinning Reserve provided shall
be subtracted from its Normal Maximum Generation energy limit.



1.7.20 Communication and Operating
Requirements.



(a) Market Participants. Each Market Participant
shall have, or shall arrange to have, its transactions in the PJM Interchange
Energy Market subject to control by a Market Operations Center, with staffing
and communications systems capable of real-time communication with the Office of
the Interconnection during normal and Emergency conditions and of control of the
Market Participant’s relevant load or facilities sufficient to meet the
requirements of the Market Participant’s transactions with the PJM Interchange
Energy Market, including but not limited to the following requirements as
applicable.



(b) Market Sellers selling from resources within
the PJM Region shall: report to the Office of the Interconnection sources of
energy available for operation; supply to the Office of the Interconnection all
applicable Offer Data; report to the Office of the Interconnection units that
are self-scheduled; report to the Office of the Interconnection bilateral sales
transactions to buyers not within the PJM Region; confirm to the Office of the
Interconnection bilateral sales to Market Buyers within the PJM Region; respond
to the Office of the Interconnection’s directives to start, shutdown or change
output levels of generation units, or change scheduled voltages or reactive
output levels; continuously maintain all Offer Data concurrent with on-line
operating information; and ensure that, where so equipped, generating equipment
is operated with control equipment functioning as specified in the PJM Manuals.



(c) Market Sellers selling from resources outside
the PJM Region shall: provide to the Office of the Interconnection all
applicable Offer Data, including offers specifying amounts of energy available,
hours of availability and prices of energy and other services; respond to Office
of the Interconnection directives to schedule delivery or change delivery
schedules; and communicate delivery schedules to the Market Seller’s Control
Area.



(d) Market Participants that are Load Serving
Entities or purchasing on behalf of Load Serving Entities shall: respond to
Office of the Interconnection directives for load management steps; report to
the Office of the Interconnection Capacity Resources to satisfy capacity
obligations that are available for pool operation; report to the Office of the
Interconnection all bilateral purchase transactions; respond to other Office of
the Interconnection directives such as those required during Emergency
operation.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 86Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 86




(e) Market Participants that are not Load Serving
Entities or purchasing on behalf of Load Serving Entities shall: provide to the
Office of the Interconnection requests to purchase specified amounts of energy
for each hour of the Operating Day during which it intends to purchase from the
PJM Interchange Energy Market, along with Dispatch Rate levels above which it
does not desire to purchase; respond to other Office of the Interconnection
directives such as those required during Emergency operation.



1.8 Selection, Scheduling and Dispatch
Procedure Adjustment Process



1.8.1 PJM Dispute Resolution Agreement.



Subject to the condition specified below, any
Member adversely affected by a decision of the Office of the Interconnection
with respect to the operation of the PJM Interchange Energy Market, including
the qualification of an entity to participate in that market as a buyer or
seller, may seek such relief as may be appropriate under the PJM Dispute
Resolution Procedures on the grounds that such decision does not have an
adequate basis in fact or does not conform to the requirements of this
Agreement.



1.8.2 Market or Control Area Hourly Operational
Disputes.



(a) Market Participants shall comply with all
determinations of the Office of the Interconnection on the selection, scheduling
or dispatch of resources in the PJM Interchange Energy Market, or to meet the
operational requirements of the PJM Region. Complaints arising from or relating
to such determinations shall be brought to the attention of the Office of the
Interconnection not later than the end of the fifth business day after the end
of the Operating Day to which the selection or scheduling relates, or in which
the scheduling or dispatch took place, and shall include, if practicable, a
proposed resolution of the complaint. Upon receiving notification of the
dispute, the Office of the Interconnection and the Market Participant raising
the dispute shall exert their best efforts to obtain and retain all data and
other information relating to the matter in dispute, and to notify other Market
Participants that are likely to be affected by the proposed resolution. Subject
to confidentiality or other non-disclosure requirements, representatives of the
Office of the Interconnection, the Market Participant raising the dispute, and
other interested Market Participants, shall meet within three business days of
the foregoing notification, or at such other or further times as the Office of
the Interconnection and the Market Participants may agree, to review the
relevant facts, and to seek agreement on a resolution of the dispute.



(b) If the Office of the Interconnection
determines that the matter in dispute discloses a defect in operating policies,
practices or procedures subject to the discretion of the Office of the
Interconnection, the Office of the Interconnection shall implement such changes
as it deems appropriate and shall so notify the Members Committee.
Alternatively, the Office of the Interconnection may notify the Members
Committee of a proposed change and solicit the comments or other input of the
Members.



(c) If either the Office of the Interconnection,
the Market Participant raising the dispute, or another affected Market
Participant believes that the matter in dispute has not been



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Third
      Revised Sheet No. 87Third Revised Rate Schedule FERC No.
      24
    
    
    
    Superseding Original Sheet No. 87




adequately resolved, or discloses a need for
changes in standards or policies established in or pursuant to the Operating
Agreement, any of the foregoing parties may make a written request for review of
the matter by the Members Committee, and shall include with the request the
forwarding party’s recommendation and such data or information (subject to
confidentiality or other non-disclosure requirements) as would enable the
Members Committee to assess the matter and the recommendation. The Members
Committee shall take such action on the recommendation as it shall deem
appropriate.



(d) Subject to the right of a Market Participant
to obtain correction of accounting or billing errors, the LLC or a Market
Participant shall not be entitled to actual, compensatory, consequential or
punitive damages, opportunity costs, or other form of reimbursement from the LLC
or any other Market Participant for any loss, liability or claim, including any
claim for lost profits, incurred as a result of a mistake, error or other fault
by the Office of the Interconnection in the selection, scheduling or dispatch of
resources.



1.9 Prescheduling.



The following procedures and principles shall
govern the prescheduling activities necessary to plan for the reliable operation
of the PJM Region and for the efficient operation of the PJM Interchange Energy
Market.



1.9.1 Outage Scheduling.



The Office of the Interconnection shall be
responsible for coordinating and approving requests for outages of generation
and transmission facilities as necessary for the reliable operation of the PJM
Region, in accordance with the PJM Manuals. The Office of the Interconnection
shall maintain records of outages and outage requests of these facilities.



1.9.2 Planned Outages.



(a) A Generator Planned Outage shall be included
in Generator Planned Outage schedules established prior to the scheduled start
date for the outage, in accordance with standards and procedures specified in
the PJM Manuals.



(b) The Office of the Interconnection shall
conduct Generator Planned Outage scheduling for Capacity Resources in accordance
with the Reliability Assurance Agreement, the Reliability Assurance
Agreement-West, and the PJM Manuals and in consultation with the Members owning
or controlling the output of Capacity Resources. A Market Participant shall not
be expected to submit offers for the sale of energy or other services, or to
satisfy delivery obligations, from all or part of a generation resource
undergoing an approved Generator Planned Outage. If the Office of the
Interconnection determines that approval of a Generator Planned Outage would
significantly affect the reliable operation of the PJM Region, the Office of the
Interconnection may withhold approval or withdraw a prior approval. Approval for
a Generator Planned Outage of a Capacity Resource shall be withheld or withdrawn
only as necessary to ensure the adequacy of reserves or the reliability of the
PJM Region in connection with anticipated implementation or avoidance of
Emergency procedures. If the Office of the Interconnection withholds or
withdraws approval, it shall coordinate with the Market Participant owning or
controlling the resource to reschedule the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 88Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 88




Generator Planned Outage of the Capacity Resource
at the earliest practical time. The Office of the Interconnection shall if
possible propose alternative schedules with the intent of minimizing the
economic impact on the Market Participant of a Generator Planned Outage.



(c) The Office of the Interconnection shall
conduct Transmission Planned Outage scheduling in accordance with procedures
specified in, as applicable, the East Transmission Owners Agreement or West
Transmission Owners Agreement and the PJM Manuals, and in accordance with the
following procedures:



(i)
    Transmission
      Owners shall submit Transmission Planned Outage schedules one year in
      advance for all outages that are expected to exceed five working days
      duration or that are anticipated to result in significant system impacts,
      with regular (at least monthly) updates as new information becomes
      available.




(ii)
    Transmission
      Owners shall submit notice of all Transmission Planned Outages to the
      Office of the Interconnection by the first day of the month preceding the
      month the outage will commence, with updates as new information becomes
      available.




(iii)
    If notice of
      a Transmission Planned Outage is not provided by the first day of the
      month preceding the month the outage will commence, and if such outage is
      determined by the Office of the Interconnection to have the potential to
      cause transmission system congestion, then the Office of the
      Interconnection may require the Transmission Owner to implement an
      alternative outage schedule to reduce or avoid the congestion. The Office
      of the Interconnection shall perform this analysis and notify the
      Transmission Owner in a timely manner if it will require rescheduling of
      the outage.




(iv)
    The Office
      of the Interconnection shall post notice of Transmission Planned Outages
      on OASIS upon receipt of such notice from the Transmission Owner;
      provided, however, that the Office of the Interconnection shall not post
      on OASIS notice of any component of a Transmission Planned Outage to the
      extent such component shall directly reveal a generator outage. In such
      cases, the Transmission Owner, in addition to providing notice to the
      Office of Interconnection as required above, concurrently shall inform the
      affected Generation Owner of such outage, limiting such communication to
      that necessary to describe the outage and to coordinate with the
      Generation Owner on matters of safety to persons, facilities, and
      equipment. The Transmission Owner shall not notify any other Market
      Participant of such outage and shall arrange any other necessary
      coordination through the Office of the Interconnection.




In addition, if the Office of the Interconnection
determines that transmission maintenance schedules proposed by one or more
Members would significantly affect the efficient and reliable operation of the
PJM Region, the Office of the Interconnection may



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Fourth
      Revised Sheet No. 89Third Revised Rate
      Schedule FERC No. 24
    
    Superseding First Revised Sheet No. 89




establish alternative schedules, but such alternative shall minimize the
economic impact on the Member or Members whose maintenance schedules the Office
of the Interconnection proposes to modify.



(d) The Office of the Interconnection shall
coordinate resolution of outage or other planning conflicts that may give rise
to unreliable system conditions. The Members shall comply with all maintenance
schedules established by the Office of the Interconnection.



1.9.3 Generator Maintenance Outages.



A Market Participant may request approval for a
Generator Maintenance Outage of any Capacity Resource from the Office of the
Interconnection in accordance with the timetable and other procedures specified
in the PJM Manuals. The Office of the Interconnection shall approve requests for
Generator Maintenance Outages for a Capacity Resource unless the outage would
threaten the adequacy of reserves in, or the reliability of, the PJM Region. A
Market Participant shall not be expected to submit offers for the sale of energy
or other services, or to satisfy delivery obligations, from a generation
resource undergoing an approved full or partial Generator Maintenance Outage.



1.9.4 Forced Outages.



(a) Each Market Seller that owns or controls a
pool-scheduled resource, or Capacity Resource whether or not pool-scheduled,
shall: (i) advise the Office of the Interconnection of a Generator Forced Outage
suffered or anticipated to be suffered by any such resource as promptly as
possible; (ii) provide the Office of the Interconnection with the expected date
and time that the resource will be made available; and (iii) make a record of
the events and circumstances giving rise to the Generator Forced Outage. A
Market Seller shall not be expected to submit offers for the sale of energy or
other services, or satisfy delivery obligations, from a generation resource
undergoing a Generator Forced Outage. A Capacity Resource that does not deliver
all or part of its scheduled energy shall be deemed to have experienced a
Generator Forced Outage with respect to such undelivered energy, in accordance
with standards and procedures for full and partial Generator Forced Outages
specified in the Reliability Assurance Agreement, the Reliability Assurance
Agreement-West, and the PJM Manuals.



(b) The Office of the Interconnection shall
receive notification of Forced Transmission Outages, and information on the
return to service, of Transmission Facilities in the PJM Region in accordance
with standards and procedures specified in, as applicable, the East Transmission
Owners Agreement or West Transmission Owners Agreement and the PJM Manuals.



1.9.5 Market Participant Responsibilities.



Each Market Participant making a bilateral sale
covering a period greater than the following Operating Day from a generating
resource located within the PJM Region for delivery outside the PJM Region shall
furnish to the Office of the Interconnection, in the form and manner specified
in the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1,
      2004Vice President, Government
    PolicyIssued On:
    
    April 30,
    2004




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 90Third Revised Rate
      Schedule FERC No. 24




PJM Manuals, information regarding the source of
the energy, the load sink, the energy schedule, and the amount of energy being
delivered.



1.9.6 Internal Market Buyer Responsibilities.



Each Internal Market Buyer making a bilateral
purchase covering a period greater than the following Operating Day shall
furnish to the Office of the Interconnection, in the form and manner specified
in the PJM Manuals, information regarding the source of the energy, the load
sink, the energy schedule, and the amount of energy being delivered. Each
Internal Market Buyer shall provide the Office of the Interconnection with
details of any load management agreements with customers that allow the Office
of the Interconnection to reduce load under specified circumstances.



1.9.7 Market Seller Responsibilities.



(a) Not less than 30 days before a Market Seller’s
initial offer to sell energy from a given generation resource on the PJM
Interchange Energy Market, the Market Seller shall furnish to the Office of the
Interconnection the information specified in the Offer Data for new generation
resources.



(b) Market Sellers authorized to request
market-based start-up fees may choose to submit either market-based or
cost-based start-up fees.



(i)
    If a Market
      Seller chooses to submit market-based start-up and no-load fees, such
      Market Seller, in its Offer Data, shall submit a specification of such
      fees to the Office of the Interconnection for each generating unit as to
      which the Market Seller intends to request such fees. Any such
      specification shall be submitted on or before March 31 for the period
      April 1 through September 30, and on or before September 30 for the period
      October 1 through March 31, and shall remain in effect without change
      throughout each such period for which a specification was submitted. The
      Office of the Interconnection shall reject any request for start-up and
      no-load fees in a Market Seller’s Offer Data that does not conform to the
      Market Seller’s specification on file with the Office of the
      Interconnection.




(ii)
    If a Market
      Seller chooses to submit cost-based start-up fees, the start-up fee may be
      changed daily.




1.9.8 Transmission Owner Responsibilities.



All Transmission Owners shall regularly update and
verify facility ratings, subject to review and approval by PJM, in accordance
with the following procedures and the procedures in the PJM Manuals:



(a) Each Transmission Owner shall verify to the
Operations Planning Department (or successor Department) of the Office of the
Interconnection all of its transmission facility ratings two months prior to the
beginning of the summer season (i.e., on April 1) and two months prior to the
beginning of the winter season (i.e., on October 1) each calendar year, and



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20,
      2003Vice President, Governmental
      PolicyIssued On:
    
    March 20,
    2003




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    Superseding Original Sheet No. 91




shall provide detailed data justifying such
transmission facility ratings when directed by the Office of the
Interconnection.



(b) In addition to the seasonal verification of
all ratings, each Transmission Owner shall submit to the Operations Planning
Department (or successor Department) of the Office of the Interconnection
updates to its transmission facility ratings as soon as such Transmission Owner
is aware of any changes. Such Transmission Owner shall provide the Office of the
Interconnection with detailed data justifying all such transmission facility
ratings changes.



(c) All Transmission Owners shall submit to the
Operations Planning Department (or successor Department) of the Office of the
Interconnection formal documentation of any procedure for changing facility
ratings under specific conditions, including: the detailed conditions under
which such procedures will apply, detailed explanations of such procedures, and
detailed calculations justifying such pre-established changes to facility
ratings. Such procedures must be updated twice each year consistent with the
provisions of this Section.



1.9.9 Office of the Interconnection
Responsibilities.



(a) The Office of the Interconnection shall
perform seasonal operating studies to assess the forecasted adequacy of
generating reserves and of the transmission system, in accordance with the
procedures specified in the PJM Manuals.



(b) The Office of the Interconnection shall
maintain and update tables setting forth Operating Reserve and other reserve
objectives as specified in the PJM Manuals and as consistent with the
Reliability Assurance Agreement and Reliability Assurance Agreement-West.



(c) The Office of the Interconnection shall
receive and process requests for firm and non-firm transmission service in
accordance with procedures specified in the PJM Tariff.



(d) The Office of the Interconnection shall
maintain such data and information relating to generation and transmission
facilities in the PJM Region as may be necessary or appropriate to conduct the
scheduling and dispatch of the PJM Interchange Energy Market and PJM Region.



(e) The Office of the Interconnection shall
maintain an historical database of all transmission facility ratings, and shall
review, and may modify or reject, any submitted change or any submitted
procedure for pre-established transmission facility rating changes. Any dispute
between a Transmission Owner and the Office of the Interconnection concerning
transmission facility ratings shall be resolved in accordance with the dispute
resolution procedures in schedule 5 to the Operating Agreement; provided,
however, that the rating level determined by the Office of the Interconnection
shall govern and be effective during the pendency of any such dispute.



(f) The Office of the Interconnection shall
coordinate with other interconnected Control Area as necessary to manage,
alleviate or end an Emergency.



1.10 Scheduling.



1.10.1 General.



(a) The Office of the Interconnection shall
administer scheduling processes to implement a Day-ahead Energy Market and a
Real-time Energy market.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Second
      Revised Sheet No. 92Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 92




(b) The Day-ahead Energy Market shall enable
Market Participants to purchase and sell energy through the PJM Interchange
Energy Market at Day-ahead Prices and enable transmission customers to reserve
transmission service with Transmission Congestion Charges based on locational
differences in Day-ahead Prices. Market Participants whose purchases and sales,
and transmission customers whose transmission uses are scheduled in the
Day-ahead Energy Market, shall be obligated to purchase or sell energy, or pay
Transmission Congestion Charges, at the applicable Day-ahead Prices for the
amounts scheduled.



(c) In the Real-time Energy Market, Market
Participants that deviate from the amounts of energy purchases or sales, or
transmission customers that deviate from the transmission uses, scheduled in the
Day-ahead Energy Market shall be obligated to purchase or sell energy, or pay
Transmission Congestion Charges, for the amount of the deviations at the
applicable Real-time Prices or price differences, unless otherwise specified by
this Schedule.



(d) The following scheduling procedures and
principles shall govern the commitment of resources to the Day-ahead Energy
Market and the Real-time Energy Market over a period extending from one week to
one hour prior to the real-time dispatch. Scheduling encompasses the day-ahead
and hourly scheduling process, through which the Office of the Interconnection
determines the Day-ahead Energy Market and determines, based on changing
forecasts of conditions and actions by Market Participants and system
constraints, a plan to serve the hourly energy and reserve requirements of the
Internal Market Buyers and the purchase requests of the External Market Buyers
in the least costly manner, subject to maintaining the reliability of the PJM
Region. Scheduling shall be conducted as specified below, subject to the
following condition. If the Office of the Interconnection’s forecast for the
next seven days projects a likelihood of Emergency conditions, the Office of the
Interconnection may commit, for all or part of such seven day period, to the use
of generation resources with notification or start-up times greater than one day
as necessary in order to alleviate or mitigate such Emergency, in accordance
with the Market Sellers’ offers for such units for such periods and the
specifications in the PJM Manuals.



1.10.1A Day-ahead Energy Market Scheduling.



The following actions shall occur not later than
12:00 noon on the day before the Operating Day for which transactions are being
scheduled, or such other deadline as may be specified by the Office of the
Interconnection in order to comply with the practical requirements and the
economic and efficiency objectives of the scheduling process specified in this
Schedule.



(a) Each Market Participant may submit to the
Office of the Interconnection specifications of the amount and location of its
customer loads and/or energy purchases to be included in the Day-ahead Energy
Market for each hour of the next Operating Day, such specifications to comply
with the requirements set forth in the PJM Manuals. Each Market Buyer shall
inform the Office of the Interconnection of the prices, if any, at which it
desires not to include its load in the Day-ahead Energy Market rather than pay
the Day-ahead Price.



(b) Each Generating Market Buyer shall submit to
the Office of the Interconnection: (i) hourly schedules for resource increments,
including hydropower units, self-scheduled by the Market Buyer to meet its
Equivalent Load; and (ii) the Dispatch Rate at which



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Third
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    Superseding First Revised Sheet No. 93




each such self-scheduled resource will disconnect
or reduce output, or confirmation of the Market Buyer’s intent not to reduce
output.



(c) All Market Participants shall submit to the
Office of the Interconnection schedules for any bilateral transactions involving
use of generation or Transmission Facilities as specified below, and shall
inform the Office of the Interconnection whether the transaction is to be
included in the Day-ahead Energy market. Any Market Participant that elects to
include a bilateral transaction in the Day-ahead Energy Market may specify the
price (such price not to exceed the maximum price that may be specified in the
PJM Manuals), if any, at which it will be wholly or partially curtailed rather
than pay Transmission Congestion Charges. The foregoing price specification
shall apply to the price difference between the specified bilateral transaction
source and sink points in the day-ahead scheduling process only. Any Market
Participant that elects not to include its bilateral transaction in the
Day-ahead Energy Market shall inform the Office of the Interconnection if the
parties to the transaction are not willing to incur Transmission Congestion
Charges in the Real-time Energy Market in order to complete any such scheduled
bilateral transaction. Scheduling of bilateral transactions shall be conducted
in accordance with the specifications in the PJM Manuals and the following
requirements:



i)
    Internal
      Market Buyers shall submit schedules for all bilateral purchases for
      delivery within the PJM Region, whether from generation resources inside
      or outside the PJM Region;




ii)
    Market
      Sellers shall submit schedules for bilateral sales to entities outside the
      PJM Region from generation within the PJM Region that is not dynamically
      scheduled to such entities pursuant to Section 1.12; and




iii)
    In addition
      to the foregoing schedules for bilateral transactions, Market Participants
      shall submit confirmations of each scheduled bilateral transaction from
      each other party to the transaction in addition to the party submitting
      the schedule, or the adjacent Control Area.




(d) Market Sellers wishing to sell into the
Day-ahead Energy Market shall submit offers for the supply of energy (including
energy from hydropower units), Regulation, Operating Reserves or other services
for the following Operating Day. Offers shall be submitted to the Office of the
Interconnection in the form specified by the Office of the Interconnection and
shall contain the information specified in the Office of the Interconnection’s
Offer Data specification, as applicable. Market Sellers owning or controlling
the output of a Capacity Resource that has not been rendered unavailable by a
Generation Planned Outage, a Generator Maintenance Outage, or a Generation
Forced Outage shall submit offers for the available capacity of such Capacity
Resource, including any portion that is self-scheduled by the Generating Market
Buyer claiming the resource as a Capacity Resource. The submission of offers for
resource increments that are not Capacity Resources shall be optional, but any
such offers must contain the information specified in the Office of the
Interconnection’s Offer Data specification, as applicable. Energy offered from
generation resources that are not Capacity Resources shall not be supplied from
resources that are included in or otherwise committed



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Superseding First Revised Third Revised Sheet No.
94




to supply the Operating Reserves of a Control Area
outside the PJM Region. The foregoing offers:



i)
    Shall
      specify the generation resource and energy for each hour in the offer
      period;




ii)
    Shall
      specify the amounts and prices for the entire Operating Day for each
      resource component offered by the Market Seller to the Office of the
      Interconnection;




iii)
    If based on
      energy from a specific generating unit, may specify start-up and no-load
      fees equal to the specification of such fees for such unit on file with
      the Office of the Interconnection;




iv)
    Shall set
      forth any special conditions upon which the Market Seller proposes to
      supply a resource increment, including any curtailment rate specified in a
      bilateral contract for the output of the resource, or any cancellation
      fees;




v)
    May include
      a schedule of offers for prices and operating data contingent on
      acceptance by the deadline specified in this Schedule, with a second
      schedule applicable if accepted after the foregoing deadline;




vi)
    Shall
      constitute an offer to submit the resource increment to the Office of the
      Interconnection for scheduling and dispatch in accordance with the terms
      of the offer, which offer shall remain open through the Operating Day for
      which the offer is submitted;




vii)
    Shall be
      final as to the price or prices at which the Market Seller proposes to
      supply energy or other services to the PJM Interchange Energy Market, such
      price or prices being guaranteed by the Market Seller for the period
      extending through the end of the following Operating Day; and




viii)
    Shall not
      exceed an energy offer price of $1,000/megawatt-hour.




(e) A Market Seller that wishes to make a resource
available to sell Regulation service shall submit an offer for Regulation that
shall specify the MW of Regulation being offered, the Regulation Zone for which
such regulation is offered, the price of the offer in dollars per MWh, and such
other information specified by the Office of the Interconnection as may be
necessary to evaluate the offer and the resource’s opportunity costs. The price
of the offer shall not exceed $100 per MWh in the case of regulation offered for
the MAAC Control Zone. Regulation offered for any Regulation Zone comprised of
the ECAR Control Zone(s), or MAIN Control Zone(s) shall be cost-based (including
opportunity costs) plus seven dollars and fifty cents until such time as
market-based pricing is approved for regulation in such Regulation Zone.
Qualified Regulation capability must satisfy the verification tests specified in
the PJM Manuals.



(f) Each Market Seller owning or controlling the
output of a Capacity Resource shall submit a forecast of the availability of
each such Capacity Resource for the next seven days. A Market Seller (i) may
submit a non-binding forecast of the price at which it expects to offer a
generation resource increment to the Office of the Interconnection over the next
seven days, and (ii) shall submit a binding offer for energy, along with
start-up and no-load fees, if any, for the next seven days or part thereof, for
any generation resource with minimum notification or start-up requirement
greater than 24 hours.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1,
      2004Vice President, Government
    PolicyIssued On:
    
    January ,
      2005Note: This
      sheet includes language accepted by the Commission which will be included
      in a clean up filing.




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    Second
      Revised Sheet No. 95Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 95




(g) Each offer by a Market Seller of a Capacity
Resource shall remain in effect for subsequent Operating Days until superseded
or canceled.



(h) The Office of the Interconnection shall post
on the PJM Open Access Same-time Information System the total hourly loads
scheduled in the Day-ahead Energy Market, as well as, its estimate of the
combined hourly load of the Market Buyers for the next four days, and peak load
forecasts for an additional three days.



(i) All Market Participants may submit Increment
Bids and/or Decrement Bids that apply to the Day-ahead Energy Market only. Such
bids must comply with the requirements set forth in the PJM Manuals and must
specify amount, location and price, if any, at which the Market Participant
desires to purchase or sell energy in the Day-ahead Energy Market. The Office of
the Interconnection may require that a market participant shall not submit in
excess of 3000 bid/offer segments in the Day-ahead Energy Market, when the
Office of the Interconnection determines that such limit is required to avoid or
mitigate significant system performance problems related to bid/offer volume.
Notice of the need to impose such limit shall be provided prior to 10:00 a.m.
EPT on the day that the Day-ahead Energy Market will clear. For purposes of this
provision, a bid/offer segment is each pairing of price and megawatt quantity
submitted as part of an Increment Bid or Decrement Bid.



(j) A Market Seller that wishes to make a resource
available to sell Spinning Reserve shall submit an offer for Spinning Reserve
that shall specify the megawatt of Spinning Reserve being offered, the price of
the offer in dollars per megawatt hour, and such other information specified by
the Office of the Interconnection as may be necessary to evaluate the offer and
the energy used by the resource to provide the Spinning Reserve and the
resource’s unit specific opportunity costs. The price of the offer shall not
exceed the variable operating and maintenance costs for providing Spinning
Reserve plus seven dollars and fifty cents.



1.10.2 Pool-scheduled Resources.



Pool-scheduled resources are those resources for
which Market Participants submitted offers to sell energy in the Day-ahead
Energy Market and which the Office of the Interconnection scheduled in the
Day-ahead Energy Market as well as generators committed by the Office of the
Interconnection subsequent to the Day-ahead Energy Market. Such resources shall
be committed to provide energy in the real-time dispatch unless the schedules
for such units are revised pursuant to Sections 1.10.9 or 1.11. Pool-scheduled
resources shall be governed by the following principles and procedures.



(a) Pool-scheduled resources shall be selected by
the Office of the Interconnection on the basis of the prices offered for energy
and related services, start-up, no-load and cancellation fees, and the specified
operating characteristics, offered by Market Sellers to the Office of the
Interconnection by the offer deadline specified in Section 1.10.1A.



(b) A resource that is scheduled by a Market
Participant to support a bilateral sale, or that is self-scheduled by a
Generating Market Buyer, shall not be selected by the Office of the
Interconnection as a pool-scheduled resource except in an Emergency.



(c) Market Sellers offering energy from hydropower
or other facilities with fuel or environmental limitations may submit data to
the Office of the Interconnection that is sufficient to enable the Office of the
Interconnection to determine the available operating hours of such facilities.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 17, 2003Vice President, Governmental
      PolicyIssued On:
    
    September 22, 2003




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    Original
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(d) The Market Seller of a resource selected as a
pool-scheduled resource shall receive payments or credits for energy or related
services, or for start-up and no-load fees, from the Office of the
Interconnection on behalf of the Market Buyers in accordance with Section 3 of
this Schedule 1. Alternatively, the Market Seller shall receive, in lieu of
start-up and no-load fees, its actual costs incurred, if any, up to a cap of the
resource’s start-up cost, if the Office of the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 17, 2003Vice President, Governmental
      PolicyIssued On:
    
    September 22, 2003




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    Third
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    Superseding First Revised Sheet No. 96




Interconnection cancels its selection of the
resource as a pool-scheduled resource and so notifies the Market Seller before
the resource is synchronized.



(e) Market Participants shall make available their
pool-scheduled resources to the Office of the Interconnection for coordinated
operation to supply the Operating Reserves needs of the applicable Control Zone.



1.10.3 Self-scheduled Resources.



Self-scheduled resources shall be governed by the
following principles and procedures.



(a) Each Generating Market Buyer shall use all
reasonable efforts, consistent with Good Utility Practice, not to self-schedule
resources in excess of its Equivalent Load.



(b) The offered prices of resources that are
self-scheduled, or otherwise not following the dispatch orders of the Office of
the Interconnection, shall not be considered by the Office of the
Interconnection in determining Locational Marginal Prices.



(c) Market Participants shall make available their
self-scheduled resources to the Office of the Interconnection for coordinated
operation to supply the Operating Reserves needs of the applicable Control Zone,
by submitting an offer as to such resources.



(d) A Market Participant self-scheduling a
resource in the Day-ahead Energy Market that does not deliver the energy in the
Real-time Energy Market, shall replace the energy not delivered with energy from
the Real-time Energy Market and shall pay for such energy at the applicable
Real-time Price.



1.10.4 Capacity Resources.



(a) A Capacity Resource selected as a
pool-scheduled resource shall be made available for scheduling and dispatch at
the direction of the Office of the Interconnection. A Capacity Resource that
does not deliver energy as scheduled shall be deemed to have experienced a
Generator Forced Outage to the extent of such energy not delivered. A Market
Participant offering such Capacity Resource in the Day-ahead Energy Market shall
replace the energy not delivered with energy from the Real-time Energy Market
and shall pay for such energy at the applicable Real-time Price.



(b) Energy from a Capacity Resource that has not
been scheduled in the Day-ahead Energy Market may be sold on a bilateral basis
by the Market Seller, may be self-scheduled, or may be offered for dispatch
during the Operating Day in accordance with the procedures specified in this
Schedule. A Capacity Resource that has not been scheduled in the Day-ahead
Energy Market and that has been sold on a bilateral basis must be made available
upon request to the Office of the Interconnection for scheduling and dispatch
during the Operating Day if the Office of the Interconnection declares a Maximum
Generation Emergency. Any such resource so scheduled and dispatched shall
receive the applicable Real-time Price for energy delivered.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Superseding First Revised Sheet No. 97




(c) A Capacity Resource that has been
self-scheduled shall not receive payments or credits for start-up or no-load
fees.



1.10.5 External Resources.



(a) External Resources may submit offers to the
PJM Interchange Energy Market, in accordance with the day-ahead and real-time
scheduling processes specified above. An External Resource selected as a
pool-scheduled resource shall be made available for scheduling and dispatch at
the direction of the Office of the Interconnection, and except as specified
below shall be compensated on the same basis as other pool-scheduled resources.
External Resources that are not capable of dynamic dispatch shall, if selected
by the Office of the Interconnection on the basis of the Market Seller’s Offer
Data, be block loaded on an hourly scheduled basis. Market Sellers shall offer
External Resources to the PJM Interchange Energy Market on either a
resource-specific or an aggregated resource basis. A Market Participant whose
pool-scheduled resource does not deliver the energy scheduled in the Day-ahead
Energy Market shall replace such energy not delivered as scheduled in the
Day-ahead Energy Market with energy from the PJM Real-time Energy Market and
shall pay for such energy at the applicable Real-time Price.



(b) Offers for External Resources from an
aggregation of two or more generating units shall so indicate, and shall
specify, in accordance with the Offer Data requirements specified by the Office
of the Interconnection: (i) energy prices; (ii) hours of energy availability;
(iii) a minimum dispatch level; (iv) a maximum dispatch level; and (v) unless
such information has previously been made available to the Office of the
Interconnection, sufficient information, as specified in the PJM Manuals, to
enable the Office of the Interconnection to model the flow into the PJM Region
of any energy from the External Resources scheduled in accordance with the Offer
Data. If a Market Seller submits more than one offer on an aggregated resource
basis, the withdrawal of any such offer shall be deemed a withdrawal of all
higher priced offers for the same period.



(c) Offers for External Resources on a
resource-specific basis shall specify the resource being offered, along with the
information specified in the Offer Data as applicable.



1.10.6 External Market Buyers.



(a) Deliveries to an External Market Buyer not
subject to dynamic dispatch by the Office of the Interconnection shall be
delivered on a block loaded basis to the load bus or buses at the electrical
boundaries of the PJM Region, or in such area with respect to an External Market
Buyer’s load within such area not served by Network Service, at which the energy
is delivered to or for the External Market Buyer. External Market Buyers shall
be charged or credited at either the Day-ahead Prices or Real-time Prices,
whichever is applicable, for energy at the foregoing load bus or buses.



(b) An External Market Buyer’s hourly schedules
for energy purchased from the PJM Interchange Energy Market shall conform to the
ramping and other applicable requirements of the interconnection agreement
between the PJM Region and the Control Area to which, whether as an intermediate
or final point of delivery, the purchased energy will initially be delivered.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Superseding Original Sheet No. 98




(c) The Office of the Interconnection shall
curtail deliveries to an External Market Buyer if necessary to maintain
appropriate reserve levels for a Control Zone as defined in the PJM Manuals, or
to avoid shedding load in such Control Zone.



1.10.6A Transmission Loading Relief Customers.



(a) An entity that desires to elect to pay
Transmission Congestion Charges in order to continue its energy schedules during
an Operating Day over contract paths outside the PJM Region in the event that
PJM initiates Transmission Loading Relief that otherwise would cause PJM to
request security coordinators to curtail such Member’s energy schedules shall:



(i)
    enter its
      election on OASIS by 12:00 p.m. of the day before the Operating Day, in
      accordance with procedures established by PJM, which election shall be
      applicable for the entire Operating Day; and




(ii)
    if PJM
      initiates Transmission Loading Relief, provide to PJM, at such time and in
      accordance with procedures established by PJM, the hourly integrated
      energy schedules that impacted the PJM Region (as indicated from the NERC
      Interchange Distribution Calculator) during the Transmission Loading
      Relief.




(b) If an entity has made the election specified
in Section (a), then PJM shall not request security coordinators to curtail such
entity’s energy transactions, except as may be necessary to respond to
Emergencies.



(c) In order to make elections under this Section
1.10.6A, an entity must (i) have met the creditworthiness standards established
by the Office of the Interconnection or provided a letter of credit or other
form of security acceptable to the Office of the Interconnection, and (ii) have
executed either the Agreement, a Service Agreement under the PJM Tariff, or
other agreement committing to pay all Transmission Congestion Charges incurred
under this Section.



1.10.7 Bilateral Transactions.



Bilateral transactions as to which the parties
have notified the Office of the Interconnection by the deadline specified in
Section 1.10.1A that they elect not to be included in the Day-ahead Energy
Market and that they are not willing to incur Transmission Congestion Charges in
the Real-time Energy Market shall be curtailed by the Office of the
Interconnection as necessary to reduce or alleviate transmission congestion.
Bilateral transactions that were not included in the Day-ahead Energy Market and
that are willing to incur congestion charges and bilateral transactions that
were accepted in the Day-ahead Energy Market shall continue to be implemented
during periods of congestion, except as may be necessary to respond to
Emergencies.



1.10.8 Office of the Interconnection
Responsibilities.



(a) The Office of the Interconnection shall use
its best efforts to determine (i) the least-cost means of satisfying the
projected hourly requirements for energy, Operating Reserves, and other
ancillary services of the Market Buyers, including the reliability requirements
of the PJM



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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      24
    
    Superseding Third Revised Sheet No. 99




Region, of the Day-ahead Energy Market, and (ii)
the least-cost means of satisfying the Operating Reserve and other ancillary
service requirements for any portion of the load forecast of the Office of the
Interconnection for the Operating Day in excess of that scheduled in the
Day-ahead Energy Market. In making these determinations, the Office of the
Interconnection shall take into account: (i) the Office of the Interconnection’s
forecasts of PJM Interchange Energy Market and PJM Control Area, and PJM West
Region energy requirements, giving due consideration to the energy requirement
forecasts and purchase requests submitted by Market Buyers; (ii) the offers
submitted by Market Sellers; (iii) the availability of limited energy resources;
(iv) the capacity, location, and other relevant characteristics of
self-scheduled resources; (v) the objectives of each Control for Operating
Reserves, as specified in the PJM Manuals; (vi) the requirements of each
Regulation Zone for Regulation and other ancillary services, as specified in the
PJM Manuals; (vii) the benefits of avoiding or minimizing transmission
constraint control operations, as specified in the PJM Manuals; and (viii) such
other factors as the Office of the Interconnection reasonably concludes are
relevant to the foregoing determination, including, without limitation,
transmission constraints on external coordinated flowgates to the extent
provided by section 1.7.6. The Office of the Interconnection shall develop a
Day-ahead Energy Market based on the foregoing determination, and shall
determine the Day-ahead Prices resulting from such schedule. The Office of the
Interconnection shall report the planned schedule for a hydropower resource to
the operator of that resource as necessary for plant safety and security, and
legal limitations on pond elevations.



(b) Not later than 4:00 p.m. of the day before
each Operating Day, or such earlier deadline as may be specified by the Office
of the Interconnection in the PJM Manuals, the Office of the Interconnection
shall: (i) post the aggregate Day-ahead Energy Market; (ii) post the Day-ahead
Prices; and (iii) inform the Market Sellers and Market Buyers of their scheduled
injections and withdrawals respectively.



(c) Following posting of the information specified
in Section 1.10.8(b), the Office of the Interconnection shall revise its
schedule of generation resources to reflect updated projections of load,
conditions affecting electric system operations in the PJM Region, the
availability of and constraints on limited energy and other resources,
transmission constraints, and other relevant factors. The Office of the
Interconnection shall post on the PJM Open Access Same-time Information System
at times specified in the PJM Manuals a revised forecast of the location and
duration of any expected transmission congestion, and of the range of
differences in Locational Marginal Prices between major subareas of the PJM
Region expected to result from such transmission congestion.



(d) Market Buyers shall pay and Market Sellers
shall be paid for the quantities of energy scheduled in the Day-ahead Energy
Market at the Day-ahead Prices.



1.10.9 Hourly Scheduling.



(a) Following the initial posting by the Office of
the Interconnection of the Locational Marginal Prices resulting from the
Day-ahead Energy Market, and subject to the right of the Office of the
Interconnection to schedule and dispatch pool-scheduled resources and to direct
that schedules be changed in an Emergency, a generation rebidding period shall
exist from 4:00 p.m. to 6:00 p.m. on the day before each Operating Day. During
the rebidding period, Market Participants may submit revisions to generation
offer data for any generation resource that was not selected as a pool-scheduled
resource in the Day-ahead Energy Market. Adjustments to Day-ahead Energy Markets
shall be settled at the applicable Real-time Prices, and shall not affect the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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    First
      Revised Sheet No. 100Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 100




obligation to pay or receive payment for the
quantities of energy scheduled in the Day-ahead Energy market at the applicable
Day-ahead Prices.



(b) A Market Participant may adjust the schedule
of a resource under its dispatch control on an hour-to-hour basis beginning at
10:00 p.m. of the day before each Operating Day, provided that the Office of the
Interconnection is notified not later than 60 minutes prior to the hour in which
the adjustment is to take effect, as follows:



i)
    A Generating
      Market Buyer may self-schedule any of its resource increments, including
      hydropower resources, not previously designated as self-scheduled and not
      selected as a pool-scheduled resource in the Day-ahead Energy Market;




ii)
    A Market
      Participant may request the scheduling of a non-firm bilateral
      transaction; or




iii)
    A Market
      Participant may request the scheduling of deliveries or receipts of Spot
      Market Energy; or




iv)
    A Generating
      Market Buyer may remove from service a resource increment, including a
      hydropower resource, that it had previously designated as self-scheduled,
      provided that the Office of the Interconnection shall have the option to
      schedule energy from any such resource increment that is a Capacity
      Resource at the price offered in the scheduling process, with no
      obligation to pay any start-up fee.




(c) With respect to a pool-scheduled resource that
is included in the Day-ahead Energy Market, a Market Seller may not change or
otherwise modify its offer to sell energy.



(d) An External Market Buyer may refuse delivery
of some or all of the energy it requested to purchase in the Day-ahead Energy
Market by notifying the Office of the Interconnection of the adjustment in
deliveries not later than 60 minutes prior to the hour in which the adjustment
is to take effect, but any such adjustment shall not affect the obligation of
the External Market Buyer to pay for energy scheduled on its behalf in the
Day-ahead Energy Market at the applicable Day-ahead Prices.



(e) For each hour in the Operating Day, as soon as
practicable after the deadlines specified in the foregoing subsection of this
Section 1.10, the Office of the Interconnection shall provide External Market
Buyers and External Market Sellers and parties to bilateral transactions with
any revisions to their schedules for the hour.



1.11 Dispatch.



The following procedures and principles shall
govern the dispatch of the resources available to the Office of the
Interconnection.



1.11.1 Resource Output.



The Office of the Interconnection shall have the
authority to direct any Market Seller to adjust the output of any pool-scheduled
resource increment within the operating characteristics specified in the Market
Seller’s offer. The Office of the Interconnection may cancel its selection of,
or otherwise release, pool-scheduled resources, subject to an obligation to pay
any applicable start-up, no-load or cancellation fees. The Office of the
Interconnection shall adjust the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




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    Fifth
      Revised Sheet No. 101Third Revised Rate Schedule FERC No.
      24
    
    Superseding Fourth Revised Sheet No. 101




output of pool-scheduled resource increments as
necessary: (a) to maintain reliability, and subject to that constraint, to
minimize the cost of supplying the energy, reserves, and other services required
by the Market Buyers and the operation of the PJM Region; (b) to balance load
and generation, maintain scheduled tie flows, and provide frequency support
within the PJM Region; and (c) to minimize unscheduled interchange not frequency
related between the PJM Region and other Control Areas.



1.11.2 Operating Basis.



In carrying out the foregoing objectives, the
Office of the Interconnection shall conduct the operation of the PJM Region in
accordance with the PJM Manuals, and shall: (i) utilize available generating
reserves and obtain required replacements; and (ii) monitor the availability of
adequate reserves.



1.11.3 Pool-dispatched Resources.



(a) The Office of the Interconnection shall
implement the dispatch of energy from pool-scheduled resources with limited
energy by direct request. In implementing mandatory or economic use of limited
energy resources, the Office of the Interconnection shall use its best efforts
to select the most economic hours of operation for limited energy resources, in
order to make optimal use of such resources consistent with the dynamic
load-following requirements of the PJM Region and the availability of other
resources to the Office of the Interconnection.



(b) The Office of the Interconnection shall
implement the dispatch of energy from other pool-dispatched resource increments,
including generation increments from Capacity Resources the remaining increments
of which are self-scheduled, by sending appropriate signals and instructions to
the entity controlling such resources, in accordance with the PJM Manuals. Each
Market Seller shall ensure that the entity controlling a pool-dispatched
resource offered or made available by that Market Seller complies with the
energy dispatch signals and instructions transmitted by the Office of the
Interconnection.



1.11.3A Maximum Generation Emergency.



If the Office of the Interconnection declares a
Maximum Generation Emergency, all deliveries to load that is served by
Point-to-Point Transmission Service outside the PJM Region from Capacity
Resources may be interrupted in order to serve load in the PJM Region.



1.11.4 Regulation.



(a) A Market Buyer may satisfy its Regulation
Obligation from its own resources capable of performing Regulation service, by
contractual arrangements with other Market Participants able to provide
Regulation service, or by purchases from the PJM Interchange Energy Market at
the rates set forth in Section 3.2.2.



(b) The Office of the Interconnection shall obtain
Regulation service from the least-cost alternatives available from either
pool-scheduled or self-scheduled resources as needed to meet Regulation Zone
requirements not otherwise satisfied by the Market Buyers. Resources offering to
sell Regulation shall be selected to provide Regulation on the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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    Third
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    Superseding Second Revised Sheet No. 102




basis of each resource’s regulation offer and the
estimated opportunity cost of the resource providing regulation and in
accordance with the Office of the Interconnection’s obligation to minimize the
total cost of energy, Operating Reserves, Regulation, and other ancillary
services. Estimated opportunity costs shall be determined by the Office of the
Interconnection on the basis of the expected value of the energy sales that
would be foregone or uneconomic energy that would be produced by the resource in
order to provide Regulation, in accordance with procedures specified in the PJM
Manuals. If the Office of the Interconnection is not able to distinguish
resources offering Regulation on the basis of their regulation offers and
estimated opportunity costs, resources shall be selected on the basis of the
quality of Regulation provided by the resource as determined by tests
administered by the Office of the Interconnection.



(c) The Office of the Interconnection shall
dispatch resources for Regulation by sending Regulation signals and instructions
to resources from which Regulation service has been offered by Market Sellers,
in accordance with the PJM Manuals. Market Sellers shall comply with Regulation
dispatch signals and instructions transmitted by the Office of the
Interconnection and, in the event of conflict, Regulation dispatch signals and
instructions shall take precedence over energy dispatch signals and
instructions. Market Sellers shall exert all reasonable efforts to operate, or
ensure the operation of, their resources supplying load in the PJM Region as
close to desired output levels as practical, consistent with Good Utility
Practice.



