2013 unscheduled flow mitigation plan - combined … usfmp docs combined... · web viewdocument...

2

WECC PolicyUnscheduled Flow Mitigation Policy

Document name Unscheduled Flow Mitigation PolicyCategory ( ) Regional Reliability Standard

( ) Regional Criteria(X) Policy( ) Guideline( ) Report or other( ) Charter

Document date

Adopted/approved by Unscheduled Flow AdministrativeSubcommittee/Operating Committee

Date adopted/approved June 27, 2013

Custodian (entity responsible for maintenance and upkeep)

Unscheduled Flow Administrative Subcommittee

Stored/filed Physical location:Web URL:

Previous name/number (if any)

Status (x) in effect( ) usable, minor formatting/editing required( ) modification needed( ) superseded by _____________________( ) other _____________________________( ) obsolete/archived

3

WECC Unscheduled Flow Mitigation PolicyIntroductionUnscheduled Flow (USF) has been an impediment for Transmission Operators throughout the Western Electricity Coordinating Council (WECC) since the interconnected system has been in existence. USF is the phenomenon by which power flows over paths other than its contract or scheduled paths. USF is a result of operating an interconnected electric system in which many parallel paths exist for power flowing from sending points to receiving points. The magnitude of the USF on a given path will vary as a function of several interrelated factors. The existence of USF is a physical byproduct of interconnected-system operation. The benefits of interconnected operation, however, far outweigh the problems caused by USF. Any solution for coordinated USF mitigation must contain the following:

1. Recognize that USF is created by all users of the WECC interconnected system; therefore, all users should participate in coordinated USF mitigation.

2. Address long-term solutions including maintaining existing facilities and investing in new facilities.

3. Address USF in both major and minor loops.

4. Provide reimbursement to the owners of Controllable Devices operated to control USF.

5. Provide equitable treatment for interconnected system users.

6. Be consistent with NERC and WECC Standards and Criteria.

7. Be relatively simple to implement and administer.

Thus, the WECC Unscheduled Flow Mitigation Policy was created and adopted to provide the course or method of mitigation given the severity of the USF problem and to guide and determine present and future decisions concerning the solutions associated with the USF problem. The Policy is put into practice by the WECC Unscheduled Flow Reduction Guideline which is a step-by-step procedure on how to implement the Policy.

Policy CriteriaThe WECC Unscheduled Flow Mitigation Policy addresses the prescribed method of mitigation for USF and the details for its implementation. The entities that the Policy applies to are listed below:

Balancing Authority

Interchange Authority

Load-Serving Entity

Reliability Coordinator

Purchasing-Selling Entity

Transmission Operator

Transmission Service Provider

4

The following guidelines shall be used to determine Controllable Devices compensation and annual membership dues.

a. WECC Unscheduled Flow Mitigation Controllable Devices Compensation Guideline

b. WECC Unscheduled Flow Mitigation for Establishing Annual Dues

5

1. RecitalsThis Policy is set forth with reference to the following facts and principles, among others:

1.1. It is a recognized fact that all Schedules contribute to USF and that some amount of USF is inevitable. The WECC interconnected regional transmission systems have experienced Unscheduled Flow (USF) for many years, often constraining the scheduled use of transmission facilities.

1.2. WECC recognizes that significant USF is an inevitable and occasionally burdensome consequence of interconnected-system operation.

1.3. WECC also recognizes that effective control of USF will provide significant transmission benefits to all owners and users of the interconnected- transmission system.

1.4. Past administrative and schedule curtailment procedures to relieve or mitigate the impact of such USF have not been as successful as desired.

1.5. A number of Controllable Devices, primarily phase-shifting transformers, have been installed within the WECC interconnected system in the past several years by their respective owners for specific local purposes.

1.6. Controllable Devices have the capability to alter power flow on parallel alternating current Transfer Paths. The Controllable Devices may be used to control actual flow within the limits of Scheduled Flow and unaltered power flow.

1.7. The coordinated operation of the phase-shifting transformers and other Controllable Devices has been demonstrated to be very effective in reducing the level of USF over both the major loop and some minor loop transmission paths in the WECC interconnected system.

1.8. The owners of these Controllable Devices are willing to make them available for coordinated operation to assist in relieving Qualified Transfer Paths constrained by USF, provided that such operation does not materially adversely impact their intended purposes or the Controllable Device owners' respective customers.

1.9. WECC has developed this Policy to control USF and to provide relief to the transmission owners and operators and to prevent excessive amounts of USF from creating constrained Transfer Paths.

1.10. This Policy is based on the WECC Unscheduled Flow Principles document, which has been incorporated into this Policy.

1.11. WECC seeks through this Policy to combine the use of controllable devices (series capacitors, phase shifting transformers, and DC transmission lines), coordinated operation of the Qualified Controllable Devices, together with Schedule adjustments to relieve the constraints

6

on Qualified Transfer Paths caused by excessive amounts of USF.

1.12. This Policy provides a means to collect funds from the applicable entities and to disburse these funds to the Controllable Device owners for their reasonably-incurred costs associated with coordinated operation to relieve WECC Qualified Transfer Path constraints.

1.13. Controllable Devices — such as phase-shifting transformers — have limited operating lifetimes, and the phase-shifter owners do not want to adversely affect the planned lifetimes and effectiveness of those devices through overuse. Coordinated operation of the Controllable Devices must be used in combination with other operational tools, including Schedule curtailment, to effectively mitigate USF.

1.14. This Policy attempts to balance the mitigation responsibilities among all applicable entities through shared operating costs for control, and curtailment requirements (when necessary).

1.15. Experience gained has proven the value of the Policy and, in particular, the value of coordinated operation of Controllable Devices in mitigating USF.

2. TermThe term of this Policy will commence on the latter of: (1) the first day of the first quarter at least 45 days after regulatory approval; or (2) upon complete implementation of applicable webSAS changes and FERC approval of the Plan and revised Regional Reliability Standard IRO-006-WECC-2.

3. DefinitionsThe following terms, when used herein with initial capitalization (whether in the singular or plural), shall have the meanings specified:

3.1. Controllable Device: An element (phase shifter, series capacitors, back-to- back DC, etc.) that can be used to mitigate the effects of USF.

3.2. Controllable Devices Coordinated Operating Process (CDCO Process): The WECC Controllable Devices Coordinated Operating Process is described in the document titled Unscheduled Flow Mitigation Process for Controllable Devices Coordination.

3.3. FERC: Federal Energy Regulatory Commission.

3.4. Policy: This WECC Unscheduled Flow Mitigation Policy and the following documents:

WECC Unscheduled Flow Reduction Guideline

CDCO Procedure paper

WECC Unscheduled Flow Mitigation Controllable Devices Compensation Guideline

WECC Unscheduled Flow Mitigation for Establishing Annual Member Dues

7

WECC Unscheduled Flow Principles paper

3.5. Policy Year: The 12-month period that equals the current calendar year.

3.6. Guidelines: The step-by-step instructions and procedures needed to implement the operational portion of this Policy; specifically, the USF Reduction Guideline and the CDCO Process.

3.7. Qualified Controllable Device: A Controllable Device that has met the qualification requirements described in Section 9 and has been approved by the WECC Operating Committee.

3.8. Qualified Transfer Path: A Transfer Path that has met the qualification requirements described in Section 8 and has been approved by the WECC Operating Committee.

3.9. Receiver: The Balancing Authority in which a transaction sinks is determined to be the Receiver. Note: Due to automation and changes to the process used, this is a change to what has historically been used.

3.10. Scheduled Flow: The algebraic sum of individual Schedules for an hour across a Transfer Path, e.g., net Schedules.

3.11. Sender: An entity delivering a Schedule of energy across a Transfer Path or series of Transfer Paths.

3.12. System Operating Limit (SOL):1 The value (such as MW, MVar, Amperes, Frequency or Volts) that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria. System Operating Limits are based upon certain operating criteria. These include, but are not limited to:

Facility Ratings (Applicable pre- and post-Contingency equipment or facility ratings)

Transient Stability Ratings (Applicable pre- and post-Contingency

Stability Limits)

Voltage Stability Ratings (Applicable pre- and post-Contingency

Voltage Stability)

System Voltage Limits (Applicable pre- and post-Contingency Voltage Limits)

3.13. Transfer Path: An element or group of elements (transmission lines, transformers, series capacitors, buses, or other pieces of electrical equipment interconnecting control areas or parts of a control area) over which a Schedule can be established.

3.14. Transfer Path Operator: The Transmission Operator that operates the Qualified Transfer Path.

1 As defined in NERC’s Glossary of Terms Used in Reliability Standards, updated April 20, 2009.

8

3.15. Unscheduled Flow (USF): Transfer Path actual flow minus Transfer Path Scheduled Flow.

3.16. Unscheduled Flow Administrative Subcommittee (UFAS): The subcommittee that is described in Section 4 of this Policy.

3.17. Unscheduled Flow Dues (USF Dues): Each applicable entity's dues allocation of the costs associated with achieving coordinated operation of the Qualified Controllable Devices.

3.18. Unscheduled Flow Reduction Guideline (USF Reduction Guideline): The WECC Unscheduled Flow Reduction Guideline.

3.19. WECC: Western Electricity Coordinating Council, its successors and assigns.

3.20. WECC Dispute Resolution Procedures: The written procedure adopted by WECC in Appendix C of the “Bylaws of the Western Electricity Coordinating Council” to govern the voluntary process for applicable entities to resolve disputes relating to the reliability, planning, and operation of the western interconnected system.

3.21. Restricted Transaction: After a USF event is declared, any transaction with greater than a ten percent transfer distribution factor on the Qualified Transfer Path in the qualified direction.

4. Administration4.1. The administrative organization that shall implement this Policy and the

USF Reduction Guideline is as follows:

4.1.1. WECC Board of Directors

4.1.2. WECC Operating Committee4.1.3. Unscheduled Flow Administrative Subcommittee (UFAS)

reporting to the WECC Operating Committee

4.1.4. WECC staff4.2. The WECC Board of Directors is responsible for communicating the

activities of the WECC Operating Committee and the UFAS to the applicable entities. The WECC staff support of the USF Reduction Guideline and the WECC Operating Committee and the UFAS activities shall be done with the advice and consent of the WECC Board of Directors. The WECC Board of Directors shall perform the following functions and responsibilities:4.2.1 Approve changes, deletions, and amendments to the Policy and

Guideline that in its judgment do not have significant adverse impact on any applicable entity.

4.2.2 Present significant changes, deletions, and amendments to the Policy or its Guidelines to the applicable entities for review and approval.

4.2.3 Upon receipt of written requests from 20 percent of the

9

applicable entities, initiate a review of the USF Dues allocation and report the results and any recommended changes to the applicable entities in a timely manner.

4.3. The WECC Operating Committee shall perform the following tasks:4.3.1 Review and approve recommendations of the UFAS to qualify or

delete Transfer Paths for USF control.4.3.2 Review and approve recommendations of the UFAS to qualify or

delete Controllable Devices for USF coordinated control compensation under this Policy and the Guideline.

4.3.3 Review UFAS recommendations of changes, deletions, and amendments to the Policy and the Guideline, and recommend such to the WECC Board of Directors.

4.3.4 Review UFAS recommendations of subsequent procedures to deal with USF and forward to the WECC Board of Directors as appropriate.

4.3.5 Perform other duties as assigned by the WECC Board of Directors.

4.3.6 Coordinate changes to this Policy and the Guideline with the Planning Coordination Committee.

4.4. The UFAS shall be made up of an equal number of representatives from the following member groups:

entities that operate Qualified Controllable Devices

entities that operate Qualified Transfer Paths

at-large representatives from entities that do not operate either Qualified Controllable Devices or Qualified Transfer Paths

The WECC Operating Committee Chairman shall appoint the at-large representatives and shall determine the overall size of the UFAS. The applicable entities that operate Qualified Controllable Devices and Qualified Transfer Paths shall appoint their respective representatives. However, the WECC Operating Committee Chairman may appoint representatives to fill vacancies with respect to either member group to serve until a majority of the applicable entities in the group agree upon replacement representatives. The UFAS will carry out its responsibilities based on a majority vote of UFAS representatives and shall have the following functions and responsibilities:4.4.1 Review requests for the qualification, requalification, and deletion

of Transfer Paths, and recommend requests to the WECC Operating Committee.

4.4.2 Recommend changes, deletions, and amendments to the Policy and to the Guideline, to the WECC Operating Committee.

4.4.3 Determine whether proposed Controllable Devices meet, or current qualifying Controllable Devices fail to meet, the appropriate qualifying criteria (for coordination and compensation) and report such to the WECC Operating

10

Committee.4.4.4 Perform other duties as may be required under the Policy, the

Guideline, or as may be assigned by the WECC Board of Directors or the WECC Operating Committee.

4.4.5 Collect performance data and monitor compliance with the Policy.

4.5. The WECC staff shall perform the following tasks annually:4.5.1 Compute each applicable entity's USF Dues obligation under this

Policy.4.5.2 Compute the annual compensation payment for each Qualified

Controllable Device under this Policy.4.5.3 Provide each applicable entity with an annual summary of USF

Dues and payments.4.5.4 Develop an annual USF budget with the UFAS for each calendar

year, which shall include an estimate of the annual compensation payments and the USF Dues obligation for each applicable entity.

4.5.5 Include WECC staff expenses to implement and administer the Policy in the annual WECC budget.

4.5.6 Collect the applicable entities' USF Dues and distribute the collected funds to the Qualified Controllable Device owners in accordance with Section 8 of this document.

5. ProtocolThe protocol for action to be taken is in the following order:

5.1. Coordinated Controllable Device operation must be accomplished as provided in Section 8: Controllable Device Qualification, Operation, and Compensation.

5.2. Schedule curtailments must be accomplished as provided in Section 10: Unscheduled Flow Reduction.

6. Transfer Path Qualification, Requalification, or Deletion6.1. The UFAS shall determine that a Transfer Path Operator has provided

the required documentation and meets the criteria for qualification, requalification, or deletion as specified in the USF Reduction Guideline prior to recommending its qualification, requalification, or deletion to the WECC Operating Committee.

7. Controllable Device Qualification, Operation, and Compensation

7.1. Any applicable entity may propose a Controllable Device to be qualified for compensation for coordinated operation under this Policy by presenting a plan for coordinated operation to the UFAS pursuant to the USF Reduction Guideline.

11

7.2. Qualified Controllable Devices that are no longer made available or are not capable of providing the minimum average effectiveness across all the Qualified Transfer Paths (specified in the USF Reduction Guideline) shall be considered by UFAS for deletion from the list of Qualified Controllable Devices according to the guidelines set forth in the USF Reduction Guideline.

7.3. During periods when there is a scheduling limitation due to USF on a Qualified Transfer Path and the Transfer Path Operator has utilized Controllable Devices — such as series capacitors, phase shifting transformers, and DC transmission lines to the maximum extent practical in reducing the USF across the constrained Qualified Transfer Path to a level at or below the SOL. The owners of Qualified Controllable Devices shall make the control capability of such Qualified Controllable Devices available to reduce USF on the Qualified Transfer Path. Where there is more than one Qualified Controllable Device available, they shall be operated in a coordinated manner in accordance with the CDCO Process to reduce USF on the affected Qualified Transfer Path. In the event that such coordinated operation creates excess loadings or other adverse effects elsewhere in the WECC system, the level of USF control shall be reduced to avoid such adverse effects.

7.4. During periods when there is no scheduling limitation due to USF on any Qualified Transfer Path affected by the Controllable Device, the Controllable Device may be operated as desired by its owner(s) provided such operation is consistent with NERC and WECC standards and criteria.