1.11.4A Spinning Reserve



a) A Market Buyer may satisfy its Spinning Reserve
Obligation from its own resources capable of providing Spinning Reserve, by
contractual arrangements with other Market Participants able to provide Spinning
Reserve, or by purchases from the PJM Spinning Reserve Market at the rates set
forth in Section 3.2.3A.



b) The Office of the Interconnection shall obtain
Spinning Reserve from the least-cost alternatives available from either
pool-scheduled or self-scheduled resources as needed to meet the Spinning
Reserve requirements of each Spinning Reserve Zone of the PJM Region not
otherwise satisfied by the Market Buyers. Resources offering to sell Spinning
Reserve shall be selected to provide Spinning Reserve on the basis of each
resource’s Spinning Reserve offer and the estimated unit specific opportunity
cost of the resource providing Spinning Reserve, and in accordance with the
Office of the Interconnection’s obligation to minimize the total cost of energy,
Operating Reserves, Spinning Reserve and other ancillary services. Estimated
unit specific opportunity costs shall be equal to the sum of (i) the product of
(A) the megawatts of energy used by the resource to provide Spinning Reserve as
submitted as part of the resource’s Spinning Reserve offer times (B) the
Locational Marginal Price at the generation bus of the resource, and (ii) the
product of (A) the deviation of the resource’s output necessary to follow the
Office of the Interconnection’s signals and instructions from the resource’s
expected output level if it had been dispatched in economic merit order, times
(B) the absolute value of the difference between the Locational Marginal Price
at the generation bus for the resource and the offer price for energy from the
resource (at the megawatt level of the Spinning Reserve set point for the
resource) in the PJM Interchange Energy Market.



c) The Office of the Interconnection shall
dispatch resources for Spinning Reserve by sending Spinning Reserve instructions
to resources from which Spinning Reserve has been offered by Market Sellers, in
accordance with the PJM Manuals. Market Sellers shall comply with Spinning
Reserve dispatch instructions transmitted by the Office of the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




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    Fourth
      Revised Sheet No. 103Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 103




Interconnection and, in the event of a conflict,
Spinning Reserve dispatch instructions shall take precedence over energy
dispatch signals and instructions. Market Sellers shall exert all reasonable
efforts to operate, or ensure the operation of, their resources supplying load
in the PJM Region as close to desired output levels as practical, consistent
with Good Utility Practice.



1.11.5 PJM Open Access Same-time Information
System.



The Office of the Interconnection shall update the
information posted on the PJM Open Access Same-time Information System to
reflect its dispatch of generation resources.



1.12 Dynamic Scheduling.



(a) An entity that owns or controls a generating
resource in the PJM Region may electrically remove all or part of the generating
resource’s output from the PJM Region through dynamic scheduling of the output
to load outside the PJM Region. Such output shall not be available for economic
dispatch by the Office of the Interconnection.



(b) An entity requesting dynamic scheduling shall
be responsible for arranging for the provision of signal processing and
communications from the generator to the Office of the Interconnection and other
participating control areas and complying with any other procedures established
by the Office of the Interconnection regarding dynamic scheduling as set forth
in the PJM Manuals.



(c) An entity requesting dynamic scheduling shall
be responsible for reserving amounts of firm transmission service necessary to
deliver the range of the dynamic transfer and any required ancillary services.



2. CALCULATION OF LOCATIONAL MARGINAL PRICES



2.1 Introduction.



The Office of the Interconnection shall calculate
the price of energy at the load busses and generation busses in the PJM Region
and at the interface busses between adjacent Control Areas and the PJM Region on
the basis of Locational Marginal Prices. Locational Marginal Prices determined
in accordance with this Section shall be calculated on a day-ahead basis for
each hour of the Day-ahead Energy Market, and every five minutes during the
Operating Day for the Real-time Energy Market.



2.2 General.



The Office of the Interconnection shall determine
the least cost security-constrained dispatch, which is the least costly means of
serving load at different locations in the PJM Region based on actual operating
conditions existing on the power grid (including transmission constraints on
external coordinated flowgates to the extent provided by section 1.7.6) and on
the prices at which Market Sellers have offered to supply energy in the PJM
Interchange Energy Market. Locational Marginal Prices for the generation and
load busses in the PJM Region, including interconnections with other Control
Areas, will be calculated based on the actual economic dispatch and the prices
of energy offers. The process for the determination of Locational Marginal
Prices shall be as follows:



(a) To determine actual operating conditions on
the power grid in the PJM Region, the Office of the Interconnection shall use a
computer model of the interconnected grid that uses available metered inputs
regarding generator output, loads, and power flows to model remaining flows and
conditions, producing a consistent representation of power flows on the network.
The computer model employed for this purpose, referred to as the State Estimator
program, is a standard industry tool and is described in Section 2.3 below. It
will be used to obtain information regarding the output of generation supplying
energy to the PJM Region, loads at buses in the PJM Region, transmission losses,
and power flows on binding transmission constraints for use in the calculation
of Locational Marginal Prices. Additional information used in the calculation,
including Dispatch Rates and real time schedules for external transactions
between PJM and other Control Areas, will be obtained from the Office of the
Interconnection’s dispatchers.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Second
      Revised Sheet No. 104Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 104




(b) Using the prices at which energy is offered by
Market Sellers to the PJM Interchange Energy Market, the Office of the
Interconnection shall determine the offers of energy that will be considered in
the calculation of Locational Marginal Prices. As described in Section 2.4
below, every offer of energy by a Market Seller from a resource that is
following economic dispatch instructions of the Office of the Interconnection
will be utilized in the calculation of Locational Marginal Prices.



(c) Based on the system conditions on the PJM
power grid, determined as described in (a), and the eligible energy offers,
determined as described in (b), the Office of the Interconnection shall
determine the least costly means of obtaining energy to serve the next increment
of load at each bus in the PJM Region, in the manner described in Section 2.5
below. The result of that calculation shall be a set of Locational Marginal
Prices based on the system conditions at the time.



2.3 Determination of System Conditions Using
the State Estimator.



Power system operations, including, but not
limited to, the determination of the least costly means of serving load, depend
upon the availability of a complete and consistent representation of generator
outputs, loads, and power flows on the network. In calculating Locational
Marginal Prices, the Office of the Interconnection shall obtain a complete and
consistent description of conditions on the electric network in the PJM Region
by using the most recent power flow solution produced by the State Estimator,
which is also used by the Office of the Interconnection for other functions
within power system operations. The State Estimator is a standard industry tool
that produces a power flow model based on available real-time metering
information, information regarding the current status of lines, generators,
transformers, and other equipment, bus load distribution factors, and a
representation of the electric network, to provide a complete description of
system conditions, including conditions at buses for which real-time information
is unavailable. The Office of the Interconnection shall obtain a State Estimator
solution every five minutes, which shall provide the megawatt output of
generators and the loads at buses in the PJM Region, transmission line losses,
and actual flows or loadings on constrained transmission facilities. External
transactions between PJM and other Control Areas shall be included in the
Locational Marginal Price calculation on the basis of the real time transaction
schedules implemented by the Office of the Interconnection’s dispatcher.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Second
      Revised Sheet No. 105Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 105




2.4 Determination of Energy Offers Used in
Calculating Real-time Prices.



(a) During the Operating Day, real-time Locational
Marginal Prices derived in accordance with this Section shall be determined
every five minutes and integrated hourly values of such determinations shall be
the basis of sales and purchases of energy in the Real-time Energy Market and of
Transmission Congestion Charges under the PJM Tariff not covered by the
Day-ahead Energy Market.



(b) To determine the energy offers submitted to
the PJM Interchange Energy Market that shall be used during the Operating Day to
calculate the Real-time Prices, the Office of the Interconnection shall
determine which resources are following its economic dispatch instructions. A
resource will be considered to be following economic dispatch instructions and
shall be included in the calculation of Real-time Prices if:



i)
    the
      applicable price bid by a Market Seller for energy from the resource is
      less than or equal to the Dispatch Rate for the area of the PJM Region in
      which the resource is located; or




ii)
    the resource
      is specifically requested to operate by the Office of the
      Interconnection’s dispatcher.




(c) In determining whether a resource satisfies
the condition described in (b), the Office of the Interconnection will determine
the bid price associated with an energy offer by comparing the actual megawatt
output of the resource with the Market Seller’s offer price curve. Because of
practical generator response limitations, a resource whose megawatt output is
not ten percent more than the megawatt level specified on the offer price curve
for the applicable Dispatch Rate shall be deemed to be following economic
dispatch instructions, but the energy price offer used in the calculation of
Real-time Prices shall not exceed the applicable Dispatch Rate. Units that must
be run for local area protection shall not be considered in the calculation of
Real-time Prices.



2.5 Calculation of Real-time Prices.



(a) The Office of the Interconnection shall
determine the least costly means of obtaining energy to serve the next increment
of load at each bus in the PJM Region represented in the State Estimator and
each interface bus between PJM and an adjacent Control Area, based on the system
conditions described by the most recent power flow solution produced by the
State Estimator program and the energy offers that are the basis for the
Day-ahead Energy Market, or that are determined to be eligible for consideration
under Section 2.4 in connection with the real-time dispatch, as applicable. This
calculation shall be made by applying an incremental linear optimization method
to minimize energy costs, given actual system conditions, a set of energy
offers, and any binding transmission constraints that may exist. In performing
this calculation, the Office of the Interconnection shall calculate the cost of
serving an increment of load at each bus from each resource associated with an
eligible energy offer as the sum of: (1) the price at which the Market Seller
has offered to supply an additional increment of energy from the resource, and
(2) the effect on transmission congestion costs (whether positive or negative)
associated with increasing the output of the resource, based on the effect of
increased generation from that resource on transmission line loadings. The
energy offer or offers that can serve an



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 106Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 106




increment of load at a bus at the lowest cost, calculated in this manner,
shall determine the Real-time Price at that bus.



(b) During the Operating Day, the calculation set
forth in (a) shall be performed every five minutes, using the Office of the
Interconnection’s Locational Marginal Price program, producing a set of
Real-time Prices based on system conditions during the preceding interval. The
prices produced at five-minute intervals during an hour will be integrated to
determine the Real-time Prices for that hour.



2.6 Calculation of Day-ahead Prices.



For the Day-ahead Energy Market, day-ahead
Locational Marginal Prices shall be determined on the basis of the least-cost,
security-constrained dispatch, model flows and system conditions resulting from
the load specifications, offers for generation, dispatchable load, Increment
Bids, Decrement Bids, and bilateral transactions submitted to the Office of the
Interconnection and scheduled in the Day-ahead Energy Market. Such prices shall
be determined in accordance with the provisions of this Section applicable to
the Day-ahead Energy Market and shall be the basis for purchases and sales of
energy and Transmission Congestion Charges resulting from the Day-ahead Energy
Market. This calculation shall be made for each hour in the Day-ahead Energy
Market by applying a linear optimization method to minimize energy costs, given
scheduled system conditions, scheduled transmission outages, and any
transmission limitations that may exist. In performing this calculation, the
Office of the Interconnection shall calculate the cost of serving an increment
of load at each bus from each resource associated with an eligible energy offer
as the sum of: (1) the price at which the Market Seller has offered to supply an
additional increment of energy from the resource, and (2) the effect on
transmission congestion costs (whether positive or negative) associated with
increasing the output of the resource, based on the effect of increased
generation from that resource on transmission line loadings. The energy offer or
offers that can serve an increment of load at a bus at the lowest cost,
calculated in this manner, shall determine the Day-ahead Price at that bus.



2.7 Performance Evaluation.



The Office of the Interconnection shall undertake
an evaluation of the foregoing procedures for the determination of Locational
Marginal Prices, as well as the procedures for determining and allocating
Financial Transmission Rights and associated Transmission Congestion Charges and
Credits, not less often than every two years, in accordance with the PJM
Manuals. To the extent practical, the Office of the Interconnection shall retain
all data needed to perform comparisons and other analyses of locational marginal
pricing. The Office of the Interconnection shall report the results of its
evaluation to the Market Participants, along with its recommendations, if any,
for changes in the procedures.



3. ACCOUNTING AND BILLING



3.1 Introduction.



This schedule sets forth the accounting and
billing principles and procedures for the purchase and sale of services on the
PJM Interchange Energy Market and for the operation of the PJM Region.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 107Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 107




3.2 Market Buyers.



3.2.1 Spot Market Energy.



(a) Market Buyers shall be charged for all load
(net of Behind The Meter Generation expected to be operating, but not to be less
than zero) scheduled to be served from the PJM Interchange Energy Market in the
Day-ahead Energy Market at the Day-ahead Prices applicable to each relevant load
bus.



(b) Generating Market Buyers shall be paid for all
energy scheduled to be delivered to the PJM Interchange Energy Market in the
Day-ahead Energy Market at the Day-ahead Prices applicable to each relevant
generation bus.



(c) At the end of each hour during an Operating
Day, the Office of the Interconnection shall calculate the load payment at each
Market Buyer’s load bus to be charged at Real-time Prices determined by the
product of the hourly Real-time Price at the relevant bus times the Market
Buyer’s megawatts of load (net of operating Behind The Meter Generation, but not
to be less than zero) at the bus in that hour in excess of the load (net of
Behind The Meter Generation expected to be operating, but not to be less than
zero) scheduled to be served at that bus in the hour in the Day-ahead Energy
Market. To the extent that the load (net of operating Behind The Meter
Generation, but not to be less than zero) actually served at a load bus is less
than the load (net of Behind The Meter Generation expected to be operating, but
not to be less than zero) scheduled to be served at that bus in the Day-ahead
Energy Market, the Market Buyer shall be credited for the difference at the
Real-time Price for the load bus at the time of the shortfall. The megawatts of
load at each load bus shall be the sum of the megawatts of load (net of
operating Behind The Meter Generation, but not less than zero) for that bus of
that Market Buyer as determined by the State Estimator, plus an allocated share
of transmission losses, plus any megawatts of that Market Buyer’s bilateral
sales to purchasers outside of the PJM Region attributable to that bus. The
total load charge for each Market Buyer shall be the sum, for each of a Market
Buyer’s load buses, of the charges at Day-ahead Prices determined in accordance
with the Day-ahead Energy Market as specified in Section 1.10.1a plus the
charges at Real-time Prices determined as specified herein, net of any credits
specified herein for each of the Market Buyer’s load buses.



(d) At the end of each hour during an Operating
Day, the Office of the Interconnection shall calculate the generation revenue at
each Generating Market Buyer’s generation bus to be paid at Real-time Prices,
determined by the product of the hourly Real-time Price at the relevant bus
times the Generating Market Buyer’s megawatts of generation at such generation
bus in the hour, as determined by the State Estimator, in excess of the energy
scheduled to be injected at that bus in that hour in the Day-ahead Energy
Market. To the extent that the energy actually injected at the generation bus is
less than the energy scheduled to be injected at that bus in the Day-ahead
Energy Market, the Generating Market Buyer shall be debited for the difference
at the Real-time Price for the generation bus at the time of the shortfall. The
megawatts of generation at each generation bus shall be the sum of the megawatts
of generation for that bus of that Generating Market Buyer as determined by the
State Estimator, plus any megawatts of bilateral purchases of that Generating
Market Buyer from sellers outside of the PJM Region attributable to that bus.
The total generation revenue for each Generating Market Buyer shall be the sum,
for each of the Generating Market Buyer’s generation buses, of the revenues at
Day-ahead Prices determined in accordance with the Day-ahead Energy Market as
specified in Section 1.10.1A plus the revenues at Real-time Prices determined as
specified herein, net of any debits specified herein for each of the Market
Buyer’s generation buses.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2004Vice President, Government
    PolicyIssued On:
    
    August 31, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 108Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 108




(e) At the end of each hour during an Operating
Day, the Office of the Interconnection shall calculate a net bill for each
Market Buyer, determined as the difference between its total load charges and
its total generation revenue. The portions of the net bill attributable to net
hourly PJM Interchange and to Transmission Congestion Charges in the Day-ahead
Energy Market and the Real-time Energy Market shall be determined as set forth
in this Section and in Section 5.1.3.



(f) At the end of each hour during an Operating
Day, the Office of the Interconnection shall calculate the total amount of net
hourly PJM Interchange for each Market Buyer, including Generating Market
Buyers, in accordance with the PJM Manuals. For Internal Market Buyers that are
Load Serving Entities or purchasing on behalf of Load Serving Entities, this
calculation shall include determination of the net energy flows from: (i) tie
lines; (ii) any generation resource the output of which is controlled by the
Market Buyer but delivered to it over another entity’s Transmission Facilities;
(iii) any generation resource the output of which is controlled by another
entity but which is directly interconnected with the Market Buyer’s transmission
system; (iv) deliveries pursuant to bilateral energy sales; (v) receipts
pursuant to bilateral energy purchases; and (vi) an adjustment to account for
the day-ahead PJM Interchange, calculated as the difference between scheduled
withdrawals and injections by that Market Buyer in the Day-ahead Energy Market.
For Electric Distributors that report hourly net energy flows from metered tie
lines, this calculation also shall include 500 kV transmission losses and
Inadvertent Interchange allocated to the Electric Distributor and shall exclude
the energy delivered to load of other Network Customers and Transmission
Customers. For External Market Buyers and Internal Market Buyers that are not
Load Serving Entities or purchasing on behalf of Load Serving Entities, this
calculation shall determine the energy scheduled hourly for delivery to the
Market Buyer net of the amounts scheduled by the External Market Buyer in the
Day-ahead Energy Market.



(g) The Office of the Interconnection shall
calculate Locational Marginal Prices in the form of Day-ahead Prices and
Real-time Prices for each load and generation bus in the PJM Region, in
accordance with Section 2 of this Schedule.



(h) An Internal Market Buyer shall be charged for
Spot Market Energy purchases to the extent of its hourly net purchases from the
PJM Interchange Energy Market, determined as specified in Section 3.2.1(f)
above. An External Market Buyer shall be charged for its Spot Market Energy
purchases based on the energy delivered to it, determined as specified in
Section 3.2.1(f) above. The Office of the Interconnection shall calculate an
hourly weighted average Real-time Price for each such Market Buyer, based on the
hourly average of the Market Buyer’s Real-time Prices at each bus weighted by
the Market Buyer’s load deviations at the bus. The total charge shall be
determined by the product of the hourly net amount of PJM Interchange Imports
times the hourly weighted-average Real-time Price for that Market Buyer.



(i) A Generating Market Buyer shall be credited as
a Market Seller for sales of Spot Market Energy to the extent of its hourly net
sales into the PJM Interchange Energy Market, determined as specified in Section
3.2.1(f) above. The Office of the Interconnection shall calculate an hourly
weighted average Real-time Price for each such Market Seller, based on the
hourly average of the Market Seller’s Real-time Prices at each bus weighted by
the Market Buyer’s generation deviations at each bus. The total credit shall be
determined by the product of the hourly net amount of PJM Interchange Exports
times the hourly weighted average Real-time Price for that Market Seller.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Second Revised Sheet No. 109Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Original Sheet No.
109




3.2.2 Regulation.



(a) Each Internal Market Buyer that is a Load
Serving Entity in a Regulation Zone shall have an hourly Regulation objective
equal to its pro rata share of the Regulation requirements of such
Regulation Zone for the hour, based on the Market Buyer’s total load (net of
operating Behind The Meter Generation, but not to be less than zero) in such
Regulation Zone for the hour (“Regulation Obligation”). An Internal Market Buyer
that does not meet its hourly Regulation obligation shall be charged for
Regulation dispatched by the Office of the Interconnection to meet such
obligation at the Regulation market-clearing price determined in accordance with
paragraph (c) of this Section, plus the amounts, if any, described in paragraph
(f) of this section.



(b) A Generating Market Buyer supplying Regulation
in a Regulation Zone at the direction of the Office of the Interconnection in
excess of its hourly Regulation obligation shall be credited for each increment
of such Regulation at the higher of (i) the Regulation market-clearing price in
such Regulation Zone or (ii) the sum of the regulation offer and the
unit-specific opportunity cost of the resource supplying the increment of
Regulation, as determined by the Office of the Interconnection in accordance
with procedures specified in the PJM Manuals.



(c) The Regulation market-clearing price in each
Regulation Zone shall be determined at a time to be determined by the Office of
the Interconnection which shall be no earlier than the day before the Operating
Day and the market-clearing price each hour shall be equal to the highest sum of
a resource’s Regulation offer plus its estimated unit-specific opportunity costs
from among the resources selected to provide Regulation. A resource’s Regulation
offer for any of the Regulation Zone(s) in the PJM West Region shall not exceed
the cost of providing Regulation from such resource, plus seven dollars and
fifty cents, unless and until market-based pricing is authorized for Regulation
in such Regulation Zone.



(d) In determining the Regulation market-clearing
price in each Regulation Zone, the estimated unit-specific opportunity costs of
a resource offering to sell Regulation each hour shall be equal to the product
of (i) the deviation of the set point of the resource that is expected to be
required in order to provide Regulation from the resource’s expected output
level if it had been dispatched in economic merit order times (ii) the absolute
value of the difference between the expected Locational Marginal Price at the
generation bus for the resource and the offer price for energy from the resource
(at the megawatt level of the Regulation set point for the resource) in the PJM
Interchange Energy Market.



(e) In determining the credit under subsection (b)
to a Generating Market Buyer selected to provide Regulation in a Regulation Zone
and that actively follows the Office of the Interconnection’s Regulation signals
and instructions, the unit-specific opportunity cost of a resource shall be
determined for each hour that the Office of the Interconnection requires a
resource to provide Regulation and shall be equal to the product of (i) the
deviation of the resource’s output necessary to follow the Office of the
Interconnection’s Regulation signals from the resource’s expected output level
if it had been dispatched in economic merit order times (ii) the absolute value
of the difference between the Locational Marginal Price at the generation bus
for the resource and the offer price for energy from the resource (at the
megawatt level of the Regulation set point for the resource) in the PJM
Interchange Energy Market.



(f) Any amounts credited for Regulation in an hour
in excess of the Regulation market-clearing price in that hour shall be
allocated and charged to each Internal Market Buyer in a Regulation Zone that
does not meet its hourly Regulation obligation in proportion to its purchases of
Regulation in such Regulation Zone in megawatt-hours during that hour.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    January ,
      2005Note: This sheet includes language accepted
      by the Commission which will be included in a clean up
    filing.




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 110Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 110




Sheet Reserved for Future Use.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    August 31, 2004




---

PJM Interconnection, L.L.C.
    
    Sixth
      Revised Sheet No. 111Third Revised Rate Schedule FERC No.
      24
    
    Superseding Fourth Revised Sheet No. 111




3.2.3 Operating Reserves.



(a) A Market Seller’s pool-scheduled resources
capable of providing operating reserves shall be credited as specified below
based on the prices offered for the operation of such resource, provided that
the resource was available for the entire time specified in the Offer Data for
such resource.



(b) The following determination shall be made for
each pool-scheduled resource that is scheduled in the Day-ahead Energy Market:
the total offered price for start-up and no-load fees and Spot Market Energy,
determined on the basis of the resource’s scheduled output, shall be compared to
the total value of that resource’s Spot Market Energy as determined by the
Day-ahead Energy Market and the Day-ahead Prices applicable to the relevant
generation bus in the Day-ahead Energy Market. Except as provided in Section
3.2.3(n), if the total offered price summed over all hours exceeds the total
value summed over all hours, the difference shall be credited to the Market
Seller.



(c) The sum of the foregoing credits calculated in
accordance with Section 3.2.3(b) plus any unallocated charges from Section
3.2.3(h) and 5.1.7, and any shortfalls paid pursuant to the Market Settlement
provision of the Day-ahead Economic Load Response Program shall be the cost of
Operating Reserves in the Day-ahead Energy Market.



(d) The cost of Operating Reserves in the
Day-ahead Energy Market shall be allocated and charged to each Market
Participant in proportion to the sum of its (i) scheduled load (net of Behind
The Meter Generation expected to be operating, but not to be less than zero) and
accepted Decrement Bids in the Day-ahead Energy Market in megawatt-hours for
that Operating Day; and (ii) scheduled energy sales in the Day-ahead Energy
Market from within the PJM Region to load outside such region in megawatt-hours
for that Operating Day, but not including its bilateral transactions that are
dynamically scheduled to load outside such area pursuant to Section 1.12.



(e) At the end of each Operating Day, the
following determination shall be made for each synchronized pool-scheduled
resource of each Market Seller that operates as requested by the Office of the
Interconnection and that is not committed solely for the purpose of providing
Spinning Reserve: the total offered price for start-up and no-load fees and Spot
Market Energy, determined on the basis of the lesser of the resource’s (i)
hourly output as determined by the State Estimator, or (ii) requested output as
determined by the PJM dispatch. The total offered price shall be compared to the
total value of that resource’s energy in the Day-ahead Energy Market plus any
credit or charge for quantity deviations, at PJM dispatch direction, from the
Day-ahead Energy Market during the Operating Day. Except as provided in Section
3.2.3(m), if the total offered price exceeds the total value, the difference
less any credit as determined pursuant to Section 3.2.3(b) and less any amounts
credited for Regulation in excess of the Regulation offer plus the resources
opportunity cost and less any amounts credited for Spinning Reserve in excess of
the Spinning Reserve offer plus the resource’s opportunity cost, shall be
credited to the Market Seller.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2004Vice President, Government
    PolicyIssued On:
    
    August 31, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 111.01Third Revised Rate Schedule FERC No.
      24




(f) A Market Seller’s steam-electric generating
unit or combined cycle unit operating in combined cycle mode that is pool
scheduled (or self-scheduled, if operating according to paragraph 1.10.3 (c)),
the output of which is reduced or suspended at the request of the Office of the
Interconnection due to a transmission constraint or other reliability issue, and
for which the hourly integrated, real-time LMP at the unit’s bus is higher than
the unit’s offer corresponding to the level of output requested by the Office of
the Interconnection (as indicated either by the desired MWs of output from the
unit determined by PJM’s unit dispatch system or as



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2004Vice President, Government
    PolicyIssued On:
    
    March 1, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 111AThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 111A




directed by the PJM dispatcher through a manual
override), shall be credited hourly in an amount equal to {(LMPDMW - AG) x
(URTLMP – UB)}, where:



Issued By:
    
    Craig Glazer
    
    Effective:
    
    September 1, 2004Vice President, Government
    PolicyIssued On:
    
    August 9, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER03-1086-001, issued July 9, 2004, 108 FERC ¶
61,030.




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 112Third Revised Rate
      Schedule FERC No. 24
    
    Superseding First Revised Sheet No. 112




LMPDMW equals the level of output for the unit
determined according to the point on the scheduled offer curve on which the unit
was operating corresponding to the hourly integrated real time LMP;



AG equals the actual hourly integrated output of
the unit;



URTLMP equals the real time LMP at the unit’s bus;



UB equals the unit offer for that unit for which
output is reduced or suspended, determined according to the real-time scheduled
offer curve on which the unit was operating, unless such schedule was a
price-based schedule and the offer associated with that price schedule is less
than the cost-based offer provided for the unit, in which case the offer for the
unit will be determined from the cost-based schedule; and



where URTLMP - UB shall not be negative.



(f-1) A Market Seller’s combustion turbine unit or
combined cycle unit operating in simple cycle mode that is pool scheduled (or
self-scheduled, if operating according to paragraph 1.10.3 (c)), operated as
requested by the Office of the Interconnection, shall be compensated for lost
opportunity cost if either of the following conditions occur:



(i) if the unit output is reduced at the direction
of the Office of the Interconnection and the real time LMP at the unit’s bus is
higher than the unit’s offer corresponding to the level of output requested by
the Office of the Interconnection (as directed by the PJM dispatcher), then the
Market Seller shall be credited in a manner consistent with that described above
for a steam unit or combined cycle unit operating in combined cycle mode.



(ii) if the unit is scheduled to produce energy in
the day-ahead market, but the unit is not called on by PJM and does not operate
in real time, then the Market Seller shall be credited hourly in an amount equal
to the higher of (i) {(URTLMP – UDALMP) x DAG}, or (ii) {(URTLMP – UB) x DAG}
where:



URTLMP equals the real time LMP at the unit’s bus;



UDALMP equals the day-ahead LMP at the unit’s bus;



DAG equals the day-ahead scheduled unit output for
the hour;



Issued By:
    
    Craig Glazer
    
    Effective:
    
    September 1, 2004Vice President, Government
    PolicyIssued On:
    
    August 9, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER03-1086-001, issued July 9, 2004, 108 FERC ¶
61,030.




---

PJM Interconnection, L.L.C.
    
    Fourth
      Revised Sheet No. 112AThird Revised Rate Schedule FERC No.
      24
    
    Superseding Third Revised Sheet No. 112A




UB equals the offer price for the unit, determined
according to the schedule on which the unit was committed day-ahead, unless such
schedule was a price-based schedule and the offer associated with that price
schedule is less than the cost-based offer provided for the unit, in which case
the offer for the unit will be determined from the cost-based schedule; and



where URTLMP - UDALMP and URTLMP – UB shall not be
negative.



(f-2) A Market Seller’s hydroelectric resource
that is pool scheduled (or self-scheduled, if operating according to paragraph
1.10.3 (c)), the output of which is altered at the request of the Office of the
Interconnection from the schedule submitted by the owner, due to a transmission
constraint or other reliability issue, shall be compensated for lost opportunity
cost in the same manner as provided in sections 3.2.2A(d) and 3.2.3A(f) and
further detailed in the PJM Manuals.



(f-3) If a Market Seller can demonstrate to the
satisfaction of the Office of the Interconnection and the Market Monitoring Unit
that, due to specific pre-existing binding commitments to which it is a party,
and that properly should be recognized for purposes of this section, the above
calculations do not accurately compensate the Market Seller for opportunity cost
associated with following PJM dispatch instructions and reducing or suspending a
unit’s output due to a transmission constraint or other reliability issue, then
the Office of the Interconnection will negotiate with the individual Market
Seller such appropriate compensation, subject to approval of such compensation
by the Market Monitoring Unit.



(g) The sum of the foregoing credits, plus any
cancellation fees paid in accordance with Section 1.10.2(d), such cancellation
fees to be applied to the Operating Day for which the unit was scheduled, plus
any shortfalls paid pursuant to the Market Settlement provision of the Real-time
Economic Load Response Program, less any payments received from another Control
Area for Operating Reserves, plus any redispatch costs incurred in accordance
with section 10(a) of this Schedule, shall be the cost of Operating Reserves for
the Real-time Energy Market in each Operating Day.



(h) The cost of Operating Reserves for the
Real-time Energy Market for each Operating Day shall be allocated and charged to
each Market Participant in proportion to the sum of the absolute values of its
(i) load deviations (net of operating Behind The Meter Generation) from the
Day-ahead Energy Market in megawatt-hours during that Operating Day; (ii)
generation deviations (not including deviations in Behind The Meter Generation)
from the Day-ahead Energy Market for non-dispatchable generation resources,
including External Resources, in megawatt-hours during the Operating Day; (iii)
deviations from the Day-ahead Energy Market for bilateral transactions from
outside the PJM Region for delivery within such region in megawatt-hours during
the Operating Day; and (iv) deviations of energy sales from the Day-ahead Energy
Market from within the PJM Region to load outside such region in megawatt-hours
during that Operating Day, but not including its bilateral transactions that are
dynamically scheduled to load outside such region pursuant to Section 1.12.



(i) At the end of each Operating Day, Market
Sellers shall be credited on the basis of their offered prices for synchronous
condensing for purposes other than providing Spinning Reserve or Reactive
Services, as well as the credits calculated as specified in Section 3.2.3(b) for
those generators committed solely for the purpose of providing synchronous
condensing for purposes other than providing Spinning Reserve or Reactive
Services, at the request of the Office of the Interconnection.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2004Vice President, Government
    PolicyIssued On:
    
    June 30, 2004




---

PJM Interconnection, L.L.C.
    
    Sixth
      Revised Sheet No. 112BThird Revised Rate Schedule FERC No.
      24
    
    Superseding Fifth Revised Sheet No. 112B




(j) The sum of the foregoing credits as specified
in Section 3.2.3(i) shall be the cost of Operating Reserves for synchronous
condensing for the PJM Region for purposes other than providing Spinning Reserve
or Reactive Services, or in association with post-contingency operation for the
Operating Day and shall be separately determined for each Control Zone of the
PJM Region based on the Control Zone to which the resource was synchronized to
provide synchronous condensing for purposes other than providing Spinning
Reserve or Reactive Services, or in association with post-contingency operation.



(k) The cost of Operating Reserves for synchronous
condensing for purposes other than providing Spinning Reserve or Reactive
Services, or in association with post-contingency operation for each Operating
Day shall be allocated and charged to each Market Participant in proportion to
the sum of its (i) deliveries of energy to load (net of operating Behind The
Meter Generation, but not to be less than zero) in the PJM Region, served under
Network Transmission Service, in megawatt-hours during that Operating Day; and
(ii) deliveries of energy sales from within the PJM Region to load outside such
region in megawatt-hours during that Operating Day, but not



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 113Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 113




including its bilateral transactions that are
dynamically scheduled to load outside such Control Zone pursuant to Section
1.12, as compared to the sum of all such deliveries for all Market Participants.



(l) For any Operating Day in either, as
applicable, the Day-ahead Energy Market or the Real-time Energy Market for
which, for all or any part of such Operating Day, the Office of the
Interconnection: (i) declares a Maximum Generation Emergency; (ii) issues an
alert that a Maximum Generation Emergency may be declared (“Maximum Generation
Emergency Alert”); or (iii) schedules units based on the anticipation of a
Maximum Generation Emergency or a Maximum Generation Emergency Alert, the
Operating Reserves credit otherwise provided by Section 3.2.3.(b) or Section
3.2.3(e) in connection with marked-based offers shall be limited as provided in
paragraphs (n) or (m), respectively. The Office of the Interconnection shall
provide timely notice on its internet site of the commencement and termination
of any of the actions described in clause (i), (ii), or (iii) of this paragraph
(l) (collectively referred to as “MaxGen Conditions”). Following the posting of
notice of the commencement of a MaxGen Condition, a Market Seller may elect to
submit a cost-based offer in accordance with Schedule 2 of the Operating
Agreement, in which case paragraphs (m) and (n) shall not apply to such offer;
provided, however, that such offer must be submitted in accordance with the
deadlines in Section 1.10 for the submission of offers in the Day-ahead Energy
Market or Real-time Energy Market, as applicable. Submission of a cost-based
offer under such conditions shall not be precluded by Section 1.9.7(b);
provided, however, that the Market Seller must return to compliance with Section
1.9.7(b) when it submits its bid for the first Operating Day after termination
of the MaxGen Condition.



(m) For the Real-time Energy Market, if the
Effective Offer Price (as defined below) for a market-based offer is greater
than $1,000/MWh, the Market Seller shall not receive any credit for Operating
Reserves. For purposes of this paragraph (m), the Effective Offer Price shall be
the amount that, absent paragraphs (l) and (m), would have been credited for
Operating Reserves for such Operating Day pursuant to Section 3.2.3(e) plus the
Real-time Energy Market revenues for the hours that the offer is economic
divided by the megawatthours of energy provided during the hours that the offer
is economic. The hours that the offer is economic shall be: (i) the hours that
the offer price for Spot Market Energy is less than or equal to the Real-time
Price for the relevant generation bus, (ii) the hours in which the offer for
Spot Market Energy is greater than Locational Marginal Price and the unit is
operated at the direction of the Office of the Interconnection that are in
addition to any hours required due to the minimum run time or other operating
constraint of the unit, and (iii) for any unit with a minimum run time of one
hour or less and with more than one start available per day, any hours the unit
operated at the direction of the Office of the Interconnection.



(n) For the Day-ahead Energy Market, if notice of
a MaxGen Condition is provided prior to 12:00 noon on the day before the
Operating Day for which transactions are being scheduled and the Effective Offer
Price is greater than $1,000/MWh, the Market Seller shall not



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Fourth
      Revised Sheet No. 114Third Revised Rate Schedule FERC No.
      24
    
    Superseding Third Revised Sheet No. 114




receive any credit for Operating Reserves. If
notice of a MaxGen Condition is provided after 12:00 noon on the day before the
Operating Day for which transactions are being scheduled and the Effective Offer
Price is greater than $1,000/MWh, the Market Seller shall receive credit for
Operating Reserves determined in accordance with Section 3.2.3(b), subject to
the limit on total compensation stated below. If the Effective Offer Price is
less than or equal to $1,000/MWh, regardless of when notice of a MaxGen
Condition is provided, the Market Seller shall receive credit for Operating
Reserves determined in accordance with Section 3.2.3(b), subject to the limit on
total compensation stated below. For purposes of this paragraph (n), the
Effective Offer Price shall be the amount that, absent paragraphs (l) and (n),
would have been credited for Operating Reserves for such Operating Day divided
by the megawatt hours of energy offered during the Specified Hours, plus the
offer for Spot Market Energy during such hours. The Specified Hours shall be the
lesser of: (1) the minimum run hours stated by the Market Seller in its Offer
Data; and (2) either (i) for steam-electric generating units and for
combined-cycle units when such units are operating in combined-cycle mode, the
six consecutive hours of highest Day-ahead Price during such Operating Day when
such units are running or (ii) for combustion turbine units and for
combined-cycle units when such units are operating in combustion turbine mode,
the two consecutive hours of highest Day-ahead Price during such Operating Day
when such units are running. Notwithstanding any other provision in this
paragraph, the total compensation to a Market Seller on any Operating Day that
includes a MaxGen Condition shall not exceed $1,000/MWh during the Specified
Hours, where such total compensation in each such hour is defined as the amount
that, absent paragraphs (l) and (n), would have been credited for Operating
Reserves for such Operating Day pursuant to Section 3.2.3(b) divided by the
Specified Hours, plus the Day-ahead Price for such hour, and no Operating
Reserves payments shall be made for any other hour of such Operating Day. If a
unit operates in real time at the direction of the office of the Interconnection
consistently with its day-ahead clearing, then paragraph (m) does not apply.



3.2.3A Spinning Reserve.



(a) Each Internal Market Buyer that is a Load
Serving Entity shall have an obligation for hourly Spinning Reserve equal to its
pro rata share of Spinning Reserve requirements for the hour for each
Spinning Reserve Zone of the PJM Region, based on the Market Buyer’s total load
(net of operating Behind The Meter Generation, but not to be less than zero) in
such Spinning Reserve Zone, for the hour (“Spinning Reserve Obligation”), less
any amount obtained from condensers associated with provision of Reactive
Services as described in section 3.2.3B(i) and any amount obtained from
condensers associated with post-contingency operations, as described in section
3.2.3C(b). An Internal Market Buyer that does not meet its hourly Spinning
Reserve Obligation shall be charged for the Spinning Reserve dispatched by the
Office of the Interconnection to meet such obligation at the Spinning Reserve
Market Clearing Price determined in accordance with paragraph (d) of this
section, plus the amounts if any, described in paragraphs (g), (h) and (i) of
this section.



(b) A Generating Market Buyer supplying Spinning
Reserve at the direction of the Office of the Interconnection, in excess of its
hourly Spinning Reserve Obligation, shall be credited as follows:



i) Credits for Spinning Reserve provided by units
that are then subject to the energy dispatch signals and instructions of the
Office of the Interconnection and that increase their current output in response
to a Spinning



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 115Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 115




Reserve Event (“Tier 1 Spinning Reserve”) shall be
at the Spinning Energy Premium Price.



ii) Credits for Spinning Reserve provided by units
that are synchronized to the grid but, at the direction of the Office of the
Interconnection, are operating at a point that deviates from the Office of the
Interconnection energy dispatch signals and instructions (“Tier 2 Spinning
Reserve”) shall be the higher of (i) the Spinning Reserve Market Clearing Price
or (ii) the sum of (A) the Spinning Reserve offer, and (B) the unit specific
opportunity cost of the resource supplying the increment of Spinning Reserve, as
determined by the Office of the Interconnection in accordance with procedures
specified in the PJM Manuals.



c) The Spinning Reserve Energy Premium Price is
the average of the five-minute Locational Marginal Prices calculated during the
Spinning Reserve Event plus an adder in an amount to be determined periodically
by the Office of the Interconnection not less than fifty dollars and not to
exceed one hundred dollars per megawatt hour.



d) The Spinning Reserve Market Clearing Price
shall be determined for each Spinning Reserve Zone by the Office of the
Interconnection prior to the operating hour and such market-clearing price shall
be equal to, from among the resources selected to provide Spinning Reserve for
such Spinning Reserve Zone, the highest sum of (i) a resource’s Spinning Reserve
offer and (ii) the unit specific opportunity cost of the resource.



e) In determining the Spinning Reserve Market
Clearing Price, the estimated unit-specific opportunity cost shall be equal to
the sum of (i) the product of (A) the expected Locational Marginal Price at the
generation bus for the resource times (B) the megawatts of energy used to
provide Spinning Reserve submitted as part of the Spinning Reserve offer and
(ii) the product of (A) the deviation of the set point of the resource that is
expected to be required in order to provide Spinning Reserve from the resource’s
expected output level if it had been dispatched in economic merit order times
(B) the absolute value of the difference between the expected Locational
Marginal Price at the generation bus for the resource and the offer price for
energy from the resource (at the megawatt level of the Spinning Reserve set
point for the resource) in the PJM Interchange Energy Market.



f) In determining the credit under subsection (b)
to a Generating Market Buyer selected to provide Tier 2 Spinning Reserve and
that actively follows the Office of the Interconnection’s signals and
instructions, the unit-specific opportunity cost of a resource shall be
determined for each hour that the Office of the Interconnection requires a
resource to provide Tier 2 Spinning Reserve and shall be equal to the sum of (i)
the product of (A) the megawatts of energy used by the resource to provide
Spinning Reserve as submitted as part of the resource’s Spinning Reserve offer
times (B) the Locational Marginal Price at the generation bus of the resource,
and (ii) the product of (A) the deviation of the resource’s output necessary to
follow the Office of the Interconnection’s signals and instructions from the
resource’s expected output level if it had been dispatched in economic merit
order, times (B) the absolute value of the difference between the Locational
Marginal Price at the generation bus for the resource and the offer price for
energy from the resource (at the megawatt level of the Spinning Reserve set
point for the resource) in the PJM Interchange Energy Market.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




---

PJM Interconnection, L.L.C.
    
    Fourth
      Revised Sheet No. 116Third Revised Rate Schedule FERC No.
      24
    
    Superseding Third Revised Sheet No. 116




g) Charges for Tier 1 Spinning Reserve will be
allocated in proportion to the amount of Tier 1 Spinning Reserve applied to each
Spinning Reserve Obligation. In the event Tier 1 Spinning Reserve is provided by
a Market Seller in excess of that Market Seller’s Spinning Reserve Obligation,
the remainder of the Tier 1 Spinning Reserve that is not utilized to fulfill the
Seller’s obligation will be allocated proportionately among all other Spinning
Reserve Obligations.



h) Any amounts credited for Tier 2 Spinning
Reserve in an hour in excess of the Spinning Reserve Market Clearing Price in
that hour shall be allocated and charged to each Internal Market Buyer that does
not meet its hourly Spinning Reserve Obligation in proportion to its purchases
of Spinning Reserve in megawatt-hours during that hour.



i) In the event the Office of the Interconnection
needs to assign more Tier 2 Spinning Reserve during an hour than was estimated
as needed at the time the Spinning Reserve Market Clearing Price was calculated
for that hour due to a reduction in available Tier 1 Spinning Reserve, the costs
of the excess Tier 2 Spinning Reserve shall be allocated and charged to those
providers of Tier 1 Spinning Reserve whose available Tier 1 Spinning Reserve was
reduced from the needed amount estimated during the Spinning Reserve Market
Clearing Price calculation, in proportion to the amount of the reduction in Tier
1 Spinning Reserve availability.



j) In the event a resource that either has been
assigned by the Office of the Interconnection or self-scheduled by the owner to
provide Tier 2 Spinning Reserve fails to provide the assigned or self-scheduled
amount of Spinning Reserve in response to an actual Spinning Reserve Event, the
owner of the resource shall incur an additional Spinning Reserve Obligation in
the amount of the shortfall for a period of three consecutive days with the same
peak classification (on-peak or off-peak) as the day of the Spinning Event at
least three business days following the Spinning Reserve Event. The overall
Spinning Reserve requirement for each Spinning Reserve Zone of the PJM Region on
which the Spinning Reserve Obligations, except for the additional obligations
set forth in this section, are based shall be reduced by the amount of this
shortfall for the applicable three-day period.



3.2.3B Reactive Services.



(a) A Market Seller providing Reactive Services at
the direction of the Office of the Interconnection shall be credited as
specified below for the operation of its resource. These provisions are intended
to provide payments to generating units when the LMP dispatch algorithms would
not result in the dispatch needed for the required reactive service. LMP will be
used to compensate generators that are subject to redispatch for reactive
transfer limits.



(b) At the end of each Operating Day, where the
active energy output of a Market Seller’s resource is reduced or suspended at
the request of the Office of the Interconnection for the purpose of maintaining
reactive reliability within the PJM Region, the Market Seller shall be credited
according to Sections 3.2.3B(c) & 3.2.3B(d).



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 116AThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 116A




(c) A Market Seller providing Reactive Services
from either a steam-electric generating unit or combined cycle unit operating in
combined cycle mode, where such unit is pool-scheduled (or self-scheduled, if
operating according to paragraph 1.10.3 (c)), and where the hourly integrated,
real time LMP at the unit’s bus is higher than the price offered by the Market
Seller for energy from the unit at the level of output requested by the Office
of the Interconnection (as indicated either by the desired MWs of output from
the unit determined by PJM’s unit dispatch system or as directed by the PJM
dispatcher through a manual override) shall be compensated for lost opportunity
cost by receiving a credit hourly in an amount equal to {(LMPDMW - AG) x (URTLMP
- UB)}



where:



LMPDMW equals the level of output for the unit
determined according to the point on the scheduled offer curve on which the unit
was operating corresponding to the hourly integrated real time LMP;



AG equals the actual hourly integrated output of
the unit;



URTLMP equals the real time LMP at the unit’s bus;



UB equals the unit offer for that unit for which
output is reduced or suspended determined according to the real time scheduled
offer curve on which the unit was operating, unless such schedule was a
price-based schedule and the offer associated with that price-based schedule is
less than the cost-based offer for the unit, in which case the offer for the
unit will be determined based on the cost-based schedule; and



where URTLMP - UB shall not be negative.



(d) A Market Seller providing Reactive Services
from either a combustion turbine unit or combined cycle unit operating in simple
cycle mode that is pool scheduled (or self-scheduled, if operating according to
paragraph 1.10.3 (c)), operated as requested by the Office of the
Interconnection, shall be compensated for lost opportunity cost if either of the
following conditions occur:



(i) if the unit output is reduced at the direction
of the Office of the Interconnection and the real time LMP at the unit’s bus is
higher than the price offered by the Market Seller for energy from the unit at
the level of output requested by the Office of the Interconnection as directed
by the PJM dispatcher, then the Market Seller shall be credited in a manner
consistent with that described above in Section 3.2.3B(c) for a steam unit or a
combined cycle unit operating in combined cycle mode.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    September 1, 2004Vice President, Government
    PolicyIssued On:
    
    August 9, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER03-1086-001, issued July 9, 2004, 108 FERC ¶
61,030.