7.5. Owners of Qualified Controllable Devices shall be compensated by WECC for their coordinated operation. The level of compensation and its allocation among the Qualified Controllable Devices shall be determined using an effectiveness test, in conjunction with the number of hours of Controllable Device operation requested during the year, as shown in the WECC Unscheduled Flow Mitigation Controllable Devices Compensation Guideline. The effectiveness test recognizes that some Controllable Devices are able to achieve a greater reduction in USF over all Qualified Transfer Paths than other Controllable Devices. In this way, the effectiveness test provides a means for apportioning the compensation among the Controllable Devices according to their effectiveness in reducing USF.

7.6. Qualified Controllable Devices shall receive the full annual compensation according to the schedule shown in the WECC Unscheduled Flow Mitigation Controllable Devices Compensation Guideline, provided the Qualified Controllable Device was available for coordinated operation at least 90 percent of the time for which coordinated operation was requested. Operating performance at levels below this minimum shall result in a pro- rata reduction in the annual compensation pursuant to the following formula:

12

Annual Qualified Controllable Device Compensation = (Calculated Compensation Amount per WECC Phase Shifter Compensation Proposal) * AF

where

AF: Availability Factor = AA / (0.90 * RA) but not greater than 1.0

AA: Actual Availability = RA minus the number of hours in a calendar year for which operation of the Controllable Device was requested, but was not provided

RA: Requested Availability = Number of hours in a calendar year for which operation of the Controllable Device was requested

The calculation of AA and RA shall not include hours in which a Controllable Device is not operated in accordance with the last sentence of Section 8.3. If no requests for coordinated operations are made, then the AF shall be deemed to be 100 percent.

8. Unscheduled Flow Reduction8.1. When utilization of Controllable Devices — such as series capacitors,

phase shifting transformers, and DC transmission lines to the maximum extent practical, combined with coordinated operation of the Qualified Controllable Devices is insufficient to reduce the actual flow on the Qualified Transfer Path to below the Transfer Limit, the Transfer Path Operator shall request curtailments in Schedules that contribute to the USF through the Qualified Transfer Path according to the USF Reduction Guideline.

8.2. Applicable entities shall comply in a timely manner with a Transfer Path

8.3. Operator's request for Schedule curtailments.

9. Annual Unscheduled Flow Dues AllocationIn accordance with Article VIII, Section 7 of the WECC Agreement, as amended, each applicable entity shall be allocated an USF Dues obligation according to the methodology set forth in the WECC Unscheduled Flow Mitigation for Establishing Annual Membership Dues.

10. Dispute Resolution10.1. Any disputes that arise as a result of an applicable entity's performance

or non-performance under this Policy or the associated Guideline shall be resolved using the WECC Voluntary Dispute Resolution Procedure in effect at the time the notice is given to the UFAS and the WECC staff.

11. Limitation of Liability11.1. Except for the obligation to make payments hereunder, this Policy shall

not create or be interpreted as creating any duty to, any standard of

13

care with reference to, or any liability to, any applicable entity or anyone else.

11.2. Each applicable entity shall be responsible for protecting its facilities from (i) possible damage by reason of electrical disturbances or faults caused by the operation, faulty operation, or non-operation of the facilities of any other applicable entity being used under or as part of this Policy, and (ii) the performance or non-performance of any applicable entity under this Policy. No damages; direct, indirect, secondary, or consequential; shall arise hereunder by reason of any such operation, non-operation, performance, or non-performance and each applicable entity hereby waives any claim for any such damages thereby arising.

12. Audit RightsAny entity shall have the right to audit the records of the owners of the Qualified Controllable Devices in substantiation of their annual ownership and operating costs associated with any Qualified Controllable Device. Such audit right shall remain in place for five years following the Policy Year for which the costs were applicable in determining the level of compensation for the Qualified Controllable Device.

Approved By:

Approving Committee, Entity or Person Date

Unscheduled Flow Administrative Subcommittee 5-17-13

Operating Committee 6-19-13

Board of Directors 6-27-13

This policy supersedes and revokes any and all past policies and practices and oral and written representations concerning the subject matter covered herein. WECC reserves the right to add to, delete, change or revoke this policy at any time, with or without notice.Caution! – This document may be out of date if printed.

14

Western Electricity Coordinating Council GuidelineUnscheduled Flow Reduction Guideline

Date: March 09, 2012Document name Unscheduled Flow Reduction GuidelineCategory ( ) Regional reliability standard

( ) Regional criteria( ) Policy(X) Guideline( ) Report or other( ) Charter

Document date January 26, 2012Adopted/approved by Operating Committee/WECC BoardDate adopted/approved March 09, 2012/ March 15, 2012Custodian (entity responsible for maintenance and upkeep)

UFAS

Stored/filed Physical location: Web URL:

Previous name/number (if any)Status ( ) in effect

( ) usable, minor formatting/editing required( ) modification needed( ) superseded by( X ) other _Awaiting further approvals and tool modifications ( ) obsolete/archived)

15

WECC Guideline:UNSCHEDULED FLOW REDUCTION GUIDELINE

IntroductionThe combination of Scheduled and Unscheduled Flows (USF) on a Transfer Path may exceed the transfer capability of that Transfer Path. This Unscheduled Flow Reduction Guideline (Guideline) can be used by the Qualified Transfer Path Operator to reduce the USFs across a constrained Qualified Transfer Path.

GuidelineThe WECC Guideline addresses the prescribed method of mitigation for USF and the details for its implementation. This Guideline recognizes the effectiveness of coordinated control and operation of the Qualified Controllable Devices installed within the WECC systems. It is subject to modification as provided in Section 4.2 of the WECC Unscheduled Flow Mitigation Policy (Policy).

The entities that the Guideline applies to are:

Balancing Authority (BA)

Reliability Coordinator (RC)


These entities may also be impacted by the Guideline:

Interchange Authority

Load-Serving Entity



16

WECC UNSCHEDULED FLOW REDUCTION GUIDELINEThe combination of Scheduled and Unscheduled Flows on a Qualified Transfer Path may exceed the System Operating Limit (SOL) of that Transfer Path. This Guideline will be used to reduce the USF across a constrained Qualified Transfer Path. The Guideline has the following parts:

1. Transfer Path Qualification ................................................................................... 16

2. Transfer Path Requalification ............................................................................... 18

3. Qualified Transfer Path Deletion .......................................................................... 18

4. Actions Required Following Addition of a New Qualified Transfer Path ............. 18

5. Controllable Device Qualification ......................................................................... 19

6. Qualified Controllable Device Deletion ................................................................ 20

7. General Terms ..................................................................................................... 20

8. General Action Rules ........................................................................................... 22

9. Action Steps ........................................................................................................ 22

10. Competing Paths ................................................................................................... 25

11. Further Action ........................................................................................................ 27

12. Term ...................................................................................................................... 28

Attachment A: Summary of Curtailment Actions ............................................................... 29

Exhibit A: List of Qualified Transfer Paths as of January 26, 2012 .............................. 31

Terms that are initially capitalized in this Guideline refer to defined terms in the WECC Unscheduled Flow Mitigation Policy.

1. Transfer Path QualificationRequests for Transfer Path qualification shall be made directly to the Unscheduled Flow Administrative Subcommittee (UFAS). To qualify a Transfer Path under this Guideline, a Transfer Path Operator must specify the applicable direction and provide documentation to satisfy the requirements for qualification set forth below:

a. The Transfer Path must be a transmission element or elements across which:

a Schedule (in MW) can be established;

actual flow (MW) is metered; and

an SOL has been established and published in WECC Planning Coordination Committee or WECC Operating Committee (OC) documents.

b. A historical record exists to document that, concurrently:

For at least 100 hours in the most recent 36 months, actual flow across a Transfer Path (MW) has exceeded 97 percent of the SOL in megawatts;

17

and

Energy Schedules were curtailed because of the USF.

c. The Transfer Path Operator shall request to be included on the UFAS agenda at a future scheduled meeting to make a presentation on qualifying the Transfer Path. The presentation to the UFAS will explain how the SOL was determined and how the historical actual flow and/or Schedule curtailment records were obtained.

d. An incremental power flow for the current operating season confirming that a feasible combination of Schedules between Sender and Receiver can create USF across the proposed Transfer Path. The power flow must be applicable to the proposed Transfer Path and the path’s USF sum must be equal to or greater than 5 percent of the SOL.

e. The Transfer Path Operator shall conduct the studies and provide supporting documentation as needed to satisfy the requirements for qualification defined in Section 1 of this Guideline.

f. The Transfer Path Operator shall provide the following documentation to the UFAS:

Description of series-connected Controllable Devices in the path that can be used to reduce USF, as set forth in Section 9 . a .ii. SECOND S T E P .

Description of any unique operating procedures or agreements that might affect the WECC USF plan if the path is qualified.

Description of USF comparison to other paths available to the Transfer Path Operator as per the Guideline, S e cti o n 8 . b .

g. The Transfer Path Operator, Qualified Transfer Path Operators with representation on the UFAS, and WECC staff shall provide a description of any known simultaneous operating conditions that may limit Controllable Device coordination to the UFAS.

h. WECC staff shall develop a sample analysis showing the impact of the proposed path on the compensation table.

i. After the UFAS has reviewed the documentation and presentation, a recommendation will be forwarded to the WECC OC. The Transfer Path Operator may be requested to make a presentation to the WECC OC.

j. Upon approval by the WECC OC, the Transfer Path will be added to the list of Qualified Transfer Paths on the effective date to be determined by the WECC OC. If this occurs during a Plan Year (January 1 – December 31), the compensation to the qualified Controllable Device owners will be prorated accordingly.

k. A Transfer Path is normally qualified for USF reduction in only one direction. The Transfer Path may be qualified for USF reduction in both directions, but supporting data must be provided for each direction.

18

2. Transfer Path RequalificationIf there is a change in the SOL for an existing Qualified Transfer Path or the addition of a Controllable Device in the Qualified Transfer Path, the Qualified Transfer Path Operator shall make a presentation to the UFAS so that the UFAS can determine whether requalification of the Qualified Transfer Path is necessary.

3. Qualified Transfer Path DeletionIf the following conditions are maintained for 36 consecutive months, the UFAS shall make a determination as to whether the WECC system configuration has been altered sufficiently so that USF Schedule reductions on the Qualified Transfer Path would no longer be expected:

There have been no Schedule reductions; and

The actual flow across a Qualified Transfer Path has not exceeded 97 percent of the SOL.

An affirmative finding of the UFAS and approval by the WECC OC will be required to delete a Qualified Transfer Path.

4. Actions Required Following Addition of a New Qualified Transfer Patha. A new Transfer Path will be added to WECC’s list of Qualified Transfer Paths,

attached as Exhibit A, on approval of the WECC OC.

b. Owners of facilities that comprise the new Qualified Transfer Path will designate a Qualified Transfer Path Operator.

c. Incremental power flow matrices will at a minimum be prepared for the current summer and winter seasons. These matrices will be:

based on appropriately-modified operating base cases for each Qualified Transfer Path;

provided to the WECC OC members;

based on incremental power flow studies; and

used to determine the magnitude of each Contributing Schedule's2

contribution to the USF.

d. The effectiveness factors and compensation for the Qualified Controllable Devices will be recalculated.

2 A "Contributing Schedule" is the net Schedule between individual Senders and Receivers that contributes USF across a Qualified Transfer Path in the same direction as the actual flow across that Qualified Transfer Path.

19

5. Controllable Device Qualificationa. Any applicable entity wishing to qualify a Controllable Device to receive

compensation for coordinated operation under the Policy shall present a plan for coordinated operation to the UFAS. This plan should include the following elements:

The procedures are developed to ensure that adequate communication and coordination occurs between the operator of the applicable entity's proposed Controllable Device and the operators, including the RC, of other Qualified Controllable Devices.

The sponsoring applicable entity and/or WECC staff shall conduct studies to demonstrate the proposed Controllable Device USF effectiveness and impacts on the WECC system. They will present these results to the UFAS and demonstrate that the applicable entity’s Controllable Device meets the criteria specified below:

The demonstration will use the methodology in the USF Mitigation Criteria for Controllable Devices Compensation.

The demonstration will show that by adding the applicable entity’s controllable Device to the overall coordinated Controllable Device control strategy, the proposed Controllable Device will reduce USF:

1) by an average over all of the then-Qualified Transfer Paths of at least 1 percent of the respective Qualified Transfer Path limits, (which corresponds to average percent control of 6.7 percent in Table 1 of the Controllable Devices Compensation Guideline), and

2) for more than half of the Qualified Transfer Paths, by at least 1 percent of each of the respective Qualified Transfer Path limits.

b. The sponsoring applicable entity shall provide the following documentation to the UFAS:

Brief written description including simplified one-line diagram(s) for project/substation.

Commercial operation date for the new device and a proposed date of availability for USF mitigation.

Description of typical operating modes.

Description of any unique operating agreements or issues affecting the WECC USF plan.

Description of device capital cost, percent of ownership breakdown (if there are multiple owners), and annual fixed charge rate(s).

Description of existing or planned communication facilities that will be used to ensure operation of the applicable entity’s Controllable Device in a coordinated fashion with other WECC Qualified Controllable Devices.

c. WECC staff shall develop sample analyses showing impacts of the proposed

20

Controllable Device on the USF compensation table.

d. After the UFAS has reviewed the documentation and presentation, it will make a recommendation to the WECC OC. Upon approval by the WECC OC, the Controllable Device will be added to the list of Qualified Controllable Devices. If this occurs during a Plan Year, the compensation for the new device will be prorated accordingly.

6. Qualified Controllable Device Deletiona. A Qualified Controllable Device shall be considered by the UFAS for deletion

from the list of Qualified Controllable Devices if the Qualified Controllable Device is no longer capable of reducing USF on the current Qualified Transfer Paths, by the criteria specified in Section 5.a above.

b. Approval of the WECC OC will be required to delete a Qualified Controllable Device. The Controllable Device will no longer be required to participate in coordinated operation. However, its continued participation is encouraged.

7. General Termsa. All applicable entities shall cooperate with the Qualified Transfer Path

Operator by reducing Schedules as requested to achieve the appropriate reduction in USF. If a BA desires to provide the relief through alternative means, that relief must be equal to or greater than the relief that would be provided through curtailment of the Schedules.

b. Applicable entities having Controllable Devices in series or parallel — such as series capacitors, phase shifting transformers, and DC transmission lines — shall cooperate with the Qualified Transfer Path Operator to the extent practical by using these elements to reduce USF across the constrained Qualified Transfer Path. Operation of such Controllable Devices shall be required where the Controllable Devices are being operated in a coordinated manner pursuant to the Policy.

Operation of Controllable Devices that have not been Qualified shall be at the discretion of and consistent with the normal practice of the applicable entity. Schedule reductions shall not be required by the applicable entity to the extent that controllable elements (which are not operated in a coordinated manner) are incrementally operated during the USF event to achieve an equivalent reduction in USF across the constrained Qualified Transfer Path. The applicable entity shall be able to document and demonstrate that an equivalent USF reduction has been achieved through the use of the controllable element(s).

It is intended that the Qualified Controllable Devices shall not be requested to operate in a coordinated manner in response to requests under this Guideline in excess of 4,000 hours per year. The UFAS shall monitor the coordinated operation of the Qualified Controllable Devices and make recommendations to the WECC OC for adjustments as needed to meet this objective.

21

c. To the extent that a Controllable Device is capable of operating to achieve Actual Flows through the device equal to Scheduled Flows, such Schedules shall be deemed to be 100 percent effective through the device and thus shall be exempt from the Schedule reductions required under this Guideline.

For example, a Phase Shifting Transformer (PST) operator has the option to use the operation of that device to satisfy some or all of its path flow relief obligation under the Schedule Curtailment phase of the Policy. The curtailment phase of the Guideline specifies that applicable entities shall make adjustments to contributing import Schedules — in accordance with a set of matrices — to provide a reduction in USF to the constrained path.

In certain circumstances, it may be desirable for an applicable entity to provide some or all of the prescribed flow reduction through the operation of Controllable Devices (e.g., PSTs) such that the combined action would provide equivalent flow relief to the path. The following explains how that is accomplished:

An applicable entity that owns/operates a Controllable Device shall not be granted exemption from its obligation to provide the additional relief prescribed in the Schedule Curtailment phase of the Guideline.

Under the Guideline, Qualified Controllable Devices are used to the maximum extent possible for mitigating the USF on a constrained path.

If the collective relief provided by these Qualified Controllable Devices is insufficient, requiring advancement to the Schedule curtailment phase of the Guideline, then all applicable entities (including the Qualified PST owners) are required to provide additional relief, typically in the form of Schedule curtailments.

While the Qualified PSTs are providing relief to the constrained path, compensation is already allocated to the Qualified PST owners through the financial provisions of the Policy.

In the situation where a PST is being operated so that Actual Flow equals Scheduled Flow (holding Schedule), there will be zero USF on the path that is directly controlled by the PST. However, there will generally be USF created at other points in the network due to the various parallel paths that exist between the sending area and the controlled transmission element.

The exception to this will be the case where the sending and receiving areas are located immediately adjacent to one another. In this instance, if the flows are being held equal to Schedule, then no other USF is being generated by that Schedule. As such, the following rule applies:

Interchange Schedules between immediately adjacent Balancing Authorities through a phase shifting transformer or other Controllable Device shall be exempt from curtailments under the Unscheduled Flow Mitigation Policy when the actual flow is controlled equal to the Scheduled amount.

The above language applies to both Qualified and non-Qualified PSTs. Therefore, while an owner/operator of a Controllable Device is not exempt

22

from the Schedule curtailment phase of the Guideline, those Import Schedules from adjacent BAs that are being controlled by the PST to yield zero USF a re e x emp t from consideration for curtailment.

d. The WECC staff will provide the WECC OC with a summary of all Qualified Controllable Devices that are being operated in a coordinated manner pursuant to the Policy, whenever a new Controllable Device is qualified.

8. General Action Rulesa. This Guideline applies to all applicable entities. The UFAS shall develop

and/or modify this Guideline to enable the Qualified Transfer Path Operators to implement actions that will achieve the desired control/curtailment results in the scheduling hour immediately following the request. The Guideline shall ensure that neither over-control nor over-curtailment shall be expected.

b. The Qualified Transfer Path Operator will verify the magnitude of USF across the Qualified Transfer Path by checking adjacent metered and scheduled values prior to requesting any other applicable entities take actions under this Guideline. Actual Flow must reach a level greater than or equal to 95 percent of the Path’s SOL, with Actual Flows greater than the Scheduled Flows by an amount of 2 percent of the Qualified Transfer Path SOL or 25 MW, whichever is greater.

c. Qualified Transfer Path Operators should consider the USF impact of their BA ACE, if applicable, contributing to USF prior to requesting USF reduction. RCs should consider the USF impact of neighboring BA ACE prior to taking action.

d. The UFAS shall review the participation of Qualified Controllable Devices regarding each device’s participation in USF events.

e. The major loop USF will be monitored in a minimum of two locations during hours in which any coordinated operation of the Qualified Controllable Devices or curtailments are occurring under this Guideline.

f. The Qualified Transfer Path Operator will continue to take actions necessary to reduce Actual Flow to a level at or below the SOL of the Qualified Transfer Path.

g. Upon request from the Qualified Transfer Path Operator for USF relief, applicable Schedule reductions will occur or equivalent alternative actions will be implemented to provide required relief in accordance with the following actions:

Upon approval of Qualified Transfer Path Operator request by the RC, the curtailment calculation tool will initiate a prescription for Schedule reductions that will result in the megawatt relief requested by Qualified Transfer Path Operator. BAs will receive curtailment prescriptions for Schedules sinking within their boundaries, and upon receipt of the curtailment prescription, shall take action to approve prescribed Schedule reductions; or

BAs may arrange to provide relief called for by this Guideline in a manner

23

other than prescribed, provided that the arrangements are as effective as the identified Schedule reduction in reducing USF across the Qualified Transfer Path.

h. In the event of a transmission system emergency on any applicable entities' system, such applicable entity may request that the RC initiate coordinated operation of the Qualified Controllable Devices if such operation is reasonably expected to assist in relieving the emergency condition.

i. Each hour is deemed to be a separate event for USF reduction purposes. The Qualified Transfer Path Operator shall reissue USF events each hour that relief is called for.

j. During a USF event, all applicable entities cooperate with the Qualified Transfer Path Operator to reduce Schedules as requested to achieve a reduction in USF on the Qualified Transfer Path. While this Guideline is in progress, creation of new transactions or increases in existing transactions may have an adverse impact on USF on the Qualified Transfer Path and reduce the effectiveness of any designated Schedule curtailments. It is recognized that complete prohibition of scheduling during a USF event, regardless of the minor impact on the Qualified Transfer Path, is not desired.

The following identifies how changes to Schedules will be treated during a USF

event:

Identification of Pre-Event Schedules

At the time a USF Curtailment Action is initiated, Schedules are established by the existence of confirmed tags. Schedule curtailments apply to transactions in the "Confirmed" state at the time of the USF event is requested by the Qualified Transfer Path Operator.

Restricted Transactions

A Restricted Transaction is either:

a new transaction with a Transfer Distribution Factor (TDF) on the Qualified Transfer Path equal to or greater than 10 percent in the qualified direction; or

the increase in a Pre-Event Schedule, with a TDF on the Qualified Transfer Path equal to or greater than 10 percent in the qualified direction.

Restricted transactions approved after a USF Curtailment Action is issued will become Confirmed Interchange based upon tag approvals, and then immediately curtailed to zero or Pre-Event Scheduled amounts for the effective time of the USF event. For all subsequent hours shown on the tag, the modified profile will be included in the list of Pre-Event Schedules. Future modifications to the tag will be treated as a new tag and the time it became a Confirmed Transaction will be used to determine whether it is a Pre-Event Schedule or Restricted Transaction.

24

9. Action StepsThe Qualified Transfer Path Operator shall advise the applicable entities, via the WECC communications system and the curtailment calculator tool, of a current or an impending curtailment period and may request assistance in mitigating the curtailment.

When assistance is requested in mitigating a curtailment, the following actions shall become effective at the start of the next scheduling hour following the request.

a. Acti on s Tak e n

First Step: The Qualified Transfer Path Operator shall advise the RC of the situation and intended action.

Second Step: To the extent a Qualified Transfer Path Operator has the right to make use of Controllable Devices — such as series capacitors, phase shifting transformers, and DC transmission lines — these elements will be used to the maximum extent practical in reducing the USF across the constrained Qualified Transfer Path to a level at or below the SOL. Operations of such Controllable Devices shall comply with the NERC and WECC standards and criteria.

Third Step: Before invoking the third step (or higher) of the Guideline, a Qualified Transfer Path Operator must ensure the actual flow on the Qualified Path must reach a level greater than or equal to 95 percent of the Path’s SOL, with Actual Flows greater than the Scheduled Flows by an amount of 2 percent of the Qualified Transfer Path SOL or 25 MW, whichever is greater.

Once the flow has been verified by the Qualified Transfer Path Operator, the operator will request that the RC initiate Coordinated Operation of Qualified Controllable Devices and issue a notification of moving to the third step via the WECC communications system and the curtailment calculator tool. The RC will notify operators of Qualified Controllable Devices.

At the request of the RC and in coordination with the Qualified Transfer Path Operator, the Qualified Controllable Device operators shall operate their Controllable Devices in a coordinated manner so as to minimize the USF on the constrained Qualified Transfer Path, consistent with NERC and WECC standards and criteria. This may happen at any time in the event.

Fourth Step: If the previous steps did not address the Qualified Transfer Path loading issue, the Qualified Transfer Path Operator — in coordination with the RC — shall determine the amount of relief needed based on Actual Flows on the Qualified Transfer Path. The Qualified Transfer Path Operator will then request a level of megawatt relief needed through the curtailment calculator tool. Based on the level of relief requested, the curtailment calculator tool will prescribe a relief requirement solution of Schedule curtailments. The process used to determine the curtailment

25

order is detailed in Attachment A. The approval of USF reduction shall be issued prior to 30 minutes before the start of the hour for which it is to be in effect.

b. Ra p id A d v an c e m en t o f t h e St e p s

The effective management of USF in the Western Interconnection can, at times, demand quick response and activation of this Guideline.

The following general guidance is provided for a Qualified Transfer Path Operator to use in making decisions regarding which steps of the Guideline should be used in the initial phases of USF reduction. Experience and identification of patterns with respect to Qualified Transfer Path overloading will affect the timing of the initiation of the Guideline by the Qualified Transfer Path Operator. The intent of this section is to enable the Qualified Transfer Path Operators to more rapidly implement actions under the Guideline that will achieve the desired USF relief.

G u id a n ce

Based on previous and recent experience with Qualified Transfer Path USF, the Qualified Transfer Path Operator may initiate the Guideline at any step, up to and including the Fourth Step. The Qualified Transfer Path Operator must be able to demonstrate through recent experience or other equivalent judgment, that the overload of the Qualified Transfer Path is severe enough to warrant the actions of the particular step being requested.

If Rapid Advancement is requested by the Qualified Transfer Path Operator, the coordinated operation of the Qualified Controllable Devices shall occur as soon as possible, but prior to the ramp for the next hour.

10. Competing PathsWith the number and location of Qualified Transfer Paths within WECC, and the interrelation of power flows on these various paths, at times coordinated operation of Qualified Control Devices and Schedule curtailments may be necessary for more than one Qualified Transfer Path at a time. The following guidance provides direction for coordinated operation and Schedule curtailment methodology.

St e p 3 G u id a n ce

When encountering competing requests for coordinated operation, best efforts will be made by the RC to coordinate the settings of the available Qualified Controllable Devices to maximize the total USF relief to both competing Qualified Transfer Paths. Actions will not be directed by the RC without first considering the effects of those actions on the USF on each of the competing Qualified Transfer Paths, as well as the effects on other transmission facilities within the Interconnection.

Congestion of multiple Qualified Transfer Paths can occur either as a result of the operation of coordinated Qualified Controllable Devices for one path (which causes another path to exceed its flow limits), or may simply result

26

from normal system operation (two paths encounter congestion simultaneously as load and generation patterns change).

When two Qualified Transfer Paths become congested, the operators of those paths are expected to coordinate their needs for relief with the RC and with each other. The RC, in monitoring the Qualified Transfer Paths, will generally be aware of path flow interactions and the interactions between the Qualified Controllable Devices that are used to relieve congestion.

The RC should coordinate at a pace that is slow enough and, to a degree that is slight enough, to minimize congestion on paths that are parallel to a given Qualified Transfer Path. The RC should direct operation of the Qualified Controllable Devices so that the highest amount of relief that is practical may be achieved. Certain instances of path interaction will result in less than maximum relief for both of the constrained paths.

Step 4 Guidance

In a situation where two Qualified Transfer Paths are competing for USF relief, certain curtailment prescriptions for Schedules, if implemented, may cause USF relief for one path but result in an increase in USF on the other. As such, Schedule adjustments should be implemented in a way that will generally result in reduced levels of USF for both paths.

Due to the complex interaction of Schedules and flows on the competing paths, the curtailment calculator tool logic has been developed to prescribe the curtailment actions to be taken under competing path events. This process is identical in operation to how the individual transfer path process is used. However, it incorporates logical tests to ensure that curtailment actions will only be advised for those instances where the curtailment will be significantly beneficial to one (or both) path(s) without being significantly detrimental to the other. The curtailment calculator tool is populated with the “adjusted contribution percentages” according to the logic described below:

For a given Schedule:

1) If the Schedule has a positive contribution (increasing USF) on both of the competing paths, this Schedule is subject to curtailment by an amount that corresponds to the larger of the two contribution percentages.

2) If the Schedule has a negative contribution (decreasing USF) on both of the competing paths, this Schedule should not be curtailed.

3) If the Schedule has a positive contribution to the first path, but a negative contribution to the second path, the Schedule is subject to curtailment only if the positive contribution percentage divided by the rating of the first path is greater than two times the negative contribution percentage divided by the rating of the second path. If this is not true, the Schedule should not be curtailed.

The table below includes specific examples of typical Schedules, and the corresponding “adjusted contribution” percentages.

Path 36/66 Competing Path Event Example:

27

Schedule #

P-6

6 (4

175

MW

) C

ontri

butio

n %

P-3

6 (1

424

MW

) C

ontri

butio

n %

Adj

uste

dC

ontr

ibut

ion

%

Comment

1 40 15 40 Both are (+); curtail according to 40%contribution.

2 -18 -26 -26 Both are (-); no curtailment.

3 -20 18 18 18%/1424 is >2X 20%/4175; curtail accordingto 18% contribution.

4 -40 15 Xx 15%/1424 is <2X 40%/4175; no curtailment.

5 35 -20 Xx 35%/4175 is <2X 20%/1424; no curtailment.

6 40 -5 40 40%/4175 is >2X 5%/1424; curtail according to 40% contribution.

The Competing Path Methodology incorporates the above logic and displays simply the “adjusted contribution” percentages. For example, if both Path 36 and Path 66 were calling for Schedule curtailments, a system operator would consult the information for “Path 36/66 Competing Path Event” and determine Schedule adjustments based on the contribution percentages indicated. This logic is included in the curtailment calculator tool.

While it is possible that any two Qualified Transfer Paths may become simultaneously constrained to the point where the curtailment of contributing Schedules is necessary, experience with the patterns of USF has shown that the most likely pair is Path 36 and Path 66.

A dd iti o na l G u i dan c e f o r Sc he d u le Cur t a i l m e n t s (t w o Qua l i f i e d P a t h s

c on strai n ed )

In instances where two paths are requesting contributing Schedule curtailment under the Guideline, the RC will send a message via WECC communication system alerting the applicable entities of this fact. The RC message will specifically state that the situation is a “competing path” event, which requires a unique response from the applicable entities.

11. Further ActionThe Qualified Transfer Path Operator will continue to take actions necessary to reduce Actual Flow to a level at or below the SOL.

28

12. TermThis Guideline will remain in effect for the duration of the Policy.

29

WECC UNSCHEDULED FLOW GUIDELINEAttachment A: Summary of Curtailment Actions

Detailed ProcessThe process to determine the curtailment priority essentially divides Confirmed e-Tags into 16 groups, based upon the transmission priority and the contract path on which a transaction is scheduled. If a transaction is scheduled on the qualified path needing relief, it is considered an on-path Schedule. If a transaction is scheduled on a different path but still impacts the qualified path due to a TDF greater than the minimum acceptable level, it is considered an off-path Schedule.

For on-path Schedules, the transmission priority used to determine the tag’s curtailment priority will be the Qualified Transfer Path segment of transmission on the e-Tag. For off-path Schedules, the lowest transmission priority of any segment on the tag will be used to determine the curtailment priority of the e-Tag. The minimum acceptable TDF level is +10 percent; transactions with a lesser TDF will be excluded from the relief requirement calculation.

When an event is called that requires curtailments, the Qualified Transfer Path Operator will issue a request for a megawatt level of relief. This requested relief will be used to determine the Schedules that must be curtailed by taking each individual tag’s impact on the path (as determined by the TDFs), starting with the first group and proceeding through the groups until the level of relief is obtained. This will identify the groups that are assigned a relief requirement.