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 116BThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 116B




(ii) if the unit is scheduled to produce energy in
the day-ahead market, but the unit is not called on by PJM and does not operate
in real time, then the Market Seller shall be credited hourly in an amount equal
to the higher of (i) {(URTLMP – UDALMP) x DAG, or (ii) {(URTLMP – UB) x DAG
where:



URTLMP equals the real time LMP at the unit’s bus;



UDALMP equals the day-ahead LMP at the unit’s bus;



DAG equals the day-ahead scheduled unit output for
the hour;



UB equals the offer price for the unit determined
according to the schedule on which the unit was committed day-ahead, unless such
schedule was a price-based schedule and the offer associated with that
price-based schedule is less than the cost-based offer for the unit, in which
case the offer for the unit will be determined based on the cost-based schedule;
and



where URTLMP - UDALMP and URTLMP – UB shall not be
negative.



(e) At the end of each Operating Day, where the
active energy output of a Market Seller’s unit is increased at the request of
the Office of the Interconnection for the purpose of maintaining reactive
reliability within the PJM Region and the offered price of the energy is above
the real-time LMP at the unit’s bus, the Market Seller shall be credited
according to Section 3.2.3B(f).



(f) A Market Seller providing Reactive Services
from either a steam-electric generating unit, combined cycle unit or combustion
turbine unit, where such unit is pool scheduled (or self-scheduled, if operating
according to paragraph 1.10.3 (c)), and where the hourly integrated, real time
LMP at the unit’s bus is lower than the price offered by the Market Seller for
energy from the unit at the level of output requested by the Office of the
Interconnection (as indicated either by the desired MWs of output from the unit
determined by PJM’s unit dispatch system or as directed by the PJM dispatcher
through a manual override), shall receive a credit hourly in an amount equal to
{(AG - LMPDMW) x (UB - URTLMP)}where:



AG equals the actual hourly integrated output of
the unit;



LMPDMW equals the level of output for the unit
determined according to the point on the scheduled offer curve on which the unit
was operating corresponding to the hourly integrated real time LMP;



UB equals the unit offer for that unit for which
output is increased, determined according to the real time scheduled offer curve
on which the unit was operating;



URTLMP equals the real time LMP at the unit’s bus;
and



where UB - URTLMP shall not be negative.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 116CThird Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 116C




(g) A Market Seller providing Reactive Services
from a hydroelectric resource where such resource is pool scheduled (or
self-scheduled, if operating according to paragraph 1.10.3 (c)), and where the
output of such resource is altered from the schedule submitted by the Market
Seller for the purpose of maintaining reactive reliability at the request of the
Office of the Interconnection, shall be compensated for lost opportunity cost in
the same manner as provided in sections 3.2.2A(d) and 3.2.3A(f) and further
detailed in the PJM Manuals.



(h) If a Market Seller can demonstrate to the
satisfaction of the Office of the Interconnection and the Market Monitoring Unit
that, due to specific pre-existing binding commitments to which it is a party,
and that properly should be recognized for purposes of this section, the above
calculations do not accurately compensate the Market Seller for lost opportunity
cost associated with following the Office of the Interconnection’s dispatch
instructions to reduce or suspend a unit’s output for the purpose of maintaining
reactive reliability, then the Office of the Interconnection will provide such
alternate lost opportunity cost compensation to the Market Seller as can be
agreed upon by the Market Seller, the Office of the Interconnection and the
Market Monitoring Unit.



(i) The amount of spinning reserve provided by
units maintaining reactive reliability shall be counted as Spinning Reserve
satisfying the overall PJM Spinning Reserve requirements. Operators of these
units shall be notified of such provision, and to the extent a unit’s operator
indicates that the unit is capable of providing Spinning Reserve, shall be
subject to the same requirements contained in Section 3.2.3A regarding provision
of Tier 2 Spinning Reserve. At the end of each Operating Day, to the extent a
condenser operated to provide Reactive Services also provided Spinning Reserve,
a Market Seller shall be credited for providing synchronous condensing for the
purpose of maintaining reactive reliability at the request of the Office of the
Interconnection, in an amount equal to the higher of (i) the hourly Spinning
Reserve Market Clearing Price for each hour a unit provided synchronous
condensing multiplied by the amount of spinning reserve provided by the
synchronous condenser or (ii) the sum of (A) the unit’s hourly cost to provide
synchronous condensing, calculated in accordance with the PJM Manuals, (B) the
hourly product of MW energy usage for providing synchronous condensing
multiplied by the real time LMP at the unit’s bus, (C) the unit’s startup-cost
of providing synchronous condensing, and (D) the unit-specific lost opportunity
cost of the resource supplying the increment of Spinning Reserve as determined
by the Office of the Interconnection in accordance with procedures specified in
the PJM Manuals. To the extent a condenser operated to provide Reactive Services
was not also providing Spinning Reserve, the Market Seller shall be credited
only for the unit’s cost to condense, as described in (ii) above. The total
Spinning Reserve Obligations of all Load Serving Entities under section
3.2.3A(a) in the zone where these condensers are located shall be reduced by the
amount counted as satisfying the PJM Spinning Reserve requirements. The Spinning
Reserve Obligation of each Load Serving Entity in the zone under section
3.2.3A(a) shall be reduced to the same extent that the costs of such condensers
counted as Spinning Reserve are allocated to such Load Serving Entity pursuant
to paragraph (l) below.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    September 1, 2004Vice President, Government
    PolicyIssued On:
    
    July 2, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 116C.01Third Revised Rate Schedule FERC No.
      24




(j) A Market Seller’s pool scheduled
steam-electric generating unit or combined cycle unit operating in combined
cycle mode, that is not committed to operate in the Day-ahead Market, but that
is directed by the Office of Interconnection to operate solely for the purpose
of maintaining reactive reliability, at the request of the Office of the
Interconnection, shall be credited in the amount of the unit’s offered price for
start-up and no-load fees. The unit also shall receive, if applicable,
compensation in accordance with Sections 3.2.3B(e)-(f).



(k) The sum of the foregoing credits as specified
in Sections 3.2.3B(b)-(j) shall be the cost of Reactive Services for the purpose
of maintaining reactive reliability for the Operating Day and shall be
separately determined for each transmission zone in the PJM Region based on
whether the resource was dispatched for the purpose of maintaining reactive
reliability in such transmission zone.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    September 1, 2004Vice President, Government
    PolicyIssued On:
    
    July 2, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 116DThird Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 116D




(l) The cost of Reactive Services for the purpose
of maintaining reactive reliability in a transmission zone in the PJM Region for
each Operating Day shall be allocated and charged to each Market Participant in
proportion to its deliveries of energy to load in such transmission zone, served
under Network Transmission Service, in megawatt-hours during that Operating Day,
as compared to all such deliveries for all Market Participants in such
transmission zone.



(m) Generating units receiving dispatch
instructions from the Office of the Interconnection under the expectation of
increased actual or reserve reactive shall inform the Office of the
Interconnection dispatcher if the requested reactive capability is not
achievable. Should the operator of a unit receiving such instructions realize at
any time during which said instruction is effective that the unit is not, or
likely would not be able to, provide the requested amount of reactive support,
the operator shall as soon as practicable inform the Office of the
Interconnection dispatcher of the unit’s inability, or expected inability, to
provide the required reactive support, so that the associated dispatch
instruction may be cancelled. PJM Performance Compliance personnel will audit
operations after-the-fact to determine whether a unit that has altered its
active power output at the request of the Office of the Interconnection has
provided the actual reactive support or the reactive reserve capability
requested by the Office of the Interconnection. PJM shall utilize data
including, but not limited to, historical reactive performance and stated
reactive capability curves in order to make this determination, and may withhold
such compensation as described above if reactive support as requested by the
Office of the Interconnection was not or could not have been provided.



3.2.3C Synchronous Condensing for
Post-Contingency Operation.



(a) Under normal circumstances, PJM operates
generation out of merit order to control contingency overloads when the flow on
the monitored element for loss of the contingent element (“contingency flow”)
exceeds the long-term emergency rating for that facility, typically a 4-hour or
2-hour rating. At times however, and under certain, specific system conditions,
PJM does not operate generation out of merit order for certain contingency
overloads until the contingency flow on the monitored element exceeds the
30-minute rating for that facility (“post-contingency operation”). In
conjunction with such operation, when the contingency flow on such element
exceeds the long-term emergency rating, PJM operates synchronous condensers in
the areas affected by such constraints, to the extent they are available, to
provide greater certainty that such resources will be capable of producing
energy in sufficient time to reduce the flow on the monitored element below the
normal rating should such contingency occur.



(b) The amount of spinning reserve provided by
synchronous condensers associated with post-contingency operation shall be
counted as spinning reserve satisfying the PJM Spinning Reserve requirements.
Operators of these units shall be notified of such provision, and to the extent
a unit’s operator indicates that the unit is capable of providing Spinning
Reserve, shall be subject to the same requirements contained in Section 3.2.3A
regarding provision of Tier 2 Spinning Reserve. At the end of each Operating
Day, to the extent a condenser operated in conjunction with post-contingency
operation also provided Spinning Reserve, a Market Seller shall be credited for
providing synchronous condensing in conjunction with post-contingency operation
at the request of the Office of the Interconnection, in an amount equal to the
higher of (i) the hourly Spinning Reserve Market Clearing Price for each hour a
resource provided synchronous condensing multiplied by the amount of spinning
reserve provided by the synchronous condenser or (ii) the sum of (A) the
resource’s hourly cost to



Issued By:
    
    Craig Glazer
    
    Effective:
    
    September 1, 2004Vice President, Government
    PolicyIssued On:
    
    July 2, 2004




---

PJM Interconnection, L.L.C.
    
    Original Sheet No. 116D.01Third Revised Rate Schedule FERC No.
      24




provide synchronous condensing multiplied by the
real-time LMP at the generation bus of the resource, (C) the resource’s start-up
cost of providing synchronous condensing, and (D) the unit-specific lost
opportunity cost of the resource supplying the increment of Spinning Reserve as
determined by the Office of the Interconnection in accordance with procedures
specified in the PJM Manuals. To the extent a condenser operated in association
with post-contingency constraint control was not also providing Spinning
Reserve, the Market Seller shall be credited only for the unit’s cost to
condense, as described in (ii) above. The total Spinning Reserve Obligations of
all Load Serving Entities under section 3.2.3A(a) in the zone where these
condensers are located shall be reduced by the amount counted as satisfying the
PJM Spinning Reserve requirements. The Spinning Reserve Obligation of each Load
Serving Entity in the zone under section 3.2.3A(a) shall be reduced to the same
extent that the costs of such condensers counted as Spinning Reserve are
allocated to such Load Serving Entity pursuant to paragraph (d) below.



(c) The sum of the foregoing credits as specified
in section 3.2.3C(b) shall be the cost of synchronous condensers associated with
post-contingency operations for the Operating Day and shall be separately
determined for each transmission zone in the PJM Region based on whether the
resource was dispatched in association with post-contingency operation in such
transmission zone.



(d) The cost of synchronous condensers associated
with post-contingency operations in a transmission zone in the PJM Region for
each Operating Day shall be allocated and charged to each Market Participant in
proportion to its deliveries of energy to load in such transmission zone, served
under Network Transmission Service, in megawatt-hours during that Operating Day,
as compared to all such deliveries for all Market Participants in such
transmission zone.



3.2.4 Transmission Congestion.



Each Market Buyer shall be charged or credited for
Transmission Congestion Charges as specified in Section 5 of this Schedule.



3.2.5 Transmission Losses.



(a) Whenever the Office of the Interconnection has
in place appropriate computer hardware, software, and other necessary resources
to account for marginal losses in the dispatch of energy and the calculation of
Locational Marginal Prices, loss accounting shall be determined on that basis,
and the provisions of this Section shall be revised accordingly. Until such
time, the following accounting provisions for losses shall apply.



(b) Each Internal Market Buyer that is a Load
Serving Entity or purchasing on behalf of a Load Serving Entity shall be
credited in an amount equal to its pro rata share of the hourly total
amounts collected from Transmission Customers either as charges for transmission



Issued By:
    
    Craig Glazer
    
    Effective:
    
    September 1, 2004Vice President, Government
    PolicyIssued On:
    
    July 2, 2004




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 117Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 117




losses in the PJM Region as specified in Section
3.4.2 or for transmission losses supplied in kind in accordance with Section
3.4.2(c) based on the Locational Marginal Price at the interface where such
losses were delivered. This credit shall be determined by the ratio of the
Internal Market Buyer’s total hourly load (net of its operating Behind The Meter
Generation, but not to be less than zero), divided by the total hourly load in
the PJM Region (net of total operating Behind The Meter Generation).



(c) MAAC Control Zone 500 kV losses shall be
allocated to each Electric Distributor that reports hourly net energy flows from
metered tie lines in proportion to its hourly load (net of operating Behind The
Meter Generation, but not to be less than zero) in the MAAC Control Zone.



(d) 500 kV and 345 kV losses in the PJM West
Region shall be allocated to each Electric Distributor that reports hourly net
energy flows from metered tie lines in proportion to its hourly load (net of
Behind The Meter Generation, but not to be less than zero) in the PJM West
Region.



3.2.6 Emergency Energy.



(a) Market Participants shall be allocated a
proportionate share of the net cost of Emergency energy purchased by the Office
of the Interconnection. Such allocated share during each hour of such Emergency
energy purchase shall be in proportion to the amount of each Market
Participant’s real-time deviation from its net PJM Interchange in the Day-ahead
Energy Market, whenever that deviation increases the Market Participant’s spot
market purchases or decreases its spot market sales. This deviation shall not
include any reduction or suspension of output of pool scheduled resources
requested by PJM to manage an Emergency within the PJM Region.



(b) Net revenues in excess of Real-time Prices
attributable to sales of energy in connection with Emergencies to other Control
Areas shall be credited to Market Participants during each hour of such
Emergency energy sale in proportion to the sum of (i) each Market Participant’s
real-time deviation from its net PJM Interchange in the Day-ahead Energy Market,
whenever that deviation increases the Market Participant’s spot market purchases
or decreases its spot market sales, and (ii) each Market Participant’s energy
sales from within the PJM Region to entities outside the PJM Region that have
been curtailed by PJM.



(c) The net costs or net revenues associated with
sales or purchases of hourly energy in connection with a Minimum Generation
Emergency in the PJM Region, or in another Control Area, shall be allocated
during each hour of such Emergency sale or purchase to each Market Participant
in proportion to the amount of each Market Participant’s real-time deviation
from its net PJM Interchange in the Day-ahead Market, whenever that deviation
increases the Market Participant’s spot market sales or decreases its spot
market purchases.



3.2.7 Billing.



(a) The Office of the Interconnection shall
prepare a billing statement each billing cycle for each Market Buyer in
accordance with the charges and credits specified in Sections 3.2.1 through
3.2.6 of this Schedule, and showing the net amount to be paid or received by the
Market Buyer. Billing statements shall provide sufficient detail, as specified
in the PJM Manuals, to allow verification of the billing amounts and completion
of the Market Buyer’s internal accounting.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2004Vice President, Government
    PolicyIssued On:
    
    August 31, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 118Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 118




(b) If deliveries to a Market Buyer that has PJM
Interchange meters in accordance with Section 14 of the Operating Agreement
include amounts delivered for a Market Participant that does not have PJM
Interchange meters separate from those of the metered Market Buyer, the Office
of the Interconnection shall prepare a separate billing statement for the
unmetered Market Participant based on the allocation of deliveries agreed upon
between the Market Buyer and the unmetered Market Participant specified by them
to the Office of the Interconnection.



3.3 Market Sellers.



Except as provided in the following sentence, the
accounting and billing principles and procedures applicable to Generating Market
Buyers functioning as Market Sellers shall be as set forth in Section 3.2. This
Section sets forth the accounting and billing principles and procedures
applicable to all other Market Sellers, and to Generating Market Buyers
functioning as Market Sellers with respect to any matters not specified in
Section 3.2.



3.3.1 Spot Market Energy.



(a) Market Sellers shall be paid for all energy
scheduled to be delivered in the Day-ahead Energy Market at the Day-ahead Prices
applicable to each relevant generation bus.



(b) At the end of each hour during an Operating
Day, the Office of the Interconnection shall determine the total net amount of
energy delivered in the hour to the PJM Region by each of the Market Seller’s
resources, in accordance with the PJM Manuals and the calculation described in
Section 3.2.1(f).



(c) The Office of the Interconnection shall
calculate Day-ahead and Real-time Prices for each generation and load bus in the
PJM Region, including the bus at each point of interconnection between PJM and
each adjacent Control Area, in accordance with Section 2 of this Schedule.



(d) A Market Seller shall be credited for
Real-time sales of Spot Market Energy to the extent of its hourly net deliveries
to the PJM Region of energy in excess of amounts scheduled in the Day-ahead
Energy Market from the Market Seller’s resources. For pool External Resources,
the Office of the Interconnection shall model, based on an appropriate flow
analysis, the hourly amounts delivered from each such resource to the
corresponding interface point between adjacent Control Areas and the PJM Region.
The total real-time generation revenues for each Market Seller shall be the sum
of its credits determined by the product of (i) the hourly net amount of energy
delivered to the PJM Region at the applicable generation or interface bus in
excess of the amount scheduled to be delivered in that hour at that bus in the
Day-ahead Energy Market from each of the Market Seller’s resources, times (ii)
the hourly Real-time Price at that bus. To the extent that the energy actually
injected at a generation or interface bus in any hour is less than the energy
scheduled to be injected at that bus in the Day-ahead Energy Market, the Market
Seller shall be debited for the difference at the Real-time Price for the
applicable bus at the time of the shortfall times the amount of the shortfall.
The total generation revenue for each Market Seller shall be the sum, for each
of the Market Seller’s generation or interface buses, of the revenues at
Day-ahead Prices determined in accordance with the Day-ahead Energy Market as
specified in Section 3.3.1(a) plus the revenues at Real-time Prices determined
as specified herein, net of any debits specified herein for each of the Market
Seller’s generation or interface buses.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 119Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 119




3.3.2 Control Zone Regulation.



Each Market Seller that is also an Internal Market
Buyer as to load in a Regulation Zone shall have an hourly Regulation objective
and shall be credited or charged in connection therewith as specified in Section
3.2.2. All other Market Sellers supplying Regulation in such Regulation Zone at
the direction of the Office of the Interconnection shall be credited for each
increment of such Regulation at the price specified in Section 3.2.2(b), as
determined by the Office of the Interconnection in accordance with procedures
specified in the PJM Manuals.



3.3.3 Operating Reserves.



A Market Seller shall be credited for its
pool-scheduled resources based on the prices offered for the operation of such
resource, provided that the resource was available for the entire time specified
in the Offer Data for such resource, in accordance with the procedures set forth
in Section 3.2.3.



3.3.4 Emergency Energy.



The net costs or net revenues associated with
purchases or sales of energy in connection with Emergencies in the PJM Region,
or in another Control Area, shall be allocated to Market Participants in
accordance with the procedures set forth in Section 3.2.6.



3.3.5 Spinning Reserve.



Each Market Seller that is also an Internal Market
Buyer shall have an hourly Spinning Reserve objective and shall be credited or
charged in connection therewith as specified in Section 3.2.3A(a). All other
Market Sellers supplying Spinning Reserve at the direction of the Office of the
Interconnection shall be credited for each increment of such Spinning Reserve at
the price specified in Section 3.2.3A(b), as determined by the Office of the
Interconnection in accordance with procedures specified in the PJM Manuals.



3.3.6 Billing.



The Office of the Interconnection shall prepare a
billing statement each billing cycle for each Market Seller in accordance with
the charges and credits specified in Sections 3.3.1 through 3.3.5 of this
Schedule, and showing the net amount to be paid or received by the Market
Seller. Billing statements shall provide sufficient detail, as specified in the
PJM Manuals, to allow verification of the billing amounts and completion of the
Market Seller’s internal accounting.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 120Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 120




3.4 Transmission Customers.



3.4.1 Transmission Congestion.



Each Transmission Customer shall be charged and
credited for Transmission Congestion Charges as specified in Section 5 of this
Schedule.



3.4.2 Transmission Losses.



(a) Whenever the Office of the Interconnection has
in place appropriate computer hardware, software, and other necessary resources
to account for marginal losses in the dispatch of energy and the calculation of
Locational Marginal Prices, loss accounting shall be determined on that basis,
and the provisions of this Section shall be revised accordingly. Until such
time, the following accounting provisions for losses shall apply.



(b) Transmission Customers shall be charged for
transmission losses in an amount equal to the product of (i) the Transmission
Customer’s megawatt-hours of deliveries using Point-to-Point Transmission
Service, times (ii) the appropriate loss factor for deliveries using
Point-to-Point Transmission Service, times (iii) the weighted average Day-ahead
or Real-time Price, as applicable, for all load buses in the PJM Region. The
foregoing average hourly loss factor shall be: (i) determined by the Office of
the Interconnection from time to time as conditions affecting losses shall
warrant; and (ii) calculated separately for on-peak and off-peak hours on the
basis of the average ratio of losses to load served in each such period.



(c) A Transmission Customer may elect to pay for
losses in kind, rounded off to the nearest whole megawatt, rather than as
specified above if its total deliveries in an hour using Point-to-Point
Transmission Service are greater than 200 megawatts. If it so elects, the
Transmission Customer’s specified source for the energy to be delivered using
Point-to-Point Transmission Service may be scheduled to supply to the boundary
of the PJM Region an amount of energy equal to the delivery schedule plus the
amount of losses determined by applying the appropriate hourly loss factor, as
specified above, to the delivered amount.



3.4.3 Billing.



The Office of the Interconnection shall prepare a
billing statement each billing cycle for each Transmission Customer in
accordance with the charges and credits specified in Sections 3.4.1 through
3.4.2 of this Schedule, and showing the net amount to be paid or received by the
Transmission Customer. Billing statements shall provide sufficient detail, as
specified in the PJM Manuals, to allow verification of the billing amounts and
completion of the Transmission Customer’s internal accounting.



3.5 Other Control Areas.



3.5.1 Energy Sales.



To the extent appropriate in accordance with Good
Utility Practice, the Office of the Interconnection may sell energy to a Control
Area interconnected with the PJM Region as necessary to alleviate or end an
Emergency in that interconnected Control Area. Such sales shall be made (i) only
to Control Areas that have



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 121Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 121




undertaken a commitment pursuant to a written
agreement with the LLC to sell energy on a comparable basis to the PJM Region,
and (ii) only to the extent consistent with the maintenance of reliability in
the PJM Region. The Office of the Interconnection may decline to make such sales
to a Control Area that the Office of the Interconnection determines does not
have in place and implement Emergency procedures that are comparable to those
followed in the PJM Region. If the Office of the Interconnection sells energy to
an interconnected Control Area as necessary to alleviate or end an Emergency in
that Control Area, such energy shall be sold at 150% of the Real-time Price at
the bus or buses at the border of the PJM Region at which such energy is
delivered.



3.5.2 Operating Margin Sales.



To the extent appropriate in accordance with Good
Utility Practice, the Office of the Interconnection may sell Operating Margin to
an interconnected Control Area as requested to alleviate an operating
contingency resulting from the effect of the purchasing Control Area’s
operations on the dispatch of resources in the PJM Region. Such sales shall be
made only to Control Areas that have undertaken a commitment pursuant to a
written agreement with the Office of the Interconnection (i) to purchase
Operating Margin whenever the purchasing Control Area’s operations will affect
the dispatch of resources in the PJM Region, and (ii) to sell Operating Margin
on a comparable basis to the LLC.



3.5.3 Transmission Congestion.



Each Control Area purchasing Operating Margin
shall be assessed Transmission Congestion Charges as specified in Section 5.1.5
of this Schedule.



3.5.4 Billing.



The Office of the Interconnection shall prepare a
billing statement each billing cycle for each Control Area to which Emergency
energy or Operating Margin was sold, and showing the net amount to be paid by
such Control Area. Billing statements shall provide sufficient detail, as
specified in the PJM Manuals, to allow verification of the billing amounts.



3.6 Metering Reconciliation.



3.6.1 Meter Correction Billing.



Metering errors and corrections will be reconciled
at the end of each month by a meter correction charge or credit. The monthly
meter correction charge or credit shall be determined by the product of the
positive or negative deviation in energy amounts, times the weighted average
Locational Marginal Price for all load buses in the PJM Region.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 122Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 122




3.6.2 Meter Corrections Between Market
Participants.



If a Market Participant or the Office of the
Interconnection discovers a meter error affecting an interchange of energy with
another Market Participant and makes the error known to such other Market
Participant prior to the completion by the Office of the Interconnection of the
accounting for the interchange, and if both Market Participants are willing to
adjust hourly load records to compensate for the error and such adjustment does
not affect other parties, an adjustment in load records may be made by the
Market Participants in order to correct for the meter error, provided corrected
information is furnished to the Office of the Interconnection in accordance with
the Office of the Interconnection’s accounting deadlines. No such adjustment may
be made if the accounting for the Operating Day in which the interchange
occurred has been completed by the Office of the Interconnection.



3.6.3 500 kV Meter Errors.



Billing cycle accounting for 500 kV transmission
losses shall be adjusted to account for errors in meters on 500 kV Transmission
Facilities.



3.6.4 Meter Corrections Between Control Areas.



An error between accounted for and metered
interchange between a Party in the PJM Region and an entity in a Control Area
other than the PJM Region shall be corrected by adjusting the hourly meter
readings. If this is not practical, the error shall be accounted for by a
correction at the end of the billing cycle. The Market Participant with ties to
such other Control Area experiencing the error shall account for the full amount
of the discrepancy and an appropriate debit or credit shall be applied equally
among all Market Buyers. The Office of the Interconnection will adjust the
actual interchange between the other Control Area and the PJM Region to maintain
a proper record of inadvertent energy flow. Meter corrections on the 500 kV
system between the PJM Region and other Control Areas shall be accounted for
through the internal 500 kV system meter error allocation at the end of the
billing cycle.



3.6.5 Meter Correction Data.



Meter error data shall be submitted to the Office
of the Interconnection not later than noon on the second working day of the
Office of the Interconnection after the end of the billing cycle applicable to
the meter correction.



3.6.6 Correction Limits.



A Market Participant may not assert a claim for an
adjustment in billing as a result of a meter error for any error discovered more
than two years after the date on which the metering occurred. Any claim for an
adjustment in billing as a result of a meter error shall be limited to bills for
transactions occurring in the most recent annual accounting period of the
billing Market Participant in which the meter error occurred, and the prior
annual accounting period.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 123Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 123




4. RATE TABLE



4.1 Offered Price Rates.



Spot Market Energy, Regulation, Operating Reserve,
and Transmission Congestion are based on offers to the Office of the
Interconnection specified in this Agreement.



4.2 Transmission Losses.



Average loss factors shall be as specified in the
PJM Tariff.



4.3 Emergency Energy Purchases.



The pricing for Emergency energy purchases will be
determined by the Office of the Interconnection and: (a) an adjacent Control
Area, in accordance with an agreement between the Office of the Interconnection
and such adjacent Control Area, or (b) a Member, in accordance with arrangements
made by the Office of Interconnection to purchase energy offered by such Member
from resources that are not Capacity Resources.



5. CALCULATION OF TRANSMISSION CONGESTION
CHARGES AND CREDITS



5.1 Transmission Congestion Charge Calculation.



5.1.1 Calculation by Office of the
Interconnection.



When the transmission system is operating under
constrained conditions, or as necessary to provide third-party transmission
provider losses in accordance with Section 9.3, the Office of the
Interconnection shall calculate Transmission Congestion Charges for each Network
Service User, the PJM Interchange Energy Market, and each Transmission Customer.



5.1.2 General.



The basis for the Transmission Congestion Charges
shall be the differences in the Locational Marginal Prices between points of
delivery and points of receipt, as determined in accordance with Section 2 of
this Schedule.



5.1.3 Network Service User Calculation.



Each Network Service User shall be charged for the
increased cost of energy incurred by it during each constrained hour to deliver
the output of its firm Capacity Resources or other owned or contracted for
resources, its firm bilateral purchases, and its non-firm bilateral purchases as
to which it has elected to pay Transmission Congestion Charges. The Transmission
Congestion Charge for deliveries from each such source shall be the Network
Service User’s hourly net bill less its hourly net PJM Interchange payments or
sales as determined in accordance with Section 3.2.1 or Sections 3.3 and 3.3.1
of this Schedule.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 124Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 124




5.1.4 Transmission Customer Calculation.



Each Transmission Customer using Firm
Point-to-Point Transmission Service (as defined in the PJM Tariff), and each
Transmission Customer using Non-Firm Point-to-Point Transmission Service (as
defined in the PJM Tariff) that has elected to pay Transmission Congestion
Charges, shall be charged for the increased cost of energy during constrained
hours for the delivery of energy using Point-to-Point Transmission Service.
Except as specified in this subsection, a Transmission Congestion Charge shall
be assessed for transmission use scheduled in the Day-ahead Energy Market,
calculated as the amount to be delivered multiplied by the difference between
the Day-ahead Price at the delivery point or the delivery interface at the
boundary of the PJM Region and the Day-ahead Price at the source point or the
source interface at the boundary of the PJM Region. Transmission Congestion
Charges shall be assessed for real-time transmission use in excess of the
amounts scheduled for each hour in the Day-ahead Energy Market, calculated as
the excess amount multiplied by the difference between the Real-time Price at
the delivery point or the delivery interface at the boundary of the PJM Region,
and the Real-time Price at the source point or the source interface at the
boundary of the PJM Region. A Transmission Customer shall be credited for
Transmission Congestion Charges for real-time transmission use falling below the
amounts scheduled for each hour in the Day-ahead Energy Market, calculated as
the shortfall amount multiplied by the difference between the Real-time Price at
the delivery point or the delivery interface at the boundary of the PJM Region,
and the Real-time Price at the source point or the source interface at the
boundary of the PJM Region. Real-time deviations from the Point-to-Point
Transmission Service scheduled in the Day-ahead Energy Market shall be
determined by the lesser of the real-time injection or withdrawal associated
with such transmission service. The Transmission Congestion Charge for Market
Sellers using point-to-point transmission service for deliveries out of the PJM
Region from generating resources within such area shall be the amount of its net
bill less the Market Seller’s net hourly PJM Interchange payments or sales as
determined in accordance with Section 3.3 of this Schedule.



5.1.5 Operating Margin Customer Calculation.



Each Control Area purchasing Operating Margin
shall be assessed Transmission Congestion Charges for any increase in the cost
of energy resulting from the provision of Operating Margin. The Transmission
Congestion Charge shall be the amount of Operating Margin purchased in an hour
multiplied by the difference in the Real-time Price at what would be the
delivery interface and the Real-time Price at what would be the source
interface, if the operating contingency that was the basis for the purchase of
Operating Margin had occurred in that hour. Operating Margin may be allocated
among multiple source and delivery interfaces in accordance with an applicable
load flow study.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 125Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 125




5.1.6 Transmission Loading Relief Customer
Calculation.



(a) Each Transmission Loading Relief Customer
shall be assessed Transmission Congestion Charges for any increase in the cost
of energy in the PJM Region resulting from its energy schedules over contract
paths outside the PJM Region during Transmission Loading Relief.



(b) The Transmission Congestion Charge shall be
the total amount of energy specified in such energy schedules multiplied by the
difference between a Locational Marginal Price calculated by the Office of the
Interconnection for the energy schedule source location specified in the NERC
Interchange Distribution Calculator and a Locational Marginal Price calculated
by the Office of the Interconnection for the energy schedule sink location
specified in the NERC Interchange Distribution Calculator. Transmission
Congestion Charges that are less than zero shall be set equal to zero for
Transmission Loading Relief Customers.



(c) The Office of the Interconnection will
determine the Locational Marginal Prices at the energy schedule source and sink
locations external to PJM with reference to and based solely on the prices of
energy in the PJM Region and at the interface buses between adjacent Control
Areas and the PJM Region and the system conditions and actual power flow
distributions as described by the PJM State Estimator program. The Office of the
Interconnection will determine the Locational Marginal Prices at the external
energy schedule source and sink locations and the resulting Congestion Charge
based on the portion of the energy schedule that flows through the PJM Region as
reflected by the flow distributions from the PJM State Estimator program.



5.1.7 Total Transmission Congestion
Charges.



The total Transmission Congestion Charges
collected by the Office of the Interconnection each hour will be the aggregate
net amounts determined as specified in this Schedule. The Office of the
Interconnection shall collect Transmission Congestion Charges for each hour the
transmission system operates under constrained conditions.



5.2 Transmission Congestion Credit
Calculation.



5.2.1 Eligibility.



(a) Except as provided in Section 5.2.1(b), each
holder of a Financial Transmission Right shall receive as a Transmission
Congestion Credit a proportional share of the total Transmission Congestion
Charges collected for each constrained hour.



(b) If a holder of a Financial Transmission Right
between specified delivery and receipt buses acquired the Financial Transmission
Right in a Financial Transmission Rights Auction (the procedures for which are
set forth in Part 7 of this Schedule 1) and (i) had an Increment Bid and/or
Decrement Bid that was accepted by the Office of the Interconnection for an
applicable hour in the Day-ahead Energy Market for delivery or receipt at or
near delivery or receipt buses of the Financial Transmission Right; and (ii) the
result of the acceptance of such Increment Bid or Decrement Bid is that the
difference in locational marginal prices in the Day-ahead Energy Market between
such delivery and receipt buses is greater than the difference in



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 126Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 126




locational marginal prices between such delivery
and receipt buses in the Real-time Energy Market, then the Market Participant
shall not receive any Transmission Congestion Credit, associated with such
Financial Transmission Right in such hour, in excess of one divided by the
number of hours in the applicable month multiplied by the amount that the Market
Participant paid for the Financial Transmission Right in the Financial
Transmission Rights Auction.



(c) For purposes of Section 5.2.1(b) a bus shall
be considered at or near the Financial Transmission Right delivery or receipt
bus if seventy-five percent or more of the energy injected or withdrawn at that
bus and which is withdrawn or injected at any other bus is reflected in the
constrained path between the subject Financial Transmission Right delivery and
receipt buses that were acquired in the Financial Transmission Rights Auction.



5.2.2 Financial Transmission Rights.



(a) Transmission Congestion Credits will be
calculated based upon the Financial Transmission Rights held at the time of the
constrained hour. Except as provided in paragraph (e) below, Financial
Transmission Rights shall be auctioned as set forth in Section 7.



(b) The hourly economic value of a Financial
Transmission Right Obligation is based on the Financial Transmission Right MW
reservation and the difference between the Day-ahead Price at the point of
delivery and the point of receipt of the Financial Transmission Right. The
hourly economic value of a Financial Transmission Right Obligation is positive
(a benefit to the Financial Transmission Right holder) when the Day-ahead Price
at the point of delivery is higher than the Day-ahead Price at the point of
receipt. The hourly economic value of a Financial Transmission Right Obligation
is negative (a liability to the holder) when the Day-ahead Price at the point of
receipt is higher than the Day-ahead Price at the point of delivery. The
Day-ahead Prices determined for purposes of this subsection shall exclude the
Locational Marginal Price adjustments for third-party transmission losses
provided by Section 9.3.



(c) The hourly economic value of a Financial
Transmission Right Option is based on the Financial Transmission Right MW
reservation and the difference between the Day-ahead Price at the point of
delivery and the point of receipt of the Financial Transmission Right when that
difference is positive. The hourly economic value of a Financial Transmission
Right Option is positive (a benefit to the Financial Transmission Right holder)
when the Day-ahead Price at the point of delivery is higher than the Day-ahead
Price at the point of receipt. The hourly economic value of a Financial
Transmission Right Option is zero (neither a benefit nor a liability to the
holder) when the Day-ahead Price at the point of receipt is higher than the
Day-ahead Price at the point of delivery. The Day-ahead Prices determined for
purposes of this subsection shall exclude the Locational Marginal Price
adjustments for third-party transmission losses provided by Section 9.3.



(d) A Financial Transmission Right, or the right
to Transmission Congestion Credits attributable to a Financial Transmission
Right, may be sold or otherwise transferred by agreement, subject to compliance
with such procedures as may be established by the Office of the Interconnection
for verification of the rights of the purchaser or transferee.



(e) Network Service Users and Firm Transmission
Customers that take service that sinks in new PJM zones, at their election, may
receive a direct allocation of Financial Transmission Rights instead of an
allocation of Auction Revenue Rights. Network Service Users and Firm
Transmission Customers may make this election for the succeeding two annual FTR
auctions after the integration of the new zone into the PJM interchange energy
market. Such



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Substitute First Revised Sheet No. 126AThird Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 126A




election shall be made prior to the commencement
of each annual FTR auction. For purposes of this election, the Allegheny Power
Zone shall be considered a new zone with respect to the annual Financial
Transmission Right auction in 2003 and 2004. Network Service Users and Firm
Transmission Customers in new PJM zones that elect not to receive direct
allocations of Financial Transmission Rights shall receive allocations of
Auction Revenue Rights. During the annual allocation process, the Financial
Transmission Right allocation for new PJM zones shall be performed
simultaneously with the Auction Revenue Rights allocations in existing and new
PJM zones. Prior to the effective date of the initial allocation of FTRs in a
new PJM Zone, PJM shall file with FERC, under section 205 of the Federal Power
Act, the FTRs and ARRs allocated in accordance with sections 5 and 7 of this
Schedule 1.



(f) For Network Service Users and Firm
Transmission Customers that take service that sinks in new PJM zones that elect
to receive direct allocations of Financial Transmission Rights, Financial
Transmission Rights shall be allocated using the same allocation methodology as
is specified for the allocation of Auction Revenue Rights in Section 7.4.2 and
in accordance with the following:



(i)
    All
      Financial Transmission Rights must be simultaneously feasible. If all
      Financial Transmission Right requests made when Financial Transmission
      Rights are allocated for the new zone are not feasible then Financial
      Transmission Rights are prorated and allocated in proportion to the MW
      level requested and in inverse proportion to the effect on the binding
      constraints.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    September 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 1, 2004Filed to comply with order of the Federal
      Energy Regulatory Commission, Docket Nos. ER03-406-005, issued August 2,
      2004, 108 FERC ¶ 61,117.




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 127Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 127




(ii)
    In the event that
      Network Load changes from one Network Service User to another after an
      initial or annual allocation of Financial Transmission Rights in a new
      zone, Financial Transmission Rights will be reassigned on a proportional
      basis from the Network Service User losing the load to the Network Service
      User that is gaining the Network Load.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    February 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    September 30, 2003




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 127AThird Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 127A




is gaining the Network Load may
      request Financial Transmission Rights commensurate with the amount of the
      Network Load gained.




(g) At least one month prior to the integration of
a new zone into the PJM interchange energy market, Network Service Users and
Firm Transmission Customers that take service that sinks in the new zone shall
receive an initial allocation of Financial Transmission Rights that will be in
effect from the date of the integration of the new zone until the next annual
allocation of Financial Transmission Rights and Auction Revenue Rights. Such
allocation of Financial Transmission Rights shall be made in accordance with
Section 5.2.2(f) of this Schedule.



(h) The following congestion charge crediting and
uplift (hereinafter, “mitigation”) rules shall apply to each new zone first
integrated on any date from May 1, 2004 through May 31, 2005 for which FERC
orders such mitigation as a result of a filing for such zone of the type
specified in subsection (g) above. Where FERC orders such mitigation, such rules
shall remain in effect for such zone from the date of its integration through
May 31, 2005. All such mitigation shall terminate for all such zones on May 31,
2005.



1.)
    Mitigation
      shall apply only to Long-Term Firm Point-to-Point Transmission Service
      customers in such a zone that did not receive an allocation of ARRs or
      FTRs, as applicable, equal to the ARRs or FTRs such customer requested in
      the allocation for such zone. Only pro-rated requests that complied with
      the source, sink, and service level limitations stated in section 7.4.2(d)
      are eligible for mitigation. Such mitigation shall continue for the period
      stated above if a customer eligible for mitigation renews or rolls over
      its service agreement, but shall no longer apply if such a customer
      redirects its service to alternate points on a firm basis.




2.)
    The affected
      customers that will receive mitigation will be notified by PJM of the MW
      amount of mitigation they will receive based on the difference between the
      amount of ARRs or FTRs requested and the amount of ARRs or FTRs awarded.




3.)
    Mitigation
      provided herein applies only to requests submitted and pro-rated in the
      interim or annual ARR/FTR allocation process conducted for such zones for
      the time period specified above.




4.)
    For each
      affected customer as described above, PJM each month will provide a
      mitigation credit to offset any congestion charges incurred by such
      customer in connection with the MW amount for the contract reservation
      eligible for mitigation as determined under paragraph (2) above. In no
      event shall the amount of any such credit exceed the net amount of any
      congestion paid (after taking account of any congestion credits) by such
      customer during such month with respect to such identified MW amount.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 24, 2004Filed to
      comply with the following orders of the Federal Energy Regulatory
      Commission: 1) Docket No. ER04-653-002, 108 FERC ¶ 61,307, issued
      September 22, 2004; 2) Docket No. ER04-742-001, 108 FERC ¶ 61,269, issued
      September 21, 2004; and 3) Docket No. ER04-1077-000, 108 FERC ¶ 61,246,
      issued September 17, 2004.




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 127BThird Revised Rate Schedule FERC No.
      24




5.)
    The total
      cost of all such credits for all mitigated customers in a zone each month
      shall be charged to and collected from all Network Integration
      Transmission Service and Long-Term Firm Point-to-Point Transmission
      Service customers within such zone that received ARRs or FTRs or that
      received mitigation under this subsection (h), in proportion to each such
      customer’s share of the total allocated ARR/FTR MWs (including mitigation
      MWs). Mitigation and uplift shall be determined separately for each such
      zone.




5.2.3 Target Allocation of Transmission
Congestion Credits.



A target allocation of Transmission Congestion
Credits for each entity holding a Financial Transmission Right shall be
determined for each Financial Transmission Rights. Each Financial Transmission
Right shall be multiplied by the Day-ahead Price differences for the receipt and
delivery points associated with the Financial Transmission Right, calculated as
the Locational Marginal Price at the delivery point(s) minus the Locational
Marginal Price at the receipt point(s). For the purposes of calculating
Transmission Congestion Credits, the Day-ahead Price of a Zone is calculated as
the sum of the Day-ahead Price of the buses that comprise the Zone multiplied by
the percent of annual peak load assigned to each node. When the FTR Target
Allocation is positive, the FTR Target Allocation is a credit to the FTR holder.
When the FTR



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 24, 2004Filed to
      comply with the following orders of the Federal Energy Regulatory
      Commission: 1) Docket No. ER04-653-002, 108 FERC ¶ 61,307, issued
      September 22, 2004; 2) Docket No. ER04-742-001, 108 FERC ¶ 61,269, issued
      September 21, 2004; and 3) Docket No. ER04-1077-000, 108 FERC ¶ 61,246,
      issued September 17, 2004.




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 128Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 128




Target Allocation is negative, the FTR Target
Allocation is a debit to the FTR holder if the FTR is a Financial Transmission
Right Obligation. When the FTR Target Allocation is negative, the FTR Target
Allocation is set to zero if the FTR is a Financial Transmission Right Option.
The total target allocation for Network Service Users and Transmission Customers
for each hour shall be the sum of the target allocations associated with all of
the Network Service Users’ or Transmission Customers’ Financial Transmission
Rights. The Day-ahead Prices determined for purposes of this section shall
exclude the Locational Marginal Price adjustments for third-party transmission
losses provided by Section 9.3.



5.2.4 [Reserved.]



5.2.5 Calculation of Transmission Congestion
Credits.



(a) The total of all the target allocations
determined as specified above shall be compared to the total Transmission
Congestion Charges in each hour resulting from both the Day-ahead Energy Market
and the Real-time Energy Market. If the total of the target allocations is less
than the total of the Transmission Congestion Charges, the Transmission
Congestion Credit for each entity holding an FTR shall be equal to its target
allocation. All remaining Transmission Congestion Charges shall be distributed
as described below in Section 5.2.6 “Distribution of Excess Congestion Charges.”



(b) If the total of the target allocations is
greater than the total Transmission Congestion Charges for the hour resulting
from both the Day-ahead Energy Market and the Real-time Energy Market, each
holder of Financial Transmission Rights shall be assigned a share of the total
Transmission Congestion Charges in proportion to its target allocations for
Financial Transmission Rights which have a positive Target Allocation value.
Financial Transmission Rights which have a negative Target Allocation value are
assigned the full Target Allocation value as a negative Transmission Congestion
Credit.



5.2.6 Distribution of Excess Congestion
Charges.



(a) Excess Transmission Congestion Charges
accumulated in a month shall be distributed to each holder of Financial
Transmission Rights in proportion to, but not more than, any deficiency in the
share of Transmission Congestion Charges received by the holder during that
month as compared to its total target allocations for the month.



(b) After the excess Transmission Congestion
Charge distribution described in Section 5.2.6(a) is performed, any excess
Transmission Congestion Charges remaining at the end of a month shall be
distributed to each holder of Financial Transmission Rights in proportion to,
but not more than, any deficiency in the share of Transmission Congestion
Charges received by the holder during the current Planning Period, including
previously distributed excess Transmission Congestion Charges, as compared to
its total target allocation for the Planning Period.



(c) Any excess Transmission Congestion Charges
remaining at the end of a Planning Period shall be distributed to each holder of
Auction Revenue Rights in proportion to, but not more than, any Auction Revenue
Right deficiencies for that Planning Period. After Auction Revenue Right
deficiencies are satisfied, any remaining excess Transmission Congestion Charges
shall be distributed to Network Service Users and Transmission Customers
purchasing Firm Point-to-Point Transmission Service in proportion to their
Demand Charges for Network Service and their charges for Reserved Capacity for
Firm Point-to-Point Transmission Service over such period.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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    Third
      Revised Sheet No. 129Third Revised Rate Schedule FERC No.
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    Superseding Original Sheet No. 129




5.3 Unscheduled Transmission Service (Loop
Flow).



(a) When there are agreements between the Members
(or the Office of the Interconnection on behalf of the Members) and others for
compensation to be paid or received for unscheduled transmission service (loop
flow) into or out of the PJM Region, the net compensation received shall be
included in the total Transmission Congestion Charges that are distributed in
accordance with Section 5.2.



(b) With respect to payments by the Office of the
Interconnection to the New York Power Pool for the installation and operation of
phase angle regulating facilities at Ramapo to control or limit unscheduled
transmission service (loop flow), each East Transmission Owner with revenue
requirements under the PJM Tariff shall pay a share of the charges on a
transmission revenue requirements ratio share basis.



6. “MUST-RUN” FOR RELIABILITY GENERATION



6.1 Introduction.



The following procedures shall apply to any
generation resource subject to the dispatch of the Office of the Interconnection
that (a) is a generation resource for which construction commenced before July
9, 1996, and (b) as a result of transmission constraints, the Office of the
Interconnection determines, in the exercise of Good Utility Practice, must be
run in order to maintain the reliability of service in the PJM Region. The
provisions of this Schedule shall otherwise apply to the scheduling, dispatch,
operation and accounting treatment of such resources, to the extent not
inconsistent with the provisions of this Section 6.