All Schedules in a lower priority grouping will be curtailed to a zero megawatt energy profile for the event. The Schedules in the highest priority group that has a relief requirement will have a relief requirement assigned based upon a “TDF Squared” process that will assign the relief requirement that requires the higher TDF Schedules to be assigned a proportionally greater relief requirement, resulting in a lower total curtailment for all Schedules in that Group. However, all Schedules with a relief requirement in that group will be curtailed to some extent.

The following is a list of the groups in the order of relief requirement (first relief requirement to last relief requirement):

Group 1 – Priority 0 (Transmission Product - code 0-NX) off-path

Group 2 – Priority 0 on-path

Group 3 – Priority 1 (Transmission Product - code 1-NS) off-path


Group 5 – Priority 2 (Transmission Product - code 2-NH) off-path


Group 7 – Priority 3 (Transmission Product - code 3-ND) off-path


Group 9 – Priority 4 (Transmission Product - code 4-NW) off-path


30

Group 11 – Priority 5 (Transmission Product - code 5-NM) off-path


Group 13 – Priority 6 (Transmission Product - codes 6-NN and 6-CF) off-path


Group 15 – Priority 7 (Transmission Product - codes 7-F and 7-FN) off-path


31

Exhibit A:List Of Qualified Transfer Paths as of January 26, 2012

PathC o de

Path O p r

Q u a l i f i e d T r an s f e r P at h QualifyingD i r e c t i o n *

Path TransferC a p a b il i t y - MW **

66 CISO California-Oregon IntertieMalin-Round Mt. 500-kV lines 1&2Captain Jack-Olinda 500-kV line

CCW (north-south) 4800

22 APS Four Corners-Central ArizonaFour Corners-Moenkopi 500-kV lineFour Corners-Cholla 345-kV lines 1&2

CW (east-west) 2325

23 APS Four Corners 345/500-kV Transformer with Four Corners Unit 5 out of service or at greatly reduced output

CW (low-high) 840

30 WACM TOT 1A transmission path Hayden-Artesia 138-kV Meeker-Rangely 138-kV Bears Ears-Bonanza 345-kV

CW (east-west) 650

31 WACM TOT 2A transmission path Hesperus-Glade Tap 115-kV line Lost Canyon-Shiprock 230-kV line Waterflow-San Juan 345-kV line

CW (north-south) 690

36 WACM TOT 3 transmission path Laramie River-Ault 345-kV line Laramie River-Story 345-kV line Archer-Ault 230-kV line

Sidney- Spring Canyon 230-kV line Sidney-Sterling 115-kV line Cheyenne-Owl Creek 115-kV line Cheyenne-Ault 230-kV line

CW (north-south) 1680

* Direction in which the Path is qualified to request USF relief:CCW = Counterclockwise directionCW = Clockwise direction

** These values are nominal. The actual value may change with system conditions. Accommodation levels are based on the path transfer capability available at the time.

Approved By:

Approving Committee, Entity, or Person Date

Operating Committee March 9, 2012

WECC Board March 15, 2012

32

Western Electricity Coordinating Council GuidelineUnscheduled Flow Mitigation:

Establishing Annual Membership Dues GuidelineDate:

Document Title: Unscheduled Flow Mitigation for EstablishingAnnual Membership Dues

Category Guideline

Document date July 30, 2001Adopted/approved byDate adopted/approvedCustodian (entityresponsible for maintenance and upkeep)Stored/filed Physical location:

Web URL:Previous name/number (if any)Status ( ) in effect

( ) usable, minor formatting/editing required( ) modification needed( ) superseded by( ) other( ) obsolete/archived)

33

Western Electricity Coordinating Council GuidelineUnscheduled Flow Mitigation:

Establishing Annual Membership Dues GuidelineDate:

IntroductionThis paper, along with the attached Tables 1 through 7 explains and documents the methodology used to allocate the costs associated with the Qualified Controllable Devices among the WECC membership pursuant to the WECC Unscheduled Flow Mitigation Policy (Policy).

GuidelineThe WECC Annual Membership Dues Guideline addresses the prescribed method of determining the dues to be paid by the applicable entities (entities) for their use in controlling unscheduled flow as outlined in the Unscheduled Flow (USF) Reduction Guideline. The entities that the Dues Guideline applies to are listed below:

Balancing Authority

Load-Serving Entity




Guideline DetailsThe basic objectives of the cost allocation methodology are to spread the costs associated with the operation of the Qualified Controllable Devices among the entities in a manner that will:

Involve participation of all entities.

Assure that smaller entities will not be excessively burdened, and provide that the cost will be allocated fairly among all entities in a manner that reflects each entities’ size and relative use of the WECC interconnected system.

Tie Qualified Controllable Device owners’ payments to actual use of the devices in controlling USF.

Provide the opportunity for Qualified Controllable Device owners to recover the full compensation allowed under the original Policy if the devices are used extensively.

Retain the minimum compensation of $50,000 per year for each device installation.

Provide substantially reduced annual cost allocations for entities’ systems when devices are not used or are used very little, resulting in few benefits being realized. Reduce annual payments for everyone to no more than 90 percent of their 1995 allocation if devices are used for no more than 100 hours.

34

Limit each entity’s annual cost allocation to a maximum of 115 percent of its 1995 allocation.

Ensure that any increases an entity would see above 1995 dues allocations are limited and well defined.

Eliminate the possibility of a significant increase to an entity’s allocation as the result of shifting to a larger-sized group due to a small change in system data or another entity terminating its membership in WECC.

Adopt a method for calculating a cap for new entities.

Ensure that device owners receive compensation for all hours for which the devices are actually used and ultimately receive approximately the same total compensation established under the Policy if the devices are used for 4,000 hours.

35

Western Electricity Coordinating Council GuidelineUNSCHEDULED FLOW MITIGATION

FOR ESTABLISHING ANNUAL MEMBERSHIP DUESGene ral

The Unscheduled Flow Reduction Guideline reflects significant interdependent compromises among the entities on issues such as:

Schedule curtailment obligations and procedures.

Subordination of Qualified Controllable Device owners’ control priorities in favor of coordinated operation.

Increased obligations and liabilities for Qualified Controllable Device owners.

Appropriate level of reimbursement of Qualified Controllable Device owners’

fixed and variable costs by the entities.

The cost allocation methodology reflects interdependent compromises among the entities regarding the appropriate entity’s system information for use in determining:

Each entity's relative size and use of the interconnected system.

An appropriate distinction between large and small entities.

The appropriate parameters for allocating the costs among the entities.

O b jec t i v e s

Changes Required in 2001

The critical energy supply situation encountered by WECC entities in 2001 resulted in a large increase in the number of hours requiring USF mitigation on several Qualified Paths. Consequently, more than half of the 2,000 available hours of coordinated Qualified Controllable Device operation was used by the end of April 2001.

The UFAS considered other alternatives, but determined the most effective approach to making the Policy viable and effective was to increase the available hours of coordinated Qualified Controllable Device operation. The UFAS recommended, to the Qualified Controllable Device owners, increasing the coordinated Qualified Controllable Device operation availability to 4,000 hours, with compensation to be at the same hourly rate as is used at or below 2,000 hours. On May 18, 2001, the device owners approved this recommendation.

The recommendation was then brought to the OC, along with an estimate of the increased dues required to compensate the device owners. The OC approved the recommendation by e-mail ballot on June 4, 2001.

En tity Syste m I nfo rma tion

In order to provide a consistent data base from which to establish cost allocators based on each entity's relative size and use of the interconnected system, all entities were initially requested to supply annual energy information for the years 1991, 1992, and1993 in the following six categories:

36

Generation (G)

Imports (I)

Remote Generation Imports (RGI)

Exports (E)

Remote Generation Exports (RGE)

Load (L)

The information from these categories is updated annually to maintain a three-year rolling average of each category. The three-year averages are used, as described below, to establish a relative ranking of each entity's size and use of the interconnected system as well as to calculate the cost allocation to each entity. Use of the three-year rolling averages is intended to minimize the volatility of an entity’s assessments due to variables such as weather and rainfall patterns throughout the WECC geographic area, while still capturing an entity's changing use of the interconnected system. Each entity’s annual energy (GWh) information for the years 1991, 1992, and 1993 and the three-year averages are set forth in Tables 2 through 5. For t h o se e n tities that have not submitted the requested information as set forth above, the information will be estimated and such estimate will be used to determine those entities’ cost allocatio n .

In 1998, the OC approved a recommendation by the Unscheduled Flow Administrative Subcommittee to modify the definition of Imports and Exports that had previously been used. The Board of Directors subsequently approved this recommendation. Under the modified definition, transactions among marketers at a single bus or scheduling node do not have to be included as Imports or Exports. Only transactions that actually use the transmission system must be accounted for as Imports or Exports.

Example: Marketer A purchases energy from Generator A at Scheduling Node (bus) X.

The transmission system is used to transmit the energy from the generator to the scheduling node. At the scheduling node, Marketer A sells the energy to Marketer B who sells it to Marketer C. These “paper transactions” do not use the transmission system. Marketer C then sells the energy to Utility Y, who imports it to serve load. This last transaction again uses the transmission system to transmit the energy to the load.

In the above scenario, Generator A would account for an export, Marketer A would account for an import, Marketer C books an export and Utility Y incurs an import. Marketer B would incur neither an import nor an export.

This modified definition of Imports and Exports will result in a reduced USF dues allocation to entities that do a significant amount of business simply buying and selling energy at a scheduling node. It does, however, require a significant change in most entities’ accounting practices to ensure that “paper transactions” are accurately recorded apart from transactions that actually use the transmission system. The change was made effective beginning January 1, 1999.

Rela tive Ran king of W ECC En titie s (La rge vs . Sma ll)

37

While no single indicator of size and use of the interconnected system was acceptable to all entities, it was agreed that appropriate indicators of such size and use should include each entity’s:

Load (L)

Imports plus Remote Generation Imports (I + RGI)

Exports (E)

Generation minus Remote Generation Exports (G - RGE)

To achieve consensus, it was decided to establish each entity's final relative ranking as the average of the entity’s relative ranking in each of the above four categories, using three-year rolling averages of the information submitted by each entity. The results of the ranking process in each of the four categories and each entity's final relative ranking are set forth in Tables 6 and 7.

Examination of the information provided by the entities in each of the four ranking categories described above provides no obvious logical transition points to differentiate between “large,” “medium,” and “small” entities. Therefore, it was decided that the transition between large, medium, and small entities would be derived by applying the following subjective judgments:

entity assessments should not exceed 400 percent of current annual WECC dues

large entities should pay the largest share of the cost

assessments should not create a WECC membership disincentive for small entities

small entity assessments should be in the range of $1000-$4000

After applying the above judgments to numerous experimental allocations, it was decided to establish the “large,” “medium,” and “small” groupings at final relative rankings of 1-13, 14-34, and 35 or higher, respectively.

In 1996, the following changes to the ranking process were made:

Allocate costs pro rata to entity systems based upon each entity’s size in all the energy categories listed in the section above called Entity System information. However, place an upper limit on the allocated costs to entities at 90–115 percent (depending upon the device utilization level) of their 1995 allocation.

Since capping the smaller entities results in large revenue shortfalls, apply a multiplier of 135 percent to the 13 largest entities’ interim allocation. As device usage approaches 4,000 hours, application of the multiplier to the interim allocation results in recovering revenue comparable to the revenue received under the original Policy. This multiplier replaces the 60/40 split (60 percent of total cost to large entities, 40 percent to all entities) used in the original Policy. Application of the 135 percent multiplier results in a three percent increase in payments (compared to the original Policy) to device owners at 2,000 hours of actual use. Because of the 135 percent multiplier, the total dues allocated may exceed the value calculated in the PST cost spreadsheet. On the other hand, due to the cap on dues, the total may be less.”

38

Cost A llo ca tio n Amon g En titie s

The following steps are followed in the new allocation methodology:

1. Determine total device compensation as the $500,000 baseline minimum payment, added to the product of the hourly rate multiplied by the actual hours of coordinated device operation.

2. Determine each entity’s size by ranking according to the procedure originally established by the Policy; i.e., rank according to size in each of several energy categories, average the resulting rankings, and use the average rank to determine a final rank. Entities ranked one to 13 constitute the “large” entities, those ranked 14 to 34 are in the “medium” classification, and those ranked greater than 34 are considered “small.” (Note: under the new methodology, dues allocations are “capped.” This eliminates the possibility of an entity’s dues being determined by its position in the alphabet rather than by its actual size when its average rank is the same as that of another entity.)

3. Determine each entity’s average percentage of all energy categories in WECC, using three years of actual system data and various energy categories, as outlined in the Policy. The energy categories are: Imports plus Remote Generation Imports plus Exports, Load plus Generation less Remote Generation Exports, and Load only. The percentages in these three categories are averaged to obtain a final percentage for each entity.

4. Allocate the total compensation for the appropriate usage scenario to all entities, pro rata, according to their final percentage described in Item 3. above. The total compensation to be provided to the Qualified Controllable Device owners is multiplied by each entity’s final average percentage to calculate its “initial” allocation.

5. Calculate an entity’s “interim” allocation by implementing a ceiling. For large entities, set the ceiling at 115 percent of the 1995 allocation. For medium and small entities, cap the allocation for the use of Qualified Controllable Devices as follows:

Zero to 100 hours – 90 percent of 1995 final allocations.

101 to 499 hours – 105 percent of 1995 final allocations.

500 to 999 hours – 110 percent of 1995 final allocations.

1000 hours or more – 115 percent of 1995 final allocations.

6. The above-described “caps” create a large shortfall in revenue; i.e., the allocation calculated in Item 5. above provides considerably less than the compensation allowed by the initial allocation calculated in Item 4. This is because the straight percentage allocation results in greatly reducing the initial allocation to the large entities while increasing the initial allocation to small and medium entities. (The original Policy used a methodology that allocated 60 percent of the total cost plus a share of the remaining 40 percent to the largest 13 entities.)

This proposal eliminates the shortfall by multiplying the largest 13 entities’ interim allocation by a factor (135 percent) which increases their allocation (but still limits the final allocation to no greater than 1995 final allocation plus 15 percent, in the

39

scenario with the highest hours of use). Using this multiplier allows the device owners to recover slightly more (e.g., a total of $2,240,443) than the 1995 amount if devices are used extensively. The full-year allocation for 1995 was $2,178,596.

This approach partially compensates the device owners for the reduced revenue (as compared to the original Policy) during years of little use.

This proposal achieves all the objectives listed. Most entities will not pay more than their 1995 allocation unless Qualified Controllable Devices are used for more than 100 hours per year, and even then the increase is limited to a maximum of 15 percent. It reduces annual payments for all entities to no more than 90 percent of their 1995 allocation if devices are used less than 100 hours. Qualified Controllable Device owners receive a minimum payment, even if their devices are not used, and their compensation increases as device use increases. Approaching 2,000 hours of actual use, device owners receive approximately the amount of compensation established by the original Policy.

Although it may appear that the largest 13 entities derive the greatest benefit from this change (in terms of cost reduction), they still contribute 76 percent of the total when devices are used very little, and nearly 90 percent of the total when the devices are used extensively.

Ch an g e s R e q u i r e d in 2 00 1 to R e c o v e r Costs a t u p t o 4 , 00 0 H ou rs o f C oo rdin a t e d Qua lif ied Con trollab le Device Ope ratio n

The increased cost associated with increasing the coordinated operation hours cannot be recovered with the caps established by the 1996 modifications to this Policy. The commitment to not increase any entity’s dues to more than 115 percent of its 1995 allocation is not feasible in a situation where the costs will nearly double. Therefore, it is necessary to increase the “cap” level on dues.