6.2 Identification of Facility Outages.



Not later than one hour prior to the deadline
specified in Section 1.10.1 of this Schedule, the Office of the Interconnection
shall identify on the PJM Open Access Same-Time Information System any facility
outage or other system condition which it has determined may give rise to a
transmission constraint that may require, in order to maintain system
reliability, the dispatch of one or more generation resources that otherwise
would not be dispatched based on the merits of their offers to the PJM
Interchange Energy Market.



6.3 Dispatch for Local Reliability.



6.3.1 Request and Dispatch.



In addition to the dispatch of generation by the
Office of the Interconnection to maintain reliability on transmission facilities
monitored by it, a Member that owns or leases with rights equivalent to
ownership local Transmission Facilities, as defined in this Agreement, the West
Transmission Owners Agreement, or the East Transmission Owners Agreement and
that operates a local control center in accordance with Section 11.3.3 of this
Agreement or a Market Operations Center in accordance with Section 1.7.5 of this
Schedule may request the Office of the Interconnection to dispatch generation in
order to maintain reliability on any such local Transmission Facilities that are
not then monitored by the Office of the Interconnection, subject to the rules
and procedures in Section 6.3.2 and the PJM Manuals. The Office of the
Interconnection shall dispatch generation to maintain reliability on such local
Transmission Facilities by incorporating the facilities in the State Estimator
program described in Section 2.3 as set forth below, unless the Office of the
Interconnection determines that such dispatch would



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004This tariff
      sheet is subject to further modifications and clarifications pursuant to
      order of the Federal Energy Regulatory Commission, Docket No. EL03-236,
      issued January 25, 2005, 110 FERC ¶ 61,053.




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    Third
      Revised Sheet No. 130Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 130




adversely affect reliability in the PJM Region or
would otherwise not be in accordance with Good Utility Practice.



6.3.2 Designation of Local Transmission
Facilities.



The following rules and procedures shall apply to
a Member request that the Office of the Interconnection dispatch generation on
one or more local Transmission Facilities that are not then directly monitored
by the Office of the Interconnection.



(a)
    The local
      Transmission Facilities that are the subject of the request for monitoring
      and dispatch control must be among the facilities that comprise the
      Transmission System under the PJM Tariff and must meet the PJM Reliability
      Planning Criteria set forth in the PJM Manuals;




(b)
    The Member
      shall provide modeling information for such local Transmission Facilities
      and provide sufficient telemetry to the Office of the Interconnection such
      that power flows are observable by the State Estimator program described
      in Section 2.3;




(c)
    The request
      for monitoring and dispatch control of local Transmission Facilities shall
      constitute a request that such local Transmission Facilities become and
      remain monitored by the Office of the Interconnection and subject to its
      dispatch control for a period of not less than one year;




(d)
    Requests
      under this Section for monitoring and dispatch control of local
      Transmission Facilities may be made only annually pursuant to the
      procedures set forth in the PJM Manuals;




(e)
    The Office
      of the Interconnection shall post all requests for monitoring and dispatch
      control of local Transmission Facilities made under this Section on the
      PJM Internet site; and




(f)
    The Member
      shall comply with all other operating procedures established by the Office
      of the Interconnection regarding dispatch for local reliability as set
      forth in the PJM Manuals.




6.3.3  Transition Procedures for Local
Transmission Facilities under the Monitoring Responsibility and Dispatch Control
of the Office of the Interconnection as of June 1, 2002.



The Office of the Interconnection shall determine
whether local Transmission Facilities under its monitoring responsibility and
dispatch control as of June 1, 2002 meet the PJM Reliability and Planning
Criteria. Members with such local Transmission Facilities that do not meet the
PJM Reliability Planning Criteria must either (1) remove the local Transmission
Facilities from the dispatch control and monitoring responsibility of the Office
of the Interconnection within 60 days of notification by the Office of the
Interconnection of its determination that the local Transmission Facilities do
not meet the PJM Reliability and Planning Criteria; or (2) commit, at their own
cost and by a completion date agreed to by the Office of the Interconnection and
the Member, to reinforce the local Transmission Facilities to enable the local
Transmission Facilities to meet the PJM Reliability and Planning Criteria. This
commitment to reinforce the local Transmission Facilities is subject to the
requirements of applicable law, government regulations and approvals, including,
without limitation, requirements to obtain any



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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    Substitute First Revised Sheet No. 131Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 131




necessary state or local siting, construction and
operating permits, to the ability to acquire necessary right-of-way, and to the
right to recover, pursuant to appropriate financial arrangements and tariffs or
contracts, all reasonably incurred costs, plus a reasonable return on
investment, provided that, in the event that a Member cannot reinforce the local
Transmission Facilities due to the unavailability of required financing, the
local Transmission Facilities must be removed from the monitoring responsibility
and dispatch control of the Office of the Interconnection within 60 days of the
determination that required financing is unavailable. The local Transmission
Facilities will remain under the monitoring and dispatch control of the Office
of the Interconnection during the construction of the reinforcements.



6.4 Offer Price Caps.



6.4.1 Applicability.



(a) Except as specified below, if, at any time, it
is determined by the Office of the Interconnection in accordance with Sections
1.10.8 or 6.1 of this Schedule that any generation resource may be dispatched
out of economic merit order to maintain system reliability as a result of limits
on transmission capability, the offer prices for energy from such resource shall
be capped at the levels specified below. If the Office of the Interconnection is
able to do so, such offer prices shall be capped only during each hour when the
transmission limit affects the schedule of the affected resource, and otherwise
shall be capped for the entire Operating Day. The energy offer prices as capped
shall be used to determine any Locational Marginal Price affected by the offer
price of such resource.



(b) The energy offer price by any generation
resource requested to be dispatched in accordance with Section 6.3 of this
Schedule shall be capped at the levels specified below. If the Office of the
Interconnection is able to do so, such offer prices shall be capped only during
each hour when the affected resource is so scheduled, and otherwise shall be
capped for the entire Operating Day. The energy offer prices as capped shall be
used to determine any Locational Marginal Price affected by the price of such
resource.



(c) Generation resources subject to an offer price
cap shall be paid for energy at the applicable Locational Marginal Price.



(d) Offer price caps shall not be applicable to
generation resources used to relieve the Western, Central and Eastern reactive
limits in the PJM Control Area. In addition, offer price caps shall not be
applicable to generation resources used to relieve any other transmission limit
as to which the FERC has determined that offer price caps shall not be
applicable.



(e) Offer price caps shall be suspended for any
transmission limit(s) for any hour in which there are not three or fewer
generation suppliers available for redispatch under subsection (a) that are
jointly pivotal with respect to such transmission limit(s). Notwithstanding the
number of jointly pivotal suppliers in any hour, if the Market Monitoring Unit
determines that a reasonable level of competition will not exist based on an
evaluation of all facts and circumstances, it may propose to the Commission the
removal of offer-capping suspensions otherwise authorized by this section. Such
proposals shall take effect only upon Commission acceptance or approval.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 26, 2005Vice President, Government
    PolicyIssued On:
    
    July 16, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      EL03-236, issued May 6, 2004, 107 FERC ¶ 61,112.




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PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 131AThird Revised Rate
      Schedule FERC No. 24
    
    Superseding Substitute Original Sheet No.
131A




6.4.2 Level.



(a) The offer price cap shall be one of the
amounts specified below, as specified in advance by the Market Seller for the
affected unit:



(i) The weighted average Locational Marginal Price
at the generation bus at which energy from the capped resource was delivered
during a specified number of hours during which the resource was dispatched for
energy in economic merit order, the specified number of hours to be determined
by the Office of the Interconnection and to be a number of hours sufficient to
result in an offer price cap that reflects reasonably contemporaneous
competitive market conditions for that unit;



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 26, 2005Vice President, Government
    PolicyIssued On:
    
    November 2, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      EL03-236-000, issued May 6, 2004, 107 FERC ¶
61,112.




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    Third
      Revised Sheet No. 132Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 132




(ii)
    The
      incremental operating cost of the generation resource as determined in
      accordance with Schedule 2 of this Agreement and the PJM Manuals, plus 10%
      of such costs;




(iii)
    For a unit
      that is offer capped for 80 percent or more of its run hours, the
      incremental operating cost of the generation resource as determined in
      accordance with Schedule 2 of this Agreement and the PJM Manuals, plus the
      higher of $40 per megawatt-hour or the unit-specific going forward costs
      of the affected unit as reflected in an agreement entered pursuant to
      subparagraph (iv), below; or




(iv)
    An amount
      determined by agreement between the Office of the Interconnection and the
      Market Seller, provided that, if the Office of the Interconnection and the
      Market Seller cannot reach agreement after 60 days from the commencement
      of negotiations, then the Market Seller may submit the rates, terms, and
      conditions of its proposed offer cap to the Commission for resolution.




(b) For purposes of section 6.4.2(a)(iii), a unit
shall qualify for the specified offer cap if it was offer capped for 80 percent
or more of its run hours over the course of the 12 month period ending December
31 of the calendar year preceding the calendar year in which the offer is
submitted.



(c) For purposes of section 6.4.2(a)(iii), the
unit-specific going forward costs determined by agreement between the Office of
the Interconnection and the Market Seller shall include only the costs included
in the Deactivation Avoidable Cost Rate, excluding costs associated with the
Avoidable Project Investment Recovery Rate (APIR), set forth in section 115 of
the PJM Tariff. Any costs that would be capitalized according to generally
accepted accounting principles, associated carrying costs, or other fixed costs
shall not be included. The agreement shall further provide that (i) in order for
such costs to qualify for inclusion in the amounts determined by the agreement,
the Market Seller must agree to provide to PJM relevant cost data concerning
fuel, operating and maintenance, and other avoidable costs, (ii) the maintenance
practices and incurrence of expense at the unit shall be subject to audit by the
Office of the Interconnection, and (iii) the unit owner agrees to operate the
unit in accordance with Good Utility Practice.



(d) Any agreement entered pursuant to section
6.4.2(a)(iv) shall be filed with the Commission and shall be effective only upon
acceptance of the agreement for filing by the Commission.



7. FINANCIAL TRANSMISSION RIGHTS AUCTIONS



7.1 Auctions of Financial Transmission Rights.



Annual and periodic auctions to allow Market
Participants to acquire or sell Financial Transmission Rights shall be conducted
by the Office of the Interconnection in accordance with the provisions of this
Section.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 26, 2005Vice President, Government
    PolicyIssued On:
    
    November 2, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      EL03-236-000, issued May 6, 2004, 107 FERC ¶ 61,112. This tariff sheet is
      subject to further modifications and clarifications pursuant to order of
      the Federal Energy Regulatory Commission, Docket No. EL03-236, issued
      January 25, 2005, 110 FERC ¶ 61,053.




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 132.01Third Revised Rate Schedule FERC No.
      24




7.1.1 Auction Period and Scope of Auctions.



(a) The periods covered by auctions shall be: (1)
the one-year period beginning the month after the final round of the annual
auction and (2) the one-month period following the date that the monthly auction
is conducted. With the exception of FTRs allocated pursuant to Section 5.2.2 (e)
of this Schedule and the Financial Transmission Rights awarded as a result of
the exercise of the conversion option pursuant to Section 7.1.1(b) of this
Schedule, in the annual auction, the Office of the Interconnection shall offer
for sale the entire Financial Transmission Rights capability for the year in
four rounds with 25 percent of the capability offered in each round. In the
monthly auction, the Office of the Interconnection shall offer for sale in the
auction any remaining Financial Transmission Rights capability for the month
after taking into account all of the Financial Transmission Rights already
outstanding at the time of the auction. In addition, any holder of a Financial
Transmission Right for the period covered by an auction may offer such Financial
Transmission Right for sale in such auction. On-Peak, off-peak and 24-hour FTRs
will be offered in the annual and monthly auctions. FTRs will be offered as
Financial Transmission Right Obligations and Financial Transmission Right
Options, provided that such Financial Transmission Right Obligations and
Financial Transmission Right Options shall be awarded based only on the residual
system capability that remains after the allocation of Financial Transmission
Rights pursuant to Section 5.2.2(e) and the award of Financial Transmission
Rights pursuant to Section 7.1.1(b) of this Schedule. Market Participants may
bid for and acquire any number of Financial Transmission Rights, provided that
all Financial Transmission Rights awarded are simultaneously feasible with each
other and with all Financial Transmission Rights outstanding at the time of the
auction and not sold into the auction. An ARR holder may self-schedule an FTR on
the same path in the Annual FTR auction according to the rules described in the
PJM Manuals.



(b) An Auction Revenue Rights holder may convert
Auction Revenue Rights to Financial Transmission Rights. Such Financial
Transmission Rights must (i) have the same source and sink points as the Auction
Revenue Rights; (ii) be a 24-hour product; and (iii) be Financial Transmission
Right Obligations. The Auction Revenue Rights holder must inform the Office of
the Interconnection in accordance with the procedures established by the Office
of the Interconnection that it intends to exercise the conversion option prior
to close of round one of the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 26, 2005Vice President, Government
    PolicyIssued On:
    
    November 2, 2004




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    Second
      Revised Sheet No. 132AThird Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 132A




annual Financial Transmission Rights auction. Once
the conversion option is exercised, it will remain in effect for the entire
Financial Transmission Rights auction. The Office of the Interconnection will
designate twenty-five percent of the megawatt amount of the Auction Revenue
Rights to be converted as price-taker bids in each of the four rounds of the
Financial Transmission Rights auction. An Auction Revenue Rights holder that
converts its Auction Revenue Rights may not designate a price bid for its
converted Financial Transmission Rights and will receive a price equal to the
clearing price set by other bids in the annual Financial Transmission Right
auction. To the extent a market participant seeks to obtain FTRs in the annual
auction through such conversion, the FTRs sought will not be included in the
calculation of such market participant’s credit requirement for such annual FTR
auction.



7.1.2 Frequency and Time of Auctions.



Subject to Section 7.1.1 of this Schedule, annual
Financial Transmission Rights auctions shall offer the entire FTR capability of
the PJM system in four rounds with 25 percent of the capability offered in each
round. All four rounds of the annual Financial Transmission Rights auction shall
occur within the two-month period (April – May) preceding the start of the PJM
planning period. Each round shall occur over five business days and shall be
conducted sequentially. Each round shall begin with the bid and offer period
opening the first day at 12:00 midnight (Eastern Prevailing Time) and closing
the third day at 5:00 p.m. (Eastern Prevailing Time). Monthly Financial
Transmission Rights auctions shall be held. The bid and offer period shall open
at 12:00 midnight (Eastern Prevailing Time) on the thirteenth (13th) business
day preceding the month for which Financial Transmission Rights are being
auctioned and shall close at 5:00 PM (Eastern Prevailing Time) on the tenth
(10th) business day preceding the month for which Financial Transmission Rights
are being auctioned.



7.1.3 Duration of Financial Transmission
Rights.



Each Financial Transmission Right acquired in a
Financial Transmission Rights auction shall entitle the holder to credits of
Transmission Congestion Charges for the period that was specified in the
corresponding auction.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    February 28, 2004Vice President, Governmental
      PolicyIssued On:
    
    February 27, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER03-406-001, et. al, issued January 28, 2004, 106 FERC ¶
      61,049.




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 133Third Revised Rate Schedule FERC No.
      24
    
    Superseding Substitute Original Sheet No.
133




Each Financial Transmission Right acquired in a
Financial Transmission Rights auction shall entitle the holder to credits of
Transmission Congestion Charges for the period that was specified in the
corresponding auction.



7.2 Financial Transmission Rights
Characteristics.



7.2.1 Reconfiguration of Financial Transmission
Rights.



Through an appropriate linear programming model,
the Office of the Interconnection shall reconfigure the Financial Transmission
Rights offered or otherwise available for sale in any auction to maximize the
value to the bidders of the Financial Transmission Rights sold, provided that
any Financial Transmission Rights acquired at auction shall be simultaneously
feasible in combination with those Financial Transmission Rights outstanding at
the time of the auction and not sold in the auction. The linear programming
model shall, while respecting transmission constraints and the maximum MW
quantities of the bids and offers, select the set of simultaneously feasible
Financial Transmission Rights with the highest net total auction value as
determined by the bids of buyers and taking into account the reservation prices
of the sellers.



7.2.2 Specified Receipt and Delivery Points.



Auction bids for annual Financial Transmission
Rights Obligations may specify as receipt and delivery points any combination of
hubs, Zones, aggregates, generators, and interface buses. Auction bids for
annual Financial Transmission Rights Options may specify as receipt and delivery
points such combination of hubs, Zones, aggregates, generators, and interface
buses as the Office of the Interconnection shall allow from time to time as set
forth in its FTR business manual. Auction bids for monthly Financial
Transmission Rights may specify any combination of receipt and delivery buses
represented in the State Estimator model for which the Office of the
Interconnection calculates and posts Locational Marginal Prices. Auction bids
may specify receipt and delivery points from locations outside of the PJM Region
to locations inside such region, from locations within the PJM Region to
locations outside such region, or to and from locations within the PJM Region.



7.2.3 Transmission Congestion Charges.



Financial Transmission Rights shall entitle
holders thereof to credits only for Transmission Congestion Charges, and shall
not confer a right to credits for payments arising from or relating to
transmission congestion made to any entity other than the Office of the
Interconnection.



7.3 Auction Procedures.



7.3.1 Role of the Office of the
Interconnection.



Financial Transmission Rights auctions shall be
conducted by the Office of the Interconnection in accordance with standards and
procedures set forth in the PJM Manuals, such standards and procedures to be
consistent with the requirements of this Schedule.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 134Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 134




7.3.2 Notice of Offer.



A holder of a Financial Transmission Right wishing
to offer the Financial Transmission Right for sale shall notify the Office of
the Interconnection of any Financial Transmission Rights to be offered. Each
Financial Transmission Right sold in an auction shall, at the end of the period
for which the Financial Transmission Rights were auctioned, revert to the
offering holder or the entity to which the offering holder has transferred such
Financial Transmission Right, subject to the term of the Financial Transmission
Right itself and to the right of such holder or transferee to offer the
Financial Transmission Right in the next or any subsequent auction during the
term of the Financial Transmission Right.



7.3.3 Pending Applications for Firm Service.



(a) [Reserved.]



(b) Financial Transmission Rights may be assigned
to entities requesting Network Transmission Service or Firm Point-to-Point
Transmission Service pursuant to Section 5.2.2 (e), only if such Financial
Transmission Rights are simultaneously feasible with all outstanding Financial
Transmission Rights, including Financial Transmission Rights effective for the
then-current auction period. If an assignment of Financial Transmission Rights
pursuant to a pending application for Network Transmission Service or Firm
Point-to-Point Transmission Service cannot be completed prior to an auction,
Financial Transmission Rights attributable to such transmission service shall
not be assigned for the then-current auction period. If a Financial Transmission
Right cannot be assigned for this reason, the applicant may withdraw its
application, or request that the Financial Transmission Right be assigned
effective with the start of the next auction period.



7.3.4 On-Peak, Off-Peak and 24-Hour Periods.



On-peak, off-peak and 24-hour FTRs will be offered
in the annual and monthly auction. On-Peak Financial Transmission Rights shall
cover the periods from 7:00 a.m. up to the hour ending at 11:00 p.m. on Mondays
through Fridays, except holidays as defined in the PJM Manuals. Off-Peak
Financial Transmission Rights shall cover the periods from 11:00 p.m. up to the
hour ending 7:00 a.m. on Mondays through Fridays and all hours on Saturdays,
Sundays, and holidays as defined in the PJM Manuals. The 24-hour period shall
cover the period from hour ending 1:00 a.m. to the hour ending 12:00 midnight on
all days. Each bid shall specify whether it is for an on-peak, off-peak, or
24-hour period.



7.3.5 Offers and Bids.



(a) Offers to sell and bids to purchase Financial
Transmission Rights shall be submitted during the period set forth in Section
7.1.2, and shall be in the form specified by the Office of the Interconnection
in accordance with the requirements set forth below.



(b) Offers to sell shall identify the specific
Financial Transmission Right, by megawatt quantity and receipt and delivery
points, offered for sale. An offer to sell a specified megawatt quantity of
Financial Transmission Rights shall constitute an offer to sell a quantity of
Financial Transmission Rights equal to or less than the specified quantity. An
offer to sell may



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 7, 2003Vice President, Governmental
      PolicyIssued On:
    
    November 6, 2003




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    Third
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    Superseding Second Revised Sheet No. 135




not specify a minimum quantity being offered. Each
offer may specify a reservation price, below which the offeror does not wish to
sell the Financial Transmission Right. Offers submitted by entities holding
rights to Financial Transmission Rights shall be subject to such reasonable
standards for the verification of the rights of the offeror as may be
established by the Office of the Interconnection. Offers shall be subject to
such reasonable standards for the creditworthiness of the offer or for the
posting of security for performance as the Office of the Interconnection shall
establish.



(c) Bids to purchase shall specify the megawatt
quantity, price per megawatt, and receipt and delivery points of the Financial
Transmission Right that the bidder wishes to purchase. A bid to purchase a
specified megawatt quantity of Financial Transmission Rights shall constitute a
bid to purchase a quantity of Financial Transmission Rights equal to or less
than the specified quantity. A bid to purchase may not specify a minimum
quantity that the bidder wishes to purchase. A bid may specify receipt and
delivery points in accordance with Section 7.2.2 and may include Financial
Transmission Rights for which the associated Transmission Congestion Credits may
have negative values. Bids shall be subject to such reasonable standards for the
creditworthiness of the bidder or for the posting of security for performance as
the Office of the Interconnection shall establish.



(d) Bids and offers shall be specified to the
nearest tenth of a megawatt and shall be greater than zero. The Office of the
Interconnection may require that a market participant shall not submit in excess
of 5000 bids and offers for any single monthly auction, or for any single round
of the annual auction, when the Office of the Interconnection determines that
such limit is required to avoid or mitigate significant system performance
problems related to bid/offer volume. Notice of the need to impose such limit
shall be provided prior to the start of the bidding period if possible. Where
such notice is provided after the start of the bidding period, market
participants shall be required within one day to reduce their bids and offers
for such auction below 5000, and the bidding period in such cases shall be
extended by one day.



7.3.6 Determination of Winning Bids and
Clearing Price.



(a) At the close of the bidding period each month,
the Office of the Interconnection will create a base Financial Transmission
Rights power flow model that includes all outstanding Financial Transmission
Rights that have been approved and confirmed for any portion of the month for
which the auction was conducted and that were not offered for sale in the
auction. The base Financial Transmission Rights model also will include
estimated uncompensated parallel flows into each interface point of the PJM
Region and estimated scheduled transmission outages.



(b) In accordance with the requirements of Section
7.4 of this Schedule and subject to all applicable transmission constraints and
reliability requirements, the Office of the Interconnection shall determine the
simultaneous feasibility of all outstanding Financial Transmission Rights not
offered for sale in the auction and of all Financial Transmission Rights that
could be awarded in the auction for which bids were submitted. The winning bids
shall be determined from an appropriate linear programming model that, while
respecting transmission constraints and the maximum MW quantities of the bids
and offers, selects the set of simultaneously feasible Financial Transmission
Rights with the highest net total auction value as determined by the bids of
buyers and taking into account the reservation prices of the sellers. In the
event that there are two or more identical bids for the selected Financial
Transmission Rights and there are insufficient Financial Transmission Rights to
accommodate all of the identical bids, then each such bidder will receive a pro
rata share of the Financial Transmission Rights that can be awarded.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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    First
      Revised Sheet No. 136Third Revised Rate Schedule FERC No.
      24
    
    Superseding Substitute Original Sheet No.
136




(c) Financial Transmission Rights shall be sold at
the market-clearing price for Financial Transmission Rights between specified
pairs of receipt and delivery points, as determine by the bid value of the
marginal Financial Transmission Right that could not be awarded because it would
not be simultaneously feasible. The linear programming model shall determine the
clearing prices of all Financial Transmission Rights paths based on the bid
value of the marginal Financial Transmission Rights, which are those Financial
Transmission Rights with the highest bid values that could not be awarded fully
because they were not simultaneously feasible, and based on the flow
sensitivities of each Financial Transmission Rights path relative to the
marginal Financial Transmission Rights paths flow sensitivities on the binding
transmission constraints.



7.3.7 Announcement of Winners and Prices.



Within two (2) business days after the close of a
monthly auction, or annual auction round, the Office of the Interconnection
shall post the winning bidders, the megawatt quantity, and the receipt and
delivery points for each Financial Transmission Right awarded in the auction and
the price at which each Financial Transmission Right was awarded. The Office of
the Interconnection shall not disclose the price specified in any bid to
purchase or the reservation price specified in any offer to sell.



7.3.8 Auction Settlements.



All buyers and sellers of Financial Transmission
Rights between the same points of receipt and delivery shall pay or be paid the
market-clearing price, as determined in the auction, for such Financial
Transmission Rights.



7.4 Allocation of Auction Revenues.



7.4.1 Eligibility.



(a) Annual and monthly auction revenues, net of
payments to entities selling Financial Transmission Rights into the auction,
shall be allocated among holders of Auction Revenue Rights in proportion to, but
not more than, the Target Allocation of Auction Revenue Rights Credits for the
holder.



(b) Auction Revenue Rights Credits will be
calculated based upon the clearing price results of the applicable Annual
Financial Transmission Rights auction.



7.4.2 Auction Revenue Rights.



(a) On an annual basis by such deadline
established by the Office of the Interconnection, the allocation of Auction
Revenue Rights shall be performed using a two stage allocation process. In the
first stage of the allocation process, each Network Service User may request
Auction Revenue Rights from a subset of the historical generation resources that
were designated to be delivered to load based on the historical reference year
for the Zone. The historical reference year for all Zones shall be 1998, except
that the reference year shall be 2002 for the Allegheny Power and Rockland
Electric Zones, and the Office of the Interconnection shall specify a historical
reference year for a new PJM zone corresponding to the year that the zone is
integrated into the PJM Interchange Energy Market. For each Zone, the Office of
the Interconnection shall determine a set of eligible generation sources based
on the historical reference year and assign a pro rata amount



Issued By:
    
    Craig Glazer
    
    Effective:
    
    February 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    September 30, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 136AThird Revised Rate Schedule FERC No.
      24




of megawatt capability from each resource to each
Network Service User in the Zone based on its proportion of peak load in the
Zone. Auction Revenue Rights shall be allocated to each Network Service User in
a Zone from each historical generation resource in a number of megawatts equal
to or less than the amount of the resource that has been assigned to the Network
Service User. Each Auction Revenue Right shall be to the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    February 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    September 30, 2003




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 137Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 137




aggregate load busses of the Network Service User
in a Zone or, with respect to Non-Zone Network Load, to the border of the area
comprised of the PJM West Region and PJM Control Area. In the first stage of the
allocation process, the sum of each Network Service User’s allocated Auction
Revenue Rights for a Zone must be equal to or less than the Network Service
User’s peak load for that Zone as determined under Section 34.1 of the Tariff.
The sum of each Network Service User’s Auction Revenue Rights for Non-Zone
Network Load must be equal to or less than the Network Service User’s
transmission responsibility for Non-Zone Network Load as determined under
Section 34.1 of the Tariff.



(b) In the second stage of the allocation process,
the Office of the Interconnection shall conduct an iterative allocation process
that consists of four rounds with 25 percent of the remaining system Auction
Revenue Rights capability allocated in each round. Each round of this allocation
process will be conducted sequentially with Network Service users and
Transmission Customers being given the opportunity to view results of each
allocation round prior to submission of Auction Revenue Right requests into the
subsequent round. In each round, each Network Service User shall designate a
subset of buses from which Auction Revenue Rights will be sourced. Valid Auction
Revenue Rights source buses include only zones, generators, hubs and external
interface buses. The Network Service User shall specify the amount of Auction
Revenue Rights requested from each source bus. Each Auction Revenue Right shall
be sinked to the aggregate load busses of the Network Service User in a Zone or,
with respect to Non-Zone Network Load, to the border of the area comprised of
the PJM West Region and PJM Control Area. The sum of each Network Service User’s
Auction Revenue Rights requests in each allocation round for each Zone must be
equal to or less than 25 percent of the difference between the Network Service
User’s peak load for that Zone as determined under Section 34.1 of the Tariff
and its Auction Revenue Right Allocation from the first stage of the allocation
process for that Zone.



(c) On a daily basis within the annual Financial
Transmission Rights auction period, a proportionate share of Network Service
User’s Auction Revenue Rights for each Zone are reallocated as Network Load
changes from one Network Service User to another within that Zone.



(d) Each Transmission Customer receiving firm
Point-to-Point Transmission Service shall specify whether it wishes to receive
Auction Revenue Rights. If the Transmission Customer elects to request Auction
Revenue Rights, the customer may do so by specifying such selection in the
second stage of the allocation process. The Auction Revenue Rights that the
Transmission Customer may request in each round must be equal to or less than 25
percent of the number of megawatts equal to the megawatts of firm service being
provided between the receipt and delivery points as to which the Transmission
Customer has firm Point-to-Point Transmission Service. The source point of the
Auction Revenue Rights must be the designated source point that is specified in
the transmission service request and the sink point of the Auction Revenue
Rights must be the designated sink point that is specified in the transmission
service request.



(e) All Auction Revenue Rights must be
simultaneously feasible. If all Auction Revenue Right requests made during the
annual allocation process are not feasible then Auction Revenue Rights are
prorated and allocated in proportion to the MW level requested and in inverse
proportion to the effect on the binding constraints.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    August 31, 2004




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PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 138Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 138




7.4.3 Target Allocation of Auction Revenue
Right Credits.



A target allocation of Auction Revenue Right
Credits for each entity holding an Auction Revenue Right shall be determined for
each Auction Revenue Right. After each round of the annual Financial
Transmission Right Auction, each Auction Revenue Right shall be divided by four
and multiplied by the price differences for the receipt and delivery points
associated with the Auction Revenue Right, calculated as the Locational Marginal
Price at the delivery points(s) minus the Locational Marginal Price at the
receipt point(s), where the price for the receipt and delivery point is
determined by the clearing prices of each round of the annual Financial
Transmission Right auction. The daily total target allocation for an entity
holding the Auction Revenue Rights shall be the sum of the daily target
allocations associated with all of the entity’s Auction Revenue Rights.



7.4.4 Calculation of Auction Revenue Right
Credits.



(a) Each day, the total of all the daily target
allocations determined as specified above in Section 7.4.3 plus any additional
Auction Revenue Rights target allocations applicable for that day shall be
compared to the total revenues of the monthly Financial Transmission Rights
auction (divided by the number of days in the month) plus the total revenues of
the annual Financial Transmission Rights auction (divided by the number of days
in the planning period). If the total of the target allocations is less than the
total auction revenues, the Auction Revenue Right Credit for each entity holding
an Auction Revenue Right shall be equal to its target allocation. All remaining
funds shall be distributed as Excess Congestion Charges pursuant to Section
5.2.5.



(b) If the total of the target allocations is
greater than the total auction revenues, each holder of Auction Revenue Rights
shall be assigned a share of the total auction revenues in proportion to its
Auction Revenue Rights target allocations for Auction Revenue Rights which have
a positive Target Allocation value. Auction Revenue Rights which have a negative
Target Allocation value are assigned the full Target Allocation value as a
negative Auction Revenue Right Credit.



7.5 Simultaneous Feasibility.



The Office of the Interconnection shall make the
simultaneous feasibility determinations specified herein using appropriate
powerflow models of contingency-constrained dispatch. Such determinations shall
take into account outages of both individual generation units and transmission
facilities and shall be based on reasonable assumptions about the configuration
and availability of transmission capability during the period covered by the
auction that are not inconsistent with the determination of the deliverability
of Capacity Resources under the Reliability Assurance Agreement or Reliability
Assurance Agreement-West. The goal of the simultaneous feasibility determination
shall be to ensure that there are sufficient revenues from Transmission
Congestion Charges to satisfy all Financial Transmission Rights obligations for
the auction period under expected conditions and to ensure that there are
sufficient revenues from the annual Financial Transmission Right Auction to
satisfy all Auction Revenue Rights obligations.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 139Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 139




8. INTERREGIONAL TRANSMISSION CONGESTION

MANAGEMENTPILOT PROGRAM



8.1 Introduction.



The following procedures shall govern the
redispatch of generation to alleviate transmission congestion on selected
pathways on the transmission systems operated by the Office of the
Interconnection and the New York ISO (“NYISO”). The procedures shall be used
solely when, in the exercise of Good Utility Practice, the Office of the
Interconnection or NYISO determines that the redispatch of generation units on
the other’s transmission system would reduce or eliminate the need to resort to
Transmission Loading Relief or other transmission-related emergency procedures.



8.2 Identification of Transmission Constraints.



(a) On a periodic basis determined by the Office
of the Interconnection and NYISO, the Office of the Interconnection and NYISO
shall identify potential transmission operating constraints that could result in
the need to use Transmission Loading Relief or other emergency procedures in
order to alleviate the transmission constraints, the need for which could be
reduced or eliminated by the redispatch of generation on the other’s system.



(b) In addition to the identification of such
potential transmission operating constraints, the Office of the Interconnection
and NYISO shall identify generation units on the other’s system, the redispatch
of which would alleviate the identified transmission constraints.



(c) From the identified transmission constraints,
the Office of the Interconnection and NYISO shall agree in writing on the
transmission operating constraints and redispatch options that shall be subject
to Section 8 of this Schedule until otherwise agreed. In reaching such
agreement, the Office of the Interconnection shall endeavor reasonably to limit
the number of transmission constraints that are subject to Section 8 of this
Schedule so as to minimize potential cost shifting among market participants in
the control area of NYISO and the PJM Region resulting from the redispatch of
generation under Section 8 of this Schedule. The Office of the Interconnection
shall post the transmission operating constraints that are subject to Section 8
of this Schedule on PJM’s internet site.



8.3 Redispatch Procedures.



If (i) a transmission constraint subject to
Section 8 of this Schedule occurs and continues or reasonably can be expected to
continue after the exhaustion of all economic alternatives that are reasonably
available to the transmission system on which the constraint occurs and (ii) the
Office of the Interconnection or NYISO, as applicable, has determined that it
must either use Transmission Loading Relief or other emergency procedures, then
(iii) the affected entity may request the other to redispatch one or more of the
previously identified generation units to alleviate the transmission constraint.
Upon such request, the Office of the Interconnection or NYISO, as applicable,
shall redispatch such generation if it is then subject to its dispatch control
and such redispatch is consistent with Good Utility Practice.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 140Third Revised Rate Schedule FERC No.
      24




8.4 Locational Marginal Price.



(a) In the event that the Office of the
Interconnection requests that NYISO redispatch generation under this Section 8,
the Office of the Interconnection shall include the generator’s offer price (in
the NYISO energy market) in a reference price at the appropriate NYISO generator
bus in the PJM State Estimator and in the calculation of Real-time Prices and
shall include the cost of any applicable startup and no-load fees in the cost of
Operating Reserves for the Real-time Energy Market; provided, however, that if
the energy offer price plus any applicable start-up or no-load fees exceeds
$1000/megawatt-hour, then the entire cost of the redispatch will be included in
the cost of Operating Reserves for the Real-time Energy Market and will not be
included in the Real-time Prices calculation.



(b) The redispatch of a generator by the Office of
the Interconnection in response to a request from NYISO under Section 8 of this
Schedule shall not be included in the determination of Locational Marginal
Prices under Section 2 of this Schedule.



8.5 Generator Compensation.



Generators that have increased or decreased
generation output above or below the level that would otherwise represent the
economic dispatch level and as a result of a request made pursuant to this
Section 8 (the “MWh Adjustment”) shall be compensated based on the following:



(a) For a positive MWh Adjustment:



Payment to Generator = MWh Adjustment * (unit
offer price – marginal price at the generator bus) + any applicable start-up or
no-load costs not recovered by the marginal price



(b) For a negative MWh Adjustment:



Payment to Generator = |MWh Adjustment| *
(marginal price at the generator bus – unit offer price) + any applicable
start-up or no-load costs not recovered by the marginal price



8.6 Settlements.



(a) If NYISO redispatches generation under this
Section 8, then the Office of the Interconnection shall include in its monthly
accounting and billing a payment to NYISO for the costs of such redispatch as
determined in accordance with Section 8.5.



(b) If the Office of the Interconnection
redispatches generation under this Section 8, then it shall include in its
monthly accounting and billing a credit to each redispatched generator
calculated in accordance with Section 8.5. The Office of the Interconnection
shall invoice NYISO and NYISO shall collect from its market participants and pay
to the Office of the Interconnection on behalf of such market participants an
amount equal to all such credits to generators.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 141Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 141




(c) Unless there is a separate emergency energy
transaction accompanying any generation adjustment under this Schedule 8, there
shall be no adjustment in interchange between PJM and NYISO as a result of
redispatch under this Schedule 8. In the event that an emergency energy
transaction accompanies any generation adjustment, compensation for such
transaction shall be at the rates for emergency purchases and sales which have
been approved by the FERC, as they may be amended from time-to-time.



8.7 Effective Date



Section 8 of this Schedule shall become effective
only upon (a) approval or acceptance by the Federal Energy Regulatory Commission
and (b) approval or acceptance by the Federal Energy Regulatory Commission of
any comparable amendments to rate schedules of NYISO, if required.



9. COMMONWEALTH EDISON ZONE MARKET INTEGRATION

DURING THE COMED INTEGRATION PHASE



9.1 Introduction



The following procedures shall govern the
application of the PJM Interchange Energy Market and related rules to the Zone
of Commonwealth Edison Company and Commonwealth Edison Company of Indiana
(“ComEd”) during the period (“ComEd Integration Phase”) beginning upon the date
that the ComEd Zone is added to the PJM West Region and concluding upon the date
that the zone of American Electric Power Company is added to the PJM West
Region. During the ComEd Integration Phase, the zone of ComEd shall be a
separate control area (“Northern Illinois Control Area”) from the remainder of
the PJM Region (“PJM Control Area”). The PJM Interchange Energy Market shall
encompass both control areas, and all other provisions of this Agreement and its
Schedules and Attachments shall apply to the Northern Illinois Control Area
during the ComEd Integration Phase except to the extent expressly modified
below.



9.2 Generation Transfer Pathway



(a) A generation transfer pathway will be used to
facilitate the application of the PJM Interchange Energy Market to the Northern
Illinois Control Area. Transmission reservation holders with a valid existing
transmission service reservation on the OASIS of American Electric Power Company
(“Intermediate Transmission Provider”), where such reservation has a point of
receipt or delivery in the Northern Illinois Control Area and a point of receipt
or delivery in the PJM Control Area (in either direction) may allocate all or
part of such reservation, in accordance with the following procedures, to the
Office of the Interconnection for its exclusive use in administering the PJM
Interchange Energy Market and conducting the security-constrained economic
dispatch of resources to serve the loads of the PJM Region.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 141AThird Revised Rate Schedule FERC No.
      24




(b) Intermediate Transmission Provider reservation
holders may submit requests on the Transmission Provider’s OASIS to allocate
firm transmission service to the pathway for monthly or annual periods, by no
later than 11:00 a.m. eastern prevailing time (“EPT”) on the day before the
allocation is to commence. Monthly allocations shall commence at 00:00 EPT on
the first day of a calendar month and end at 00:00 EPT on the first day of the
next consecutive calendar month. Annual allocations shall commence at 00:00 EPT
on the first day of a calendar year and end at 00:00 EPT on the first day of the
next consecutive calendar year. All such requests must be pre-confirmed, and
must identify the reservation holder’s existing reservation from the
Intermediate Transmission Provider OASIS. The allocation may be for a quantity
less than or equal to the existing Intermediate Transmission Provider
reservation. Service allocated to the Office of the Interconnection may not be
recalled by the reservation holder, or scheduled or redirected by the
reservation holder on the Intermediate Transmission Provider’s system, for the
quantity or term of the allocation, but may be relied upon by the reservation
holder to qualify a resource located in either of the two control areas in the
PJM region during the Interim Period as a Capacity Resource to serve load in the
other control area of the PJM Region. The Office of the Interconnection shall
adopt such procedures as necessary to coordinate with the Intermediate
Transmission Provider to ensure that the foregoing provision is enforced. The
reservation holder remains responsible for all costs, charges, and obligations
(financial or otherwise) under its transmission service agreement with the
Intermediate Transmission Provider (excluding transmission losses, which shall
be provided by the Office of the Interconnection in-kind pursuant to section 9.3
hereof) relating to the service being allocated.



(c) The allocated transmission service shall be
under the exclusive use and control of the Office of the Interconnection and
shall be employed to further its duties and responsibilities in accordance with
the Operating Agreement, including, without limitation, the principles of
section 7.7(i) of such Agreement. The Office of the Interconnection shall
establish a dynamic schedule with the Intermediate Transmission Provider in
either direction between the Northern Illinois Control Area and the PJM Control
Area under the allocated transmission service to support the
security-constrained, economic dispatch of resources to serve the loads of the
PJM Region. In each direction, the dynamic schedule shall be subject to the
quantity, duration, and priority of the transmission service allocated in such
direction, and the dynamic schedule may be curtailed or limited by the
Intermediate Transmission Provider in accordance with the terms and conditions
of its governing tariff. The Office of the Interconnection shall treat
curtailments of or limitations on the dynamic schedule in the same manner as
transmission constraints internal to the PJM Region.



(d) Transmission Customers may not schedule as a
single transmission transaction with the Office of the Interconnection
point-to-point transmission service with a point of receipt (or delivery) at the
border of the Northern Illinois Control Area and any third-party control area
and a corresponding point of delivery (or receipt) at the border of the PJM
Control Area and any third-party control area. Such service shall require (in
addition to any necessary service from the Office of the Interconnection)
transmission service from the Intermediate Transmission Provider or other
appropriate transmission provider.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 141BThird Revised Rate Schedule FERC No.
      24




9.3 Transmission Loss Recovery



The Office of the Interconnection shall be
responsible for arranging for the generation of energy in, and its delivery
from, the PJM Region to satisfy Intermediate Transmission Provider tariff
requirements for recovery of transmission losses associated with allocated
transmission service. The Office of the Interconnection shall apply the loss
factors from the Intermediate Transmission Provider’s tariff (including any
variances in such loss factors between on-peak and off-peak periods, as defined
in such tariff) to the quantity of energy dynamically scheduled to calculate the
additional energy to be provided to the Intermediate Transmission Provider for
in-kind satisfaction of transmission losses. The Office of the Interconnection
shall adjust locational marginal prices in the PJM Region based on the adjusted
dispatch necessary to generate the energy for Intermediate Transmission Provider
losses and to compensate generators for supplying such additional energy.



9.4 Financial Transmission Rights



(a) Financial Transmission Rights shall be
allocated to Network Service Users and Firm Transmission Customers that take
service that sources or sinks in the Northern Illinois Control Area in
accordance with the provisions of section 5.2.2(f) and (g) of this Schedule
applicable to new PJM zones; provided that, solely for purposes of allocating
Financial Transmission Rights in the ComEd Zone during the term of the Phase-In
Period, as such term is defined in Schedule 17 of the PJM West RAA, Financial
Transmission Rights shall be allocated in the ComEd Zone in two stages: first,
to all Firm Point-to-Point Transmission Customers and to all Network Integration
Transmission Service paths for which the source point is a Capacity Resource or
for which the original transmission service request identified a specific
source; and, second, to the extent Financial Transmission Rights remain
available after such allocation, to Network Integration Transmission Service
paths for which there is no specifically designated source. The sum of the FTRs
requested by a Load-serving Entity in both stages may not exceed the
Load-serving Entity’s Network Integration Transmission Service peak load. FTR
requests in the first stage for which the source point is a Capacity Resource
may not exceed the capability of the resource, and requests in such stage that
are based on reserved Network service from a specifically identified source must
be from such source and may not exceed the capacity of such reservation. The
Office of the Interconnection shall identify in the PJM Manuals appropriate
points of interconnection between the Northern Illinois Control Area and
adjacent control areas for purposes of designating points of receipt or delivery
for Financial Transmission Rights. If a Network Service User is the buyer under
a wholesale supply contract that specifies the Network Service User’s load as
the delivery point, the Network Service User may elect to assign to the seller
under such wholesale supply contract, if such seller chooses to assume such
right, the right to nominate FTRs as described above, solely for purposes of
allocating Financial Transmission Rights in the ComEd zone during the Phase-In
Period. Following the Phase-in Period, Financial Transmission Rights (or Auction
Revenue Rights, as applicable) shall be allocated in accordance with section
5.2.2.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 141CThird Revised Rate Schedule FERC No.
      24




(b) Transmission reservation holders that allocate
firm transmission service to the Office of the Interconnection in accordance
with this section 9 may request Financial Transmission Rights (solely as
obligations, and not as options) in return for such allocation, and such request
shall be granted by providing Financial Transmission Rights between the border
of the Northern Illinois Control Area Zone and the border of the PJM Control
Area in the amount requested, provided that the request is for a megawatt amount
equal to or less than the megawatt amount of the transmission service so
allocated. Such Financial Transmission Rights shall be in the same direction as
the allocated transmission service and for a term equal to the term of the
transmission service allocation. Financial Transmission Rights from the border
points for the allocated transmission service to the source or sink points in
the PJM Region shall be granted to the extent not previously granted and to the
extent simultaneously feasible in accordance with section 7.5.



9.5 Ancillary Services



For purposes of applying the provisions of
sections 3.2.2, 3.2.3, and 3.2.3A pertaining to regulation, operating reserves,
and spinning reserves, the Northern Illinois Control Area shall be deemed a
Control Zone. The offer of a resource located in the Northern Illinois Control
Area for regulation, operating reserves, or spinning reserve shall be
cost-based, unless and until market-based pricing is authorized for such service
in the Northern Illinois Control Area.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 141DThird Revised Rate Schedule FERC No.
      24




10. PJM-FE INTERREGIONAL TRANSMISSION

CONGESTION MANAGEMENT



(a) The Office of the Interconnection may from
time to time enter into agreements with FirstEnergy Solutions Corp. (“FES”)
providing procedures for the redispatch of generation resources to alleviate
transmission congestion, for use solely when, in the exercise of Good Utility
Practice, the Office of the Interconnection determines, absent any other
effective market-based solutions available to it, that the redispatch of
generation units on the FE transmission system would reduce or eliminate the
need to resort to Transmission Loading Relief or other transmission-related
emergency procedures. The Office of the Interconnection is authorized to incur
costs as described herein on behalf of the Market Participants to obtain such
redispatch, and shall allocate and recover such costs as described herein. Such
cost recovery shall be limited to the costs incurred by the Office of the
Interconnection pursuant to an agreement providing for the redispatch of
generation resources at FE’s Sammis Generating Station to alleviate actual or
contingency overloads on the PJM Wylie Ridge transformers (the #5 transformer or
the #7 transformer) or the PJM Sammis-Wylie Ridge 345kV transmission line. The
costs the Office of the Interconnection is authorized to incur and to recover
hereunder to obtain such redispatch shall be those necessary to compensate for
reasonable opportunity costs incurred by FE in connection with such redispatch
as calculated based upon the cost of the energy that could have been produced by
the Sammis units as developed in accordance with the PJM Cost Development
Manual, as well as costs incurred by FE related to reduced efficiency caused by
cycling its units at the request of the Office of the Interconnection.



(b) Any payments to FE associated with redispatch
under section 10(a) shall be included in the cost of Operating Reserves for the
Real-time Energy Market, in accordance with Section 3.2.3(g) of this Schedule 1.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2004Vice President, Government
    PolicyIssued On:
    
    June 30, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 142Third Revised Rate Schedule FERC No.
      24




PJM Emergency Load Response Program



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Substitute Original Sheet No. 143Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 143




Table of Contents



Emergency Load Response
Program
    
    144Effective Date
    
    144Participant of Qualifications
    
    144Metering Requirements
    
    145Registration
    
    146Emergency Operations
    
    146Verification
    
    147Market Settlements
    
    147Reporting
    
    148Non-Hourly Metered Customer
    Pilot
    
    148Load Response Example
    
    149




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 27, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 144Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 144




EMERGENCY LOAD RESPONSE
PROGRAM



The Emergency Load Response Program is designed to
provide a method by which end-use customers may be compensated by PJM for
voluntarily reducing load during an emergency event.



EFFECTIVE DATE



The program will be effective beginning December
1, 2004, and will remain in effect until December 31, 2007. The PJM
Market Monitoring Unit will review the program following each summer period.



PARTICIPANT QUALIFICATIONS



Two primary types of distributed resources are
candidates to participate in the PJM Emergency Load Response Program:



On Site Generators



These generators (including Behind The Meter
Generation) can be either synchronized or non-synchronized to the grid. Capacity
Resources are not eligible for compensation under this program. Injections into
the grid by local generators also will not be eligible for compensation under
this program.



Load Reductions



A participant that has the ability to reduce a
measurable and verifiable portion of its load, as metered on an EDC account
basis.



PJM membership is required to participate in the
Emergency Load Response Program. Special membership provisions have been
established for program participants, as described below. Any existing PJM
Member may as a third party for non-members, in which case the third party will
be referred to as the Curtailment Service Provider (CSP). All payments are made
to the PJM Member. Participants must become signatories to the PJM Operating
Agreement, as described in the PJM Manual for Administrative Services for
the Operating Agreement of the PJM Interconnection, L.L.C.However, for
the special members the $5,000 annual member fee, the $1,500 application fee,
and liability for Member defaults are waived, along with the following other
modifications.



Special Members are limited to be PJM market
sellers;

Voting privileges and sector designation are
waived;

Thirty day notice for waiting period is waived;



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 145Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 145




Requirement for 24/7 control center coverage is
waived;



No PJM-supported user group capability is
permitted.



To participate in the emergency program, the
distributed resource must:



Be capable of reducing at least 100 kW of load



Be capable of receiving PJM notification to
participate during emergency conditions.



METERING REQUIREMENTS



The Load Response Program participants must have
metering equipment that provides integrated hourly kWh values on an EDC account
basis, that either meets the EDC requirements for accuracy or has a maximum
error of two percent over the full range of the meter (including Potential
Transformers and Current Transformers). The metering requirements can be met
using either of the following two methods:



Metering that is capable of recording integrated
hourly values for generation running to serve local load (net of that used by
the generator).



Metering that provides actual load change by
measuring actual load before and after the reduction request, such that there is
a valid integrated hourly value for the hour prior to the event and each hour
during the event. This value cannot be estimated nor can it be averaged over
some historical period. This load will be metered on an EDC account basis.



Metered load reductions will be adjusted up to
consider transmission and distribution losses as submitted by the CSP and
verified by PJM with the EDC.



The installed meter must be one of the following:



EDC-owned hourly meter,



Customer-owned meter including one provided by an
independent metering service provider or acquired from the CSP, approved by PJM,
that is read electronically by PJM, or Customer-owned meter including one
provided by an independent metering service provider or acquired from the CSP,
approved by PJM, that is read by the customer (or the CSP), the readings from
which are forwarded to PJM.



Nothing here changes the existence of one
recognized meter by the state commissions as the official billing meter for
recording consumption.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 146Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 146




REGISTRATION



Participants must complete the PJM Emergency Load
Response Program Registration Form that is posted on the PJM web site
(www.pjm.com). The following general steps will be followed:



1.
    The
      participant completes the PJM Emergency Load Response Program registration
      form located on the PJM web site.




PJM reviews the application and ensures that the
qualifications are met, including verifying that the appropriate metering
exists. PJM also confirms with the appropriate LSE and EDC whether the load
reduction is under other contractual obligations. Other such obligations may not
preclude participation in the program, but may require special consideration by
PJM such that appropriate settlements are made within the confines of the
existing contract. The EDC and LSE have ten (10) business days to respond or PJM
assumes acceptance.



2.
    PJM informs
      the requesting participant of acceptance into the program and notifies the
      appropriate LSE and EDC of the participant’s acceptance into the program.




Any end-use customer intending to run distributed
generating units in support of local load for the purpose of participating in
this program must represent in writing to PJM that it holds all applicable
environmental and use permits for running those generators. Continuing
participation in this program will be deemed as a continuing representation by
the owner that each time its distributed generating unit is run in accordance
with this program, it is being run in compliance with all applicable permits,
including any emissions, run-time limit or other constraint on plant operations
that may be imposed by such permits.



EMERGENCY OPERATIONS



PJM will initiate the request for load reduction
following the declaration of Maximum Emergency Generation and prior to the
implementation of ALM Steps 1 and 2. (Implementation of the Emergency Load
Response Program can be used for regional emergencies.) It is implemented
whenever generation is needed that is greater than the highest economic
incremental cost. PJM posts the request for load reduction on the PJM web site,
on the Emergency Conditions page, and on eData, and issues a burst email to the
Emergency Load Response majordomo. A separate All-Call message is also issued.



Operational procedures are described in detail in
the PJM Manual for Emergency Operations.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 147Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 147




VERIFICATION



PJM requires that the load reduction meter data be
submitted to PJM within 60 days of the event. If the data are not received
within 60 days, no payment for participation is provided. Meter data must be
provided for the hour prior to the event, as well as every hour during the
event.



These data files are to be communicated to PJM
either via the Load Response Program web site or email. Files that are emailed
must be in the PJM-approved file format. Meter data will be forwarded to the EDC
and LSE upon receipt, and these parties will then have ten (10) business days to
provide feedback to PJM. All load reduction data are subject to PJM Market
Monitoring Unit audit.



MARKET SETTLEMENTS



Payment for reducing load is based on the actual
kWh relief provided plus the adjustment for losses. The minimum duration of a
load reduction request is two hours. The magnitude of relief provided could be
less than, equal to, or greater than the kW amount declared on the Emergency
Load Response Program Registration form.



PJM pays the higher of the applicable Locational
Marginal Price (LMP) or $500/MWh to the PJM Member that nominates the load.
Payment will be equal to the measured reduction (either measured output of
backup generation or the difference between the measured load the hour before
the reduction and each hour during the reduction) adjusted for loses times the
higher of the applicable Locational Marginal Price (LMP) otherwise in use for
settlement of the given load or $500/MWh.



During emergency conditions, costs for emergency
purchases in excess of LMP are allocated among PJM Market Buyers in proportion
to their increase in net purchases from the PJM energy market during the hour in
the real time market compared to the day-ahead market. Consistent with this
pricing methodology, all charges under this program are allocated to purchasers
of energy, in proportion to their increase in net purchases from the PJM energy
market during the hour from day-ahead to real time. An Active Load Management
(ALM) Customer may participate in the Load Response program during ALM events as
long as the customer’s ALM contract explicitly excludes payment or credit for
energy not consumed during ALM events. If the LSE that submitted the customer
for ALM credit indicates that the customer is not eligible for simultaneous
credit under the Load Response program and ALM is called for concurrent with the
Load Response program, then payments will be made to the customer according to
the Load Response program only for the time during which ALM obligations were
not in effect. Any response in excess of the contracted ALM amount will be



Issued By:
    
    Craig Glazer
    
    Effective:
    
    January 15, 2005Vice President, Government
    PolicyIssued On:
    
    November 15, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 148Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 148




compensated under the Load Response program for
the entire duration of response. Program charges and credits will appear on the
PJM Members monthly bill, as described in the PJM Manual for Operating
Agreement Accounting and the PJM Manual for Billing.



REPORTING



Actual load reductions will be added back for the
purpose of peak load calculations for capacity.



PJM will submit any required reports to FERC on
behalf of the Load Response Program participants. PJM will also post this
document, as well as any other program-related documentation on the PJM web
site.



On an annual basis PJM will prepare a report that
summarizes the status of the program and will submit it to the PJM Board of
Managers, the Members Committee, the Reliability Committee, the Energy Market
Committee, and the Operating Committee for review.



NON-HOURLY METERED
CUSTOMER PILOT



PJM will also consider customers without hourly
metering for participation in a pilot program for up to two years per customer,
provided the customers or their representatives propose an alternate method for
measuring hourly load reductions. Alternate measurement mechanisms will be
approved by PJM on a case-by-case basis. Participation in the non-hourly metered
customer pilot will be limited to 100MW aggregate load reduction over the PJM
region and across all load response programs, and with the sole exception of the
requirement for hourly metering, will be subject to the same rules and
procedures as the applicable load response program in which the customer has
enrolled. Following the 2-year pilot period, each alternate method must be
approved through the normal PJM stakeholder process in order to continue to be
used.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 149Third Revised Rate Schedule FERC No.
      24




LOAD RESPONSE EXAMPLE



The scenario described below is intended to
illustrate how PJM would calculate the payments made to participants upon
implementation of the Emergency Load Response Program. The example assumes the
customer has acquired the appropriate form of PJM membership, completed the
appropriate PJM Load Response Program Registration Form, and been approved for
participation by PJM.



The following is a typical timeline by which a
load could respond to PJM emergency procedures:



One day Prior to Operating Day:



2230 –
    PJM calls
      Max Emergency generation into the capacity for the next day. This
      information is posted on the PJM OASIS, web site, eDATA, etc.




Operating Day:



1300 –
    PJM Issues
      Max Emergency Generation. This information is posted on the PJM OASIS,
      PJM’s web site, eDATA, etc.




1330 –
    PJM begins
      to recall off-system sales.




1400 –
    PJM loads
      Max Emergency generation, begins to purchase emergency energy, and
      implements the Emergency Load Response Program.




1800 –
    PJM cancels
      and begins unloading Max Emergency generation, curtails emergency
      purchases, and cancels the Emergency Load Response Program.




Customer ABC has a typical load of 500kW. Of this
load, approximately 150kW may be shut down within one hour during emergency
conditions. At 1400, Customer ABC receives notification that PJM has implemented
the Emergency Load Response Program. Customer ABC immediately begins the process
of disconnecting the applicable load. All such load is disconnected by 1445.
Customer ABC receives notification at 1800 that PJM has cancelled implementation
of the Emergency Load Response Program and the load is reconnected to the system
at 1830.



The metered load for those hours following
implementation of the program is compared to the hour preceding implementation
to determine the actual reduction. The following table illustrates how the
customer metering and associated payments might appear:



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 150Third Revised Rate Schedule FERC No.
      24




Hour Ending
    
    Integrated Load
      (kWh)
    
    Delta
      (kWh)
    
    Integrated
      Zonal LMP
      ($/MWh)
    
    Payment
      ($)1400
    
    495
    
    0
    
    1000
    
    01500
    
    467.5
    
    27.5
    
    1000
    
    27.501600
    
    345
    
    150
    
    1000
    
    150.001700
    
    348
    
    147
    
    850
    
    124.951800
    
    345
    
    150
    
    400
    
    75.001900
    
    420
    
    75
    
    300
    
    0




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 151Third Revised Rate Schedule FERC No.
      24




PJM Economic Load Response Program



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 152Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 152




Table of Contents



Introduction
    
    153Economic Load Response Program – Real
      Time
    
    154Effective Period Of Program
    
    154Participant Qualifications
    
    154Metering Requirements
    
    155Customer Baseline Load (CBL)
    
    156Weather-Sensitive Adjustment
      (“WSA”)
    
    158Registration
    
    159AReal-time Operations
    
    160Verification
    
    161PJM Market Monitoring
    
    161Market Settlements
    
    161Reporting
    
    162Economic Load Response Program - Day
      Ahead
    
    163Effective Period Of Program
    
    163Participant Qualifications
    
    163Metering Requirements
    
    163Customer Baseline Load (CBL)
    
    163Weather-Sensitive Adjustment
      (“WSA”)
    
    164Registration
    
    164Day-ahead Operations
    
    164Verification
    
    164PJM Market Monitoring
    
    164Market Settlements
    
    164Non-Performance
    
    166Reporting
    
    166Non-Hourly Metered Customer
    Pilot
    
    166




Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 153Third Revised Rate Schedule FERC No.
      24




INTRODUCTION



PJM Load Response Program



This program is designed to provide an incentive
to end-use customers or curtailment service providers to enhance the ability and
opportunity for reduction of consumption when PJM Locational Marginal Prices
(“LMP”) prices are high.*The
program purposefully incorporates incentives that are greater than strict
economics would provide for the same curtailment. This departure from economics
is justified to overcome initial barriers to end-use customer load response.
This program is not intended to be a permanent fix to the lack of load response
seen in the PJM markets today. The designers of this program contemplate that
when the existing market barriers are removed and end-use customers are better
able to respond to real time prices, the need for this program and others like
it will disappear. Until that happens, however, programs like this are necessary
for fully functioning markets.



Economic Load Response Program - Real Time



This option will provide a mechanism by which any
qualified Load Serving Entity (“LSE”) or Curtailment Service Provider (“CSP”)
may offer end-use customers the opportunity to, or end-use customers that are
PJM members independently may choose to, reduce load they draw from the PJM
system during times of high prices and receive payments based on real time LMP
for the reductions.



The program will be effective June 1, 2002, and
will remain in effect until December 1, 2004. At that time, the program will be
terminated unless it is extended by a two-thirds sector vote of the Members
Committee.



Economic Load Response Program - Day Ahead



This option will provide a mechanism by which any
qualified LSEs or CSPs may offer end-use customers the opportunity to, or
end-use customers that are PJM members independently may choose to, commit to a
reduction of load they draw from the PJM system in advance of real time
operations and receive payments based on day-ahead LMP for the reductions.



The program will be effective June 1, 2002, and
will remain in effect until December 1, 2004. At that time, the program will be
terminated unless it is extended by a two-thirds sector vote from the Members
Committee.



This program is not intended to be a replacement
for Active Load Management (“ALM”), but rather an additional means by which
distributed generation resources and end-use customers capable of reducing load
can participate in PJM operations and markets.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 154Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 154




The program is applicable to both the PJM and PJM
West control areas.



•
    
    For the
      purposes of the Economic Load Response Program LMP refers to the hourly
      integrated LMP.




ECONOMIC LOAD RESPONSE
PROGRAM – REAL TIME



EFFECTIVE PERIOD OF
PROGRAM



The program will be effective December 1, 2004,
and will remain in effect until December 31, 2007. At that time, the program
will be terminated unless it is extended by a two-thirds sector vote of the
Members Committee.



PARTICIPANT QUALIFICATIONS



Two primary types of distributed resources are
candidates to participate in the PJM Economic Load Response Program:



•
    
    On-Site
      Generators




These generators (including Behind The Meter
Generation) can be either synchronized or non-synchronized to the grid. Capacity
Resources are not eligible for compensation under this program. Injections into
the grid by local generators also will not be eligible for compensation under
this program.



•
    
    Load
      Reduction




A participant that has the ability to reduce a
measurable and verifiable portion of its load as metered on an Electric
Distribution Company (“EDC”) account basis.



The Economic Load Response Program is intended to
encourage broad participation in economic load reductions by any hourly-metered
curtailable loads. PJM membership is required to participate in the Economic
Load Response Program. Special membership provisions have been established for
certain program participants, as described below any existing PJM Member may act
as an agent for non-members in which case the agent will be the CSP for the
non-member. A CSP may act on behalf of PJM Members, non-members or itself (if a
PJM member and end-use customer). All payments are made to the PJM Member.
Participants must become signatories to the Amended and Restated Operating
Agreement of PJM Interconnection, L.L.C. (“PJM Operating Agreement”), as
described in the PJM Manual for Administrative Services for the Operating
Agreement of the PJM Interconnection, L.L.C. However, for special
members the $1,500 application fee and liability for Member defaults are waived,
along with the following other modifications:



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    November 4, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 154AFERC Electric TariffSixth Revised Volume No. 1




Special members shall pay an annual membership
fee of $500 plus 10% of each payment owed by PJM for a load reduction event up
to a total of $5,000 in a calendar year. Special members whose contributions
toward the annual membership fee equal $5,000 under this program shall
nonetheless retain the status of special members and may not convert to full
membership in the same year;



Special members are limited to participating in
the PJM markets as Market Sellers, which means that they are qualified only for
the Economic Load Response Program – Real Time;



Voting privileges and sector designation are
waived;



Thirty day notice for waiting period is waived;



Requirement for 24/7 control center coverage is
waived;



No PJM-supported user group is permitted.



Effective on the start of any calendar year, a
special member may convert a pre-existing special membership to a full
membership subject to all PJM rules governing membership, including regular
application and membership fee requirements.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 5, 2004Vice President, Government
    PolicyIssued On:
    
    November 4, 2004






---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 155Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 155




End-use customers that have LMP-based contracts
under which they have agreed to pay their LSE for the physical delivery of
energy according to the hourly value of the real-time LMP as calculated by PJM
may participate in the real time market as provided for under Real-time
Operations below.



To participate in the program, the participant
must also meet the metering requirements as described in the next section.



METERING REQUIREMENTS



Except for participants in the non-hourly metered
customer pilot program, the Load Response Program end-use customers must have
metering equipment that provides integrated hourly kWh values on an EDC account
basis, for market settlement purposes, that either meets the EDC requirements
for accuracy or has a maximum error of two percent over the full range of the
meter (including potential transformers and current transformers). The installed
meter must be one of the following:



•
    
    EDC-owned
      hourly meter,




•
    
    End-use
      customer-owned meter including one provided by an independent metering
      service provider or acquired from the CSP or LSE, approved by PJM, that is
      read electronically by PJM, or




•
    
    End-use
      customer-owned meter including one provided by an independent metering
      service provider or acquired from the CSP or LSE, approved by PJM, that is
      read by the end-use customer (or the CSP/LSE), the readings from which are
      forwarded to PJM.




Nothing here changes the existence of one
recognized meter by the state commissions as the official billing meter for
recording consumption.



Note that various Internet applications now exist
for transmission of real time metered data. Use of these applications is
acceptable provided that PJM receives metered load reductions in a timely,
reliable manner.



The metering requirements can be met using either
of the following methods:



•
    
    Metering
      that is capable of recording integrated hourly values for generation
      running to serve local load (net of that used by the generators).




•
    
    Metered load
      on an EDC account basis, comparing actual metered load to a Customer
      Baseline Load (“CBL”) calculated as described below.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    November 6, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 156Third Revised Rate Schedule FERC No.
      24




CUSTOMER BASELINE LOAD
(CBL)



For those program end-use customers that wish to
measure load reductions by comparing metered load against an estimate of what
metered load would have been absent the reduction, a CBL must be calculated. The
CBL is calculated using the following methodologies:



The Average Day CBL



Average Day CBL formula for weekdays



Step 1. Establish the CBL Basis: A set of days
that will serve as representative of end-use customer’s typical usage.



The Weekday CBL Basis Window is
comprised of the 10 most recent days, beginning with the day two days prior to
the event day for which the CBL is being calculated, excluding the following
day-types



1.
    NERC
      holidays




2.
    Weekend days




3.
    Event days,
      which are defined as days on which:




•
    
    PJM declared
      a curtailment event for which the end-use customer was eligible, or




•
    
    the end-use
      customer actually reduced load and its measured reduction was submitted to
      PJM for compensation.




4.
    Any day
      which the day’s average daily event period usage is less than 75% of the
      average event period usage level.




To define the days that comprise the weekday CBL
Basis Window:



Begin with the 10-day period defined by the
weekday that is two days prior to the event through the weekday that is eleven
days prior to the event day. This creates a 10-day window.



Eliminate any holidays, and replace them with days
beginning with the 12th weekday day prior to the event day continuing until a
non-holiday is encountered. This results in a 10-day window.



Eliminate any event days, replacing them with
subsequent prior days, picking up with the first day not yet included in the
window after completing the holiday replacement requirement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 157Third Revised Rate Schedule FERC No.
      24




The final weekday CBL Window must contain
10 weekdays.



Step 2. Establish the CBL Basis. Identify the
five days from the 10-day weekday CBL Basis Window to be used to develop CBL
values for each hour of the event.



For each of the 10 days in the weekday CBL Basis
Window, create the average daily event period usage for that day, which
is defined as the simple average of the participant’s actual usage over the
hours in the day that define the event for which the weekday CBL is being
developed.



Create the average event period usage level
for the 10 days in the weekday CBL Basis Window, which is defined as the simple
average of the 10 average daily event period usage values.



Eliminate low usage days. For any day in the
10-day window for which the day’s average daily event period usage is less than
75% of the average event period usage level, eliminate that day, then repeat
Step 1 and 2 to replace the eliminated days and to create a new 10-day weekday
CBL Basis Window.



Order the 10 days in the weekday CBL Basis Window
according to their average daily event period usage level, and eliminate the
five days with the lowest average daily event period usage.



The remaining five days constitute the weekday
CBL Basis.



For each hour of the event, the weekday CBL is the
average of the usage in that hour in the five days that comprise the weekday CBL
Basis.



Average Day CBL formula for weekends and NERC
holidays



Step 1. Establish the CBL Weekend/Holiday Basis
Window



The weekend/holiday CBL Basis Window is comprised
of the most recent three like (Saturday or Sunday) weekend days. There are no
exclusions for holidays or event days.



Step 2. Establish the Weekend/Holiday CBL
Basis.



Calculate the average daily event period usage
value for each of the three days in the weekend/holiday CBL Basis Window.



Order the three days according to their average
daily event period usage level.



Eliminate the day with the lowest average value



The weekend/holiday CBL Basis contains 2 days.



Step 3. Calculate Weekend Average Day CBL
values for the event.



For each hour of the event, the CBL value is the
average of usage in that hour in the two days that comprise the weekend/holiday
CBL Basis.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 158Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 158




Significant Load Change Notification



The end-use customer shall inform PJM directly or
inform its CSP/LSE, who shall inform PJM, of any significant change to the
end-use customer’s operations that increases or decreases the end-use customer’s
CBL. A significant incremental change is defined as any operational or physical
change to the end-use customer’s facilities that will adjust more than half the
hours in the end-use customer’s CBL by at least 20% for more than twenty
consecutive days. PJM may require and approve such adjustments to the CBL as are
necessary to reflect the significant incremental change.



Alternate Methods



PJM may consider a metering basis other than those
described above if the method accurately represents an end-use customer’s normal
load profile during the event. Suggestions for alternative methods by which load
reductions may be measured may be approved by PJM for use in this program if
negotiated in good faith and agreed to by all appropriate parties, including the
EDC, LSE, the end-use customer, and CSP. PJM will consider such suggestions on a
case-by-case basis and intends to study alternative measurement methods during
the life of the program and report the results. Metered load reductions will be
adjusted up to consider transmission and distribution losses as submitted by the
CSP and verified by PJM with the EDC.



WEATHER-SENSITIVE
ADJUSTMENT (“WSA”)



•
    
    At the time
      it enters the Load Response Program, the end-use customer or its
      representative (LSE/CSP), shall specify whether it desires to apply the
      WSA for the summer period (May-October, inclusive) or the winter period
      (November-April) or both. The election to apply the WSA may be changed
      only annually.




•
    
    The WSA
      shall increase or decrease the CBL. The WSA shall be calculated for
      interval-metered end-use customers as follows:




Regression Analysis (available for the summer and
the winter period.)



Step 1: Perform a regression analysis in Excel
using the slope & intercept functions between the end-use customer’s on-peak
(8 AM to 8 PM), non-holiday, weekday hourly loads and the temperature-humidity
index (“THI”) on a seasonal basis for the period the WSA is being applied.



PJM will post on the PJM website a spreadsheet of
the THI values for all relevant weather stations located within PJM.



The regression analysis will produce a slope (m),
expressed in kW/THI, and an intercept (b), expressed in kW, that describes the
sensitivity of the end-use customer’s load to weather.



Step 2: Determine the average THI for the
on-peak hours for the five days used in the weekday CBL calculation.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 159Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 159




Step 3: Determine the average THI for the
on-peak hours of the event day.



Step 4: Calculate the WSA based on the
following formula:



WSA = [(m x THIEVENT DAY) + b]/[(m x THICBL DAYS) + b]



Simplified Analysis (available for the summer
period only)



Step 1: Determine that the load is weather
sensitive by agreement of the end-use customer, the CSP, and the LSE or by PJM
if there is no agreement. Weather adjustments could be negative or positive.



Step 2: Show that the hourly temperature reading
at the nearest airport that provides weather information to PJM equaled or
exceeded 85 degrees Fahrenheit during each hour of the reduction event. The
hourly temperature reading of another major airport nearby the end-use
customer’s location may be used if it can be shown that the temperature at the
end-use customer’s location correlates more closely.



Step 3: Calculate the average hourly load over two
full hours beginning three hours prior to the load reduction event.



Step 4: Calculate the average hourly load for the
same hours using the values given by the CBL calculation.



Step 5: Compare the resulting average two hour
loads from Steps 3 and 4.



Step 6: Determine if the difference from Step 5
expressed as a percentage is greater than 5%. If the difference is greater than
5% then the percentage will be the WSA for the reduction event.



Step 7: Submit an Excel spreadsheet to PJM
documenting the weather adjustment.



•
    
    The WSA,
      expressed in percentage terms, shall be applied to each hour of the CBL
      during the event period in order to establish a weather-adjusted CBL.




•
    
    For end-use
      customers without interval data from the previous summer that select the
      regression analysis, the WSA shall initially be set at 100%. After one
      month of actual program response, a regression analysis shall be performed
      and the WSA shall be adjusted in accordance with Steps 1-4, above.




•
    
    In no event
      shall application of the WSA produce a weather-adjusted CBL that exceeds
      the end-use customer’s historical, seasonal, on-peak non-coincident peak
      load.




•
    
    Case-by-case
      suggestions for alternative WSA methods or adjustments to the end-use
      customer’s historical, seasonal, on-peak non-coincident peak load may be
      approved by PJM for use in this Economic Load Response Program if
      negotiated in good faith and agreed to by all appropriate parties.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 159AThird Revised Rate Schedule FERC No.
      24




REGISTRATION



End-use customers or their representatives
(LSEs/CSPs) must complete the PJM Economic Load Response Program Registration
Form that is posted on the PJM web site (www.pjm.com). The following general
steps will be followed:



1.
    The end-use
      customer or its representative (LSE/CSP) completes the PJM Economic Load
      Response Program registration form located on the PJM web site. In the
      event an LSE or CSP completes the form, a separate registration form must
      be submitted for each end-use customer the LSE/CSP represents that
      actually can reduce load.




2.
    PJM reviews
      the application and ensures that the qualifications for participation in
      the program are met, including verifying that the appropriate metering
      exists. PJM also confirms with the appropriate EDC and LSE whether the
      load that might be reduced is under other contractual obligation. Other
      such obligations may not preclude participation in the program, but may
      require special consideration by PJM such that appropriate settlements are
      made within the confines of the existing contract. PJM will verify the
      transmission and generation1charges with the appropriate EDC/LSE. The EDC and
      LSE have ten (10) business days to respond or PJM assumes acceptance.




3.
    PJM informs
      the end-use customer or its representative (LSE/CSP) of acceptance into
      the program and notifies the appropriate LSE and EDC of the participant’s
      acceptance into the program.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 160Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 160




4.
    Any end-use
      customer intending to run distributed generating units in support of local
      load for the purpose of participating in this program must represent in
      writing to PJM that it holds all applicable environmental and use permits
      for running those generators. Continuing participation in this program
      will be deemed as a continuing representation by the owner that each time
      its distributed generating unit is run in accordance with this program, it
      is being run in compliance with all applicable permits, including any
      emissions, run-time limit or other constraint on plant operations that may
      be imposed by such permits.




5.
    End-use
      customers may not be registered simultaneously in the Economic Load
      Response Program and the Emergency Load Response Program. End-use
      customers, however, may switch programs upon one-day notice if it has
      participated in the same load response program for 15 consecutive days.




REAL TIME OPERATIONS



The Economic Load Response Program is not based on
the declaration of emergency conditions in PJM, but rather on the economic
decisions of the PJM market participants. That is, the participants in the
program are responsible for determining the conditions under which load
reductions will actually take place and implementing the reductions should those
conditions arise. The prime indicator of such conditions is assumed to be the
LMP of energy on the PJM system.



1
    EDCs functioning as LSEs may use the average shopping credit for
      generation and transmission for a rate class.




In order to maintain adequate system control, PJM
operators will be required to know the amount of load expected to be reduced at
varying price levels. These amounts may change on a daily basis. An end-use
customer or its representative (LSE/CSP) is therefore responsible for
maintaining the load reduction information associated with the end-use customer
signed up for the program, including the amount and the price at which load
might be reduced. The Load Response Program Registration/Update web site shall
be used for this purpose. PJM will utilize the data that has been submitted via
this site to compile daily aggregate load reductions on a zonal basis for use in
operations.



Except for end-use customers that have LMP-based
contracts as described below, end-use customers participating in the Economic
Load Response Program may choose to reduce load whenever their zonal LMP
dictates that it is economically beneficial for them to do so or may choose to
be dispatched by PJM. The end-use customer or its representative (LSE/CSP) shall
send an email to PJM (address to be supplied upon registration) concurrent with
or up to one hour immediately prior to beginning the reduction. In cases where
the load response is dispatched by PJM, payment will not be less than the total
value of the load response bid including any submitted start-up costs associated
with reducing load, including direct labor and



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 160.01Third Revised Rate Schedule FERC No.
      24




equipment costs and opportunity costs and costs
associated with a minimum number of contiguous hours for which the load
reduction must be committed. Load reductions under this program will not be
eligible to set real time price on the PJM system unless metered directly by
PJM. End-use customers or their representatives (LSE/CSP) shall send an email to
PJM (address to be supplied upon registration) concurrent with or up to one hour
immediately prior to the end of their load reduction.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 160AThird Revised Rate Schedule FERC No.
      24




End-use customers that have LMP-based contracts
pursuant to which they have agreed to pay their LSE for the physical delivery of
energy according to the hourly value of the real-time LMP as calculated by PJM,
may choose to reduce load and be compensated for the reduction under the
following circumstances. The end-use customer or its representative (LSE/CSP)
shall provide PJM with a “strike” price for the end-use customer’s zonal LMP at
which the end-use customer will reduce load, as well as any start-up costs
associated with reducing load, including direct labor and equipment costs and
opportunity costs and costs associated with the minimum number of contiguous
hours for which the load reduction must be committed. In cases where the end-use
customer’s zonal LMP reaches the “strike” price and the load response is
dispatched by PJM, PJM shall pay such end-use customer the difference between
the actual savings achieved based on zonal LMP and the total value of the
end-use customer’s load response bid, if savings achieved by the end-use
customer are less than the total value of the load response bid. For purposes of
this provision the total value of the load response bid will be the sum of the
“strike” price times the MW of reduction achieved during each hour of the time
period the reduction was dispatched by PJM or the minimum down-time whichever is
greater, plus the submitted start-up costs. Load reductions hereunder will not
be eligible to set real time price on the PJM system.



End-use customers or their representatives
(LSEs/CSPs) shall send e-mails to PJM (address to be supplied upon registration)
concurrent with or up to one hour immediately prior to, and at the end of, their
load reductions.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    November 6, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 161Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 161




VERIFICATION



For load reduction that is not metered directly by
PJM (i.e. – is collected by the EDC), data is to be submitted to PJM within 60
days of the event. If the data is not received within 60 days, no payment for
participation is provided. Meter readings must be provided for each hour during
which load reduction was accomplished.



These data files are to be communicated to PJM
either via the Load Response Program web site or email. Files that are emailed
must be in the PJM-approved file format. PJM will forward directly metered data
to the appropriate EDC and LSE immediately following an event for optional
review. PJM will forward CBL and WSA calculations to the appropriate EDC and LSE
immediately following an event for optional review. Data files submitted
after-the-fact will be forwarded to the EDC and LSE upon receipt. The LSE and/or
EDC have ten (10) business days after receiving the data to provide feedback to
PJM. All load reduction data is subject to audit by PJM.



PJM MARKET MONITORING



PJM may investigate participant behavior and
claims under this program and may take actions as described under the PJM Market
Monitoring Plan.



MARKET SETTLEMENTS



Reimbursement for reducing load is based on the
actual kWh relief provided in excess of committed day-ahead load reductions plus
the adjustment for losses. If the real time LMP is less than $75/MWh, the
end-use customer (or its representative (LSE/CSP)) that curtails load in
real-time will be paid by PJM the real time LMP less an amount equal to the
applicable generation and transmission2charges. If the real time LMP is greater than or equal to
$75/MWh, an end-use customer (or its representative (LSE/CSP)) that curtails
load in real-time will be paid the real time LMP. In cases where the load
response is dispatched by PJM, or the strike price of end-use customer with an
LMP based contract is reached and such load response is dispatched by PJM,
payment will not be less than the total value of the load response bid,
including any submitted start-up costs associated with reducing load, including
direct labor and equipment costs and opportunity costs and any costs associated
with a minimum number of contiguous hours for which the load reduction must be
committed. Any shortfall will be made up through normal, real time operating
reserves. In all cases, the applicable zonal or aggregate (including nodal) LMP
is used as appropriate for the individual end-use customer. The applicable
generation and transmission2charge is the charge the end-use customer would have otherwise paid the LSE
absent the load reduction.



An end-use customer or its representative
(LSE/CSP) will accumulate credits for energy reductions in those hours when the
energy delivered to the end-use customer is less than the end-use customer’s CBL
at the corresponding hourly rate. In the event the end-use customer’s hourly
energy consumption is greater than the CBL, the end-use customer or its
representative (LSE/CSP) will



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 162Third Revised Rate Schedule FERC No.
      24




accumulate debits at the corresponding hourly rate
for the amount the end-use customer’s hourly energy consumption is greater than
the CBL. However, in no event will the end-use customer’s (or its
representative’s) credit be reduced below zero on a daily basis.



Payments under the Economic Load Response Program
will be made by PJM to the end-use customer or its representative (LSE/CSP). In
the event the CSP or LSE is the party to be paid but is not the load reducer,
the portion of the payment that will be transferred from the LSE/CSP to the
end-use customer that actually reduced load is outside the scope of this
program, and must be arranged between the LSE/CSP and the end-use customer.



2
    EDCs functioning as LSEs may use the average shopping credit for
      generation and transmission for a rate class.




PJM shall recover LMP less an amount equal to
applicable generation and transmission charges from the LSE that otherwise would
have the load that was reduced. The amount equal to the generation and
transmission charges, if any, will be recovered from all load within the zone in
which the load that was reduced is located. If the total amount of recoverable
charges reflecting generation and transmission charges for the entire program
exceeds $17.5 million in a year, thereafter participants will receive LMP less
an amount equal to the applicable generation and transmission charges regardless
of the level of LMP.



An ALM customer may participate in the Economic
Load Response program during ALM events as long as the customer’s ALM contract
explicitly excludes payment or credit for energy not consumed during ALM events.
If the LSE that submitted the customer for ALM credit indicates that the
customer is not eligible for simultaneous credit under the Economic Load
Response program and ALM is called for concurrent with the Economic Load
Response program, then payments will be made to the end-use customer or
representative according to the Economic Load Response program only for the time
during which ALM obligations were not in effect. Any response in excess of the
contracted ALM amount will be compensated under the Economic Load Response
program for the entire duration of response.



Program credits will appear on the PJM Member’s
monthly bill, as described in the PJM Manual for Operating Agreement
Accounting and the PJM Manual for Billing.



REPORTING



PJM will submit any required reports to FERC on
behalf of the Economic Load Response Program participants. PJM will also post
this document, as well as any other program-related documentation on the PJM web
site. PJM shall submit two reports to the FERC with respect to the Economic Load
Response Program. The first report shall be filed on May 31, 2003. The second
report shall be filed on October 31, 2004, concurrently with PJM’s report
evaluating the PJM Emergency Load Response Program. These reports shall review
and evaluate



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 163Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 163




the Economic Load Response Program and shall
include (1) evaluations of whether the current demand response programs are the
best means for eliciting the maximum possible amount of demand response; (2) an
evaluation of the Non-metered Customer Pilot Program, including whether the
pilot program is the best means of obtaining participation by small customers;
(3) examination of whether the level of compensation pursuant to the Economic
Load Response Program is still necessary and appropriate to induce customers to
join and remain in the Economic Load Response Program or, whether PJM could
implement compensation programs that more closely respond to, and provide market
signals; (4) an estimate of the costs and benefits of (a) implementing a
compensation program with no incentive provision; (b) continuing the current
incentive provision, or (c) enlarging the incentive provision; and (5) an
evaluation of possible methods of obtaining significant amounts of demand
response other than by providing financial incentives.



On an annual basis, PJM will prepare a report that
summarizes the status of the program and will submit it to the PJM Board of
Managers, the Members Committee, the Reliability Committee, the Energy Market
Committee, and the Operating Committee for review.



PJM will prepare any reports by state and by zone
as may be required, subject to confidentiality requirements.



ECONOMIC LOAD RESPONSE
PROGRAM - DAY-AHEAD

EFFECTIVE PERIOD OF
PROGRAM



Same as real time.



PARTICIPANT QUALIFICATIONS



Same as real time except that end-use customers
that have LMP-based contracts may not participate in the Day-ahead Market.



METERING REQUIREMENTS



Same as real time.



CUSTOMER BASELINE LOAD
(CBL)



Same as real time.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 164Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 164




WEATHER-SENSITIVE
ADJUSTMENT (“WSA”)



Same as real time except that the Simplified
Analysis may not be used.



REGISTRATION



Same as real time.



DAY-AHEAD OPERATIONS



PJM will accept demand reduction bids from an
end-use customer or its representative (LSE/CSP) for a specific MW curtailment
(in minimum increments of .1 MW). The demand reduction bid will include the
day-ahead LMP above which the end-use customer would not consume, and could also
include start-up costs associated with reducing load, including direct labor and
equipment costs and opportunity costs and/or a minimum number of contiguous
hours for which the load reduction must be committed.



The objective function for day ahead commitment
software will be to eliminate demand reduction bids from day-ahead bid load when
the total bid production cost over the 24-hour dispatch day will be reduced
compared to serving that load, including consideration of paying the demand
reduction bid for the length of the minimum commitment time as well as any
start-up cost. Thus, curtailments will not be scheduled unless they reduce total
day-ahead production costs.



Demand reduction bids can set day-ahead LMP just
as a comparably bid generator.



VERIFICATION



Same as real time.



PJM MARKET MONITORING



Same as real time.



MARKET SETTLEMENTS



Reimbursement for reducing load is based on the
reductions of kWh committed in the Day Ahead Market. An end-use customer or its
representative (LSE/CSP) that submits a load reduction bid day ahead that is
accepted by PJM when the day ahead LMP is less than $75 MWh will be paid by PJM
the day ahead LMP less an amount equal to the applicable generation and
transmission3charges. An end-use customer or its representative (LSE/CSP) that submits a load
reduction bid day ahead that is accepted by PJM when the day ahead LMP is
greater than or equal to $75 MWh, will be paid by PJM the day ahead LMP.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 165Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 165




Total payments to end-use customers or their
representatives (LSEs/CSPs) for accepted day-ahead load response bids will not
be less than the total value of the load response bid, including any submitted
start-up costs associated with reducing load, including direct labor and
equipment costs and opportunity costs and any costs associated with a minimum
number of contiguous hours for which the load reduction must be committed. Any
shortfall will be made up through normal, day-ahead operating reserves. In all
cases, the applicable zonal or aggregate (including nodal) LMP is used as
appropriate for the individual end-use customer. The applicable generation and
transmission3charge is the charge the participant would have otherwise paid the LSE absent
the load reduction.



Payments under the Economic Load Response Program
will be made by PJM to the end-use customer or its representative (LSE/CSP). In
the event the CSP or LSE is the party to be paid but is not the load reducer,
the portion of the payment that will be transferred from the LSE/CSP to the
end-use customer that actually reduced load is outside the scope of this
program, and must be arranged between the LSE/CSP and the end-use customer.



PJM shall recover LMP less an amount equal to
applicable generation and transmission charges from the LSE that otherwise would
have the load that was reduced. The amount equal to the generation and
transmission charges, if any, will be recovered from all load within the zone in
which the load that reduced is located. If the total amount of recoverable
charges reflecting the generation and transmission charges for the entire
program exceeds $17.5 million in a year, thereafter participants will receive
LMP less an amount equal to the applicable generation and transmission charges
regardless of the level of LMP.



3
    EDCs functioning as LSEs may use the average shopping credit for
      generation and transmission for a rate class.




An ALM customer may participate in the Economic
Load Response program during ALM events as long as the customer’s ALM contract
explicitly excludes payment or credit for energy not consumed during ALM events.
If the LSE that submitted the customer for ALM credit indicates that the
customer is not eligible for simultaneous credit under the Economic Load
Response program and ALM is called for concurrent with the Economic Load
Response program, then payments will be made to the end-use customer or
representative according to the Economic Load Response program only for the time
during which ALM obligations were not in effect. Any response in excess of the
contracted ALM amount will be compensated under the Economic Load Response
program for the entire duration of response.



Program credits will appear on the PJM Member’s
monthly bill, as described in the PJM Manual for Operating Agreement
Accounting and the PJM Manual for Billing.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    December 1, 2004Vice President, Government
    PolicyIssued On:
    
    September 3, 2004




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 166Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 166




NON-PERFORMANCE



End-use customers or their representatives
(LSEs/CSPs) that have load reductions committed in the day-ahead market that
cannot demonstrate hourly performance in real time equal to at least that of the
day-ahead commitment will be charged real time LMP for the amount of the
shortfall, plus any associated day-ahead operating reserve credits. Any extra
funds collected by PJM as a result of this charge will serve to reduce the
overall day-ahead operating reserves charge for that hour.



REPORTING



Same as real time.



NON-HOURLY METERED
CUSTOMER PILOT



PJM also will consider LSE/CSP sponsored pilots
for customers without hourly metering for participation in a pilot program for
up to two years per end-use customer or the end date of the applicable program,
whichever comes first, provided the end-use customers or their representatives
(LSEs/CSPs) propose an alternate method for measuring hourly load reductions.
Proposed methods shall be reviewed with the affected LSE(s). Alternate
measurement mechanisms will be approved by PJM on a case-by-case basis.
Participation in the non-hourly metered customer pilot will be limited to 100 MW
aggregate load reduction over the PJM region and the Economic Load Response
Program and the Emergency Load Response Program, and with the sole exception of
the requirement for hourly metering, will be subject to the same rules and
procedures as the Emergency Load Response Program or Economic Load Response
Program (real-time and day-ahead options), whichever is applicable. Following
the two-year pilot period, each alternate method must be approved through the
normal PJM stakeholder process in order to continue to be used.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    May 1, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 167Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 167




SCHEDULE 2



COMPONENTS OF COST



(a) Each Market Participant obligated to sell
energy from operating capacity on the PJM Interchange Energy Market at
cost-based rates shall include the following components or their equivalent in
the determination of costs for operating capacity supplied to or from the PJM
Region:



(1)
    Boilers


Firing-up cost;

No-load cost during period of operation;

Peak-prepared-for maintenance cost;

Incremental labor cost; and

Other incremental operating costs.



(2)
    Machines




Starting cost from cold to synchronized operation;

No-load cost during period of operation;

Incremental labor cost; and

Other incremental operating costs.



(b) Each Member obligated to sell energy on the
PJM Interchange Energy Market at cost-based rates shall include the following
components or their equivalent in the determination of costs for energy supplied
to the PJM Region:



Incremental fuel cost;

Incremental maintenance cost;

Incremental labor cost; and

Other incremental operating costs.



(c) All fuel costs shall employ the marginal fuel
price experienced by the Member.



(d) The PJM Board, upon consideration of the
advice and recommendations of the Members Committee, shall from time to time
define in detail the method of determining the costs entering into the said
components, and the Members shall adhere to such definitions in the preparation
of incremental costs used on the Interconnection.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 168Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 168




SCHEDULE 2 - EXHIBIT A

EXPLANATION OF THE TREATMENT OF THE COSTS OF

EMISSION ALLOWANCES



The cost of emission allowances is included in
“Other Incremental Operating Costs” pursuant to Schedule 2. The replacement cost
of emission allowances will be used to recover the cost of emission allowances
consumed as a result of producing energy for the PJM Region.



Index



Consistent with definitions promulgated by the PJM
Board upon consideration of the advice and recommendations of the Members
Committee under Schedule 2, each Member subject to Schedule 2 will determine and
provide to the Interconnection its replacement cost of emission allowances, such
cost to be an amount not exceeding the market price index published by
Cantor-Fitzgerald Environmental Brokerage Services (“EBS”), or a PJM Board
approved index in the event that EBS should cease publication of such index. As
with all other components of cost required for accounting under this Agreement,
each Member subject to Schedule 2 will use the same replacement cost of
emissions allowances, so determined, as it uses for coordinating operation of
its generating facilities hereunder.



For each Member subject to Schedule 2, the cost of
emissions allowances is included in the cost of energy supplied to or received
from the PJM Region.



Payment



The Members subject to Schedule 2 waive the right
of payment-in-kind for emission allowances for transactions wholly between the
parties. Cash payments for emission allowances consumed in providing energy for
the PJM Region shall be incorporated into and conducted pursuant to the billing
procedures for energy prescribed by this Agreement.



Calculation of Emission Allowance Amount and Cost



Pursuant to the letter from the PJM
Interconnection to FERC dated June 26, 1995, the calculation of an annual
average for the cost of emission allowances, described below, is required due to
the profile of the PJM physical system and PJM Energy Management software
system. An average emission allowance cost based on a standard production cost
study case will be used to calculate the average cost of emission allowances for
each pool megawatt produced.