The 1996 modifications included a 135 percent multiplier on the interim allocation for the 13 largest entities to make up for the shortfall in revenue resulting from the caps applied to smaller entities. It will now be necessary to increase the multiplier under various levels of coordinated Qualified Controllable Device operation. As the caps are raised for smaller entities, this multiplier for the 13 largest entities must also be increased. However, the same caps will apply to the large entities as will apply to the medium and small entities.

Through experimentation, it was determined that increasing the multiplier above 173 percent had little effect on increasing revenue with a given cap in place. Therefore, the multiplier at each increment of 100 hours was calculated as a straight-line function between 135 percent at 2,000 hours and 173 percent at 4,000 hours. Then the cap was adjusted as necessary to obtain the required revenue for the scenario. The cap increases slowly for the first several hundred hours above 2,000, then increases more rapidly as the increasing multiplier is less effective. The cap surpasses the multiplier at 3,600 hours. The following table illustrates the increasing multipliers and caps as the hours of coordinated Qualified Controllable Device operation increase in increments of 100 hours. The multiplier is incremented by 0.00019 for each hour of coordinated Qualified Controllable Device operation and the cap is adjusted as necessary to obtain the total revenue required.

40

TABLE OF MULTIPLIERS AND CAPSMultipliers (applied to 13 largest entities' interim allocation) and caps (as % of 1995 dues applied to final allocation) to be implemented at various levels of coordinated operation.

Hours M ul t i p l i er Cap

2000 1.350 115.000% Multiplier is increased as a straight-line function (.019% for each additional hour of coordinated operation) from 135% at 2000 hours to 173% at 4000 hours. Cap is adjusted as needed to obtain the required revenue. The cap is applied to all entities' final allocation.See Policy for an expanded description of setting multipliers and caps.

2100 1.369 115.671%2200 1.388 116.479%2300 1.407 119.482%2400 1.426 122.513%2500 1.445 125.643%2600 1.464 129.021%2700 1.483 132.440%2800 1.502 135.929%2900 1.521 139.444%3000 1.540 143.058%3100 1.559 146.617%3200 1.578 150.337%3300 1.597 154.127%3400 1.616 157.893%3500 1.635 161.847%3600 1.654 165.777%3700 1.673 169.725%3800 1.692 173.647%3900 1.711 177.454%4000 1.730 181.178%

The following special conditions are addressed just as they were in the original Policy:

Entities that are only radially interconnected with WECC (such as PPA and CFE) are allocated costs only on the basis of their Imports and Exports.

Entities whose allocation parameters are fully accounted for in other entities’ cost allocations (such as TANC, USBR, and USCE) do not incur a further cost allocation.

Entities that have formed new organizations, whose allocation parameters are fully accounted for in the new organization, do not incur a cost allocation. Instead, the new organization bears the cost for its component organizations. Examples are CISO (containing PG&E, SCE, and SDGE) and PPA (containing ATCO, EAL, and TAUC).

For further information on the ranking and allocation methodology, see the attached example.

Using the revised allocation methodology and entity system information described above, Tables 1 and 1a summarize the following information:

Table 1 shows the 1995 full-year cost allocations using the methodology approved by FERC in 1995 and the allocations resulting from the new methodology adopted in 1996 (but with higher multipliers and caps) and applied to various total hours (from 2,000 to 4,000) of coordinated operation.

41

The cost allocations for various scenarios of Qualified Controllable Device usage 2,000 hours, 2,500 hours, 3,000 hours, 3,500 hours, and 4,000 hours respectively.

Table 1a shows the distribution of the dues assessments based on Plan Year 18 – Calendar Year 2012

Due s A llo catio n Chan ge s Up on Lo sin g En tities

As new entities join or existing entities leave WECC, the dues allocated to remaining entities under the original Policy are affected by the change in membership base. Increasing the number of entities provides more parties among which to spread the total costs, while losing entities reduces the parties available to bear the same cost. The magnitude of the effect depends on the size of the entity joining or leaving. One of the 13 large entities leaving, for example, would result in an entity that was formerly in the “medium” ranks to move into the top 13, with a nearly 300 percent increase in annual dues. A formerly “small” entity would move into the “medium” category, with a 400 percent increase in annual dues.

Several new entities have joined WECC, but they are in the “small” category. Their contributions are capped by the Policy at $1,000, so they have little effect on the remaining entities.

A plan for handling membership changes is needed. If a large entity withdraws from WECC, the original Policy would simply reallocate expenses to remaining entities without regard to the effect such a reallocation might have. Entities in the “small” category are protected by the $1,000 ceiling, but for larger entities — or those that move to a larger category — the resulting potential volatility in dues from year to year might prove unacceptable.

The proposed new allocation methodology would spread the cost among other entities, b u t u sing a c a p so t he y w i l l no t s e e a si g n i f ica n t incre a s e o v e r t he ir 1 99 5 d u e s a l l o c a ti o n . The ceilings imposed in this case may still result in a shortfall, but a much smaller shortfall than would result from using the original Policy. An entity that moves up in rank due to loss of a larger entity will still be capped at 115 percent of its 1995 allocation.

Due s A llo catio n Chan ge s Up on A dd ing En tities

There is also a need to address the handling of new entities joining WECC. As established, the Policy places the new entity in the appropriate size category and allocates dues accordingly. In many cases, this will not be a significant issue under the original allocation scheme. If the new entity falls naturally into the “small” category, its dues will be capped at $1000. However, under the new allocation methodology there may be significant effects on some new entities as this methodology allocates costs first according to relative size (average of all energy categories). As proposed above, resulting dues are capped at or near the 1995 allocation, but a new entity will not have such an established “ceiling.” Should there be any new entities in the “medium” or “large” category, they could see a disproportionately large allocation of USF dues.

There will be a natural tendency among new entities to expect dues in the same range as those of similarly sized existing entities. If the allocation process were

42

unconstrained, this would happen naturally. However, if “ceilings” are established at some level for existing entities — e.g., based on previous allocations — the new entity may be faced with a larger allocation than an existing entity of similar size.

Therefore, a new entity’s ceiling will be established at the same level as that of an existing entity of similar size. If there is no existing entity “close” to the new entity in size, the ceiling will be determined as an average (interpolated, if appropriate) of the ceilings of the nearest entities above and below the new entity.

Proce du re f o r Hand ling S ign if ican t Growth an d Merge rs

The procedure described above for ranking new entities addresses the new entity’s size at the time of its first dues allocation under this Policy. The limitation on dues under this Policy for existing “small” entities is appropriate only as long as they remain in the small category. Entities that exhibit significant growth, either through merger with another organization or through significant increases in the amount of business they transact in the Western Interconnection, should be allocated dues commensurate with the benefits they receive from using the interconnection. The “ceiling” established above will apply only until the entity’s three-year average in all energy categories results in an average rank higher than its initial ranking. Any entity that moves into a higher size ranking due to its own growth or merger with another entity will be assigned a dues allocation comparable to other entities in the larger size category.

Add ing Ne w De vices to t he Po licy

As described in the Unscheduled Flow Controllable Devices Compensation Guideline, whenever a new Qualified Device is added to the Policy, the total minimum payment to Device Owners is increased. The minimum compensation under the Policy for any device installation is the greater of 10 percent of annual cost or $50,000. The total minimum payment is increased by a corresponding amount. On the addition of the first new device, the minimum payment level becomes $550,000. Individual entity cost allocation is then calculated according to the procedure described previously. If that allocation procedure results in a significant revenue shortfall, the shortfall itself is allocated to the entities in proportion to their original allocation. For example, suppose the original allocation has a target of $550,000 (zero hours of device use), but the final allocation is only $500,000 (a $50,000 shortfall) due to the ceiling on allocations. A small entity with the 90 percent ceiling would have been allocated $900. As a percent of the total allocation, the $900 allocation is 0.16 percent. The entity’s allocation will be increased by 0.16 percent of $50,000, or by $80. A large entity might have an allocation of $66,000 (12 percent of the total). That entity’s allocation will be increased by 12 percent of $50,000, or $6,000. In this scenario, large entities will still be well under their 1995 actual allocation.

The example above illustrates adding one qualified device to the system. As with the original Policy, the addition of future devices eventually may cause the maximum annual entity cost allocations to increase above these levels. However, the addition of new transmission lines also tends to dilute the effectiveness factors of existing devices and reduce their revenue entitlement. This will partially offset the cost impact of adding new devices. Deletion of devices that are no longer sufficiently effective will

43

also

reduce costs.

Proce du re f o r Est ima tin g Ann ua l Ene rgy

It is highly preferred that all entities report their annual energy as described in the Entity System Information section. However, when entities fail to report that information, a method is needed to ensure they are assessed a fair share of the costs of this Policy. The estimate should be as close as possible to an entity’s actual energy load, generation, imports, and exports. However, the results of such an estimate should not encourage entities not to report their information as requested, nor should it reward them for not reporting by allocating them a less-than-fair share of the costs of the Policy. If an estimate is required, it shall be made as follows:

1. If the energy categories for the applicable year(s) have been reported to WECC for other purposes, the reported numbers will be used for cost allocation under the Policy.

2. If the numbers have not been reported for other purposes, and the entity has reported the energy categories for a prior year, the missing data will be estimated from the prior years’ data. This estimate will be based on an assumed 25 percent annual growth rate in each of the applicable energy categories.

3. If the entity’s numbers have not been reported for a prior year, data used for determining the entity’s WECC Annual Dues will be the basis for the estimate. Such estimates will be made for each entity category as follows:

a. Traditional utilities – the output of the organization’s owned and operated generation facilities plus its imports at the time of its system peak demand shall set the peak value in each energy category. To determine the energy, the annual load factor/capacity factor shall be estimated at 80 percent.

b. Independent Power Producers – the non-simultaneous maximum output (MW) of all owned and operated generation facilities at an assumed capacity factor of 85 percent.

c. Marketers – the annual MWh transacted shall be assigned to both imports and exports.

Alte rna tive t o E stima ting th e E ne rgy

As an alternative to estimating the annual energy, WECC may call for an audit of the entity’s energy record books, using such audit to determine the entity’s energy for purposes of dues allocation under the Policy. The costs of such audit shall be borne by the entity being audited.

EXAMPLE ALLOCATION

This example uses the Sacramento Municipal Utility District (rank #24) for illustration purposes only to explain the ranking and cost allocation methodology. It is based on the scenario of 2,784 hours of phase shifter use (CY2012).

1. SMUD has submitted the requested annual historical energy data. That information is tabulated by categories in Tables 2, 3, and 4.

1. SMUD's energy data are then averaged over the three-year period in each

44

category to produce the three-year rolling average in each category as tabulated in Table 5. As an error check, the submitted energy Load data are compared to the Load calculated as: L = G + I + RGI - E - RGE (for SMUD L = 11,418 GWh). The three-year rolling averages are then used in various combinations to determine each entity's relative ranking and cost allocation as described below.

Ran king P roce ss

1. The information in Table 5 is sorted with respect to all entities to establish the relative ranking of SMUD in the categories of L, I + RGI, G - RGE, and E. The sorted results are shown in Table 6 where SMUD’s relative rankings are shown to be: L = 21, I + RGI = 30, E = 52, and G - RGE = 25. Table 7 shows each entity's percentage share of the total for all entities in each of the four categories.

2. The results of the relative rankings shown in Table 7 are summarized in Table 6 where SMUD's relative ranking in the four categories is averaged (average = 32) and sorted again with respect to all entities to obtain SMUD's final relative ranking of 24.

3. By virtue of its final ranking of 24, SMUD is then deemed to be one of the “medium” entities and will not be assessed the 135 percent multiplier assigned to “large” entities. Except for Load (L), the ranking categories in Tables 6 and 7 are used only in the ranking process and not for determining cost allocation.

In itial an d Fina l Cost A lloca tion s

1. Using the data from Table 5, the three allocation categories of (I + RGI + E), (L + G - RGE), and (L) are created and are tabulated in Table 1a for Plan Year 18 – CY2012. SMUD’s share of each category, expressed as a percentage of the total for all WECC entities, is: I + RGI + E = 0.60%, L + G - RGE = 1.15%, and L = 1.31%. SMUD’s share in the three categories is then averaged to obtain SMUD’s 1.02 percent share, or an initial allocation of $65,657.

2. The interim allocation is then calculated by implementing a ceiling. For 2,784 hours of Qualified Controllable Device use, the ceiling is 135 percent of the 1995 final allocation. SMUD’s 1995 allocation was $12,342. SMUD’s interim allocation is 135 percent of its 1995 allocation or $16,707. For “small” entities (rank 35 and higher), the 1995 cost allocation was limited by the lesser of the allocation under the original January 7, 1994 methodology or $1,000. The limitation carries forward into the new methodology as the 1995 allocation and the 135 percent ceiling is applied to that amount.

3. The final allocation is made by multiplying the interim allocation of the 13 largest entities by 150 percent. SMUD does not fall into this category, and its final allocation is the same as the interim allocation.

45

WECC USF MITIGATION POLICY (ANNUAL MEMBERSHIP DUES)Table 1Unscheduled Flow Dues Scenarios - Increasing Coordinated Operation Hours To 4000

Multiply 13 largest entities' Interim Allocation 2) by: > 135.0% 144.5% 154.0% 163.5% 173.0%

Entity (1995)1995

Allocation 1)

Cap 115%of 1995

2000 Hrs

Cap 126%of 1995

2500 Hrs

Cap 143%of 1995

3000 Hrs

Cap 162%of 1995

3500 Hrs

Cap 181%of 1995

4000 HrsAEPC $1,000 $1,150 $1,256 $1,431 $1,618 $1,812AES $4,000 $2,411 $2,842 $3,300 $3,788 $4,304ANHM $1,000 $1,150 $1,256 $1,431 $1,618 $1,812APS $69,663 $80,112 $87,527 $99,658 $112,747 $126,214APX $4,000 $0 $0 $0 $0 $0ATCO $0 $0 $0 $0 $0 $0AVA $35,000 $40,250 $43,975 $50,070 $56,646 $63,412AXIA $4,000 $2,243 $2,644 $3,070 $3,524 $4,004BCHA $168,187 $178,075 $211,316 $240,605 $272,206 $304,718BEPC $5,330 $6,130 $6,697 $7,625 $8,626 $9,657BHPL $963 $1,108 $1,210 $1,378 $1,559 $1,745BPA $331,518 $260,444 $328,587 $406,610 $495,578 $595,767BPAP $0 $0 $0 $0 $0 $0BURB $719 $827 $904 $1,029 $1,164 $1,304CALP $975 $1,121 $1,225 $1,395 $1,578 $1,766CDWR $10,844 $12,471 $13,625 $15,514 $17,551 $19,647CFE $703 $605 $713 $828 $951 $1,080CHPD $3,122 $3,590 $3,923 $4,466 $5,053 $5,656CINE $4,000 $1,403 $1,654 $1,920 $2,204 $2,504CISO $555,249 $592,976 $697,631 $794,328 $898,653 $1,005,989CPS (EMMT) $4,000 $4,600 $5,026 $5,722 $6,474 $7,247CPSI $4,000 $120 $142 $165 $189 $215CPX $4,000 $4,600 $5,026 $5,722 $6,474 $7,247CRGL $4,000 $394 $464 $539 $619 $703CSU $1,000 $1,150 $1,256 $1,431 $1,618 $1,812DENA $4,000 $1,875 $2,210 $2,566 $2,946 $3,347DETM $11,000 $12,650 $13,821 $15,736 $17,803 $19,930DGT $1,000 $1,150 $1,256 $1,431 $1,618 $1,812DOPD $1,000 $1,150 $1,256 $1,431 $1,618 $1,812DYN $1,000 $1,150 $1,256 $1,431 $1,618 $1,812EAL $1,000 $0 $0 $0 $0 $0EPE $9,654 $11,102 $12,130 $13,811 $15,625 $17,491EPMI $20,000 $23,000 $25,129 $28,612 $32,369 $36,236EWEB $1,000 $1,150 $1,256 $1,431 $1,618 $1,812FARM $362 $416 $455 $518 $586 $656FPLE $4,000 $0 $0 $0 $0 $0GCPD $4,889 $5,622 $6,143 $6,994 $7,913 $8,858GLEN $677 $779 $851 $969 $1,096 $1,227HHWP $4,000 $4,441 $5,026 $5,722 $6,474 $7,247IGI $4,000 $120 $141 $164 $188 $214IID $7,634 $8,779 $9,591 $10,920 $12,355 $13,830IPC $30,000 $34,500 $37,693 $42,917 $48,554 $54,353LAC $323 $371 $406 $462 $522 $585LDWP $98,283 $97,777 $123,359 $140,601 $159,068 $178,067MID $1,000 $1,150 $1,256 $1,431 $1,618 $1,812MIEC $4,000 $218 $257 $298 $343 $389MIR $4,000 $4,600 $5,026 $5,722 $6,474 $7,247MPC $46,614 $23,200 $27,346 $31,751 $36,450 $41,413MWD $1,000 $1,150 $1,256 $1,431 $1,618 $1,812