The Emission Allowances (Tons of SO2) associated with a transaction will
be calculated by multiplying the magnitude of a transaction (MWhr) by an
Emissions per MWHr Factor (Tons of SO2per MWhr):



Emission
    
    
    
    Transaction
    
    
    
    EmissionsAllowances
    
    =
    
    Magnitude
    
    x
    
    per
MWhrUsed
    
    
    
    
    
    
    
    Factor(Tons of S02)
    
    
    
    (MWhr)
    
    
    
    (Tons of S02 per
      MWhr)




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 169Third Revised Rate Schedule FERC No.
      24




The Emissions per MWHr Factor will be calculated
by dividing the forecast annual emissions from all Phase I units (Tons of
SO2) by
the Forecast Annual Total PJM Energy Production (MWhr):



Emissions
      per MWhr Factor
      (Tons of SO2
      per MWhr)
    
    = Forecast Annual Phase I Unit Emissions
      (Tons of SO2)
      Forecast Annual Total PJM
      Energy Production (MWhr)




Likewise, the cost (Dollars) of the Emission
Allowances for a transaction will be calculated by multiplying the transaction
magnitude (MWhr) by a Charge per MWhr Factor (Dollars per MWHr).



Cost of
    Emission
    
    
    
    Transaction
    
    
    
    ChargeAllowances
    Used
    
    =
    
    Magnitude
    
    x
    
    per MWhr
      Factor(Dollars)
    
    
    
    (MWhr)
    
    
    
    (Dollars per
      MWhr)




The Charge per MWhr Factor will be calculated by
multiplying, for each Member subject to Schedule 2, its Forecast Annual
Emissions (Tons of SO2)by
its respective Emissions Allowance Replacement Cost (Dollars per Ton of
SO2) to
yield each the forecasted annual cost of emissions (Dollars). Then, the total of
forecasted annual cost of emissions for each Member subject to Schedule 2 is
divided by the Forecast Annual Total PJM Energy Production (MWhr) to determine
the Charge per MWHr Factor (Dollars per MWHr).



Charge perMWhr Factor
    
    =
    
    S(A x B), where:CA = Member’s Forecasted Annual Emissions,
      (Tons of SO2)
      B = Emission Allowance Replacement Cost,
      (Dollars per Ton of SO2, per company)
      C = Forecast Annual PJM Energy Production,
      (MWhr)




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 170Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 170




SCHEDULE 3



ALLOCATION OF THE COST AND EXPENSES

OF THE OFFICE OF THE INTERCONNECTION



(a) Each group of Affiliates, each group of
Related Parties, and each Member that is not in such a group shall pay an annual
membership fee, the proceeds of which shall be used to defray the costs and
expenses of the LLC, including the Office of the Interconnection. The amount of
the annual fee as of the Effective Date shall be $5,000. The annual membership
fee shall be charged on a calendar year basis. In the year that a new membership
commences, the annual membership fee may be reduced, at the election of the
entity joining, by 1/12th for each full month that has passed prior to
membership commencing. If the entity seeking to join elects to pay a prorated
annual membership fee as provided here, it shall not be permitted to vote at
meetings until the first day following the date that its entry as a new Member
is announced at a Members Committee meeting, provided that if an entity’s
membership is terminated and it seeks to rejoin within twelve months, it will be
subject to the full $5,000 annual membership fee. Annual membership fees shall
not be refunded, in whole or in part, upon termination of membership.



(b) Each group of State Offices of Consumer
Advocates from the same state or the District of Columbia and each State
Consumer Advocate that nominates its representative to vote on the Members
Committee but is not in such a group shall pay an annual fee, the proceeds of
which shall be used to defray the costs and expenses of the LLC, including the
Office of the Interconnection. The amount of the annual fee shall be $500. The
annual membership fee shall be charged on a calendar year basis and shall not be
subject to proration for memberships commencing during a calendar year.



(c) The amount of the annual fees provided for
herein shall be adjusted from time to time by the PJM Board to keep pace with
inflation.



(d) All remaining costs of the operation of the
LLC and the Office of the Interconnection and the expenses, including, without
limitation, the costs of any insurance and any claims not covered by insurance,
associated therewith as provided in this Agreement shall be costs of PJM
Interconnection, L.L.C. Administrative Services and shall be recovered as set
forth in Schedule 9 to the PJM Tariff. Such costs may include costs associated
with debt service, including the costs of funding reserve accounts or meeting
coverage or similar requirements that financing covenants may necessitate.



(e) An entity accepted for membership in the LLC
shall pay all costs and expenses associated with additions and modifications to
its own metering, communication, computer, and other appropriate facilities and
procedures needed to effect the inclusion of the entity in the operation of the
Interconnection.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 17, 2003Vice President, Governmental
      PolicyIssued On:
    
    September 22, 2003




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PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 171Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 171




SCHEDULE 4



STANDARD FORM OF AGREEMENT TO BECOME A
MEMBER OF THE LLC



Any entity which wishes to become a Member of the
LLC shall, pursuant to Section 11.6 of this Agreement, tender to the President
an application, upon the acceptance of which it shall execute a supplement to
this Agreement in the following form:



Additional Member Agreement



1. This Additional Member Agreement (the “Supplemental Agreement”), dated
as of
,
is entered into among

and the President of the LLC acting on behalf of its Members.



2.
has demonstrated that it meets all of the qualifications required of a Member to
the Operating Agreement. If expansion of the PJM Region is required to integrate
’s
facilities, a copy of Attachment J from the PJM Tariff marked to show changes in
the PJM Region boundaries is attached hereto.

agrees to pay for all required metering, telemetering and hardware and software
appropriate for it to become a member.



3.

agrees to be bound by and accepts all the terms of the Operating Agreement as of
the above date.



4.

hereby gives notice that the name and address of its initial representative to
the Members Committee under the Operating Agreement shall be:



____________________________________________________________________________



5. The President of the LLC is authorized under the Operating Agreement
to execute this Supplemental Agreement on behalf of the Members.



6. The Operating Agreement is hereby amended to include

as a Member of the LLC thereto, effective as of
,
,
the date the President of the LLC countersigned this Agreement.



IN WITNESS WHEREOF,

and the Members of the LLC have caused this Supplemental Agreement to be
executed by their duly authorized representatives.



Members of the LLCBy:Name:Title:
    
    PresidentBy:Name:Title:




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 172Third Revised Rate Schedule FERC No.
      24




SCHEDULE 5



PJM DISPUTE RESOLUTION PROCEDURES



1. DEFINITIONS



1.1 Alternate Dispute Resolution Committee.



“Alternate Dispute Resolution Committee” shall
mean the Committee established pursuant to Section 5 of this Schedule.



1.2 MAAC Dispute Resolution Committee.



“MAAC Dispute Resolution Committee” shall mean the
committee established by the Mid-Atlantic Area Council to administer its
industry-specific mechanism for resolving certain types of wholesale electricity
disputes.



1.3 Related PJM Agreements.



“Related PJM Agreements” shall mean this
Agreement, the East Transmission Owners Agreement, and the Reliability Assurance
Agreement, the West Transmission Owners Agreement, and the Reliability Assurance
Agreement-West.



2. PURPOSES AND OBJECTIVES



2.1 Common and Uniform Procedures.



The PJM Dispute Resolution Procedures are intended
to establish common and uniform procedures for resolving disputes arising under
the Related PJM Agreements. To the extent any of the foregoing agreements or the
PJM Tariff contain dispute resolution provisions expressly applicable to
disputes arising thereunder, however, this Agreement shall not supplant such
provisions, which shall apply according to their terms.



2.2 Interpretation.



To the extent permitted by applicable law, the PJM
Dispute Resolution Procedures are to be interpreted to effectuate the objectives
set forth in Section 2.1. To the extent permitted by these PJM Dispute
Resolution Procedures, the Alternate Dispute Resolution Committee shall
coordinate with the established dispute resolution committee of an Applicable
Regional Reliability Council, where appropriate, in order to conserve
administrative resources and to avoid duplication of dispute resolution
staffing.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 173Third Revised Rate Schedule FERC No.
      24




3. NEGOTIATION AND MEDIATION



3.1 When Required.



The parties to a dispute shall undertake
good-faith negotiations to resolve any dispute as to a matter governed by one of
the Related PJM Agreements. Each party to a dispute shall designate an executive
with authority to resolve the matter in dispute to participate in such
negotiations. Any dispute as to a matter governed by one of the Related PJM
Agreements that has not been resolved through good-faith negotiation shall be
subject to non-binding mediation prior to the initiation of arbitral,
regulatory, judicial, or other dispute resolution proceedings as may be
appropriate as provided by these PJM Dispute Resolution Procedures.



3.2 Procedures.



3.2.1 Initiation.



If a dispute that is subject to the mediation
procedures specified herein has not been resolved through good-faith
negotiation, a party to the dispute shall notify the Alternate Dispute
Resolution Committee in writing of the existence and nature of the dispute prior
to commencing any other form of proceeding for resolution of the dispute. The
Alternate Dispute Resolution Committee shall have ten calendar days from the
date it first receives notification of the existence of a dispute from any of
the parties to the dispute in which to distribute to the parties a list of
mediators.



3.2.2 Selection of Mediator.



The Chair of the Alternate Dispute Resolution
Committee shall distribute to the parties by facsimile or other electronic means
a list containing the names of seven mediators with mediation experience, or
with technical or business experience in the electric power industry, or both,
as it shall deem appropriate to the dispute. The Chair of the Alternate Dispute
Resolution Committee may draw from the lists of mediators maintained by the
established dispute resolution committee of an Applicable Regional Reliability
Council, as the Chair shall deem appropriate. The persons on the proposed list
of mediators shall have no official, financial, or personal conflict of interest
with respect to the issues in controversy, unless the interest is fully
disclosed in writing to all participants in the mediation process and all such
participants waive in writing any objection to the interest. The parties shall
alternate in striking names from the list with the last name on the list
becoming the mediator. The determination of which party shall have the first
strike off the list shall be determined by lot. The parties shall have ten
calendar days to complete the mediator selection process, unless the time is
extended by mutual agreement.



3.2.3 Advisory Mediator.



If the Alternate Dispute Resolution Committee
deems it appropriate, it shall distribute two lists, one containing the names of
seven mediators with mediation experience, and one containing the names of seven
mediators with technical or business experience in the electric power industry.
In connection with circulating the foregoing lists, the Alternate Dispute
Resolution Committee shall specify one of the lists as containing the proposed
mediators, and the other as a list of proposed advisors to assist the mediator
in resolving the dispute. The parties shall then utilize



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 174Third Revised Rate Schedule FERC No.
      24




the alternative strike procedure set forth above
until one name remains on each list, with the last named persons serving as the
mediator and advisor.



3.2.4 Mediation Process.



The disputing parties shall attempt in good faith
to resolve their dispute in accordance with procedures and a timetable
established by the mediator. In furtherance of the mediation efforts, the
mediator may:



(a) Require the parties to meet for face-to-face
discussions, with or without the mediator;



(b) Act as an intermediary between the disputing
parties;



(c) Require the disputing parties to submit
written statements of issues and positions;



(d) If requested by the disputing parties at any
time in the mediation process, provide a written recommendation on resolution of
the dispute including, if requested, the assessment by the mediator of the
merits of the principal positions being advanced by each of the disputing
parties; and



(e) Adopt, when appropriate, the Center for Public
Resources Model ADR Procedures for the Meditation of Business Disputes (as
revised from time to time) to the extent such Procedures are not inconsistent
with any rule, standard, or procedure adopted by the Alternate Dispute
Resolution Committee or with any provision of this Agreement.



3.2.5 Mediator’s Assessment.



(a) If a resolution of the dispute is not reached
by the thirtieth day after the appointment of the mediator or such later date as
may be agreed to by the parties, if not previously requested to do so the
mediator shall promptly provide the disputing parties with a written,
confidential, non-binding recommendation on resolution of the dispute, including
the assessment by the mediator of the merits of the principal positions being
advanced by each of the disputing parties. The recommendation may incorporate or
append, if and as the mediator may deem appropriate, any recommendations or any
assessment of the positions of the parties by the advisor, if any. Upon request,
the mediator shall provide any additional recommendations or assessments the
mediator shall deem appropriate.



(b) At a time and place specified by the mediator
after delivery of the foregoing recommendation, the disputing parties shall meet
in a good faith attempt to resolve the dispute in light of the recommendation of
the mediator. Each disputing party shall be represented at the meeting by a
person with authority to settle the dispute, along with such other persons as
each disputing party shall deem appropriate. If the disputing parties are unable
to resolve the dispute at or in connection with this meeting, then: (i) any
disputing party may commence such arbitral, judicial, regulatory or other
proceedings as may be appropriate as provided in the PJM Dispute Resolution
Procedures; and (ii) the recommendation of the mediator, and any statements made
by any party in the mediation process, shall have no further force or effect,
and shall not be admissible for any purpose, in any subsequent arbitral,
administrative, judicial, or other proceeding.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 175Third Revised Rate
      Schedule FERC No. 24




3.3 Costs.



Except as specified in Section 4.13, the costs of
the time, expenses, and other charges of the mediator and any advisor, and of
the mediation process, shall be borne by the parties to the dispute, with each
side in a mediated matter bearing one-half of such costs, and each party bearing
its own costs and attorney’s fees incurred in connection with the mediation.



4. ARBITRATION



4.1 When Required.



Any dispute as to a matter: (i) governed by one of
the Related PJM Agreements that has not been resolved through the mediation
procedures specified herein, (ii) involving a claim that one or more of the
parties owes or is owed a sum of money, and (iii) the amount in controversy is
less than $1,000,000.00, shall be subject to binding arbitration in accordance
with the procedures specified herein. If the parties so agree, any other
disputes as to a matter governed by a Related PJM Agreement may be submitted to
binding arbitration in accordance with the procedures specified herein.



4.2 Binding Decision.



Except as specified in Section 4.1, the resolution
by arbitration of any dispute under this Agreement shall not be binding.



4.3 Initiation.



A party or parties to a dispute which is subject
to the arbitration procedures specified herein shall send a written demand for
arbitration to the Chair of the Alternate Dispute Resolution Committee with a
copy to the other party or parties to the dispute. The demand for arbitration
shall state each claim for which arbitration is being demanded, the relief being
sought, a brief summary of the grounds for such relief and the basis for the
claim, and shall identify all other parties to the dispute.



4.4 Selection of Arbitrator(s).



The parties to a dispute for which arbitration has
been demanded may agree on any person to serve as a single arbitrator, or shall
endeavor in good faith to agree on a single arbitrator from a list of
arbitrators prepared for the dispute by the Alternate Dispute Resolution
Committee and delivered to the parties by facsimile or other electronic means
promptly after receipt by the Alternate Dispute Resolution Committee of a demand
for arbitration. The Alternate Dispute Resolution Committee may draw from the
lists of arbitrators maintained by the established dispute resolution committee
of an Applicable Regional Reliability Council, as the Alternate Dispute
Resolution Committee deems appropriate. If the parties are unable to agree on a
single arbitrator by the fourteenth day following delivery of the foregoing list
of arbitrators or such other date as agreed to by the parties, then not later
than the end of the seventh business day thereafter the party or parties
demanding arbitration on the one hand, and the party or parties responding to
the demand for arbitration on the other, shall each designate an arbitrator from
a list for the dispute prepared by the Alternate Dispute Resolution Committee.
The arbitrators so chosen shall then choose a third arbitrator.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 176Third Revised Rate
      Schedule FERC No. 24




4.5 Procedures.



The Alternate Dispute Resolution Committee shall
compile and make available to the arbitrator(s) and the parties standard
procedures for the arbitration of disputes, which procedures (i) shall include
provision, upon good cause shown, for intervention or other participation in the
proceeding by any party whose interests may be affected by its outcome, (ii)
shall conform to the requirements specified in these PJM Dispute Resolution
Procedures, and (iii) may be modified or adopted for use in a particular
proceeding as the arbitrator(s) deem appropriate. To the extent deemed
appropriate by the Alternate Dispute Resolution Committee, the procedures
adopted by the Alternate Dispute Resolution Committee shall be based on the
American Arbitration Association Rules, to the extent such Rules are not
inconsistent with any rule, standard or procedure adopted by the Alternate
Dispute Resolution Committee, or with any provision of these PJM Dispute
Resolution Procedures. Upon selection of the arbitrator(s), arbitration shall go
forward in accordance with applicable procedures.



4.6 Summary Disposition and Interim Measures.



4.6.1 Lack of Good Faith Basis.



The procedures for arbitration of a dispute shall
provide a means for summary disposition of a demand for arbitration, or a
response to a demand for arbitration, that in the reasoned opinion of the
arbitrator(s) does not have a good faith basis in either law or fact. If the
arbitrator(s) determine(s) that a demand for arbitration or response to a demand
for arbitration does not have a good faith basis in either law or fact, the
arbitrator(s) shall have discretion to award the costs of the time, expenses,
and other charges of the arbitrator(s) to the prevailing party.



4.6.2 Discovery Limits.



The procedures for the arbitration of a dispute
shall provide a means for summary disposition without discovery of facts if
there is no dispute as to any material fact, or with such limited discovery as
the arbitrator(s) shall determine is reasonably likely to lead to the prompt
resolution of any disputed issue of material fact.



4.6.3 Interim Decision.



The procedures for the arbitration of a dispute
shall permit any party to a dispute to request the arbitrator(s) to render a
written interim decision requiring that any action or decision that is the
subject of a dispute not be put into effect, or imposing such other interim
measures as the arbitrator(s) deem necessary or appropriate, to preserve the
rights and obligations secured by any of the Related PJM Agreements during the
pendency of the arbitration proceeding. The parties shall be bound by such
written decision pending the outcome of the arbitration proceeding.



4.7 Discovery of Facts.



4.7.1 Discovery Procedures.



The procedures for the arbitration of a dispute
shall include adequate provision for the discovery of relevant facts, including
the taking of testimony under oath, production of documents and other things,
and inspection of land and tangible items. The nature and extent of such
discovery shall be determined as provided herein and shall take into account (i)
the complexity



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 177Third Revised Rate
      Schedule FERC No. 24




of the dispute, (ii) the extent to which facts are
disputed, and (iii) the amount in controversy. The forms and methods for taking
such discovery shall be as described in the Federal Rules of Civil Procedure,
except as modified by the procedures established by the Alternate Dispute
Resolution Committee, the arbitrator(s) or agreement of the parties.



4.7.2 Procedures Arbitrator.



The sole arbitrator, or the arbitrator selected by
the arbitrators chosen by the parties, as the case may be (such arbitrator being
hereafter referred to as the “Procedures Arbitrator”), shall be responsible for
establishing the timing, amount, and means of discovery, and for resolving
discovery and other pre-hearing disagreement. If a dispute involves contested
issues of fact, promptly after the selection of the arbitrator(s) the Procedures
Arbitrator shall convene a meeting of the parties for the purpose of
establishing a schedule and plan of discovery and other pre-hearing actions.



4.8 Evidentiary Hearing.



The procedures for the arbitration of a dispute
shall provide for an evidentiary hearing, with provision for the
cross-examination of witnesses, unless all parties consent to the resolution of
the matter on the basis of a written record. The forms and methods for taking
evidence shall be as described in the Federal Rules of Evidence, except as
modified by the procedures established by the Alternate Dispute Resolution
Committee, the arbitrator(s) or agreement of the parties. The arbitrator(s) may
require such written or other submissions from the parties as shall be deemed
appropriate, including submission of the direct testimony of witnesses in
written form. The arbitrator(s) may exclude any evidence that is irrelevant,
immaterial, unduly repetitious or prejudicial, or privileged. Any party or
parties may arrange for the preparation of a record of the hearing, and shall
pay the costs thereof. Such party or parties shall have no obligation to provide
or agree to the provision of a copy of the record of the hearing to any party
that does not pay an equal share of the cost of the record. At the request of
any party, the arbitrator(s) shall determine a fair and equitable allocation of
the costs of the preparation of a record between or among the parties to the
proceeding willing to share such costs.



4.9 Confidentiality.



4.9.1 Designation.



Any document or other information obtained in the
course of an arbitral proceeding and not otherwise available to the receiving
party, including any such information contained in documents or other means of
recording information created during the course of the proceeding, may be
designated “Confidential” by the producing party. The party producing documents
or other information marked “Confidential” shall have twenty days from the
production of such material to submit a request to the Procedures Arbitrator to
establish such requirements for the protection of such documents or other
information designated as “Confidential” as may be reasonable and necessary to
protect the confidentiality and commercial value of such information and the
rights of the parties, which requirements shall be binding on all parties to the
dispute. Prior to the decision of the Procedures Arbitrator on a request for
confidential treatment, documents or other information designated as
“Confidential” shall not be used by the receiving party or parties, or the
arbitrator(s), or anyone working for or on behalf of any of the foregoing, for
any purpose other than the arbitration proceeding, and shall not be disclosed in
any form to any person not involved in the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 178Third Revised Rate Schedule FERC No.
      24




arbitration proceeding without the prior written
consent of the party producing the information or as permitted by the Procedures
Arbitrator.



4.9.2 Compulsory Disclosure.



Any party receiving a request or demand for
disclosure, whether by compulsory process, discovery request, or otherwise, of
documents or information obtained in the course of an arbitration proceeding
that have been designated “Confidential” and that are subject to a
non-disclosure requirement under these PJM Dispute Resolution Procedures or a
decision of the Procedures Arbitrator, shall immediately inform the party from
which the information was obtained, and shall take all reasonable steps, short
of incurring sanctions or other penalties, to afford the person or entity from
which the information was obtained an opportunity to protect the information
from disclosure. Any party disclosing information in violation of these PJM
Dispute Resolution Procedures or requirements established by the Procedures
Arbitrator shall thereby waive any right to introduce or otherwise use such
information in any judicial, regulatory, or other legal or dispute resolution
proceeding, including the proceeding in which the information was obtained.



4.9.3 Public Information.



Nothing in the Related PJM Agreements shall
preclude the use of documents or information properly obtained outside of an
arbitral proceeding, or otherwise public, for any legitimate purpose,
notwithstanding that the information was also obtained in the course of the
arbitral proceeding.



4.10 Timetable.



Promptly after the selection of the arbitrator(s),
the arbitrator(s) shall set a date for the issuance of the arbitral decision,
which shall be not later than eight months (or such earlier date as may be
agreed to by the parties to the dispute) from the date of the selection of the
arbitrator(s), with other dates, including the dates for an evidentiary hearing
or other final submissions of evidence, set in light of this date. The date for
the evidentiary hearing or other final submission of evidence shall not be
changed absent extraordinary circumstances. The arbitrator(s) shall have the
power to impose sanctions, including dismissal of the proceeding for dilatory
tactics or undue delay in completing the arbitral proceedings.



4.11 Advisory Interpretations.



Except as to matters subject to decision in the
arbitration proceeding, the arbitrator(s) may request as may be appropriate from
any committee or subcommittee established under a Related PJM Agreement or by
the Office of the Interconnection, an interpretation of any Related PJM
Agreements, or of any standard, requirement, procedure, tariff, Schedule,
principle, plan or other criterion or policy established by any committee or
subcommittee. Except to the extent that the Office of the Interconnection is
itself a party to a dispute, the arbitrator(s) may request the advice of the
Office of the Interconnection with respect to any matter relating to a
responsibility of the Office of the Interconnection under the Agreement or with
respect to any of the Related PJM Agreements, or to the PJM Manuals. Any such
interpretation or advice shall not relieve the arbitrator(s) of responsibility
for resolving the dispute or deciding the arbitration proceeding in accordance
with the standards specified herein.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 179Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 179




4.12 Decisions.



The arbitrator(s) shall issue a written decision,
including findings of fact and the legal basis for the decision. The arbitral
decision shall be based on (i) the evidence in the record, (ii) the terms of the
Related PJM Agreements, as applicable, (iii) applicable United States federal
and state law, including the Federal Power Act and any applicable FERC
regulations and decisions, and international treaties or agreements as
applicable, and (iv) relevant decisions in previous arbitration proceedings. The
arbitrator(s) shall have no authority to revise or alter any provision of the
Related PJM Agreements. Any arbitral decision issued pursuant to these PJM
Dispute Resolution Procedures that affects matters subject to the jurisdiction
of FERC under Section 205 of the Federal Power Act shall be filed with FERC.



4.13 Costs.



Unless the arbitrator(s) shall decide otherwise,
the costs of the time, expenses, and other charges of the arbitrator(s) shall be
borne by the parties to the dispute, with each side on an arbitrated issue
bearing its pro-rata share of such costs, and each party to an arbitral
proceeding shall bear its own costs and fees. The arbitrator(s) may award all or
a portion of the costs of the time, expenses, and other charges of the
arbitrator(s), the costs of arbitration, attorney’s fees, and the costs of
mediation, if any, to any party that substantially prevails on an issue
determined by the arbitrator(s) to have been raised without a substantial basis.



4.14 Enforcement.



If the decision of the arbitrator(s) is binding,
the judgment may be entered on such arbitral award by any court having
jurisdiction thereof; provided, however, that within one year of the issuance of
the arbitral decision any party affected thereby may request FERC or any other
federal, state, regulatory or judicial authority having jurisdiction to vacate,
modify, or take such other action as may be appropriate with respect to any
arbitral decision that is based upon an error of law, or is contrary to the
statutes, rules, or regulations administered or applied by such authority. Any
party making or responding to, or intervening in proceedings resulting from, any
such request, shall request the authority to adopt the resolution, if not
clearly erroneous, of any issue of fact expressly or necessarily decided in the
arbitral proceeding, whether or not the party participated in the arbitral
proceeding.



5. ALTERNATE DISPUTE RESOLUTION COMMITTEE



5.1 Membership.



5.1.1 Representatives.



The Alternate Dispute Resolution Committee shall
be composed of two representatives selected by each of the following: (i) the
Office of the Interconnection; (ii) the Members Committee; and one
representative selected by each of the following: (i) the parties to the
Reliability Assurance Agreement; (ii) the parties to the Reliability Assurance
Agreement-West; (iii) the parties to the West Transmission Owners Agreement; and
(iv) the parties to the East Transmission Owners Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




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5.1.2 Term.



Representatives on the Alternate Dispute
Resolution Committee shall serve for terms of three years and may serve
additional terms.



5.2 Voting Requirements.



Approval or adoption of measures by the Alternate
Dispute Resolution Committee shall require two-thirds of the votes of the
representatives present and voting. Two-thirds of the representatives on the
Alternate Dispute Resolution Committee shall constitute a quorum for the conduct
of business.



5.3 Officers.



At the first meeting of the Alternate Dispute
Resolution Committee, the representatives to the Alternate Dispute Resolution
Committee shall choose a Chair and Vice Chair from among the representatives on
the Committee. The Chair of the Alternate Dispute Resolution Committee shall
preside at meetings of the Committee, and shall have the power to call meetings
of the Committee and to exercise such other powers as are specified in this
Agreement or are authorized by the Alternate Dispute Resolution Committee. The
Vice Chair shall preside at meetings of the Alternate Dispute Resolution
Committee in the absence of the Chair, and shall exercise such other powers as
are delegated by the Chair.



5.4 Meetings.



The Alternate Dispute Resolution Committee shall
meet at such times and places as determined by the Committee, or at the call of
the Chair. The Chair shall call a meeting of the Alternate Dispute Resolution
Committee upon the request of two or more representatives on the Alternate
Dispute Resolution Committee.



5.5 Responsibilities.



The duties of the Alternate Dispute Resolution
Committee include but are not limited to the following:



i)
    Maintain a
      list of persons qualified by temperament and experience, and with
      technical or legal expertise in matters likely to be the subject of
      disputes, to serve as mediators or arbitrators under these PJM Dispute
      Resolution Procedures;




ii)
    Determine
      the rates and other costs and charges that shall be paid to mediators,
      advisors and arbitrators for or in connection with their services;




iii)
    Determine
      whether mediation is not warranted in a particular dispute;




iv)
    Provide to
      disputing parties lists of mediators, advisors or arbitrators to resolve
      particular disputes;




v)
    Compile and
      make available to parties to disputes, arbitrators, and other interested
      persons suggested procedures for the arbitration of disputes in accordance
      with Section 4.5;




vi)
    Maintain and
      make available to parties to disputes, mediators, advisors, arbitrators,
      and other interested persons the written decisions required by Section
      4.12;




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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vii)
    Establish
      such procedures and schedules, in addition to those specified herein, as
      it shall deem appropriate to further the prompt, efficient, fair and
      equitable resolution of disputes; and




viii)
    Provide such
      oversight and supervision of the dispute resolution processes and
      procedures instituted pursuant to the Related PJM Agreements as may be
      appropriate to facilitate the prompt, efficient, fair and equitable
      resolution of disputes.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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SCHEDULE 6



REGIONAL TRANSMISSION EXPANSION PLANNING
PROTOCOL



1. REGIONAL TRANSMISSION EXPANSION PLANNING
PROTOCOL



1.1 Purpose and Objectives.



This Regional Transmission Expansion Planning
Protocol shall govern the process by which the Members shall rely upon the
Office of the Interconnection to prepare a plan for the enhancement and
expansion of the Transmission Facilities in order to meet the demands for firm
transmission service, and to support competition, in the PJM Region. The
Regional Transmission Expansion Plan to be developed shall enable the
transmission needs in the PJM Region to be met on a reliable, economic and
environmentally acceptable basis.



1.2 Conformity with NERC and Other Applicable
Criteria.



(a) NERC establishes Planning Principles and
Guides to promote the reliability and adequacy of the North American bulk power
supply as related to the operation and planning of electric systems.



(b) MAAC is responsible for ensuring the adequacy,
reliability and security of the bulk electric supply systems in the MAAC region
through coordinated operations and planning of generation and transmission
facilities. Toward that end, it has adopted the NERC Planning Principles and
Guides and has established detailed Reliability Principles and Standards for
Planning the Bulk Electric Supply System of the MAAC Group.



(c) ECAR is responsible for ensuring the adequacy,
reliability and security of the bulk electric supply systems in the ECAR region
through coordinated operations and planning of generation and transmission
facilities. Toward that end, it has adopted the NERC Planning Principles and
Guides and has established detailed Reliability Principles and Standards for
Planning the Bulk Electric Supply System of the ECAR Group.



(c.01) MAIN is responsible for ensuring the
adequacy, reliability and security of the bulk electric supply systems in the
MAIN region through coordinated operations and planning of generation and
transmission facilities. Toward that end, it has adopted the NERC Planning
Principles and Guides and has established detailed Reliability Principles and
Standards for Planning the Bulk Electric Supply System for MAIN.



(d) The Regional Transmission Expansion Plan shall
conform with the applicable reliability principles, guidelines and standards of
NERC, MAAC, MAIN, ECAR, and other Applicable Regional Reliability Councils in
accordance with the operating criteria and other procedures detailed in the PJM
Manuals.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    April 30, 2004




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1.3 Establishment of Committees.



(a) The Planning Committee shall be open to
participation by all stakeholders and shall provide technical advice and
assistance to the Office of the Interconnection in all aspects of its regional
planning functions. The Transmission Owners shall supply representatives to the
Planning Committee to provide the data, information, and support necessary for
the Office of the Interconnection to perform studies as required and to develop
the Regional Transmission Expansion Plan. Other Members may provide
representatives to the Planning Committee as they deem appropriate.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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(b) The Transmission Expansion Advisory Committee
established by the Office of the Interconnection will meet periodically with
representatives of the Office of the Interconnection to provide advice and
recommendations to the Office of the Interconnection to aid in the development
of the Regional Transmission Expansion Plan. The Transmission Expansion Advisory
Committee will invite participation by: (i) all Transmission Customers, as that
term is defined in the PJM Tariff, and applicants for transmission service; (ii)
any other entity proposing to provide Transmission Facilities to be integrated
into the PJM Region; (iii) all Members; (iv) the agencies and offices of
consumer advocates of the States in the PJM Region exercising regulatory
authority over the rates, terms or conditions of electric service or the
planning, siting, construction or operation of electric facilities and (v) any
other interested entities or persons.



1.4 Contents of the Regional Transmission
Expansion Plan.



(a) The Regional Transmission Expansion Plan shall
consolidate the transmission needs of the region into a single plan which is
assessed on the bases of maintaining the reliability of the PJM Region in an
economic and environmentally acceptable manner and of supporting competition in
the PJM Region.



(b) The Regional Transmission Expansion Plan shall
reflect transmission enhancements and expansions, load and capacity forecasts
and generation additions and retirements for the ensuing ten years.



(c) The Regional Transmission Expansion Plan
shall, as a minimum, include a designation of the Transmission Owner or Owners
or other entity that will construct, own and/or finance each transmission
enhancement and expansion and how all reasonably incurred costs are to be
recovered.



(d) The Regional Transmission Expansion Plan shall
(i) avoid unnecessary duplication of facilities; (ii) avoid the imposition of
unreasonable costs on any Transmission Owner or any user of Transmission
Facilities; (iii) take into account the legal and contractual rights and
obligations of the Transmission Owners; (iv) provide, if appropriate,
alternative means for meeting transmission needs in the PJM Region; (v) strive
to maintain and, when appropriate, to enhance the economic and operational
efficiency of wholesale electric service markets in the PJM region; and (vi)
provide for coordination with existing transmission systems and with appropriate
interregional and local expansion plans.



1.5 Procedure for Development of the Regional
Transmission Expansion Plan.



1.5.1 Commencement of the Process.



(a) The Office of the Interconnection shall
initiate the enhancement and expansion study process if (i) required as a result
of a need for transfer capability identified by the Office of the
Interconnection in its evaluation of requests for interconnection with the
transmission system or for firm transmission service with a term of one year or
more; (ii) required to address a need identified by the Office of the
Interconnection’s in its on-going evaluation of the transmission system’s
economic and operational adequacy and performance; (iii) required as a result of
the Office of the Interconnection’s assessment of the transmission system’s
compliance with MAAC, MAIN or ECAR reliability criteria, more



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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stringent reliability criteria, if any; or PJM
operating criteria; (iv) constraints or available transfer capability shortage
are identified by the Office of the Interconnection as a result of generation
additions or retirements, evaluation of load forecasts, congestion events on or
operational performance of the transmission system, or proposals for the
addition of Transmission Facilities in the PJM region; or (v) expansion of the
transmission system is proposed by one or more Transmission Owners or by a
Transmission Interconnection Customer.



(b) The Office of the Interconnection shall notify
the Transmission Expansion Advisory Committee of the commencement of an
enhancement and expansion study. The Transmission Expansion Advisory Committee
shall notify the Office of the Interconnection in writing of any additional
transmission considerations to be included.



1.5.2 Development of Scope, Assumptions and
Procedures.



Once the need for an enhancement and expansion
study has been established, the Office of the Interconnection shall consult with
the Transmission Expansion Advisory Committee to prepare the study’s scope,
assumptions and procedures.



1.5.3 Scope of Studies.



In general, enhancement and expansion studies
shall include:



(a) An identification of existing and projected
limitations on the transmission system’s physical, economic and/or operational
capability or performance, with accompanying simulations to identify the costs
of controlling those limitations. Potential enhancements and expansions will be
proposed to mitigate limitations controlled by non-economic means.



(b) Evaluation and analysis of potential
enhancements and expansions, including alternatives thereto, needed to mitigate
such limitations.



(c) Identification, evaluation and analysis of
potential enhancements and expansions for the purposes of supporting competition
in the PJM region.



(d) Engineering studies needed to determine the
effectiveness and compliance (with reliability and operating criteria) of
recommended enhancements and expansions.



1.5.4 Supply of Data.



(a) The Transmission Owners shall provide to the
Office of the Interconnection on an annual basis a 10-year forecast of summer
and winter load and resources expected to be served by, or use, their
Transmission Facilities. The forecast shall include to the extent known or
reasonably capable of forecast: (i) a description of the total load to be served
from each substation; (ii) the amount of any interruptible loads included in the
total load (including conditions under which an interruption can be implemented
and any limitations on the duration and frequency of interruptions); and (iii) a
description of all generation resources to be located in the geographic region
encompassed by the Transmission Owner’s transmission facilities, including unit
sizes, VAR capability, operating restrictions, and any must-run unit
designations required for system reliability or contract reasons. The data
required under this Section shall be provided in the form and manner specified
by the Office of the Interconnection.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 21, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




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(b) In addition to the foregoing, the Transmission
Owners, those entities requesting transmission service and any other entities
proposing to provide Transmission Facilities to be integrated into the PJM
Region shall supply any other information and data reasonably required by the
Office of the Interconnection to perform the enhancement and expansion study.



(c) The Office of the Interconnection also shall
solicit from the Members, Transmission Customers and other interested parties,
including but not limited to electric utility regulatory agencies and consumer
advocates of the States in the PJM Region, information required by, or
anticipated to be useful to, the Office of the Interconnection in its
preparation of the enhancement and expansion study.



1.5.5 Coordination of the Regional Transmission
Expansion Plan.



(a) The Regional Transmission Expansion Plan shall
be developed in coordination with the transmission systems of the surrounding
regional reliability councils and with the local transmission providers.



(b) The Regional Transmission Expansion Plan shall
be developed by the Office of the Interconnection in consultation with the
Transmission Expansion Advisory Committee during the enhancement and expansion
study process.



1.5.6 Development of the Recommended Regional
Transmission Expansion Plan.



(a) The Office of the Interconnection shall be
responsible for the development of the Regional Transmission Expansion Plan and
for conducting the studies on which the plan is based.



(b) Upon completion of its studies and analysis,
the Office of the Interconnection shall prepare a recommended enhancement and
expansion plan for review by the Transmission Expansion Advisory Committee. The
Office of the Interconnection also shall invite interested parties to submit
comments on the plan to the Transmission Expansion Advisory Committee and to the
Office of the Interconnection.



(c) The recommended plan shall separately identify
enhancements and expansions for the MAAC Control Zone and for the PJM West
Region.



(d) The recommended plan shall identify
enhancements and expansions that are required to alleviate congestion on the
Transmission System which, in the judgment of the Office of the Interconnection,
cannot be hedged by the use of Financial Transmission Rights (“FTRs”) or other
hedging opportunities available in PJM markets; that otherwise have not been
proposed by any Transmission Owner or other entity; and which, in the judgment
of the Office of the Interconnection, are economically justified. Such economic
expansions and enhancements shall be developed in accordance with the procedures
and analyses described in Section 1.5.7 below.



(e) The recommended plan shall include proposed
Merchant Transmission Facilities within the PJM Region and any other enhancement
or expansion of the Transmission System requested by any participant which the
Office of the Interconnection finds to be compatible



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




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with the Transmission System, though not required
pursuant to Section 1.1, provided that (1) the requestor has complied, to the
extent applicable, with the procedures and other requirements of Part IV of the
PJM Tariff; (2) the proposed enhancement or expansion is consistent with
applicable reliability standards, operating criteria and the purposes and
objectives of the regional planning protocol; (3) the requestor shall be
responsible for all costs of such enhancement or expansion (including, but not
necessarily limited to, costs of siting, designing, financing, constructing,
operating and maintaining the pertinent facilities), and (4) except as otherwise
provided by Part IV of the PJM Tariff with respect to Merchant Network Upgrades,
the requestor shall accept responsibility for ownership, construction, operation
and maintenance of the enhancement or expansion through an undertaking
satisfactory to the Office of the Interconnection.



(f) For each enhancement or expansion that is
included in the recommended plan, the plan shall designate, based on the
planning analysis; other input from participants, including any indications of a
willingness to bear cost responsibility for such enhancement or expansion; and,
when applicable, the provisions of this Schedule 6 and/or those of Part IV of
the PJM Tariff, one or more Transmission Owners or other entities to construct,
own and/or finance the recommended transmission enhancement or expansion. To the
extent that one or more Transmission Owners are designated to construct, own
and/or finance a recommended transmission enhancement or expansion, the
recommended plan shall designate the Transmission Owner that owns transmission
facilities located in the Zone where the particular enhancement or expansion is
to be located. Otherwise, any designation under this paragraph of more than one
entity to construct, own and/or finance a recommended transmission enhancement
or expansion shall also include a designation of proportional responsibility
among them. Nothing herein shall prevent any Transmission Owner or other entity
designated to construct, own and/or finance a recommended transmission
enhancement or expansion from agreeing to undertake its responsibilities under
such designation jointly with other Transmission Owners or other entities.



(g) Based on the planning analysis and other input
from participants, including any indications of a willingness to bear cost
responsibility for an enhancement or expansion, the recommended plan shall, for
any enhancement or expansion that is included in the plan, designate (1) the
Market Participant(s) in one or more Zones that will bear cost responsibility
for such enhancement or expansion, as and to the extent provided by any
provision of the PJM Tariff, or (2) in the event and to the extent that no
provision of the PJM Tariff assigns cost responsibility, the Market
Participant(s) in one or more Zones from which the cost of such enhancement or
expansion shall be recovered through charges established pursuant to Schedule 12
of the Tariff. Any designation under clause (2) of the preceding sentence (A)
shall further be based on the Office of the Interconnection’s assessment of the
contributions to the need for, and benefits expected to be derived from, the
pertinent enhancement or expansion by affected Market Participants, and (B),
subject to FERC review and approval, shall be incorporated in any amendment to
Schedule 12 of the PJM Tariff that establishes a Transmission Enhancement Charge
Rate in connection with an economic expansion or enhancement developed under
Sections 1.5.6(d) and 1.5.7 of this Schedule 6. Before designating fewer than
all customers using Point-to-Point Transmission Service or Network Integration
Transmission Service within a Zone as customers from which the costs of a
particular enhancement or expansion may be recovered, Transmission Provider
shall consult, in a manner and to the extent that it reasonably determines to be
appropriate in each such instance, with affected state



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 24, 2003Vice President, Government
    PolicyIssued On:
    
    November 24, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-009, et al., issued October 24, 2003, 105 FERC ¶ 61,123
      (2003)




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    Superseding First Revised Sheet No. 185B




utility regulatory authorities and stakeholders.
When the plan designates more than one responsible Market Participant, it shall
also designate the proportional responsibility among them. Notwithstanding the
foregoing, with respect to any facilities that the Regional Transmission
Expansion Plan designates to be owned by an entity other than a Transmission
Owner, the plan shall designate that entity as responsible for the costs of such
facilities.



(h) Any Transmission Owner and other participants
on the Transmission Expansion Advisory Committee may offer an alternative.



(i) If the Office of the Interconnection adopts
the alternative, based upon its review of the relative costs and benefits, the
ability of the alternative to supply the required level of transmission service,
and its impact on the reliability of the Transmission Facilities, the Office of
the Interconnection shall make any necessary changes to the recommended plan.



(j) If, based upon its review of the relative
costs and benefits, the ability of the alternative to supply the required level
of transmission service, and the alternative’s impact on the reliability of the
Transmission Facilities, the Office of the Interconnection does not adopt such
alternative, the Transmission Owner or Owners whose alternative or alternatives
have not been accepted or to whom cost responsibility has been assigned and
other participants on the Transmission Expansion Advisory Committee may require
that its or their alternative(s) be submitted to Alternative Dispute Resolution.



1.5.7 Development of Economic Transmission
Enhancements and Expansions.



(a) The objective of the economic planning
component of the regional transmission planning protocol is to provide
cost-effective transmission solutions to alleviate congestion on the
Transmission System which, in the judgment of the Office of the Interconnection,
cannot be hedged by the use of FTRs or other hedging instruments available
pursuant to the PJM Tariff or the Operating Agreement and that no market
participant or other entity otherwise has proposed to resolve. Commencing with
the regional planning cycle beginning on August 1, 2003, the Office of the
Interconnection shall employ the procedures and analyses generally described in
this section to assess the need for, and, where appropriate, to develop, such
economic transmission enhancements and expansions. To the extent not stated in
this section, the Office of the Interconnection shall publish in the PJM Manuals
the specific factors and calculations used in the analysis.



(b) The Office of the Interconnection will
continuously monitor congestion on the Transmission System and will calculate
the hourly gross congestion cost associated with each transmission constraint on
the system for the duration of each constraint. The hourly gross congestion cost
for each individual constraint will be based on the shadow price associated with



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 24, 2003Vice President, Government
    PolicyIssued On:
    
    November 24, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-009, et al., issued October 24, 2003, 105 FERC ¶ 61,123
      (2003)




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    Superseding First Revised Sheet No. 185C




the constraint during each hour, as determined in
the course of calculating the Locational Marginal Price. The total load affected
by a constraint (“total affected load”) shall equal the sum of the loads at each
bus on the Transmission System subject to the constraint multiplied by the
appropriate powerflow distribution factor, excluding load at each bus that has a
distribution factor less than 3% relative to the constraint. The hourly gross
congestion cost per constraint shall be the product of (1) the applicable shadow
price for such hour multiplied by (2) the total affected load (in MW) during the
hour, (3) multiplied by the appropriate powerflow distribution factor. Total
gross congestion cost of the constraint shall be the sum of the gross congestion
cost of the constraint in all hours of the constraint’s duration. Total gross
congestion cost of each constraint shall be accumulated over each occurrence of
the constraint. The Office of the Interconnection shall post on the PJM Internet
site the shadow price of each constraint during each hour and its calculations
of the hourly and cumulative monthly total gross congestion cost of each
constraint. Publication of such data shall not be affected by the commencement
of either calculations of unhedgeable congestion under paragraph (c) below or a
cost-benefit analysis under paragraph (d) below.



(c)(1) The Initial Thresholds for cumulative
monthly total gross congestion costs for transmission constraints shall be:



Operating Voltage Of
      Constrained Facility
    
    Initial Threshold(gross congestion $)greater than 345 kV
    
    $
    2,000,000/month100 kV, up to and including 345
    kV
    
    $
    250,000/monthless than 100 kV
    
    $
    100,000/month




(2) (A) On each occasion when the cumulative
monthly total gross congestion cost of a constraint exceeds the applicable
Initial Threshold, the Office of the Interconnection shall post a notice to that
effect on the PJM Internet site and shall begin determining the extent to which
the total affected load cannot be hedged by the use of FTRs or other measures,
i.e., the extent of unhedgeable congestion associated with the applicable
transmission constraint. The Office of the Interconnection shall calculate
unhedgeable congestion on an hourly basis for each constraint.



(B) The hourly unhedgeable congestion cost per
constraint shall be the product of (1) the applicable shadow price for such hour
multiplied by (2) the total affected load (in MW) during the hour, less the sum
(in MW) of (a) the annual FTRs that were allocated to the total affected load as
ARRs in the most recent annual ARR allocation under the PJM Tariff; (b) any
additional FTRs that could have been available to the total affected load as
ARRs in the most recent annual ARR allocation, but which were not requested; (c)
other long-term FTRs available to the total affected load as ARRs or FTRs from
third parties, including Merchant Transmission Providers; and (d) economic local
generation; multiplied by (3) the appropriate powerflow distribution factor.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    April 21, 2004Vice President, Government
    PolicyIssued On:
    
    April 21, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-009, et al., issued October 24, 2003, 105 FERC ¶ 61,123
      (2003)




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(C) For purposes of the calculations of
unhedgeable congestion and the calculations of net system benefits of potential
solutions to such congestion under paragraph (d)(4) below, the following
definitions shall apply:



(i) “Economic local generation” shall mean the
amount of generation capacity (in MW) (other than units that are running out of
merit order at an offer-capped price pursuant to Section 6 of Schedule 1 of the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 18, 2004Vice President, Government
    PolicyIssued On:
    
    November 17, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket Nos.
      ER03-738-002, RT01-2-001, et al., issued October 18, 2004, 109 FERC
      ¶ 61,067.




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Operating Agreement) that is on-line and available
to affected load at each bus subject to the constraint, excluding generation at
each bus that has a powerflow distribution factor on the constraint of less than
3%, at prices (as determined from generators’ day-ahead price bids into the PJM
Energy Market, provided that a price bid of zero shall be attributed to
self-scheduled units) no greater than the PJM system marginal price.



(ii) “PJM system marginal price” shall mean the
systemwide unconstrained price of energy (system cost to meet load, assuming no
transmission constraints), as determined in the calculation of Locational
Marginal Price.



(iii) “Powerflow distribution factor” shall mean
the percentage of power injected at a bus that flows on the constrained
transmission facility relative to a system reference bus located outside the
affected load area.



(3) Total unhedgeable congestion associated with a
constraint shall be the sum of the unhedgeable congestion associated with the
constraint in all hours of the constraint’s duration. Total unhedgeable
congestion for each constraint shall be accumulated over each occurrence of the
constraint.



(4) The Office of the Interconnection shall
determine the extent to which unhedgeable congestion is attributable to
recurring or non-recurring causes of transmission constraints. Recurring causes
shall include, but shall not necessarily be limited to, periodic maintenance
outages of transmission or generation facilities, forced outages of generation
facilities, and forecasted, continuing increases in load. Non-recurring causes
shall include, but shall not necessarily be limited to, forced outages of
transmission facilities and outages for construction of new transmission
(including interconnection) facilities.



(5) The Office of the Interconnection shall post
on the PJM Internet site its calculations of the hourly and cumulative monthly
unhedgeable congestion associated with each constraint for which it undertakes
such calculations, as well as the portions of unhedgeable congestion that it
attributes to recurring and non-recurring causes of transmission constraints.
Publication of such information shall not be affected by the commencement of a
cost-benefit analysis pursuant to paragraph (d) below.



(6) In the event that a constraint for which gross
congestion costs exceeded the applicable Initial Threshold does not, within four
months after it exceeds that threshold, present sufficient unhedgeable
congestion to exceed the applicable Market Threshold under paragraph (d) below,
the Office of the Interconnection may cease calculating unhedgeable congestion
associated with the constraint until such time as the gross congestion cost
associated with it again exceeds the applicable Initial Threshold.
Notwithstanding the preceding sentence, however, the Office of the
Interconnection at any time may calculate and consider in appropriate
cost-benefit analyses unhedgeable congestion associated with a constraint for
purposes of developing, pursuant to the last sentence of paragraph (d)(3) below,
an economic transmission enhancement or expansion to resolve multiple
constraints and/or to serve other, additional purposes.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 18, 2004Vice President, Government
    PolicyIssued On:
    
    November 17, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket Nos.
      ER03-738-002, RT01-2-001, et al., issued October 18, 2004, 109 FERC
      ¶ 61,067.




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 185DThird Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 185D




(d)(1) The Market Thresholds for unhedgeable
congestion associated with transmission constraints shall be:



Operating Voltage
      Of Constrained Facility
    
    Market
      Threshold(unhedgeable congestion $)greater than 345 kV
    
    $
    100,000/month100 kV up to and including 345
    kV
    
    $
    50,000/monthless than 100 kV
    
    $
    25,000/month




(2) On each occasion when the cumulative monthly
unhedgeable congestion associated with a constraint exceeds the applicable
Market Threshold, the Office of the Interconnection shall post on the PJM
Internet site a notice advising that it shall immediately commence an initial
cost-benefit analysis of potential transmission enhancements or expansions that
would relieve the applicable transmission constraint. The Office of the
Interconnection shall publish the results of the initial cost-benefit analysis
as soon as completed, which shall be no later than 60 days after the date of the
notice of commencement. Such initial cost-benefit results shall include (A)
identification of the first transmission limit that caused the congestion that
exceeded the applicable Market Threshold; (B) an estimate of the cost of
eliminating the limit; (C) the estimated cost-benefit ratio of eliminating the
limit and the Office of the Interconnection’s preliminary judgment of the
relative likelihood that a transmission upgrade would cost-effectively resolve
the unhedgeable congestion; (D) identification of any system upgrades already
included in the Regional Transmission Expansion Plan that, in the Office of the
Interconnection’s judgment, would mitigate the congestion; (E) preliminary
identification of the market participants that would be the beneficiaries of,
and therefore likely would be designated to bear responsibility for the costs or
for payment of charges for recovery of the costs of, any economic transmission
enhancement(s) or expansion(s) needed to remedy the congestion; and (F) a
preliminary allocation of such costs among such market participants. At the
earliest practical date after opening the Market Window (as defined in paragraph
(d)(3) below), the Office of the Interconnection shall supplement the posting on
the PJM Internet site pursuant to this paragraph (d)(2) to identify any
additional transmission limits that contributed to the congestion event for
which the Market Window has been opened and to provide an estimate of the cost
of removing or mitigating each such additional limit. This supplemental
information shall be of the same nature and scope as the information provided in
the initial posting pursuant to this paragraph.



(3) Unless a market-based solution to the
associated unhedgeable congestion is proposed within one year from the date of
publication of the results of the initial cost-benefit analysis under paragraph
(d)(2) above (hereafter, the “Market Window”), the Office of the Interconnection
will propose to include in the Regional Transmission Expansion Plan the
transmission enhancement or expansion that, in its judgment, is the most
cost-effective, feasible transmission solution for the constraint associated
with the unhedgeable congestion. When appropriate in its judgment, the Office of
the Interconnection may propose an enhancement or expansion that will resolve
multiple constraints and/or that will serve other, additional purposes, so long
as it determines that the portion of such enhancement or expansion that is
attributable to resolving the constraint(s) associated with the pertinent
unhedgeable congestion is a cost-effective solution to such constraint(s).



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 18, 2004Vice President, Government
    PolicyIssued On:
    
    November 17, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket Nos.
      ER03-738-002, RT01-2-001, et al., issued October 18, 2004, 109 FERC ¶
      61,067.




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 185DaThird Revised Rate Schedule FERC No.
      24




(4)(A) The Office of the Interconnection shall
commence a cost-benefit analysis under this paragraph (d)(4) upon opening a
Market Window. Such analysis shall be ongoing in nature and shall continue
without regard to the results of the initial cost-benefit assessment under
paragraph (d)(2) above. The ongoing analysis shall take into account all
cumulative unhedgeable congestion, including unhedgeable congestion experienced
during the Market Window; the Office of the Interconnection’s projections of
likely future unhedgeable congestion arising from recurring causes of the
applicable transmission constraint (as described in paragraph (c)(4) above); the
estimated costs of transmission enhancements and expansions that, in the Office
of the Interconnection’s judgment, may cost-effectively mitigate or eliminate
the transmission



Issued By:
    
    Craig Glazer
    
    Effective:
    
    April 21, 2004Vice President, Government
    PolicyIssued On:
    
    April 21, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-009, et al., issued October 24, 2003, 105 FERC ¶ 61,123
      (2003)




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 185D.01Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 185D.01




constraint associated with the relevant
unhedgeable congestion; any transmission enhancements or upgrades that will
remedy multiple, related congestion events; anticipated load growth that may
affect the relevant congestion; and the effects of future upgrades included in
the Regional Transmission Expansion Plan. The analysis shall also take into
account the portion of unhedgeable congestion that may not be eliminated by the
transmission enhancements or expansions. In the event that an upgrade included
in, or which, during the Market Window, is added to, the Regional Transmission
Expansion Plan for purposes of maintaining reliability of service would fully
resolve the relevant unhedgeable congestion, the Office of the Interconnection
shall limit the cost-benefit analysis to assessing the cost-effectiveness of
accelerating construction of the pertinent upgrade or, in the event that the
magnitude of the congestion realized and expected to be experienced prior to
construction of the upgrade indicates that acceleration is unnecessary or
unjustified, shall suspend the cost-benefit analysis pending construction of
such upgrade.



(B) The benefits of a potential transmission
upgrade shall be the estimated net system benefit of the facility over a period
of ten years from the projected date of the upgrade’s commissioning for service.
The net system benefit shall equal (1) the value of the unhedgeable congestion
that the upgrade would relieve, determined as described below, less (2) the sum
of (a) costs associated with any increase in energy prices outside the
constrained area that is anticipated to arise from removal of the constraint,
(b) the estimated value of any increase or decrease in congestion on other
facilities after removal of the constraint, and (c) the costs of any congestion
anticipated to arise due to outages required to construct the upgrade. Factor
(1) in the calculation of net system benefit shall be projected based on hourly
calculations of congestion experienced during the Market Window and shall equal
the product of (i) the applicable shadow price multiplied by (ii) the total
affected load (in MW), less the sum (in MW) of (x) all annual FTRs available or
projected to be available to the affected load (including those allocated and
those available, but not requested, in the annual ARR allocation under the PJM
Tariff and those available as ARRs or FTRs from third parties, including
Merchant Transmission Providers); and (y) economic local generation; multiplied
by (iii) the appropriate powerflow distribution factor. Factor (2)(a) in the
calculation of net system benefit shall equal the product of (iv) the applicable
shadow price multiplied by (v) the total load outside the relevant congested
area (in MW), less (vi) economic generation located outside the constrained
area, multiplied by (vii) the appropriate powerflow distribution factor. For
purposes of this calculation, “total load outside the relevant congested area”
shall mean the sum of the loads at each bus on the Transmission System that is
not subject to the relevant constraint, multiplied by the appropriate powerflow
distribution factor, excluding load at each bus that has a distribution factor
greater than -3% relative to the constraint, and “economic generation” shall
mean generation located outside the constrained area that has a distribution
factor greater than -3% relative to the constraint, but which otherwise meets
the criteria of Section 1.5.7(c)(2)(C)(i) above.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    April 21, 2004Vice President, Government
    PolicyIssued On:
    
    April 21, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-009, et al., issued October 24, 2003, 105 FERC ¶ 61,123
      (2003)




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 185D.02Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No.
185D.02




(C) The assessment of whether a potential
transmission upgrade would be cost-effective shall be based on comparison of the
net present value of the total estimated net system benefit with the net present
value of the total estimated cost of the facility. The net present value of the
total estimated net system benefit shall be calculated based on the estimated
net system benefit for a period of ten years from the date the Office of the
Interconnection estimates the facility could be placed in service and the same
discount rate used in the net present value calculation described in the
following sentence. The net present value of the total estimated cost of the
facility shall be calculated based on the Office of the Interconnection’s
estimate of the capital cost of the potential upgrade and estimated annual
operation and maintenance costs associated with the facility, discounted at a
rate equal to the total return on investment component included in the annual
carrying charge rate and over the depreciation life stated by the applicable
Transmission Owner(s) in Schedule 12A of the PJM Tariff or any successor or
similar schedule stating such factors with respect to Required Transmission
Enhancements, provided that, in the event that no such factors are stated in the
PJM Tariff at the time of the assessment under this paragraph (d)(4), the Office
of the Interconnection shall determine a reasonable discount rate to use in its
net present value calculations. The Office of the Interconnection shall deem the
proposed transmission upgrade to be cost-effective if the net present value of
the facility’s total estimated net system benefit exceeds the net present value
of the facility’s total estimated cost.



(5) The Office of the Interconnection shall review
each Interconnection Request pending under Part IV of the PJM Tariff at the time
a Market Window is opened under paragraph (d)(3) above, and each Interconnection
Request it receives during such Market Window, to evaluate whether the project
proposed in the request could resolve, in whole or in part, and provided that
the Interconnection Customer proposing such project accepts and maintains
designation as a market solution under Sections 36A or 41A of the PJM Tariff and
executes the agreement(s) required thereunder, the unhedgeable congestion for
which the Market Window was established. In the event that such a proposed
project could resolve the unhedgeable congestion in whole or in part, the Office
of the Interconnection shall include in its ongoing cost-benefit analysis
alternative cases reflecting the expected effect of such project.



(e)(1) In the event that, at the close of a Market
Window, an Interconnection Request under Part IV of the PJM Tariff is then
pending for a project that, in the Office of the Interconnection’s judgment,
would resolve the unhedgeable congestion in whole or in part, and provided that
the Interconnection Customer proposing such project accepts and maintains
designation as a market solution under Sections 36A or 41A of the PJM Tariff and
executes the agreement(s) required thereunder,then



Issued By:
    
    Craig Glazer
    
    Effective:
    
    November 18, 2004Vice President, Government
    PolicyIssued On:
    
    November 17, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket Nos.
      ER03-738-002, RT01-2-001, et al., issued October 18, 2004, 109 FERC
      ¶ 61,067.




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 185EThird Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 185E




such interconnection project shall be deemed to be
a market-based response to the unhedgeable congestion and the Office of the
Interconnection shall not propose an economic transmission enhancement or
expansion to address such unhedgeable congestion, provided, however, that,



(A) should the Office of the Interconnection’s cost-benefit analysis
indicate that a transmission enhancement or expansion in addition to such
interconnection project would cost-effectively relieve any portion of the
unhedgeable congestion that the interconnection proposal would not relieve, the
Office of the Interconnection shall propose to include such an enhancement or
expansion in the Regional Transmission Expansion Plan; and



(B) in the event that the Interconnection Request of any interconnection
project designated as a market solution pursuant to the PJM Tariff is
subsequently terminated or withdrawn, or that the project’s designation as a
market solution under the PJM Tariff otherwise is terminated or revoked, the
Office of the Interconnection shall promptly determine whether to include in the
Regional Transmission Expansion Plan a cost-effective transmission enhancement
or expansion to resolve the unhedgeable congestion.



(2) In the event that a Market Window closes and
no market-based response to the unhedgeable congestion (as described in
paragraph (e)(1) above) has been proposed, the Office of the Interconnection
shall propose to include in the Regional Transmission Expansion Plan a
cost-effective transmission enhancement or expansion, consistent with its
cost-benefit analysis under paragraph (d) above, to resolve the unhedgeable
congestion.



(f) On each occasion when the Office of the
Interconnection, upon the close of a Market Window and otherwise in accordance
with this Section 1.5.7, shall propose to include in the Regional Transmission
Expansion Plan an economic transmission enhancement or expansion to relieve
unhedgeable congestion, it shall complete, in the shortest practical time after
the close of the applicable Market Window, the following steps before
recommending such an enhancement or expansion to the PJM Board:



(1) Based on unhedgeable congestion experienced
through the end of the Market Window, finalize its cost-benefit analysis and the
economic transmission enhancement or expansion that it will recommend to the
Board;



(2) Upon reasonable notice, convene a meeting open
to all interested stakeholders, at which the Office of the Interconnection shall
review and discuss with stakeholders its cost-benefit analysis, the economic
transmission enhancement or expansion that the Office of the Interconnection
proposes to recommend to include in the regional plan, and the Office of the
Interconnection’s proposed allocations, consistent with paragraphs (f) and (g)
of Section 1.5.6 above, of responsibility to construct and own or finance and of
responsibility to bear, or to pay charges for collection of, the costs of such
enhancement or expansion;



Issued By:
    
    Craig Glazer
    
    Effective:
    
    April 21, 2004Vice President, Government
    PolicyIssued On:
    
    April 21, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-009, et al., issued October 24, 2003, 105 FERC ¶ 61,123
      (2003)




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 186Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 186




(3) After making any refinements to its
recommendation based on stakeholder input that it deems advisable, present its
recommended economic transmission enhancement or expansion to the PJM Board for
approval as part of the Regional Transmission Expansion Plan.



(g) Any economic transmission enhancement or
expansion that becomes part of the Regional Transmission Expansion Plan in
accordance with this Section 1.5.7 shall be deemed to be placed in the
interconnection queue under Part IV of the PJM Tariff as an Interconnection
Request with a priority date equivalent to the close of the Market Window
associated with such project.



1.6 Approval of the Final Regional Transmission
Expansion Plan.



(a) The PJM Board shall approve the final Regional
Transmission Expansion Plan, including any alternatives therein, and any
additions of economic transmission enhancements or expansions pursuant to
Sections 1.5.6(d) and 1.5.7 above, in accordance with the requirements of this
Section 1.6. The Office of the Interconnection shall publish the current,
approved Regional Transmission Expansion Plan on the PJM Internet site. Within
30 days after each occasion when the PJM Board approves a Regional Transmission
Expansion Plan, or an addition to such a plan, that designates one or more
Transmission Owners to construct an economic expansion or enhancement developed
pursuant to Sections 1.5.6(d) and 1.5.7 above, the Office of the Interconnection
shall file with FERC a report identifying the economic expansion or enhancement,
its estimated cost, the entity or entities that will be responsible for
constructing and owning or financing the project, and the market participants
designated under Section 1.5.6(g) above to bear responsibility for the costs of
the project.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 24, 2003Vice President, Government
    PolicyIssued On:
    
    November 24, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-009, et al., issued October 24, 2003, 105 FERC 61,123
    (2003)




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 187Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 187




(b) If a Regional Transmission Expansion Plan is
not approved, or if the transmission service requested by any entity is not
included in an approved Regional Transmission Expansion Plan, nothing herein
shall limit in any way the right of any entity to seek relief pursuant to the
provisions of Section 211 of the Federal Power Act.



(c) Following PJM Board approval, the final
Regional Transmission Expansion Plan shall be submitted to the Applicable
Reliability Council for verification that all enhancements or expansions conform
with or exceed all reliability principles and standards of the Applicable
Regional Reliability Council.



1.7 Obligation to Build.



(a) Subject to the requirements of applicable law,
government regulations and approvals, including, without limitation,
requirements to obtain any necessary state or local siting, construction and
operating permits, to the availability of required financing, to the ability to
acquire necessary right-of-way, and to the right to recover, pursuant to
appropriate financial arrangements and tariffs or contracts, all reasonably
incurred costs, plus a reasonable return on investment, Transmission Owners
designated as the appropriate entities to construct, own and/or finance
enhancements or expansions specified in the Regional Transmission Expansion Plan
shall construct, own and/or finance such facilities or enter into appropriate
contracts to fulfill such obligations. However, nothing herein shall require any
Transmission Owner to construct, finance or own any enhancements or expansions
specified in the Regional Transmission Expansion Plan for which the plan
designates an entity other than a Transmission Owner as the appropriate entity
to construct, own and/or finance such enhancements or expansions.



(b) Nothing herein shall prohibit any Transmission
Owner from seeking to recover the cost of enhancements or expansions on an
incremental cost basis or from seeking approval of such rate treatment from any
regulatory agency with jurisdiction over such rates.



(c) The Office of the Interconnection shall be
obligated to collect on behalf of the Transmission Owner(s) all charges
established under Schedule 12 of the PJM Tariff in connection with facilities
which the Office of the Interconnection designates one or more Transmission
Owners to build pursuant to this Regional Transmission Expansion Planning
Protocol. Such charges shall compensate the Transmission Owner(s) for all costs
related to such RTEP facilities under a FERC-approved rate and will include any
FERC-approved incentives.



(d) In the event that a Transmission Owner
declines to construct an economic transmission enhancement or expansion
developed under Sections 1.5.6(d) and 1.5.7 of this Schedule 6 that such
Transmission Owner is designated by the Regional Transmission Expansion Plan to
construct (in whole or in part), the Office of the Interconnection shall
promptly file with the FERC a report on the results of the pertinent economic
planning process in order to permit the FERC to determine what action, if any,
it should take.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    October 24, 2003Vice President, Government
    PolicyIssued On:
    
    November 24, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-009, et al., issued October 24, 2003, 105 FERC ¶ 61,123
      (2003)




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 188Third Revised Rate Schedule FERC No.
      24




1.8 Relationship to the PJM Open Access
Transmission Tariff.



Nothing herein shall modify the rights and
obligations of an Eligible Customer or a Transmission Customer, as those terms
are defined in the PJM Tariff, with respect to required studies and completion
of necessary enhancements or expansions. An Eligible Customer or Transmission
Customer electing to follow the procedures in the PJM Tariff instead of the
procedures provided herein, shall also be responsible for the related costs. The
enhancement and expansion study process under this Protocol shall be funded as a
part of the operating budget of the Office of the Interconnection.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 21, 2003Vice President, Government
    PolicyIssued On:
    
    March 20, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-001, issued December 20, 2002, 101 FERC ¶ 61,345
(2002)




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 189Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 189




SCHEDULE 7



UNDERFREQUENCY RELAY OBLIGATIONS AND CHARGES



1. UNDERFREQUENCY RELAY OBLIGATION



1.1 Application.



The obligations of this Schedule apply to each
Member that is an Electric Distributor, whether or not that Member participates
in the Electric Distributor sector on the Members Committee or meets the
eligibility requirements for any other sector of the Members Committee.



1.2 Obligations.



(a) Each Electric Distributor in the MAAC Control
Zone shall install or contractually arrange for underfrequency relays to
interrupt at least 30 percent of its peak load with 10 percent of the load
interrupted at each of three frequency levels: 59.3 Hz, 58.9 Hz and 58.5 Hz.
Upon the request of the Members Committee, each Electric Distributor in the MAAC
Control Zone shall document that it has complied with the requirement for
underfrequency load shedding relays.



(b) Each Electric Distributor in the PJM West
Region shall install or contractually arrange for underfrequency relays to
interrupt at least 25 percent of its peak load with 5 percent of the load
interrupted at each of five frequency levels: 59.5 Hz, 59.3 Hz, 59.1 Hz, 58.9
Hz, and 58.7 Hz; provided, however, that each Electric Distributor in the MAIN
Control Zone shall install or contractually arrange for underfrequency relays to
interrupt at least 30 percent of its peak load with 10 percent of the load
interrupted at each of three frequency levels: 59.3 Hz, 59.0 Hz, and 58.7 Hz.
Upon the request of the Reliability Committee established by the Reliability
Assurance Agreement-West, each Electric Distributor in the PJM West Region shall
document that it has complied with the requirement for underfrequency load
shedding relays.



2. UNDERFREQUENCY RELAY CHARGES



If an Electric Distributor is determined to not
have the required underfrequency relays, it shall pay an underfrequency relay
charge of:



Charge
    
    =
    
    D x R x
  365whereD
    
    =
    
    the amount, in
      megawatts, the Electric Distributor is deficient; andR
    
    =
    
    the daily rate per
      megawatt, which shall be based on the annual carrying charges for a new
      combustion turbine generator, installed and connected to the transmission
      system, which daily deficiency rate as of the Effective Date shall be
      $58.400/per kilowatt-year or $160 per
megawatt-day.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 190Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 190




3. DISTRIBUTION OF UNDERFREQUENCY RELAY CHARGES



3.1 Share of Charges.



Each Electric Distributor that has complied with
the requirements for underfrequency relays imposed by this Agreement during a
Planning Period, without incurring an underfrequency relay charge, shall share
in any underfrequency relay charges paid by any other Electric Distributor that
has failed to satisfy said obligation during such Planning Period. Such shares
shall be in proportion to the number of megawatts of a Electric Distributor’s
load in the most recently completed month at the time of the peak for the PJM
Region during that month rounded to the next higher whole megawatt, as
established initially on the Effective Date and as updated at the beginning of
each month thereafter.



3.2 Allocation by the Office of the
Interconnection.



In the event all of the Electric Distributors have
incurred underfrequency relay charges during a Planning Period, the
underfrequency relay charges shall be distributed among the Electric
Distributors on an equitable basis as determined by the Office of the
Interconnection.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Government
    PolicyIssued On:
    
    April 30, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 191Third Revised Rate Schedule FERC No.
      24




SCHEDULE 8



DELEGATION OF PJM CONTROL AREA RELIABILITY
RESPONSIBILITIES



1. DELEGATION



The following responsibilities shall be delegated
to the Office of the Interconnection by the parties to the Reliability Assurance
Agreement.



2. NEW PARTIES



With regard to the addition, withdrawal or removal
of a party to the Reliability Assurance Agreement, the Office of the
Interconnection shall:



(a) Receive and evaluate the information submitted
by entities that plan to serve loads within the PJM Control Area, including
entities whose participation in the Agreement will expand the boundaries of the
PJM Control Area, such evaluation to be conducted in accordance with the
requirements of the Reliability Assurance Agreement; and



(b) Evaluate the effects of the withdrawal or
removal of a party from the Reliability Assurance Agreement.



3. IMPLEMENTATION OF RELIABILITY ASSURANCE
AGREEMENT



With regard to the implementation of the
provisions of the Reliability Assurance Agreement, the Office of the
Interconnection shall:



(a) Receive all required data and forecasts from
the parties to the Reliability Assurance Agreement and other owners of Capacity
Resources;



(b) Perform all calculations and analyses
necessary to determine the Forecast Pool Requirement and the capacity
obligations imposed under the Reliability Assurance Agreement, including
periodic reviews of the capacity benefit margin for consistency with the
Reliability Principles and Standards, as the foregoing terms are defined in the
Reliability Assurance Agreement;



(c) Monitor the compliance of each party to the
Reliability Assurance Agreement with its obligations under the Reliability
Assurance Agreement;



(d) Keep cost records, and bill and collect any
costs or charges due from the parties to the Reliability Assurance Agreement and
distribute those charges in accordance with the terms of the Reliability
Assurance Agreement;



(e) Assist with the development of rules and
procedures for determining and demonstrating the capability of Capacity
Resources;



(f) Establish the capability and deliverability of
Capacity Resources consistent with the requirements of the Reliability Assurance
Agreement;



(g) Collect and maintain generator availability
data;



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 21, 2003Vice President, Government
    PolicyIssued On:
    
    March 20, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-001, issued December 20, 2002, 101 FERC ¶ 61,345
(2002)




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 192Third Revised Rate Schedule FERC No.
      24




(h) Perform any other forecasts, studies or
analyses required to administer the Reliability Assurance Agreement;



(i) Coordinate maintenance schedules for
generation resources operated as part of the PJM Control Area;



(j) Determine and declare that an Emergency exists
or has ceased to exist in all or any part of the PJM Control Area or announce
that an Emergency exists or ceases to exist in a Control Area interconnected
with the PJM Control Area;



(k) Enter into agreements for (i) the transfer of
energy in Emergencies in the PJM Control Area or in a Control Area
interconnected with the PJM Control Area and (ii) mutual support in such
Emergencies with other Control Areas interconnected with the PJM Control Area;
and



(l) Coordinate the curtailment or shedding of
load, or other measures appropriate to alleviate an Emergency, to preserve
reliability in accordance with FERC, NERC or MAAC principles, guidelines,
standards and requirements and the PJM Manuals, and to ensure the operation of
the PJM Control Area in accordance with Good Utility Practice.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 21, 2003Vice President, Government
    PolicyIssued On:
    
    March 20, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-001, issued December 20, 2002, 101 FERC ¶ 61,345
(2002)




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 193Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 193




SCHEDULE 8A



DELEGATION OF PJM WEST REGION RELIABILITY
RESPONSIBILITIES



1. DELEGATION



The following responsibilities shall be delegated
to the Office of the Interconnection by the parties to the Reliability Assurance
Agreement-West.



2. NEW PARTIES



With regard to the addition, withdrawal or removal
of a party to the Reliability Assurance Agreement-West, the Office of the
Interconnection shall:



(a) Receive and evaluate the information submitted
by entities that plan to serve loads within the PJM West Region, including
entities whose participation in the Agreement will expand the boundaries of the
PJM Region, such evaluation to be conducted in accordance with the requirements
of the Reliability Assurance Agreement-West; and



(b) Evaluate the effects of the withdrawal or
removal of a party from the Reliability Assurance Agreement-West.



3. IMPLEMENTATION OF RELIABILITY ASSURANCE
AGREEMENT-WEST



With regard to the implementation of the
provisions of the Reliability Assurance Agreement-West, the Office of the
Interconnection shall:



(a) Receive all required data and forecasts from
the parties to the Reliability Assurance Agreement-West and other owners of
Capacity Resources;



(b) Perform all calculations and analyses
necessary to determine the capacity obligations imposed under the Reliability
Assurance Agreement-West;



(c) Monitor the compliance of each party to the
Reliability Assurance Agreement-West with its obligations under the Reliability
Assurance Agreement-West;



(d) Keep cost records, and bill and collect any
costs or charges due from the parties to the Reliability Assurance
Agreement-West and distribute those charges in accordance with the terms of the
Reliability Assurance Agreement-West;



(e) Assist with the development of rules and
procedures for determining and demonstrating the capability of Capacity
Resources;



(f) Establish the capability and deliverability of
Capacity Resources consistent with the requirements of the Reliability Assurance
Agreement-West;



(g) Collect and maintain generator availability
data;



(h) Perform any other forecasts, studies or
analyses required to administer the Reliability Assurance Agreement-West;



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




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PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 194Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 194




(i) Coordinate maintenance schedules for
generation resources operated as part of the PJM West Region;



(j) Determine and declare that an Emergency exists
or has ceased to exist in all or any part of the PJM West Region or announce
that an Emergency exists or ceases to exist in a Control Area interconnected
with the PJM West Region;



(k) Enter into agreements for (i) the transfer of
energy in Emergencies in the PJM Region or in a Control Area interconnected with
the PJM Region and (ii) mutual support in such Emergencies with other Control
Areas interconnected with the PJM Region; and



(l) Coordinate the curtailment or shedding of
load, or other measures appropriate to alleviate an Emergency, to preserve
reliability in accordance with FERC, NERC or ECAR principles, guidelines,
standards and requirements and the PJM Manuals, and to ensure the operation of
the PJM West Region in accordance with Good Utility Practice.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 195Third Revised Rate Schedule FERC No.
      24




SCHEDULE 9



PJM CONTROL AREA EMERGENCY PROCEDURE CHARGES



1. EMERGENCY PROCEDURE CHARGE



1.1Following an Emergency, the compliance
of each Member with the instructions of the Office of the Interconnection shall
be evaluated by the Office of the Interconnection. If, based on such evaluation,
it is determined that a Member failed to comply with the instructions of the
Office of the Interconnection to implement PJM emergency procedures, that Member
shall demonstrate that it employed its best efforts to comply with such
instructions. In the event a Member failed to employ its best efforts to comply
with the instructions of the Office of the Interconnection, that Member shall
pay (unless otherwise paid by the Member under the Reliability Assurance
Agreement an emergency procedure charge as follows:



(a) For each megawatt of voltage reduction that
was not implemented as directed, despite being capable of implementation, the
Member shall pay 365 times the daily deficiency rate per megawatt set forth in
Section A of Schedule 11 of the Reliability Assurance Agreement;



(b) For each megawatt of load that was not dropped
as directed, the Member shall pay 730 times the daily deficiency rate per
megawatt set forth in Section A of Schedule 11 of the Reliability Assurance
Agreement; and



(c) For each megawatt of ALM (as defined in the
Reliability Assurance Agreement) that was not implemented as directed and for
each megawatt of a Capacity Resource that was not made available as directed
despite being capable of producing energy at the time, and that is deliverable
to the PJM Control Area in the case of a Capacity Resource located outside of
the PJM Control Area, the Party shall pay 365 times the daily deficiency rate
per megawatt set forth in Section A of Schedule 11 of the Reliability Assurance
Agreement.



2. DISTRIBUTION OF EMERGENCY PROCEDURE CHARGES



2.1 Complying Parties.



Each Member that has complied with the emergency
procedures imposed by this Agreement during an Emergency, without incurring an
emergency procedure charge, shall share in any emergency procedure charges paid
by any other Member that has failed to satisfy said obligation during such
Emergency in an equitable manner to be determined by the PJM Board.



2.2 All Parties.



In the event all of the Members have incurred
emergency procedure charges with respect to an Emergency, the emergency
procedure charges related to that Emergency shall be distributed in an equitable
manner as directed by the PJM Board.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 21, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-001, issued December 20, 2002, 101 FERC ¶ 61,345
(2002)




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PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 196Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 196




SCHEDULE 9A



PJM WEST REGION EMERGENCY PROCEDURE CHARGES



1. EMERGENCY PROCEDURE CHARGE



1.1Following an Emergency, the compliance
of each Member with the instructions of the Office of the Interconnection shall
be evaluated by the Office of the Interconnection. If, based on such evaluation,
it is determined that a Member failed to comply with the instructions of the
Office of the Interconnection to implement PJM emergency procedures, that Member
shall demonstrate that it employed its best efforts to comply with such
instructions. In the event a Member failed to employ its best efforts to comply
with the instructions of the Office of the Interconnection, that Member shall
pay (unless otherwise paid by the Member under the Reliability Assurance
Agreement-West) an emergency procedure charge as follows:



(a) For each megawatt of voltage reduction that
was not implemented as directed, despite being capable of implementation, the
Member shall pay 365 times the daily deficiency rate per megawatt set forth in
Section A of Schedule 11 of the Reliability Assurance Agreement-West;



(b) For each megawatt of load that was not dropped
as directed, the Member shall pay 730 times the daily deficiency rate per
megawatt set forth in Section A of Schedule 11 of the Reliability Assurance
Agreement-West; and



(c) For each megawatt of ALM (as defined in the
Reliability Assurance Agreement-West) that was not interrupted as directed and
for each megawatt of a Capacity Resource that was not made available as directed
despite being capable of producing energy at the time, and that is deliverable
to the PJM West Region in the case of a Capacity Resource located outside of the
PJM West Region, the Party shall pay 365 times the daily deficiency rate per
megawatt set forth in Section A of Schedule 11 of the Reliability Assurance
Agreement-West.



2. DISTRIBUTION OF EMERGENCY PROCEDURE CHARGES



2.1 Complying Parties.



Each Member that has complied with the emergency
procedures imposed by this Agreement during an Emergency, without incurring an
emergency procedure charge, shall share in any emergency procedure charges paid
by any other Member that has failed to satisfy said obligation during such
Emergency in an equitable manner to be determined by the PJM Board.



2.2 All Parties.



In the event all of the Members have incurred
emergency procedure charges with respect to an Emergency, the emergency
procedure charges related to that Emergency shall be distributed in an equitable
manner as directed by the PJM Board.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




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PJM Interconnection, L.L.C.
    
    Substitute First Revised Sheet No. 197Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 197




SCHEDULE 10 -



FORM OF NON-DISCLOSURE AGREEMENT



THIS NON-DISCLOSURE AGREEMENT (the “Agreement”) is made this
 day of
,
2004, by and between
,
an Authorized Person, as defined below, of

(the “State Commission”) having jurisdiction within the State of
,
with offices at

and PJM Interconnection, L.L.C., a Delaware limited liability company, with
offices at 955 Jefferson Avenue, Valley Forge Corporate Center, Norristown, PA
10403 (“PJM”). The State Commission and PJM shall be referred to herein
individually as a “Party,” or collectively as the “Parties.”



RECITALS



Whereas, PJM serves as the Regional
Transmission Organization with reliability and/or functional control
responsibilities over transmission systems involving fourteen states including
the District of Columbia, and operates and oversees wholesale markets for
electricity pursuant to the requirements of the PJM Tariff and the Operating
Agreement, as defined below; and



Whereas, the PJM Market Monitor serves as
the monitor for PJM’s wholesale markets for electricity, and



Whereas, the Operating Agreement requires
that PJM and the PJM Market Monitor maintain the confidentiality of Confidential
Information; and



Whereas, the Operating Agreement requires
PJM and the PJM Market Monitor to disclose Confidential Information to
Authorized Persons upon satisfaction of conditions stated in the Operating
Agreement, including, but not limited to, the execution of this Agreement by the
Authorized Person and the maintenance of the confidentiality of such information
pursuant to the terms of this Agreement; and



Whereas, PJM desires to provide Authorized
Persons with the broadest possible access to Confidential Information,
consistent with PJM’s and the PJM Market Monitor’s obligations and duties under
the PJM Operating Agreement, the PJM Tariff and other applicable FERC
directives; and



Whereas, this Agreement is a statement of
the conditions and requirements, consistent with the requirements of the
Operating Agreement, whereby PJM or the PJM Market Monitor may provide
Confidential Information to the Authorized Person.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    July 28, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197AThird Revised Rate Schedule FERC No.
      24




NOW, THERFORE, intending to be legally bound, the Parties hereby
agree as follows:



1.
    DEFINITIONS.




1.1
    Affected
      Member.A Member of PJM which as a result of its participation in
      PJM’s markets or its membership in PJM provided Confidential Information
      to PJM, which Confidential Information is requested by, or is disclosed to
      an Authorized Person under this Agreement.




1.2
    Authorized Commission. (i) A State (which shall include the
      District of Columbia) public utility commission within the geographic
      limits of the PJM Region (as that term in defined in the Operating
      Agreement) that regulates the distribution or supply of electricity to
      retail customers and is legally charged with monitoring the operation of
      wholesale or retail markets serving retail suppliers or customers within
      its State or (ii) an association or organization comprised exclusively of
      State public utility commissions described in the immediately preceding
      clause (i).




1.3
    Authorized Person. A person, including the undersigned,
      which has executed this Agreement and is authorized in writing by an
      Authorized Commission to receive and discuss Confidential Information.
      Authorized Persons may include attorneys representing an Authorized
      Commission, consultants and/or contractors directly employed or retained
      by an Authorized Commission, provided however that consultants or
      contractors may not initiate requests for Confidential Information from
      PJM or the PJM Market Monitor




1.4
    Confidential Information.Any information that would be
      considered non-public or confidential under the Operating Agreement.




1.5
    FERC.The Federal Energy Regulatory Commission.




1.6
    Information Request. A written request, in accordance with
      the terms of this Agreement for disclosure of Confidential Information
      pursuant to Section 18.17.4 of the Operating Agreement.




1.7
    Operating
      Agreement. The Amended and Restated Operating Agreement of PJM
      Interconnection, L.L.C., as it may be further amended or restated from
      time to time.




1.8
    PJM
      Market Monitor.The Market Monitoring Unit established under
      Attachment M to the PJM Tariff.




1.9
    PJM
      Tariff.The PJM Open Access Transmission Tariff, as it may be amended
      from time to time.




1.10
    Third
      Party Request.Any request or demand by any entity upon an Authorized
      Person or an Authorized Commission for release or disclosure of
      Confidential Information. A Third Party Request shall include, but shall
      not be limited to, any subpoena, discovery request, or other request for
      Confidential Information made by any: (i) federal, state, or local
      governmental subdivision, department, official, agency or court, or (ii)
      arbitration panel, business, company, entity or individual.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197BThird Revised Rate Schedule FERC No.
      24




2.
    Protection of Confidentiality.




2.1
    Duty to
      Not Disclose.The Authorized Person represents and warrants that he or
      she: (i) is presently an Authorized Person as defined herein; (ii) is duly
      authorized to enter into and perform this Agreement; (iii) has adequate
      procedures to protect against the release of Confidential Information, and
      (iv) is familiar with, and will comply with, all such applicable State
      Commission procedures. The Authorized Person hereby covenants and agrees
      on behalf of himself or herself to deny any Third Party Request and defend
      against any legal process which seeks the release of Confidential
      Information in contravention of the terms of this Agreement.




2.2
    Conditions Precedent. As a condition of the execution,
      delivery and effectiveness of this Agreement by PJM and the continued
      provision of Confidential Information pursuant to the terms of this
      Agreement, the Authorized Commission shall, prior to the initial oral or
      written request for Confidential Information by an Authorized Person on
      its behalf, provide PJM with: (a) a final order of FERC prohibiting the
      release by the Authorized Person or the State Commission of Confidential
      Information in accordance with the terms of the Operating Agreement and
      this Agreement; and (b) either an order of the State Commission or a
      certification from counsel to the State Commission, confirming that the
      State Commission has statutory authority to protect the confidentiality of
      the Confidential Information from public release or disclosure and from
      release or disclosure to any other entity, and that it has adequate
      procedures to protect against the release of Confidential Information; and
      (c) confirmation in writing that the Authorized Person is authorized by
      the State Commission to enter into this Agreement and to receive
      Confidential Information under the Operating Agreement. PJM and the PJM
      Market Monitor shall be expressly entitled to rely upon such FERC and
      State Commission orders and/or certifications of counsel in providing
      Confidential Information to the Authorized Person, and shall in no event
      be liable, or subject to damages or claims of any kind or nature hereunder
      or pursuant to the Operating Agreement, due to the ineffectiveness of the
      FERC and/or State Commission orders, or the inaccuracy of such
      certification of counsel.




2.3
    Discussion of Confidential Information with other Authorized
      Persons. The Authorized Person may discuss Confidential Information
      with other Authorized Persons who have executed non-disclosure agreements
      with PJM containing the same terms and conditions as this Agreement;
      provided, however, that PJM shall have confirmed in advance and in writing
      that PJM has previously released the Confidential Information in question
      to such Authorized Persons. PJM shall respond to any written request for
      confirmation within two (2) business days of its receipt.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




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PJM Interconnection, L.L.C.
    
    Substitute Original Sheet No. 197CThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 197C




2.4
    Defense
      Against Third Party Requests.The Authorized Person shall defend
      against any disclosure of Confidential Information pursuant to any Third
      Party Request through all available legal process, including, but not
      limited to, obtaining any necessary protective orders. The Authorized
      Person shall provide PJM, and PJM shall provide each Affected Member, with
      prompt notice of any such Third Party Request or legal proceedings, and
      shall consult with PJM and/or any Affected Member in its efforts to deny
      the request or defend against such legal process. In the event a
      protective order or other remedy is denied, the Authorized Person agrees
      to furnish only that portion of the Confidential Information which their
      legal counsel advises PJM (and of which PJM shall, in turn, advise any
      Affected Members) in writing is legally required to be furnished, and to
      exercise their best efforts to obtain assurance that confidential
      treatment will be accorded to such Confidential Information.




2.5
    Care and
      Use of Confidential Information.




2.5.1
    Control
      of Confidential Information.The Authorized Person(s) shall be the
      custodian(s) of any and all Confidential Information received pursuant to
      the terms of this Agreement from PJM or the PJM Market Monitor.




2.5.2
    Access to
      Confidential Information.The Authorized Person shall ensure that
      Confidential Information received by that Authorized Person is
      disseminated only to those persons publicly identified as Authorized
      Persons on Exhibit “A” to the certification provided by the State
      Commission to PJM pursuant to the procedures contained in section 2.3 of
      this Agreement.




2.5.3
    Schedule
      of Authorized Persons.




(i)
    The
      Authorized Person shall promptly notify PJM of any change that would
      affect the Authorized Person’s status as an Authorized Person, and in such
      event shall request, in writing, deletion from the schedule referred to in
      section (ii), below.




(ii)
    PJM shall
      maintain a schedule of all Authorized Persons and the Authorized
      Commissions they represent, which shall be made publicly available on the
      PJM website and/or by written request. Such schedule shall be compiled by
      PJM, based on information provided by any Authorized Person and/or
      Authorized Commission. PJM shall update the schedule promptly upon receipt
      of information from an Authorized Person or Authorized Commission, but
      shall have no obligation to verify or corroborate any such information,
      and shall not be liable or otherwise responsible for any inaccuracies in
      the schedule due to incomplete or erroneous information conveyed to and
      relied upon by PJM in the compilation and/or maintenance of the schedule.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    July 28, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197DThird Revised Rate Schedule FERC No.
      24




2.5.4
    Use of
      Confidential Information.The Authorized Person shall use the
      Confidential Information solely for the purpose of assisting the State
      Commission in discharging its legal responsibility to monitor the
      wholesale and retail electricity markets, operations, transmission
      planning and siting and generation planning and siting materially
      affecting retail customers within the State, and for no other purpose.




2.5.5
    Return of
      Confidential Information.Upon completion of the inquiry or
      investigation referred to in the Information Request, or for any reason
      the Authorized Person is, or will no longer be an Authorized Person, the
      Authorized Person shall (a) return the Confidential Information and all
      copies thereof to PJM, or (b) provide a certification that the Authorized
      Person has destroyed all paper copies and deleted all electronic copies of
      the Confidential Information. PJM may waive this condition in writing if
      such Confidential Information has become publicly available or
      non-confidential in the course of business or pursuant to the PJM Tariff,
      PJM rule or order of the FERC.




2.5.6
    Notice of
      Disclosures. The Authorized Person, directly or through the Authorized
      Commission, shall promptly notify PJM, and PJM shall promptly notify any
      Affected Member, of any inadvertent or intentional release or possible
      release of the Confidential Information provided pursuant to this
      Agreement. The Authorized Person shall take all steps to minimize any
      further release of Confidential Information, and shall take reasonable
      steps to attempt to retrieve any Confidential Information that may have
      been released.




2.6
    Ownership
      and Privilege.Nothing in this Agreement, or incident to the provision
      of Confidential Information to the Authorized Person pursuant to any
      Information Request, is intended, nor shall it be deemed, to be a waiver
      or abandonment of any legal privilege that may be asserted against
      subsequent disclosure or discovery in any formal proceeding or
      investigation. Moreover, no transfer or creation of ownership rights in
      any intellectual property comprising Confidential Information is intended
      or shall be inferred by the disclosure of Confidential Information by PJM,
      and any and all intellectual property comprising Confidential Information
      disclosed and any derivations thereof shall continue to be the exclusive
      intellectual property of PJM and/or the Affected Member.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




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PJM Interconnection, L.L.C.
    
    Substitute Original Sheet No. 197EThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 197E




3.
    Procedure
      for Information Requests




3.1
    Written
      Requests.Information Requests to PJM shall be in writing, which shall
      include electronic communications, addressed to the PJM Market Monitor or
      other PJM representatives as specified by PJM, with a concurrent copy to
      PJM’s General Counsel, and shall: (a) describe with particularity the
      information sought; (b) provide a description of the purpose of the
      Information Request; (c) state the time period for which information is
      requested; and (d) re-affirm that only the Authorized Person shall have
      access to the Confidential Information requested. PJM shall provide an
      Affected Member with written notice, which shall include electronic
      communication, of an Information Request of the Authorized Person as soon
      as possible, but not later than two (2) business days after the receipt of
      the Information Request.