46

Multiply 13 largest entities' Interim Allocation 2) by: > 135.0% 144.5% 154.0% 163.5% 173.0%

Entity (1995)1995

Allocation 1)

Cap 115%of 1995

2000 Hrs

Cap 126%of 1995

2500 Hrs

Cap 143%of 1995

3000 Hrs

Cap 162%of 1995

3500 Hrs

Cap 181%of 1995

4000 HrsMWEC $1,000 $612 $721 $837 $961 $1,092NAPG $1,000 $128 $151 $175 $201 $228NCPA $4,000 $4,600 $5,026 $5,722 $6,474 $7,247NEVP $14,177 $16,303 $17,812 $20,281 $22,945 $25,685OXGC (CAE) $473 $544 $594 $676 $765 $856PACE $128,788 $87,193 $102,774 $119,332 $136,992 $155,644PACW $130,380 $87,744 $103,424 $120,087 $137,858 $156,628PASA $827 $951 $1,039 $1,184 $1,339 $1,499PECO (EXPT) $4,000 $4,600 $5,026 $5,722 $6,474 $7,247PG&E $257,856 $0 $0 $0 $0 $0PGE $80,417 $92,480 $101,039 $115,044 $130,153 $145,699PNEG $1,000 $953 $1,123 $1,304 $1,497 $1,701PNM $8,458 $9,727 $10,627 $12,100 $13,689 $15,324POPD $1,000 $1,150 $1,256 $1,431 $1,618 $1,812PPA $1,000 $1,150 $1,256 $1,431 $1,618 $1,812PPLM $4,000 $0 $0 $0 $0 $0PRPA $3,941 $4,532 $4,951 $5,638 $6,378 $7,140PSC $86,513 $80,984 $102,172 $123,763 $140,018 $156,742PSE $79,872 $81,849 $100,354 $114,264 $129,271 $144,711PWX $4,000 $4,600 $5,026 $5,722 $6,474 $7,247RDNG $456 $524 $573 $652 $738 $826REI $4,000 $1,624 $1,915 $2,223 $2,552 $2,900RVSD $627 $721 $788 $897 $1,015 $1,136SCE $279,578 $0 $0 $0 $0 $0SCL $12,254 $14,092 $15,396 $17,530 $19,833 $22,202SDGE $17,815 $0 $0 $0 $0 $0SETC $4,000 $4,600 $5,026 $5,722 $6,474 $7,247SFG $406 $467 $510 $581 $657 $736SMUD $12,342 $14,193 $15,507 $17,656 $19,975 $22,361SNCL $1,000 $1,150 $1,256 $1,431 $1,618 $1,812SNPD $8,223 $9,456 $10,332 $11,764 $13,309 $14,898SPP $8,303 $9,548 $10,432 $11,878 $13,438 $15,043SRP $80,004 $77,095 $97,266 $114,452 $129,484 $144,950TANC $0 $0 $0 $0 $0 $0TAUC $328 $0 $0 $0 $0 $0TCP $4,000 $1 $1 $1 $2 $2TEP $12,531 $14,411 $15,744 $17,927 $20,281 $22,703TID $823 $946 $1,034 $1,177 $1,332 $1,491TNP $922 $1,060 $1,158 $1,319 $1,492 $1,670TNSK $431 $496 $542 $617 $698 $781TPWR $8,488 $9,761 $10,665 $12,143 $13,738 $15,378TSGT $10,543 $12,124 $13,247 $15,083 $17,064 $19,102UAMP $1,000 $1,150 $1,256 $1,431 $1,618 $1,812UMPA $1,000 $1,150 $1,256 $1,431 $1,618 $1,812USBR $0 $0 $0 $0 $0 $0VERN $723 $831 $908 $1,034 $1,170 $1,310WAPA $118,610 $68,020 $85,817 $106,195 $129,431 $155,597WEMT $8,000 $3,067 $10,051 $11,445 $12,948 $14,494WKP $5,721 $6,579 $7,188 $8,184 $9,259 $10,365WPE $751 $864 $944 $1,074 $1,215 $1,361Total $2,893,290 $2,167,313 $2,569,205 $2,983,146 $3,424,604 $3,890,879

1) Entities that joined WECC after 1995 do not have a 1995 allocation. Cap set at $1000 to $4,000 if ranking is "small." Actual allocation may be less than the cap because percent of total energy times total cost resulted in a lower number. In several cases,

47

the 1995 allocation itself was limited by a commitment to small entities that their allocation would not be larger than the lesser of $1,000 or the January 1994 trial allocation that was published to entities.

2) To eliminate the revenue shortfall caused by capping small and medium entities' dues, apply the multiplier to the 13 largest entities' allocations.

In the allocation process, an "initial allocation" is derived by multiplying the entities' average percent of energy in the above energy categories by the total cost. In many cases, this results in an initial allocation much higher than the cap. The cap described above is applied to limit such entities' final allocations.

48

WECC USF MITIGATION POLICY (ANNUAL MEMBERSHIP DUES)

Allocation Method:

Finds each member's ranking based on the average of rolling three-year averages of annual energy for: Load(L), Imports(I+RGI), Exports(E), and Generation(G-RGE).

Allocate 0% of cost to ranks = or < 13 pro-rata to: [I+RGI + E], [L + G - RGE], [L only], and the [average of the three].

Allocate 100% of cost to members pro-rata to: [I+RGI+E], [L+G-RGE], [L only], and the [average of the three].

Members with radial interconnections to WSCC are allocated costs based only on Imports and Exports.

Ranks greater than 13 are capped at 90-181% of 1995 allocation, depending upon device usage. All members are capped at 115% of 1995 at 2000 hours usage. See Plan for usage above 2000 hours.

Table 1a: WSCC Unscheduled Flow Mitigation Plan (Year 18 – CY 2012)

Member I=RGI+E

L+G -RGE

L Only

Ave. all

115Ave.

top 13

Rank

Initial Allocatio

nNew RGE Allocation

Interim Allocation

Final Allocation

AEPC 0.33% 0.17%0.12

%0.21

% 49 $13,305 $1,000 $1,354 $1,353.71

AES 0.21% 0.26%0.24

%0.24

% 52 $15,275 $4,000 $5,415 $5,414.83

AESO 0.24% 6.96%6.57

%4.59

% 20 $295,634 $4,000 $5,415 $5,414.83

ANHM 0.39% 0.16%0.29

%0.28

% 56 $18,040 $1,000 $1,354 $1,353.71

APS 1.06% 3.88%4.07

%3.00

% 15 $193,304 $69,663 $94,303 $94,303.33

AVA 2.02% 1.08%1.43

%1.51

% 2.72% 13 $96,975 $35,000 $47,380 $47,379.77

AZUA 0.02% 0.02%0.03

%0.02

% 93 $1,428 $4,000 $1,428 $1,428.09

BARC 0.06% 0.00%0.00

%0.02

% 85 $1,371 $4,000 $1,371 $1,370.80

BCHA 1.60% 6.33%6.29

%4.74

% 8.21% 6 $305,085 $168,187 $227,676 $227,676.48

BEAR (JP Morgan) 0.05% 0.00%

0.00%

0.02% 89 $1,007 $4,000 $1,007 $1,007.23

BEPC 0.35% 0.50%0.37

%0.41

% 34 $26,309 $5,330 $7,215 $7,215.28

BHCE 0.18% 0.13%0.22

%0.18

% 66 $11,370 $1,000 $1,354 $1,353.71

BHPL 0.34% 0.36%0.38

%0.36

% 39 $23,282 $963 $1,304 $1,304.08

BPA 9.83% 9.30%5.18

%8.10

% 14.63% 2 $521,466 $331,518 $448,778 $448,778.33

BURB 0.40% 0.10%0.14

%0.21

% 48 $13,708 $719 $974 $973.98

CALP 3.16% 2.15%0.00

%1.77

% 35 $114,073 $975 $1,320 $1,319.86

CAWC 0.24% 0.16%0.30

%0.23

% 67 $14,886 $4,000 $5,415 $5,414.83CCG 1.62% 0.00% 0.00 0.54 44 $34,764 $15,000 $20,306 $20,305.61

49

Member I=RGI+E

L+G -RGE

L Only

Ave. all

115Ave.

top 13

Rank

Initial Allocatio

nNew RGE Allocation

Interim Allocation

Final Allocation

% %

CDWR 1.03% 0.66%0.75

%0.81

% 22 $52,300 $10,844 $14,680 $14,679.90

CEI 0.13% 0.00%0.00

%0.04

% 82 $2,721 $4,000 $2,721 $2,721.21

CEOE 0.24% 0.17%0.00

%0.14

% 62 $8,791 $10,845 $8,791 $8,791.01

CEPM 0.00% 0.00%0.00

%0.00

% 22 $104 $4,000 $104 $104.21

CFE 0.09% 1.35%1.24

%0.89

% 41 $57,350 $703 $952 $951.79

CHPD 0.50% 0.70%0.37

%0.52

% 30 $33,572 $3,122 $4,226 $4,226.28

COSL 0.01% 0.01%0.01

%0.01

% 96 $584 $4,000 $584 $584.43

CRGL 1.17% 0.00%0.00

%0.39

% 49 $25,074 $4,000 $5,415 $5,414.83

CSU 0.11% 0.58%0.54

%0.41

% 47 $26,251 $1,000 $1,354 $1,353.71

DBET 0.15% 0.00%0.00

%0.05

% 81 $3,223 $4,000 $3,223 $3,222.91

DEGS 0.02% 0.01%0.00

%0.01

% 88 $775 $4,000 $775 $775.20

DGT 0.47% 0.41%0.28

%0.39

% 35 $24,813 $1,000 $1,354 $1,353.71

DOPD 0.18% 0.14%0.08

%0.13

% 61 $8,563 $1,000 $1,354 $1,353.71

DYN 0.64% 0.44%0.00

%0.36

% 45 $23,149 $1,000 $1,354 $1,353.71

EMC 0.04% 1.44%1.35

%0.95

% 43 $60,845 $4,000 $5,415 $5,414.83

EPE 1.15% 0.64%0.90

%0.90

% 22 $57,692 $9,654 $13,069 $13,068.69

EWEB 0.67% 0.20%0.29

%0.39

% 38 $24,800 $1,000 $1,354 $1,353.71

FARM 0.06% 0.12%0.14

%0.11

% 76 $6,786 $362 $490 $490.04

FBC 0.52% 0.66%0.57

%0.58

% 26 $37,550 $6,000 $8,122 $8,122.25

FPLE 0.15% 0.10%0.00

%0.08

% 73 $5,273 $4,000 $5,273 $5,272.58

GCPD 0.72% 0.55%0.45

%0.57

% 24 $36,840 $4,889 $6,618 $6,618.28

GLEN 0.15% 0.08%0.14

%0.12

% 70 $7,878 $677 $916 $916.46

HGC 0.24% 0.16%0.00

%0.13

% 63 $8,495 $4,000 $5,415 $5,414.83HHWP (CCSF) 0.06% 0.16%

0.13%

0.12% 69 $7,496 $4,000 $5,415 $5,414.83

IID 1.05% 0.28%0.42

%0.58

% 28 $37,327 $7,634 $10,334 $10,333.62

IPC 2.03% 1.57%1.94

%1.85

% 3.30% 12 $118,880 $50,000 $67,685 $67,685.38

LAC 0.03% 0.05%0.06

%0.05

% 85 $3,011 $323 $437 $436.96

LDWP 4.33% 2.72%3.10

%3.38

% 6.09% 3 $217,659 $98,283 $133,046 $133,046.12

LMUD 0.01% 0.01%0.02

%0.01

% 95 $817 $4,000 $817 $817.09

MCPI 0.29% 0.00%0.00

%0.10

% 72 $6,149 $4,000 $5,415 $5,414.83

MEID 0.07% 0.01%0.05

%0.04

% 94 $2,772 $4,000 $2,772 $2,771.88

MID 0.20% 0.20%0.30

%0.23

% 59 $14,778 $1,000 $1,354 $1,353.71

50

Member I=RGI+E

L+G -RGE

L Only

Ave. all

115Ave.

top 13

Rank

Initial Allocatio

nNew RGE Allocation

Interim Allocation

Final Allocation

MLCI 6.32% 0.00%0.00

%2.11

% 33 $135,673 $4,000 $5,415 $5,414.83

MWD 0.19% 0.13%0.24

%0.18

% 78 $11,782 $1,000 $1,354 $1,353.71

MWEC 0.30% 0.00%0.00

%0.10

% 68 $6,439 $1,000 $1,354 $1,353.71

NAPG 0.04% 0.03%0.00

%0.02

% 83 $1,446 $1,000 $1,354 $1,353.71

NAT 0.02% 0.02%0.00

%0.01

% 85 $884 $4,000 $884 $883.69

NCPA 0.14% 0.17%0.24

%0.18

% 65 $11,794 $1,000 $1,354 $1,353.71

NEVP 1.07% 3.54%3.94

%2.85

% 19 $183,303 $14,177 $19,191 $19,191.31

NRG 0.22% 0.15%0.00

%0.13

% 64 $8,076 $4,000 $5,415 $5,414.83

NWMT 0.74% 1.57%1.38

%1.23

% 17 $79,168 $46,614 $63,101 $63,101.09

OCES 0.01% 0.01%0.00

%0.01

% 92 $417 $4,000 $417 $417.10

PAC 9.77% 6.97%6.66

%7.80

% 14.05% 1 $501,941 $259,168 $350,837 $350,837.10

PASA 0.14% 0.08%0.14

%0.12

% 75 $7,953 $827 $1,120 $1,119.91

PG&E 5.53% 7.06%9.87

%7.49

% 13.15% 9 $481,881 $257,856 $349,062 $349,061.72

PGE 2.16% 1.79%2.08

%2.01

% 3.58% 10 $129,225 $80,417 $108,862 $108,861.73

PGR 0.43% 0.29%0.00

%0.24

% 57 $15,547 $4,000 $5,415 $5,414.83

PNM 0.87% 0.99%1.13

%1.00

% 21 $64,235 $8,458 $11,450 $11,449.58

POC 0.07% 0.09%0.12

%0.09

% 80 $5,919 $4,000 $5,415 $5,414.83

PPLE 2.09% 0.00%0.00

%0.70

% 42 $44,858 $4,000 $5,415 $5,414.83

PPLM 0.49% 0.34%0.00

%0.28

% 53 $17,825 $4,000 $5,415 $5,414.83

PPM 0.57% 0.39%0.00

%0.32

% 51 $20,431 $4,000 $5,415 $5,414.83

PRPA 0.17% 0.42%0.37

%0.32

% 45 $20,421 $3,941 $5,335 $5,334.79

PSCO 1.39% 5.00%5.13

%3.84

% 6.65% 11 $246,996 $86,513 $117,113 $117,112.99

PSE 3.57% 2.84%3.56

%3.32

% 5.93% 4 $213,989 $79,872 $108,124 $108,123.98

PWX 4.67% 0.00%0.00

%1.56

% 37 $100,184 $4,000 $5,415 $5,414.83

RDNG 0.07% 0.06%0.09

%0.07

% 84 $4,667 $456 $617 $617.28

RVE 0.10% 0.07%0.10

%0.09

% 77 $5,730 $1,000 $1,354 $1,353.71

RVSD 0.17% 0.20%0.28

%0.22

% 58 $14,185 $627 $849 $849.03

SCE 4.78% 7.69%9.77

%7.41

% 12.98% 5 $477,019 $279,578 $378,467 $378,466.99

SCL 1.27% 1.00%1.16

%1.14

% 18 $73,559 $12,254 $16,588 $16,588.31

SDGE 1.10% 1.72%2.30

%1.71

% 27 $110,052 $17,815 $24,116 $24,115.71

SER 1.56% 1.07%0.00

%0.88

% 39 $56,415 $4,000 $5,415 $5,414.83

SMUD 0.60% 1.15%1.31

%1.02

% 24 $65,657 $12,342 $16,707 $16,707.46

SNCL 0.22% 0.21%0.34

%0.26

% 59 $16,583 $1,000 $1,354 $1,353.71

51

Member I=RGI+E

L+G -RGE

L Only

Ave. all

115Ave.