3.2
    Oral
      Disclosures by the PJM Market Monitor.The PJM Market Monitor or other
      PJM representatives as specified by PJM may, in the course of discussions
      with an Authorized Person, orally disclose information otherwise required
      to be maintained in confidence, without the need for a prior Information
      Request. Such oral disclosures shall provide enough information to enable
      the Authorized Person or the State Commission to determine whether
      additional Information Requests for information are appropriate. The PJM
      Market Monitor or other PJM representative will not make any written or
      electronic disclosures of Confidential Information to the Authorized
      Person pursuant to this section. In any such discussions, the PJM Market
      Monitor or other PJM representative shall ensure that the individual or
      individuals receiving such Confidential Information are Authorized Persons
      under this Agreement, orally designate Confidential Information that is
      disclosed, and refrain from identifying any specific Affected Member whose
      information is disclosed. The PJM Market Monitor or other PJM
      representative shall also be authorized to assist Authorized Persons in
      interpreting Confidential Information that is disclosed. PJM or the PJM
      Market Monitor shall (i) maintain a written record of oral disclosures
      pursuant to this section, which shall include the date of each oral
      disclosure and the Confidential. Information disclosed in each such oral
      disclosure, and (ii) provide any Affected Member with oral notice of any
      oral disclosure immediately, but not later than one (1) business day after
      the oral disclosure. Such oral notice to the Affected Member shall include
      the substance of the oral disclosure, but shall not reveal any
      Confidential Information of any other Member and must be received by the
      Affected Member before the name of the Affected Member is released to the
      Authorized Person; provided however, the identity of the Affected Party
      must be made available to the Authorized Person within two (2) business
      days of the initial oral disclosure.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    July 28, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197FThird Revised Rate Schedule FERC No.
      24




3.3
    Response
      to Information Requests.




3.3.1
    Subject to the provisions of Section 3.3.2 below, PJM shall
      supply Confidential Information to the Authorized Person in response to
      any Information Request within five (5) business days of the receipt of
      the Information Request, to the extent that the requested Confidential
      Information can be made available within such period; provided however,
      that in no event shall Confidential Information be released prior to the
      end of the fourth (4th) business day without the express consent of the Affected Member.
      To the extent that PJM can not reasonably prepare and deliver the
      requested Confidential Information within such five (5) day period, PJM
      shall, within such period, provide the Authorized Person with a written
      schedule for the provision of such remaining Confidential Information.
      Upon providing Confidential Information to the Authorized Person, PJM
      shall either provide a copy of the Confidential Information to the
      Affected Member(s), or provide a listing of the Confidential Information
      disclosed; provided, however, that PJM shall not reveal any Member’s
      Confidential Information to any other Member.




3.3.2
    Notwithstanding section 3.3.1, above, should PJM or an Affected
      Member object to an Information Request or any portion thereof, PJM or the
      Affected Member may, within four (4) business days following PJM’s receipt
      of the Information Request, request, in writing (which shall include
      electronic communication) addressed to the State Commission with a copy to
      either the Affected Party or PJM, as the case may be, a conference with
      the State Commission or the State Commission’s authorized designee to
      resolve differences concerning the scope or timing of the Information
      Request; provided, however, nothing herein shall require the State
      Commission to participate in any conference. Any party to the conference
      may seek assistance from FERC staff in resolution of the dispute. Should
      such conference be refused by any participant, or not resolve the dispute,
      then PJM, the Affected Member or the State Commission may initiate
      appropriate legal action at FERC within three (3) business days following
      receipt of written notice from any conference participant terminating such
      conference. Any complaints filed at FERC objecting to a particular
      Information Request shall be designated by the party as a “fast track”
      complaint and each party shall bear its own costs in connection with such
      FERC proceeding. If no FERC proceeding regarding the Information Request
      is commenced by PJM, the Affected Member or the State Commission within
      such three day period, PJM shall utilize its best efforts to respond to
      the Information Request promptly.




3.3.3
    To
      the extent that a response to any Information Request requires disclosure
      of Confidential Information of two or more Affected Parties, PJM shall, to
      the extent possible, segregate such information and respond to the
      Information Request separately for each Affected Member.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197GThird Revised Rate Schedule FERC No.
      24




4.
    Remedies.




4.1
    Material
      Breach.The Authorized Person agrees that release of Confidential
      Information to persons not authorized to receive it constitutes a breach
      of this Agreement and may cause irreparable harm to PJM and/or the
      Affected Member. In the event of a breach of this Agreement by the
      Authorized Person, PJM shall terminate this Agreement upon written notice
      to the Authorized Person and his or her Authorized Commission, and all
      rights of the Authorized Person hereunder shall thereupon terminate;
      provided, however, that PJM may restore an individual’s status as an
      Authorized Person after consulting with the Affected Member and to the
      extent that: (i) PJM determines that the disclosure was not due to the
      intentional, reckless or negligent action or omission of the Authorized
      Person; (ii) there were no harm or damages suffered by the Affected
      Member; or (iii) similar good cause shown. Any appeal of PJM’s actions
      under this section shall be to FERC.




4.2
    Judicial
      Recourse. In the event of any breach of this Agreement, PJM and/or the
      Affected Member shall have the right to seek and obtain at least the
      following types of relief: (a) an order from FERC requiring any breach to
      cease and preventing any future breaches; (b) temporary, preliminary,
      and/or permanent injunctive relief with respect to any breach; and (c) the
      immediate return of all Confidential Information to PJM. The Authorized
      Person expressly agrees that in the event of a breach of this Agreement,
      any relief sought properly includes, but shall not be limited to, the
      immediate return of all Confidential Information to PJM.




4.3
    Waiver of
      Monetary Damages.No Authorized Person shall have responsibility or
      liability whatsoever under this Agreement for any and all liabilities,
      losses, damages, demands, fines, monetary judgments, penalties, costs and
      expenses caused by, resulting from, or arising out of, or in connection
      with, the release of Confidential Information to persons not authorized to
      receive it, provided that such Authorized Person is an employee or member
      of an Authorized Commission at the time of such unauthorized release.
      Nothing in this Section 4.3 is intended to limit the liability of any
      person who is not an employee of or a member of an Authorized Commission
      at the time of such unauthorized release for any and all economic losses,
      damages, demands, fines, monetary judgments, penalties, costs and expenses
      caused by, resulting from, or arising out of or in connection with such
      unauthorized release.




5.
    Jurisdiction.The Parties agree that (i) any dispute or
      conflict requesting the relief in sections 4.1, and 4.2(a) above shall be
      submitted to FERC for hearing and resolution; (ii) any dispute or conflict
      requesting the relief in section 4.2(c) above may be submitted to FERC or
      any court of competent jurisdiction for hearing and resolution; and (iii)
      jurisdiction over all other actions and requested relief shall lie in any
      court of competent jurisdiction.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Substitute Original Sheet No. 197HThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 197H




6.
    Notices.All notices required pursuant to the terms of this Agreement shall be
      in writing, and served upon the following individuals in person, or at the
      following addresses or email addresses:




If to the Authorized Person:



_______________________

_______________________

_______________________

_______________________

(email address)



with a copy to



_______________________

_______________________

_______________________

_______________________

(email address)



If to PJM:



Market Monitor

PJM Interconnection, LLC

955 Jefferson Avenue

Valley Forge Corporate Center

Norristown, PA 19403

bowrij@pjm.com



with a copy to



General Counsel

955 Jefferson Avenue

Valley Forge Corporate Center

Norristown, PA 19403

hagelj@pjm.com



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    July 28, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




---

PJM Interconnection, L.L.C.
    
    Substitute Original Sheet No. 197IThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 197I




7.
    Severability and Survival. In the event any provision of
      this Agreement is determined to be unenforceable as a matter of law, the
      Parties intend that all other provisions of this Agreement remain in full
      force and effect in accordance with their terms. In the event of conflicts
      between the terms of this Agreement and the Operating Agreement, the terms
      of the Operating Agreement shall in all events be controlling. The
      Authorized Person acknowledges that any and all obligations of the
      Authorized Person hereunder shall survive the severance or termination of
      any employment or retention relationship between the Authorized Person and
      their respective Authorized Commission.




8.
    Representations.The undersigned represent and warrant that
      they are vested with all necessary corporate, statutory and/or regulatory
      authority to execute and deliver this Agreement, and to perform all of the
      obligations and duties contained herein.




9.
    Third
      Party Beneficiaries.The Parties specifically agree and acknowledge
      that each Member as defined in the Operating Agreement is an intended
      third party beneficiary of this Agreement entitled to enforce its
      provisions.




10.
    Counterparts. This Agreement may be executed in counterparts
      and all such counterparts together shall be deemed to constitute a single
      executed original.




11.
    Amendment.This Agreement may not be amended except by
      written agreement executed by authorized representatives of the Parties.




PJM
      INTERCONNECTION, L.L.C.
    
    
    
    AUTHORIZED
      PERSONBy:
    
    
    
    
    
    By:Name:
    
    
    
    
    
    Name:Title:
    
    
    
    
    
    Title:




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    July 28, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197JThird Revised Rate Schedule FERC No.
      24




SCHEDULE 10A



FORM OF CERTIFICATION



This Certification (the “Certification”) is
given this day of
,
200, by
, a
 (the “State Commission”),
to and for the benefit of PJM Interconnection, LLC (“PJM”) and its Members. The
State Commission and PJM shall be referred to herein collectively as the
“Parties”.



Whereas, the State Commission has
designated the individuals on attached Exhibit “A” (the “Authorized Persons”) to
receive Confidential Information from PJM, and



Whereas, the Authorized Persons and PJM
have, or will, enter into non-disclosure agreements, governing the rights and
obligations of the Authorized Persons, PJM and others regarding the Authorized
Persons’ access to, provision of, use and control of the Confidential
Information (the “Non-Disclosure Agreements”), and



Whereas, as a condition precedent to the
execution of the Non-Disclosure Agreements and provision of Confidential
Information to the Authorized Persons, the State Commission is required to make
certain representations and warranties to PJM, and



Whereas, PJM agrees to provide Confidential
Information to the Authorized Persons, in their capacity as agents of the
Authorized Commission, subject to the terms of this Certification, the
Non-Disclosure Agreements, and an appropriate order of the Federal Energy
Regulatory Commission protecting the confidentiality of such data;



Whereas, the Parties desire to set forth
those representations and warranties herein.



Now, therefore, the State Commission hereby
makes the following representations and warranties, all of which shall be true
and correct as of the date of execution of this Certification, and at all times
thereafter, and with the express understanding that PJM and any Affected Member
shall rely on each representation and/or warranty:



1.
    Definitions.Terms contained, but not defined, herein shall
      have the definitions or meanings ascribed to such terms in the
      Non-Disclosure Agreement or the Operating Agreement.




2.
    Requisite
      Authority.




a.
    The State
      Commission is an Authorized Commission hereby certifying that it has all
      necessary legal authority to execute, deliver, and perform the obligations
      in this Certification.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




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PJM Interconnection, L.L.C.
    
    Substitute Original Sheet No. 197KThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 197K




b.
    Each
      Authorized Person is, at the time of the execution of this Certification,
      an employee of, or consultant to, the State Commission, and has not
      materially breached any existing or past non-disclosure agreement or
      obligation, except as has been disclosed by the State Commission to PJM in
      writing.




c.
    The
      Authorized Persons have, through all necessary action of the State
      Commission, been appointed and directed by the State Commission to execute
      and deliver the Non-Disclosure Agreements to PJM and receive Confidential
      Information on the State Commission’s behalf and for its benefit.




d.
    The State
      Commission will, at all times after the provision of Confidential
      Information to the Authorized Persons, provide PJM with: (i) written
      notice of any changes in the Authorized Persons’ qualification as an
      Authorized Person within two (2) business days of such change; (ii)
      written confirmation to any inquiry by PJM regarding the status or
      identification of any specific Authorized Person within two (2) business
      days of such request, and (iii) periodic written updates, no less often
      than semi-annually, containing the names of all Authorized Persons
      appointed by the State Commission.




3.
    Protection of Confidential Information.




a.
    The State
      Commission has adequate internal procedures, to protect against the
      release of any Confidential Information by the Authorized Persons or other
      employee or agent of the State Commission, and the State Commission and
      the Authorized Persons will strictly enforce and periodically review all
      such procedures. In the event that PJM terminates an Agreement with an
      Authorized Person, and does not restore such individual’s status as an
      Authorized Person, then the State Commission shall review such internal
      procedures.




b.
    The State
      Commission has legal authority to protect the confidentiality of
      Confidential Information from public release or disclosure and/or from
      release or disclosure to any other person or entity, either by the State
      Commission or the Authorized Persons, as agents of the State Commission.




c.
    The State
      Commission shall ensure that Confidential Information and shall be
      maintained by, and accessible only to, the Authorized Persons.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    July 28, 2004Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      ER04-776-000, issued June 28, 2004, 107 FERC ¶
61,322.




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197LThird Revised Rate Schedule FERC No.
      24




4.
    Defense
      Against Requests for Disclosure.The State Commission shall defend
      against, and will direct the Authorized Persons to defend against,
      disclosure of any Confidential Information pursuant to any Third Party
      Request through all available legal process, including, but not limited
      to, obtaining any necessary protective orders. The State Commission shall
      provide PJM with prompt notice of any such Third Party Request or legal
      proceedings, and shall consult with PJM and/or any Affected Member in its
      efforts to deny the request or defend against such legal process. In the
      event a protective order or other remedy is denied, the State Commission
      agrees to furnish only that portion of the Confidential Information which
      their legal counsel advises PJM (and of which PJM shall, in turn, advise
      any Affected Member) in writing is legally required to be furnished, and
      to exercise their best efforts to obtain assurance that confidential
      treatment will be accorded to such Confidential Information.




5.
    Use and
      Destruction of Confidential Information.




a.
    The State
      Commission shall use, and allow the use of, the Confidential Information
      solely for the purpose of discharging its legal responsibility to monitor
      the wholesale and retail electricity markets, operations, transmission
      planning and siting and generation planning and siting materially
      affecting retail customers within their respective State, and for no other
      purpose.




b.
    Upon
      completion of the inquiry or investigation referred to in any Information
      Request initiated by or on behalf of the State Commission, or for any
      reason any Authorized Person is, or will no longer be an Authorized
      Person, the State Commission will ensure that such Authorized Person
      either (a) returns the Confidential Information and all copies thereof to
      PJM, or (b) provides a certification that the Authorized Person and/or the
      State Commission has destroyed all paper copies and deleted all electronic
      copies of the Confidential Information.




6.
    Notice of
      Disclosure of Confidential Information.The State Commission shall
      promptly notify PJM of any inadvertent or intentional release or possible
      release of the Confidential Information provided to any Authorized Person,
      and shall take all available steps to minimize any further release of
      Confidential Information and/or retrieve any Confidential Information that
      may have been released.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197MThird Revised Rate Schedule FERC No.
      24




7.
    Release
      of Claims.PJM and the PJM Market Monitor shall be expressly entitled
      to rely upon any orders of FERC and/or the State Commission or
      certifications of counsel for the State Commission, in providing
      Confidential Information to the Authorized Persons, and shall in no event
      be liable, or subject to damages or claims of any kind or nature due to
      the ineffectiveness or inaccuracies of such orders, or the inaccuracy of
      such certification of counsel, or PJM or the PJM Market Monitor’s reliance
      on such orders, and the State Commission hereby waives any such claim, now
      or in the future, whether known or unknown.




8.
    Ownership
      and Privilege.Nothing in this Certification, or incident to the
      provision of Confidential Information to the Authorized Person pursuant to
      any Information Request, is intended, nor shall it be deemed, to be a
      waiver or abandonment of any legal privilege that may be asserted against
      subsequent disclosure or discovery in any formal proceeding or
      investigation. Moreover, no transfer or creation of ownership rights in
      any intellectual property comprising Confidential Information is intended
      or shall be inferred by the disclosure of Confidential Information by PJM,
      and any and all intellectual property comprising Confidential Information
      disclosed and any derivations thereof shall continue to be the exclusive
      intellectual property of PJM and/or the Affected Member.




Executed, as of the date first set out above.



[Commission]By:Its:




SEE NEXT PAGE



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 197NThird Revised Rate Schedule FERC No.
      24




EXHIBIT A

CERTIFICATION

LIST OF AUTHORIZED PERSONS



Name Authority
    
    Mailing Address
    
    Email
    
    Tel #
    
    Scope and Duration of




Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 29, 2004Vice President, Government
    PolicyIssued On:
    
    April 29, 2004




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 198Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 198




SCHEDULE 11



PJM CAPACITY CREDIT MARKETS IN PJM REGION



1. PURPOSES AND OBJECTIVES



1.1 PJM Capacity Credit Markets in PJM Region.



This Schedule sets forth the procedures applicable
to the operation of the PJM Capacity Credit Markets in the PJM Region. The PJM
Capacity Credit Markets will allow Market Participants to buy and sell Capacity
Credits at market clearing prices that are established by the PJM Capacity
Credit Markets and made public by the Office of the Interconnection. The PJM
Capacity Credit Markets shall be administered by the Office of Interconnection
in accordance with the principles and procedures specified in this Schedule.



1.2 [Reserved.]



1.3 Use of Capacity Credits.



An entity may use Capacity Credits to meet all or
part of its capacity obligations imposed under the Reliability Assurance
Agreement or Reliability Assurance Agreement-West. Such Capacity Credits may be
used by themselves, or along with any other options for meeting capacity
obligations imposed under the Reliability Assurance Agreement or Reliability
Assurance Agreement-West.



2. DEFINITIONS



Unless the context otherwise specifies or
requires, capitalized terms used in this Schedule shall have the respective
meanings assigned herein or in the Agreement for all purposes of this Schedule
(such definitions to be equally applicable to both the singular and the plural
forms of the terms defined).



2.1 Buy Bid.



“Buy Bid” shall mean a bid to buy Capacity Credits
in a PJM Capacity Credit Market.



2.2 Capacity Credit.



“Capacity Credit” shall mean an entitlement to a
specified number of megawatts of Unforced Capacity from a Capacity Resource for
the purpose of satisfying capacity obligations imposed under the Reliability
Assurance Agreement or Reliability Assurance Agreement-West, such entitlement
not to include any entitlement to the output of the Capacity Resource. Solely
for purposes of the PJM Installed Capacity Credit Markets, the term Capacity
Credit also shall refer to credits for Installed Capacity during the Interim
Period for the ComEd Zone.



2.2A ComEd Zone.



“ComEd Zone” shall have the meaning specified in
Schedule 17 of the Reliability Assurance Agreement-West.



2.3 Capacity Resources.



“Capacity Resources” shall have the meaning
specified in the Reliability Assurance Agreement and Reliability Assurance
Agreement-West.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 198AThird Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 198A




2.4 Holiday.



“Holiday” shall mean a federal or state holiday
designated by the Office of the Interconnection for recognition in the conduct
of PJM Daily Capacity Credit Markets.



2.4A Installed Capacity.



“Installed Capacity” shall have the meaning
specified in Schedule 17 of the Reliability Assurance Agreement-West.



2.4B Interim Period.



“Interim Period” shall have the meaning specified
in Schedule 17 of the Reliability Assurance Agreement-West.



2.5 PJM Capacity Credit Market.



“PJM Capacity Credit Market” shall mean the PJM
Daily Capacity Credit Market and the PJM Monthly Capacity Credit Market.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    Third
      Revised Sheet No. 199Third Revised Rate Schedule FERC No.
      24
    
    Superseding Second Revised Sheet No. 199




2.6 PJM Daily Capacity Credit Market.



“PJM Daily Capacity Credit Market” shall mean a
competitive market, administered by the Office of the Interconnection in
accordance with the provisions of this Schedule, for the purchase and sale of
Capacity Credits for the business day following the day on which the market is
conducted or for an intervening weekend day or Holiday.



2.6A PJM Installed Capacity Credit Market.



“PJM Installed Capacity Credit Market” shall mean
a competitive market, administered by the Office of the Interconnection in
accordance with the provisions of this Schedule, for the purchase and sale of
credits for Installed Capacity for the Interim Period, or any month thereof, in
the ComEd Zone.



2.7 PJM Monthly Capacity Credit Market.



“PJM Monthly Capacity Credit Market” shall mean a
competitive market, administered by the Office of the Interconnection in
accordance with the provisions of this Schedule, for the purchase and sale of
Capacity Credits for each or any of the twelve months following the month during
which the market is conducted. Solely for purposes of the ComEd Zone during the
Interim Period, PJM Monthly Capacity Credit Markets also shall refer to separate
monthly PJM Installed Capacity Credit Markets.



2.8 Sell Offer.



“Sell Offer” shall mean an offer to sell Capacity
Credits in a PJM Capacity Credit Market.



2.9 Unforced Capacity.



“Unforced Capacity” shall have the meaning
specified in the Reliability Assurance Agreement and Reliability Assurance
Agreement-West.



2.10 Up-To Block.



“Up-To Block” shall mean a Sell Offer or Buy Bid
for a quantity of Capacity Credits equal to or less than a specified quantity.



3. PARTICIPATION IN THE PJM CAPACITY CREDIT
MARKET



3.1 Eligibility.



A Member shall become eligible to participate in
any of the PJM Capacity Credit Markets by becoming a Market Buyer or a Market
Seller, or both as may be appropriate, in accordance with the provisions of
Schedule 1 of the Agreement. In order to participate in any of the PJM Capacity
Credit Markets, a Market Buyer also either must be (a) an entity that is or will
become a Load Serving Entity in the PJM Region and a party to the Reliability
Assurance Agreement or Reliability Assurance Agreement-West, or (b) have a
contractual obligation to sell capacity (including sales for resale) which will
be used in the PJM Region. A Market Seller may participate in any PJM Capacity
Credit Market only to the extent that it has Capacity Credits available to sell
in excess of its capacity obligation imposed under the Reliability Assurance
Agreement or Reliability Assurance Agreement-West and other contractual
obligations to sell capacity (including sales for resale), as determined in
accordance with Section 6.1.3.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 199AThird Revised Rate Schedule FERC No.
      24




3.2 Effect of Withdrawal.



Withdrawal from the Agreement shall not relieve a
Market Participant of any obligation to furnish or pay for Capacity Credits
incurred in connection with participation in a PJM Capacity Credit Market prior
to such withdrawal, to pay its share of any fees and charges incurred or
assessed by the Office of the Interconnection prior to the date of such
withdrawal, or to fulfill any obligation to provide indemnification for the
consequences of acts, omissions or events occurring prior to such withdrawal;
and provided, further, that withdrawal from this



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 200Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 200




Agreement shall not relieve any Market Participant of any obligations it
may have under, or constitute withdrawal from, any Related PJM Agreement.



4. RESPONSIBILITIES OF THE OFFICE OF THE
INTERCONNECTION



4.1 Operation of the PJM Capacity Credit
Market.



The Office of the Interconnection shall operate
the PJM Capacity Credit Markets in accordance with the provisions of this
Schedule and applicable provisions of the Agreement, the Reliability Assurance
Agreement, and the Reliability Assurance Agreement-West. Operation of the PJM
Capacity Credit Markets shall include, but not be limited to, provision of the
following services:



i)
    Determining
      the qualification of entities to become Market Participants;




ii)
    Administering the PJM Capacity Credit Markets;




iii)
    Accounting
      for PJM Capacity Credit Market transactions, including but not limited to
      rendering bills to, receiving payments from, and disbursing payments to,
      participants in the PJM Capacity Credit Markets;




iv)
    Maintaining
      such records of Sell Offers and Buy Bids, clearing price determinations,
      and other aspects of PJM Capacity Credit Market transactions, as may be
      appropriate to the administration of the PJM Capacity Credit Markets; and




v)
    Monitoring
      compliance of participants in the PJM Capacity Credit Markets with the
      provisions of this Schedule and the Agreement.




4.2 Records and Reports.



The Office of the Interconnection shall prepare
and maintain such records as are required for the administration of the PJM
Capacity Credit Markets. For each day of operation of the PJM Capacity Credit
Markets, the Office of the Interconnection shall publish, as specified below:
(i) the price, if determined, at which the PJM Capacity Credit Market cleared;
(ii) the total volume of Capacity Credits purchased; and (iii) such other PJM
Capacity Credit Market data as may be appropriate to the efficient and
competitive operation of the PJM Capacity Credit Markets, consistent with
preservation of the confidentiality of commercially sensitive or proprietary
information. Publication of the foregoing information shall be by posting on the
PJM web site. Such information shall remain available on the PJM web site for
twelve months from the date of posting. The Office of the Interconnection shall
not disclose commercially sensitive or proprietary information in any report or
web site posting.



5. GENERAL PROVISIONS



5.1 Market Sellers.



Only Market Sellers shall be eligible to submit
Sell Offers. Market Sellers shall comply with the terms and conditions of all
Sell Offers, as established by the Office of the Interconnection in accordance
with this Schedule and the Agreement.



5.2 Market Buyers.



Only Market Buyers shall be eligible to submit Buy
Bids. Market Buyers shall comply with the terms and conditions of all Buy Bids,
as established by the Office of the Interconnection in accordance with this
Schedule and the Agreement.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 201Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 201




5.3 Agents.



A Market Participant may participate in the PJM
Capacity Credit Markets through an agent, provided that the Market Participant
informs the Office of the Interconnection in advance in writing of the
appointment of such agent. A Market Participant participating in the PJM
Capacity Credit Markets through an agent shall be bound by all of the acts or
representations of such agent with respect to transactions in the PJM Capacity
Credit Markets, and shall ensure that any such agent complies with the
requirements of this Schedule and the Agreement.



5.4 General Obligations of Market Participants.



Each Market Participant shall comply with all laws
and regulations applicable to the operation of the PJM Capacity Credit Markets
and the use of Capacity Credits, and shall comply with all applicable provisions
of this Schedule, the Agreement, and the Reliability Assurance Agreement, the
Reliability Assurance Agreement-West, and all procedures and requirements for
the operation of the PJM Capacity Credit Markets and the PJM Region established
by the Office of the Interconnection in accordance with the foregoing.



5.5 Relationship of Capacity Credits to
Capacity Obligations Imposed under the Reliability Assurance Agreement or
Reliability Assurance Agreement-West.



A megawatt of Capacity Credit shall satisfy a
megawatt of capacity obligation imposed under the Reliability Assurance
Agreement or Reliability Assurance Agreement-West. Capacity Credits purchased
from a PJM Capacity Credit Market shall not be adjusted for forced outages or
other reasons. Because Capacity Credits are based on Capacity Resources, no
further capability or deliverability demonstrations beyond those for the related
Capacity Resource shall be required.



5.6 Deficiency Charges.



If the Office of the Interconnection determines
that the first Market Seller in a PJM Capacity Credit Market of a Capacity
Credit did not have sufficient Unforced Capacity (or Installed Capacity, in the
case of the ComEd Zone during the Interim Period) to support the Capacity Credit
transaction at the time for which the Capacity Credit was applicable, any such
deficiency shall be satisfied through payment of deficiency charges by such
first Market Seller calculated as specified in the Reliability Assurance
Agreement and Reliability Assurance Agreement-West. Any amounts collected from
such deficiency charges shall be distributed in accordance with the Reliability
Assurance Agreement and Reliability Assurance Agreement-West.



5.7 Financial Transmission Rights.



Acquisition of a Capacity Credit shall not entitle
the holder to a Financial Transmission Right.



5.8 Confidentiality.



The following information submitted to the Office
of the Interconnection in connection with any PJM Capacity Credit Market shall
be deemed confidential information for purposes of Section 18.17 of the
Agreement: (i) the terms and conditions of all Sell Offers and Buy Bids; and
(ii) the terms and conditions of any bilateral transactions for capacity or
Capacity Credits.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 1, 2004Vice President, Governmental
      PolicyIssued On:
    
    December 31, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 202Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 202




6. OPERATION OF THE PJM CAPACITY CREDIT MARKETS



6.1 Content of Sell Offers.



6.1.1 Specifications.



Sell Offers shall specify:



i)
    The quantity
      of Capacity Credits offered, in increments of 0.1 megawatt;


ii)
    The minimum
      price, in dollars and cents per megawatt per day, that will be accepted by
      the seller;


iii)
    For a PJM
      Daily Capacity Credit Market conducted on a Friday or the day before a
      Holiday, the dates on which the offered Capacity Credits may be used; and


iv)
    For a PJM
      Monthly Capacity Credit Market, the month or months for which the offered
      Capacity Credits may be used.




6.1.2 Market-based Offers.



A Market Seller that is authorized by FERC to sell
electric generating capacity at market-based prices, or that is not required to
have such authorization, may submit Sell Offers to PJM Capacity Credit Markets
that specify market-based prices.



6.1.3 Availability of Capacity Credits for
Sale.



i)
    The Office
      of the Interconnection shall determine the maximum megawatts of Capacity
      Credits each Market Seller may offer in a PJM Capacity Credit Market,
      through verification of the availability of megawatts of capacity from:
      (a) Capacity Resources owned by or under contract to the Market Seller;
      (b) rights obtained in bilateral transactions; (c) the results of prior
      PJM Capacity Credit Markets; and (d) such other information as may be
      available to the Office of the Interconnection. The Office of the
      Interconnection may reject Sell Offers or portions of Sell Offers for
      Capacity Credits determined by it not to be available for sale.




ii)
    The Office
      of the Interconnection shall determine the maximum amount of Capacity
      Credits available for sale in a PJM Capacity Credit Market as of the
      beginning of the period during which Buy Bids and Sell Offers are accepted
      for each market. To enable the Office of the Interconnection to make this
      determination, no bilateral transactions for capacity or Capacity Credits
      applicable to the period covered by a PJM Capacity Credit Market will be
      processed from the beginning of the period for submission of Sell Offers
      and Buy Bids for that market until completion of the clearing
      determination for that market. Processing of such bilateral transactions
      will recommence once all sales for that market are deemed final as
      specified below.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2003Vice President, Government
    PolicyIssued On:
    
    May 1, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 202AThird Revised Rate Schedule FERC No.
      24




iii)
    In order for a bilateral
      transaction for the purchase and sale of a Capacity Credit to be processed
      by the Office of the Interconnection, both parties to the transaction must
      notify the Office of the Interconnection of the transfer




Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2003Vice President, Government
    PolicyIssued On:
    
    May 1, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 203Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 203




of the Capacity Credit from the
      seller to the buyer in accordance with procedures established by the
      Office of the Interconnection.




6.2 Content of Buy Bids.



Buy Bids shall specify:



i)
    The quantity
      of Capacity Credits desired, in increments of 0.1 megawatt;




ii)
    The maximum
      price, in dollars and cents per megawatt per day, that will be paid by the
      buyer;




iii)
    For a PJM
      Daily Capacity Credit Market conducted on a Friday or the day before a
      Holiday, the dates for which Capacity Credits are desired; and




iv)
    For a PJM
      Monthly Capacity Credit Market, the month or months for which Capacity
      Credits are desired.




6.3 Submission of Sell Offers and Buy Bids.



The submission of Sell Offers and Buy Bids shall
be subject to the following requirements:



i)
    A Sell Offer
      or Buy Bid that fails to specify price or quantity, or the date or months
      for which Capacity Credits are to be used if applicable, shall be rejected
      by the Office of the Interconnection.




ii)
    All Sell
      Offers and Buy Bids are for an Up-To Block.




iii)
    All Sell
      Offers and Buy Bids for a PJM Daily Capacity Market must be received by
      the Office of the Interconnection during a specified period, as determined
      by the Office of the Interconnection. A Sell Offer or Buy Bid may be
      withdrawn by a notification of withdrawal received by the Office of the
      Interconnection at any time during the foregoing period, but may not be
      withdrawn after that period.




iv)
    Sell Offers
      or Buy Bids for a PJM Daily Capacity Credit Market conducted on a Monday,
      Tuesday, Wednesday, or Thursday that is not the day before a Holiday shall
      be for capacity credits applicable to the following day.




v)
    Sell Offers
      or Buy Bids for a PJM Daily Capacity Credit Market conducted on a Friday
      or the day before a Holiday shall designate the date, to and including the
      next business day, to which the Capacity Credits are applicable. A
      separate PJM Daily Capacity Credit Market shall be conducted on such
      Friday or day before a Holiday for Capacity Credits applicable to each
      following day, to and including the next business day.




vi)
    Sell Offers
      and Buy Bids for a PJM Monthly Capacity Credit Market must be received by
      the Office of the Interconnection during a specified period, as determined
      by the Office of the Interconnection for the conduct of a PJM Monthly
      Capacity Credit Market. A Sell Offer or Buy Bid may be withdrawn by a
      notification of withdrawal received by the Office of the Interconnection
      at any time during the foregoing period, but may not be withdrawn after
      that period.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2003Vice President, Government
    PolicyIssued On:
    
    May 1, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 203AThird Revised Rate Schedule FERC No.
      24




vii)
    Sell Offers
      and Buy Bids shall be submitted or withdrawn via the Internet site
      designated by the Office of the Interconnection; provided, however, that
      if that Internet site cannot be accessed at any time during the period
      specified in the foregoing paragraph, a Sell Offer or Buy Bid may be
      submitted or withdrawn by a facsimile transmitted to the number specified
      by the Office of the Interconnection.




6.4 Conduct of PJM Capacity Credit Markets.



6.4.1 PJM Daily Capacity Credit Markets.



Each business day, following the submission of
Sell Offers and Buy Bids in accordance with the specified deadline for PJM Daily
Capacity Credit Markets, a PJM Daily Capacity Credit Market(s)



Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2003Vice President, Government
    PolicyIssued On:
    
    May 1, 2003




---

PJM Interconnection, L.L.C.
    
    Second
      Revised Sheet No. 204Third Revised Rate Schedule FERC No.
      24
    
    Superseding First Revised Sheet No. 204




will be conducted. A PJM Daily Capacity Credit
Market will clear Sell Offers and Buy Bids for Capacity Credits for use the next
business day, and on Fridays or the day before a Holiday, a separate Daily
Capacity Credit Market(s) for each intervening weekend day or Holiday shall
clear Sell Offers and Buy Bids for Capacity Credits for such days.



6.4.2 PJM Monthly Capacity Credit Markets.



Following the submission of Sell Offers and Buy
Bids in accordance with the specified deadline for PJM Monthly Capacity Credit
Markets, a PJM Monthly Capacity Credit Market will be conducted. Each such PJM
Monthly Capacity Credit Market will clear Sell Offers and Buy Bids for Capacity
Credits for use in each of the following twelve months.



6.5 Market Clearing Procedures.



i)
    For purposes
      of the rank ordering and market clearing procedures described below, the
      Office of the Interconnection will: (a) evaluate all Sell Offers for an
      Up-To Block at the same price as one Sell Offer for an Up-to Block, with
      the quantity equal to the total quantity of the equally-priced Sell
      Offers; and (b) evaluate all Buy Bids for an Up-To Block at the same price
      as one Buy Bid for an Up-to Block, with the quantity equal to the total
      quantity of the equally-priced Buy Bids.




ii)
    The Office
      of the Interconnection will rank order all Sell Offers and Buy Bids by
      price. Sell Offers will be ranked by lowest price first and then ranked in
      ascending price order. Buy Bids will be ranked by highest price first and
      then ranked in descending price order. In the event that a Market
      Participant enters one or more Buy Bids with a price higher than the
      lowest offer price of that Market Participant’s Sell Offers, then all of
      the Market Participant’s Buy Bids priced higher than its lowest priced
      Sell Offer shall be rejected.




iii)
    The Office
      of the Interconnection will determine the largest quantity of Sell Offers
      and Buy Bids for which the price of the marginal Sell Offer is equal to or
      less than the price of the marginal Buy Bid. The market will clear at
      price specified in the marginal Sell Offer.




iv)
    If a
      marginal Sell Offer or Buy Bid is a combination of Sell Offers or Buy Bids
      deemed to be a single Sell Offer or Buy Bid for an Up-To Block as
      specified above, the quantity purchased or sold will be allocated among
      the combined Sell Offers or Buy Bids in proportion to the quantities
      offered in each of the combined Sell Offers or Buy Bids.




v)
    If all Sell
      Offers remaining in the rank order are at prices higher than the highest
      price of any Buy Bid remaining in the rank order, the market will be
      cleared with no transactions, and a market clearing price will not be
      determined.




6.6 Settlement Procedures.



Upon determination of the market clearing price as
specified above: (a) all Sell Offers at a price equal to or less than the market
clearing price and not removed from the rank ordering and for which there is
sufficient Buy Bid demand at or above the market clearing price will be deemed
sold at the market clearing price, and all Buy Bids at a price equal to or
greater than the market clearing price and not removed from the rank ordering
and for which there is sufficient Sell Offer supply at or below the market
clearing price will be deemed satisfied at the market clearing price, with any
Up-To Blocks split and prorated as may be appropriate; and (b) the



Issued By:
    
    Craig Glazer
    
    Effective:
    
    July 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    May 1, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 205Third Revised Rate Schedule FERC No.
      24




accounts of Market Sellers and Market Buyers will be credited or debited
accordingly. The foregoing determinations shall be made, and all sales and
purchases shall be deemed final, as of specified times, as designated by the
Office of the Interconnection, on the day on which each PJM Capacity Market is
conducted.



6.7 Billing.



The Office of the Interconnection shall prepare a
billing statement for each Market Participant in accordance with the charges and
credits specified in this Schedule, and showing the net amount to be paid or
received by each Market Participant. Billing statements for PJM Daily Capacity
Markets shall be rendered following the end of each month for Capacity Credits
bought and sold in the month just ended. Billing statements for PJM Monthly
Capacity Credit Markets shall be rendered following the end of the month for
which the Capacity Credit applies. Billing statements shall provide sufficient
detail, as specified in the PJM Manuals, to allow verification of the billing
amounts and completion of the Market Participant’s internal accounting. Payment
of statements shall be made in accordance with the Agreement.



6.8 Time Standard.



All deadlines for the submission or withdrawal of
Sell Offers or Buy Bids, or for other purposes specified in this Schedule, shall
be determined by the time observed in the Eastern time zone.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 21, 2003Vice President, Government
    PolicyIssued On:
    
    March 20, 2003Filed to
      comply with order of the Federal Energy Regulatory Commission, Docket No.
      RT01-2-001, issued December 20, 2002, 101 FERC ¶ 61,345
(2002)




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 206Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 206




[Sheet Nos. 206 through 214 are
reserved]



Reserved for future use.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    June 1, 2003Vice President, Governmental
      PolicyIssued On:
    
    April 1, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 215Third Revised Rate Schedule FERC No.
      24




SCHEDULE 12



PJM MEMBER LIST



ACN Energy, Inc.

ACN Power, Inc.

Advantage Energy, Inc.

AES Enterprise, Inc.

AES Ironwood, LLC

Air Products & Chemicals, Inc.

Allegheny Electric Cooperative, Inc.

Allegheny Energy Supply Company, L.L.C.

Allegheny Energy Supply Conemaugh, L.L.C.

Amerada Hess Corporation

AmerGen Energy Company, L.L.C.

American Cooperative Services

American Municipal Power-Ohio, Inc.

American Ref-Fuel Company of Delaware Valley, L.P.

American Ref-Fuel Company of Essex County

American Transmission Systems Inc.

Appalachian Power Company

Aquila Merchant Services, Inc.

Atlantic City Electric Company

Automated Power Exchange, Inc.

Baltimore Gas and Electric Company

Benton Foundry, Inc.

Bethlehem Steel Corporation

BGE Home Products & Services, Inc.

BOC Energy Services, Inc.

BOC Group, Inc. (The)

Borough of Chambersburg

Borough of Ephrata

Borough of Tarentum

BP Energy Company

Calpine Energy Services, L.P.

Calvert Cliffs Nuclear Power Plant, Inc.

Cargill Power Markets, LLC

Carolina Power & Light Company

Carpenter Technology Corporation

Central Hudson Gas & Electric Corporation

Central Power & Light Company

Cincinnati Gas and Electric Company (The)

Cinergy Capital & Trading, Inc.

Cinergy Services, Inc.

Citadel Energy Products, LLC

City of New Martinsville

City of Philippi



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 216Third Revised Rate Schedule FERC No.
      24




CMS Marketing, Services and Trading Company

Columbia Energy Power Marketing Corporation

Columbus Southern Power Company

Commercial Utility Consultants, Inc.

Commonwealth Chesapeake Company, LLC

Commonwealth Energy Corporation dba electricAMERICA

Conectiv Energy Supply, Inc.

ConEdison Energy, Inc.

Consolidated Edison Company of New York, Inc.

Consolidated Edison Solutions, Inc.

Constellation Energy Source, Inc.

Constellation NewEnergy, Inc.

Constellation Power Source Generation, Inc.

Constellation Power Source, Inc.

Cook Inlet Power, L.P.

Coral Power, L.L.C.

Covanta Energy Group, Inc.

Covanta Union, Inc.

Customized Energy Solutions, Ltd.

Dayton Power & Light Company (The)

Delaware Municipal Electric Corporation

Delmarva Power & Light Company

Detroit Edison Company

Division of the Public Advocate of State of Delaware

Dominion Energy Direct Sales, Inc.

Dominion Energy Marketing, Inc.

Dominion Retail, Inc.

Dominion Virginia Power

Downes Associates, Inc.

DTE Energy Marketing, Inc.

DTE Energy Trading, Inc.

Duke Energy Trading and Marketing, L.L.C.

Duke Power Company

Dynegy Power Marketing, Inc.

E.F. Kenilworth, Inc.

Easton Utilities Commission

ECONnergy Energy Company, Inc.

ECONnergy Pa, Inc.

Edison Mission Marketing and Trading, Inc.

El Paso Merchant Energy, L.P.

Electrotek Concepts, Inc.

EME Homer City Generation, L.P.

Energy East Solutions, Inc.

Engage Energy America L.L.C.

Entergy-Koch Trading, LP

EPEX, Inc.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 217Third Revised Rate Schedule FERC No.
      24




Exelon Generation Company, L.L.C.

FirstEnergy Solutions Corp.

Florida Power & Light Company

FMF Energy, Inc.

FPL Energy Power Marketing, Inc.

GPU Advanced Resources, Inc.

Green Mountain Energy Company

Hagerstown Light Department

Handsome Lake Energy, L.L.C.

Harrison REA, Inc.

Hess Energy Inc.

Hess Energy Power & Gas Company, LLC

H.Q. Energy Services (U.S.), Inc.

Indiana Michigan Power Company

It’s Electric & Gas, L.L.C.

J. Aron & Company

Jedi Linden NB, L.L.C.

Jersey Central Power & Light Company

Kentucky Power Company

KeySpan Energy Services, Inc.

KeySpan – Ravenswood, Inc.

Lebanon Methane Recovery, Inc.

Legacy Energy Group, L.L.C. (The)

Lehigh Portland Cement Company

Letterkenny Industrial Development Authority

Mack Services Group (The)

Maryland Office of People’s Counsel

Maryland Public Service Commission

Merrill Lynch Capital Services, Inc.

Metropolitan Edison Company

MG Industries

Middlesex Generating Co., L.L.C.

MIECO, Inc.

Mirant Americas Energy Marketing, L.P.

Mirant Americas Retail Energy Marketing, L.P.

Mirant Potomac River, L.L.C.

Monongahela Power Company dba Allegheny Power

Morgan Stanley Capital Group, Inc.

New Power Company (The)

New York State Electric & Gas Corporation

New Jersey Division of the Ratepayer Advocate

NJR Natural Energy Company

Northeast Utilities Service Company

Northern States Power Company

NRG New Jersey Energy Sales LLC

NRG Power Marketing, Inc.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    First
      Revised Sheet No. 218Third Revised Rate Schedule FERC No.
      24
    
    Superseding Original Sheet No. 218




NYSEG Solutions, Inc.

Occidental Power Marketing, L.P.

Occidental Power Services, Inc.

Office of the People’s Counsel for the District of Columbia

Ohio Power Company

Old Dominion Electric Cooperative

Orion Power Midwest, L.P.

Outback Power Marketing, Inc.

Panda Power Corporation

PeakTrader, L.L.C.

PECO Energy Company

Pedricktown Cogeneration Limited Partnership

PEI Power Corporation

PEI Power II, L.L.C.

Penn Power Energy, Inc.

Pennsylvania Electric Company

Pennsylvania Office of Consumer Advocate

Pepco Energy Services, Inc.

PG Energy Services Inc. dba PG Energy PowerPlus

PG&E Energy Trading-Power, L.P.

Potomac Edison Company (The) dba Allegheny Power

Potomac Electric Power Company

Potomac Power Resources, Inc.

Powerex Corporation

PPL Brunner Island, L.L.C.

PPL Electric Utilities Corporation dba PPL Utilities

PPL EnergyPlus, L.L.C.

PPL Holtwood, L.L.C.

PPL Martins Creek, L.L.C.

PPL Montour, L.L.C.

PPL Susquehanna, L.L.C.

Praxair, Inc.

Progress Ventures, Inc.

PSEG Energy Resources and Trade LLC

PSEG Energy Technologies, Inc.

PSI Energy, Inc.

Public Service Company of Colorado

Public Service Company of Oklahoma

Public Service Electric & Gas Company

Rainbow Energy Marketing Corporation

Reliant Energy Services, Inc.

Richards’ Energy Group (The)

Rochester Gas and Electric Corporation

Rockland Electric Company



Issued By:
    
    Craig Glazer
    
    Effective:
    
    May 18, 2004Vice President, Government
    PolicyIssued On:
    
    April 27, 2004




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 219Third Revised Rate Schedule FERC No.
      24




RWE Trading Americas, Inc.

Safe Harbor Water Power Corporation

Schuylkill Energy Resources, Inc.

Select Energy, Inc.

Select Energy New York, Inc.

Sempra Energy Solutions

Sempra Energy Trading Corporation

Sheetz, Inc.

Sithe Power Marketing, L.P.

SmartEnergy.com, Inc.

South Carolina Electric & Gas Company

South Jersey Energy Company

South Jersey Energy Solutions, L.L.C.

Southern Maryland Electric Cooperative, Inc.

Southwestern Electric Power Company

Split Rock Energy, LLC

STI Capital Company

Strategic Energy L.L.C.

Sunbury Generation, L.L.C.

Sunoco Power Marketing, L.L.C.

Sunoco, Inc. (R&M)

TEC Trading, Inc.

Tosco Power, Inc.

Town of Front Royal, Virginia

Town of Thurmont, Maryland

Town of Williamsport

Tractebel Energy Marketing, Inc.

TransAlta Energy Marketing (U.S.) Inc.

TXU Energy Trading Company, LP

UBS AG, acting through its London Branch

UGI Energy Services, Inc.

UGI Development Company

UGI Utilities, Inc.

USP&G (Pennsylvania), Ltd.

Utilitech, Inc.

Vineland Municipal Electric Utility

Virginia State Corporation Commission

Washington Gas Energy Services, Inc.

West Penn Power dba Allegheny Power

West Texas Utilities Company

Weyerhaeuser Company

Williams Energy Marketing & Trading Company

WPS Energy Services, Inc.

WPS Westwood Generation, L.L.C.



Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003




---

PJM Interconnection, L.L.C.
    
    Original
      Sheet No. 220Third Revised Rate Schedule FERC No.
      24




RESOLUTION TO AMEND THE

PROCEDURES REQUIRING THE RETENTION OF

AN INDEPENDENT CONSULTANT TO

PROPOSE A LIST OF CANDIDATES

FOR THE BOARD OF MANAGERS ELECTION FOR 2001



1.
    For the
      election of Board Members at the Annual Meeting in 2001, an independent
      consultant to prepare a list of persons qualified and willing to serve on
      the PJM Board in accordance with Section 7.1 of the Operating Agreement
      shall not be required.




2.
    Section 7.1
      of the Operating Agreement shall be deemed to be amended by the foregoing
      for the election at the Annual Meeting in 2001.




3.
    PJM shall
      make the necessary regulatory filings with the Federal Energy Regulatory
      Commission to implement the foregoing.




Issued By:
    
    Craig Glazer
    
    Effective:
    
    March 20, 2003Vice President, Governmental
      PolicyIssued On:
    
    March 20, 2003