top 13

Rank

Initial Allocatio

nNew RGE Allocation

Interim Allocation

Final Allocation

SNPD 0.88% 0.46%0.79

%0.71

% 32 $45,730 $8,223 $11,132 $11,131.54

SPP 0.33% 1.22%1.33

%0.96

% 30 $61,891 $8,303 $11,240 $11,239.83

SRP 2.27% 2.76%3.21

%2.75

% 4.85% 7 $176,830 $80,004 $108,302 $108,302.02

STGP 0.18% 0.02%0.00

%0.07

% 73 $4,239 $4,000 $4,239 $4,239.14

TEP 1.34% 1.06%1.26

%1.22

% 16 $78,434 $12,531 $16,963 $16,963.31

TID 0.20% 0.25%0.24

%0.23

% 54 $14,703 $823 $1,114 $1,114.10

TNSK 0.06% 0.04%0.00

%0.04

% 79 $2,332 $431 $583 $583.45

TPWR 0.54% 0.48%0.57

%0.53

% 28 $34,197 $8,488 $11,490 $11,490.27

TSGT 1.84% 1.17%1.01

%1.34

% 14 $86,264 $10,543 $14,272 $14,272.14

UAMP 0.22% 0.36%0.48

%0.35

% 54 $22,682 $1,000 $1,354 $1,353.71

UMPA 0.18% 0.07%0.14

%0.13

% 70 $8,334 $1,000 $1,354 $1,353.71

VEA 0.04% 0.03%0.05

%0.04

% 91 $2,687 $4,000 $2,687 $2,687.16

WAPA 2.49% 1.99%1.95

%2.14

% 3.84% 7 $137,695 $118,610 $137,695 $160,563.26

WEMT 0.00% 0.05%0.05

%0.03

% 89 $2,199 $15,000 $2,199 $2,198.57

Total 100% 100% 100% 100% 100%$6,436,07

0 $2,399,562 $3,148,521$3,171,388.

87Initial Capped

1995 Interim Final

52

Table 2: 20082008 Gwh Gwh Gwh Gwh Gwh Gwh Data Diff

Company Generation Imports

Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

EstimateAEPC 2779.77 1362.16 0.00 2680.88 0.00 1461.05 1461.05 0.00AES 4385.17 0.00 0.00 0.00 0.00 4385.17 4385.17 0.00

AESO 56352.39 2248.12 0.00 558.76 0.00 58041.75 58041.75 0.00

ANHM 52.09 504.82 2879.86 752.34 0.00 2684.43 2684.43 0.00

APS 57550.32 4722.32 2366.61 1582.01 29516.22

33541.02 33541.02 0.00

AVA 5137.54 11221.41 4261.17 8026.89 0.00 12593.23 12593.23 0.00

AZUA 121.93 123.02 21.30 0.00 0.00 266.25 266.25 0.00BARC 0.00 330.06 0.00 330.06 0.00 0.00 0.00 0.00

BCHA 50485.48 11753.88 0.00 5688.11 0.00 56551.25 56551.25 0.00

BEAR (JP Morgan) 0.00 211.74 0.00 211.74 0.00 0.00 0.00 0.00

BEPC 4852.52 1204.34 0.00 2688.75 0.00 3368.11 3368.11 0.00BHCE 268.41 2082.02 0.00 394.41 0.00 1956.02 1956.02 0.00BHPL 1974.90 1983.14 558.79 1200.86 1.36 3314.61 3314.61 0.00

BPA 110841.60 26090.20 73.13 89142.70 0.00 47862.2

3 47862.23 0.00

BURB 1591.62 2481.98 635.16 2366.66 1095.58 1246.52 1246.52 0.00

CALP 37154.52 0.00 0.00 37154.52 0.00 0.00 0.00 0.00

CAWC 0.00 2505.48 0.00 0.00 0.00 2505.48 2505.48 0.00CCG 0.00 2917.01 0.00 2917.01 0.00 0.00 0.00 0.00CDWR 4023.78 4114.93 1906.44 2482.15 157.32 7405.67 7405.67 0.00CEI 0.00 1342.58 0.00 1342.58 0.00 0.00 0.00 0.00CEOE 2695.10 0.00 0.00 2695.10 0.00 0.00 0.00 0.00CEPM 30.23 0.00 0.00 30.23 0.00 0.00 0.00 0.00

CFE 11869.01 339.76 0.00 715.78 481.20 11011.79 11011.79 (0.01)

CHPD 8591.20 253.66 0.00 5555.13 0.00 3289.73 3289.73 0.00COSL 0.00 0.00CRGL 0.00 6403.29 0.00 6403.29 0.00 0.00 0.00 0.00CSU 4747.57 684.55 0.00 677.47 0.00 4754.65 4754.65 0.00DBET 460.80 460.80 0.00 0.00DEGS 24.90 24.90 0.00 0.00DGT 4584.48 1855.66 0.00 3858.54 139.86 2441.74 2441.74 0.00DOPD 3966.98 376.65 200.16 1550.21 2331.71 661.86 661.86 0.00

DYN 10862.39 0.00 0.00 10862.39 0.00 0.00 0.00 0.00

EMCU 11028.81 351.84 0.00 160.15 11220.50 11220.50 0.00

EPE 2679.68 3924.59 5343.79 4278.91 0.00 7669.16 7669.16 0.00EWEB 678.63 5203.74 92.60 3262.12 0.00 2712.84 2712.84 (0.00)FARM 747.14 428.28 275.88 176.39 0.00 1274.91 1274.91 0.00FBC 6078.15 2429.96 0.00 3504.55 0.00 5003.57 5003.57 0.00FPLE 1494.22 0.00 0.00 1494.22 0.00 0.00 0.00 0.00GCPD 9394.96 3667.44 0.00 4973.34 4359.67 3729.39 3729.39 0.00

53

2008 Gwh Gwh Gwh Gwh Gwh Gwh Data Diff


Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

EstimateGLEN 203.29 1065.76 257.86 287.85 0.00 1239.05 1239.05 0.00HGC 3013.58 0.00 0.00 3013.58 0.00 0.00 0.00 0.00HHWP (CCSF) 1285.32 120.40 0.00 357.93 0.00 1047.79 1047.79 (0.00)IID 856.34 6825.80 278.62 4254.16 0.00 3706.60 3706.60 0.00

IPC 8508.57 9078.08 7278.84 7057.90 304.29 17503.31 17503.31 0.00

LAC 329.25 170.61 72.74 42.13 0.00 530.46 530.46 0.00

LDWP 24515.79 24342.12 6528.29 20597.04 6668.79 28120.3

7 28120.37 0.00

LMUD 146.38 146.38 146.38 0.00MCPI 324.25 324.25 0.00 0.00MEID 465.43 189.19 13.11 189.19 452.32 452.32 0.00MID 593.70 1989.35 160.93 82.55 0.00 2661.43 2661.43 0.00

MLCI 0.00 29941.25 0.00 29941.25 0.00 0.00 0.00 0.00

MWD 0.00 458.96 1330.43 0.00 0.00 1789.40 1789.40 0.00MWEC 0.00 2013.23 0.00 2013.23 0.00 0.00 0.00 0.00NAPG 406.67 0.00 0.00 406.67 0.00 0.00 0.00 0.00NAT 39.21 0.46 0.00 38.75 0.00 0.92 0.92 0.00NCPA 1305.84 663.10 0.00 18.19 690.00 1260.75 1260.75 (0.00)

NEVP 29521.42 8317.09 2871.81 271.04 7287.73 33151.55 33151.55 0.00

NRG 4012.55 0.00 0.00 4012.55 0.00 0.00 0.00 0.00

NWMT 22716.88 3093.99 0.00 4570.05 10129.26

11111.55 11111.55 (0.00)

OCES 100.60 0.00 0.00 100.60 0.00 0.00 0.00 0.00

PAC 59502.82 38986.38 16949.91

54104.32 2118.21 59216.5

8 59216.58 0.00

PASA 121.67 478.92 1003.20 283.54 0.00 1320.26 1320.26 0.00

PG&E 25479.17 64784.64 0.00 1994.68 0.00 88269.13 88269.13 0.00

PGE 11901.02 13651.75 2852.96 9441.06 625.70 18338.97 18338.97 0.00

PGR 5433.22 0.00 0.00 5433.22 0.00 0.00 0.00 0.00PNM 15830.49 6079.48 2173.94 4890.56 9456.16 9737.19 9737.19 0.00POC 422.44 23.60 682.95 100.01 1028.98 1028.98 0.00

PPLE 0.00 14872.32 389.22 15261.53 0.00 0.00 0.00 0.00

PPLM 20446.85 0.00 0.00 8178.36 12268.49 0.00 0.00 0.00

PPM 5922.05 0.00 0.00 5922.05 0.00 0.00 0.00 (0.00)PRPA 3488.48 750.34 0.00 1031.05 0.00 3207.76 3207.76 0.00

PSCO 39537.34 10830.02 1090.21 3768.72 1975.96 45712.90 45712.90 0.00

PSE 14516.77 21405.94 2211.25 10310.33 176.34 27647.2

9 27647.29 0.00

PWX 0.00 23312.82 0.00 23312.82 0.00 0.00 0.00 0.00

RDNG 194.48 620.86 27.62 0.00 0.00 842.96 842.96 0.00RVE 720.54 954.02 0.00 370.72 0.00 1303.84 1303.84 0.00RVSD 697.39 511.98 1370.70 109.09 0.00 2470.98 2470.98 0.00SCE 41868.26 50356.46 10503.4 10195.4 3623.42 88909.3 88909.35 0.00

54



Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

Estimate5 2 5

SCL 6786.15 9455.29 0.00 5507.66 370.98 10362.80 10362.80 0.00

SDGE 9118.30 8425.06 3100.64 0.00 0.00 20644.00 20644.00 0.00

SER 19290.21 0.00 0.00 19290.21 0.00 0.00 0.00 0.00

SMUD 7244.52 6294.39 275.59 2095.14 0.00 11719.36 11719.36 0.00

SNCL 489.70 2515.15 0.00 0.00 0.00 3004.85 3004.85 0.00SNPD 706.51 8184.41 0.00 1913.01 0.00 6977.91 6977.91 0.00

SPP 9409.97 4337.21 0.00 14.51 1651.27 12081.40 12081.40 0.00

SRP 31380.75 9170.80 9229.87 7396.09 13633.05

28752.28 28752.28 0.00

STGP 0.00 1924.62 0.00 1924.62 0.00 0.00 0.00 0.00

TEP 6690.05 4702.25 4765.07 5778.90 0.00 10378.47 10378.47 0.00

TID 1897.44 1154.48 284.29 1225.03 0.82 2110.36 2110.36 0.00TNSK 606.39 2.91 0.00 609.30 0.00 0.00 0.00 (0.00)TPWR 2783.25 4083.51 0.00 1748.90 0.00 5117.86 5117.86 0.00

TSGT 15613.36 6306.61 3160.39 18728.49 5310.69 1041.19 1041.19 0.00

UAMP 1679.90 2282.90 251.14 0.00 0.00 4213.94 4213.94 0.00UMPA 10.74 1230.14 494.97 514.50 0.00 1221.36 1221.36 0.00VEA 0.00 479.42 0.00 0.00 0.00 479.42 479.42 (0.00)

WAPA 29495.51 14557.79 381.70 9758.47 12545.21

22131.32 22131.32 0.00

WEMT 445.65 0.00 0.00 0.00 0.00 445.65 445.65 0.00

Total 904186 525322 98783 518819 127108 882363 882363.11 (0.00)

55



Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

EstimateAEPC 2099.29 1513.71 1928.77 1684.23 0.00 0.00AES 3473.89 3473.89 0.00 0.00AESO 54958.93 2018.61 513.16 56464.3

7 56464.37 0.00

ANHM 68.13 690.56 2772.23 976.74 2554.17 2554.17 0.00APS 58707.22 13127.63 2099.68 1642.77 31332.8

540958.9

2 40958.92 0.00

AVA 5118.46 10613.47 3682.54 6968.77 12445.70 12445.70 0.00

AZUA 55.92 179.98 22.37 258.27 258.27 0.00BARC 323.74 323.74 0.00 0.00BCHA 47229.32 12255.60 5015.94 54468.9

9 54468.99 0.00

BEAR (JP Morgan) 211.25 211.25 0.00 0.00

BEPC 4732.85 1197.99 2708.74 3222.10 3222.10 0.00BHCE 257.32 1637.53 0.00 32.23 0.00 1862.62 1862.62 0.00BHPL 2710.45 1764.27 542.71 1578.00 99.66 3339.76 3339.76 0.00BPA 104149.47 22634.54 66.19 82512.6

744337.5

2 44337.52 0.00

BURB 1583.37 1897.61 590.32 1828.96 1100.64 1141.69 1141.69 0.00CALP 36850.87 36850.8

7 0.00 0.00

CAWC 2644.15 2644.15 2644.15 0.00CCG 23781.36 23781.3

6 0.00 0.00

CDWR 4052.13 4640.60 1709.42 4915.33 70.37 5416.44 5416.44 0.00CEI 439.04 439.04 0.00 0.00CEOE 2695.19 2695.19 0.00 0.00CEPM 30.95 30.95 0.00 0.00CFE 11397.56 280.29 659.17 324.70 10693.9

7 10693.97 0.00

CHPD 7928.86 381.58 5053.61 3256.83 3256.83 0.00COSL 204.00 204.00 204.00 0.00CRGL 7534.35 7534.35 0.00 0.00CSU 4597.81 592.34 624.53 4565.62 4565.62 0.00DBET 901.58 901.58 0.00 0.00DEGS 147.45 147.45 0.00 0.00DGT 4071.80 1773.07 3343.94 125.52 2375.40 2375.40 0.00DOPD 3534.21 380.93 172.37 1438.21 1981.65 667.64 667.64 0.00DYN 6732.59 6732.59 0.00 0.00EMCU 12064.11 303.54 241.49 12126.1

6 12126.16 0.00

EPE 2362.57 3317.67 5593.66 3567.46 7706.44 7706.44 0.00EWEB 621.64 4046.99 87.50 2262.70 2493.42 2493.42 (0.00)FARM 733.61 200.70 279.36 12.40 1201.27 1201.27 0.00FBC 5702.92 2394.37 3123.59 4973.70 4973.70 0.00FPLE 1638.94 1638.94 0.00 0.00GCPD 8710.61 3470.05 4414.75 3884.98 3880.93 3880.93 0.00

56



Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

EstimateGLEN 180.53 1023.99 253.26 275.43 1182.35 1182.35 0.00HGC 3102.16 3102.16 0.00 0.00HHWP (CCSF) 1456.03 171.23 597.89 1029.37 1029.37 (0.00)IID 826.89 6963.07 317.76 4445.92 3661.80 3661.80 0.00IPC 9985.67 7704.46 6940.84 7496.89 322.53 16811.5

5 16811.55 0.00

LAC 337.96 156.04 70.79 17.79 547.01 547.01 0.00LDWP 22684.72 22096.38 6404.49 18582.3

0 5822.98 26780.30 26780.30 0.00

LMUD 147.91 147.91 147.91 0.00MCPI 2060.83 2060.83 0.00 0.00MEID 458.88 225.36 12.30 225.36 446.58 446.58 0.00MID 543.42 1781.00 372.51 108.93 2588.01 2588.01 0.00MLCI 37426.25 37426.2

5 0.00 0.00

MWD 900.33 1294.20 2194.53 2194.53 0.00MWEC 1479.82 1479.82 0.00 0.00NAPG 471.13 471.13 0.00 0.00NAT 313.52 313.52 0.00 0.00NCPA 1366.49 1960.00 49.48 757.80 2519.21 2519.21 0.00NEVP 30985.01 7040.72 4133.00 306.64 6873.58 34978.5

0 34978.50 0.00

NRG 2186.94 2186.94 0.00 0.00NWMT 22333.45 3629.24 4664.56 8094.82 13203.3

1 13203.31 (0.00)

OCES 125.75 125.75 0.00 0.00PAC 55185.38 37122.93 18121.2

051286.2

9 1906.56 57236.66 57236.66 0.00

PASA 109.08 299.34 1011.53 161.20 1258.74 1258.74 0.00PG&E 28113.84 59514.79 1865.34 85763.2

9 85763.29 0.00

PGE 10527.20 13419.51 2631.94 8067.90 467.28 18043.46 18043.46 0.00

PGR 4673.99 4673.99 0.00 0.00PNM 16537.61 3427.47 2156.08 2549.79 9784.46 9786.91 9786.91 0.00POC 433.48 35.51 655.76 126.13 998.62 998.62 0.00PPLE 9016.52 388.50 9405.03 0.00 0.00PPLM 17723.49 8120.03 9603.46 0.00 0.00PPM 6292.86 6292.86 0.00 0.00PRPA 3635.41 782.44 1167.40 3250.44 3250.44 0.00PSCO 37350.47 10557.78 1031.74 2893.41 2259.13 43787.4

5 43787.45 0.00

PSE 15587.19 21894.73 1857.88 12203.78 163.54 26972.4

8 26972.48 0.00

PWX 23553.88 23553.88 0.00 0.00

RDNG 36.50 772.79 17.73 827.02 827.02 0.00RVE 733.68 910.18 368.40 1275.46 0.00 0.00RVSD 621.52 458.61 1421.38 186.40 2315.11 2315.11 0.00SCE 42151.78 35255.00 11663.4

2 58.02 3477.79 85534.38 85534.38 0.00

SCL 6328.72 8666.43 4458.31 368.93 10167.9 10167.92 0.00

57



Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

Estimate2

SDGE 6438.68 10444.29 3228.03 20111.00 20111.00 0.00

SER 16780.70 16780.70 0.00 0.00

SMUD 6949.41 5408.00 5.00 914.47 11447.94 11447.94 0.00

SNCL 471.34 2462.01 2933.36 2933.36 0.00SNPD 623.87 8087.85 1813.78 6897.94 6897.94 0.00SPP 10027.43 3087.67 66.24 1579.80 11469.0

6 11469.06 0.00

SRP 28131.85 9464.45 9617.81 7078.52 12496.63

27638.96 27638.96 0.00

STGP 983.07 983.07 0.00 0.00TEP 5858.19 4562.75 4407.39 4515.16 10313.1

7 10313.17 0.00

TID 1874.28 623.83 318.62 749.27 3.39 2064.07 2064.07 0.00TNSK 869.42 3.01 869.42 3.01 3.01 (0.00)TPWR 2803.54 4012.72 1800.76 5015.50 5015.50 0.00TSGT 15086.23 6292.18 3172.30 6912.74 5151.54 12486.4

2 12486.43 0.00

UAMP 1849.64 2012.96 256.57 4119.17 4119.17 0.00UMPA 9.79 1024.13 469.15 322.51 1180.57 1180.57 0.00VEA 470.24 470.24 470.24 0.00WAPA 26073.29 11776.79 395.49 13087.7

9 9042.05 16115.73 16115.73 0.00

WEMT 446.25 446.25 446.25 0.00Total 863763 521248 100458 497182 120282 868005 868005 0.01

58



Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

EstimateAEPC 2187.39 1410.09 0.00 1962.45 0.00 1635.04 1635.04 0.00AES 1948.47 0.00 0.00 0.00 0.00 1948.47 1948.47 0.00AESO 55718.38 2205.01 0.00 467.90 0.00 57455.4

957455.49 0.00

ANHM 41.39 636.29 2709.22 1018.66 0.00 2368.24 2368.24 0.00APS 57174.09 5241.22 2204.31 2273.62 30346.4

231955.8

031999.58 43.78

AVA 4850.65 10671.60 4089.06 7371.49 0.00 12239.82

12239.82 0.00

AZUA 57.79 169.10 22.47 0.00 0.00 249.35 249.35 0.00BARC 0.00 405.00 0.00 405.00 0.00 0.00 0.00 0.00BCHA 46253.89 12719.07 0.00 5577.25 0.00 53395.7

153395.71 0.00

BEAR (JP Morgan)

0.00 354.99 0.00 354.99 0.00 0.00 0.00 0.00

BEPC 4809.57 1174.35 0.00 2770.64 0.00 3213.28 3213.28 0.00BHCE 258.83 1681.99 0.00 18.35 0.00 1922.47 1922.47 0.00BHPL 3146.47 1511.93 517.63 1690.31 151.13 3334.60 3334.60 0.00BPA 102381.88 22965.04 48.41 82178.3

80.00 43216.9

543216.95 0.00

BURB 1661.85 1466.87 600.54 1408.81 1167.92 1152.52 1152.52 0.00CALP 30837.34 0.00 0.00 30837.3

40.00 0.00 0.00 0.00

CAWC 0.00 2651.24 0.00 0.00 0.00 2651.24 2651.24 0.00CCG 182.93 0.00 0.00 182.93 0.00 0.00 0.00 0.00CDWR 4570.53 7027.56 1354.26 6083.05 96.44 6772.85 6772.85 0.00CEI 0.00 320.24 0.00 320.24 0.00 0.00 0.00 0.00CEOE 2689.42 0.00 0.00 2689.42 0.00 0.00 0.00 0.00CEPM 34.60 0.00 0.00 34.60 0.00 0.00 0.00 0.00CFE 11207.86 220.66 0.00 651.66 178.40 10598.4

710598.47 0.00

CHPD 7651.01 386.59 0.00 4886.93 0.00 3150.67 3150.67 0.00COSL 0.00 0.17 0.00 0.00 0.00 0.17 0.17 0.00CRGL 0.00 5429.29 0.00 5429.29 0.00 0.00 0.00 0.00CSU 4863.20 420.25 0.00 598.35 0.00 4685.11 4685.11 0.00DBET 0.00 1127.00 0.00 1127.00 0.00 0.00 0.00 0.00DEGS 540.13 0.00 0.00 540.13 0.00 0.00 0.00 0.00DGT 4288.56 1551.92 0.00 3259.05 135.15 2446.27 2446.27 0.00DOPD 3534.21 380.93 172.37 1438.21 1981.65 667.64 667.64 0.00DYN 3681.18 0.00 0.00 3681.18 0.00 0.00 0.00 0.00EMCU 11747.05 306.03 0.00 47.10 0.00 12005.9

712005.97 0.00

EPE 2874.16 3050.99 5575.55 3452.93 0.00 8047.77 8047.77 0.00EWEB 586.54 4419.81 84.18 2627.52 0.00 2463.01 2463.01 0.00FARM 709.11 257.54 222.68 0.82 0.00 1188.51 1188.51 0.00FBC 5620.93 2488.86 0.00 3178.82 0.00 4930.98 4930.98 0.00FPLE 1712.80 0.00 0.00 1712.80 0.00 0.00 0.00 0.00GCPD 8193.90 3091.76 0.00 4311.11 2936.59 4037.96 4037.96 0.00GLEN 186.44 1049.71 269.39 369.92 0.00 1135.63 1135.63 0.00

59



Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

EstimateHGC 1692.23 0.00 0.00 1692.23 0.00 0.00 0.00 0.00HHWP (CCSF) 1739.05 173.94 0.00 700.56 0.00 1212.43 1212.43 0.00IID 878.94 6784.92 331.25 4442.03 0.00 3553.09 3553.09 0.00IPC 8245.71 8253.40 6844.71 6700.11 285.85 16357.8

616357.86 0.00

LAC 282.88 207.54 77.68 17.51 0.00 550.59 550.59 0.00LDWP 21901.95 20814.34 6432.44 17711.2

35322.48 26115.0

226115.02 0.00

LMUD 0.00 133.89 0.00 0.00 0.00 133.89 133.89 0.00MCPI 0.00 2364.48 0.00 2364.48 0.00 0.00 0.00 0.00MEID 0.00 460.31 324.03 12.05 324.03 448.26 448.26 0.00MID 618.31 1597.15 366.76 84.76 0.00 2497.46 2497.46 0.00MLCI 0.00 37426.25 0.00 37426.2

50.00 0.00 0.00 0.00

MWD 0.00 931.79 1258.33 0.00 0.00 2190.12 2190.12 0.00MWEC 0.00 1480.20 0.00 1480.20 0.00 0.00 0.00 0.00NAPG 450.83 0.00 0.00 450.83 0.00 0.00 0.00 0.00NAT 458.39 0.00 0.00 458.39 0.00 0.00 0.00 0.00NCPA 1366.49 1960.00 49.48 757.80 2519.21 2519.21 0.00NEVP 28676.08 7789.24 4201.32 381.93 5479.81 34804.8

934804.89 0.00

NRG 1223.31 0.00 0.00 1223.31 0.00 0.00 0.00 0.00NWMT 26222.88 3270.37 0.00 5305.27 12488.9

711699.0

011699.00 0.00

OCES 157.00 0.00 0.00 157.00 0.00 0.00 0.00 0.00PAC 55945.10 38099.10 17309.8

951817.7

01765.93 57770.4

557770.45 0.00

PASA 107.24 279.22 995.18 181.64 0.00 1200.00 1200.00 0.00PG&E 32176.75 53495.33 0.00 1607.60 0.00 84064.4

884064.48 0.00

PGE 11875.25 11803.72 2268.71 7336.96 601.32 18009.39

18009.39 0.00

PGR 4182.25 0.00 0.00 4182.25 0.00 0.00 0.00 0.00PNM 15018.46 3193.45 2733.91 1608.57 9298.74 10038.5

210038.52 0.00

POC 411.92 37.95 642.70 107.67 0.00 984.91 984.91 0.00PPLE 0.00 9775.62 206.29 9981.91 0.00 0.00 0.00 0.00PPLM 12312.83 0.00 0.00 84.62 12228.2

10.00 0.00 0.00

PPM 6562.72 0.00 0.00 6562.72 0.00 0.00 0.00 0.00PRPA 3477.14 763.77 0 1062.48 0.00 3178.42 3178.42 0.00PSCO 40243.46 10746.00 1024.20 3962.73 3479.51 44571.4

244571.42 0.00

PSE 15604.34 34071.75 1778.10 12629.97

267.43 38556.80

38556.80 0.00

PWX 0.00 30515.51 0.00 30515.51

0.00 0.00 0.00 0.00

RDNG 49.78 755.86 0.32 0.00 0.00 805.97 805.97 0.00RVE 500.06 792.32 0.00 66.85 0.00 1225.53 1225.53 0.00RVSD 1247.23 95.74 1434.21 162.76 0.00 2614.41 2614.41 0.00SCE 44881.47 29283.80 10496.8

2630.73 3027.55 81003.8

181003.81 0.00

60



Remote Gen

ImportsExports

Remote Gen

ExportsEnergy Load

Data Check

Source of

EstimateSCL 6055.70 9094.44 0.00 4882.77 369.57 9897.80 9897.80 0.00SDGE 8158.05 8548.44 2776.50 0.00 0.00 19483.0

019483.00 0.00

SER 15779.00 0.00 0.00 15779.00

0.00 0.00 0.00 0.00

SMUD 7741.66 4060.31 0.00 714.76 0.00 11087.21

11087.21 0.00

SNCL 553.96 2362.00 0.00 0.00 0.00 2915.96 2915.96 0.00SNPD 612.53 7645.17 0.00 1516.59 0.00 6741.12 6741.12 0.00SPP 9949.60 3062.46 0.00 235.42 1431.71 11344.9

311344.93 0.00

SRP 29836.19 7542.45 9370.91 6485.64 12746.49

27517.42

27517.42 0.00

STGP 0.00 523.51 0.00 523.51 0.00 0.00 0.00 0.00TEP 6037.48 6369.77 4555.29 4738.97 0.00 12223.5

812223.58 0.00

TID 2165.91 636.34 432.70 1159.78 32.39 2042.77 2042.77 0.00TNSK 652.86 3.20 0.00 652.86 0.00 3.20 3.20 (0.00)TPWR 2745.87 4196.86 0.00 2058.72 0.00 4884.01 4884.01 0.00TSGT 15023.14 6452.27 3198.92 6722.60 4949.75 13001.9

913001.99 0.00

UAMP 1660.25 2234.61 219.94 0.00 0.00 4114.80 4114.80 0.00UMPA 9.14 1017.71 460.66 270.64 0.00 1216.87 1216.87 0.00VEA 0.00 458.49 0.00 0.00 0.00 458.49 458.49 0.00WAPA 23948.39 16324.85 339.74 15740.6

612189.4

912682.8

312682.83 (0.00)

WEMT 400.11 0.00 0.00 0.00 0.00 400.11 400.11 0.00Total 856042 494683 97952 459600 124041 864992 865036 43.80

61

Table 5: Three-Year Average3-year avg. G I RGI E RGE L Cross Check

Load

Company Generation Imports Remote Gen

ImportsExports Remote

GenExports

Energy

LoadLoad diff.

AEPC 2355 1429 0 2191 561 1032 1032 0AES 2111 1158 0 1158 0 2111 2111 0AESO 55677 2157 0 513 0 57321 57321 0ANHM 54 611 2787 916 0 2536 2536 0APS 57811 7697 2224 1833 30398 35485 35500 -15AVA 5036 10835 4011 7456 0 12426 12426 0AZUA 79 157 22 0 0 258 258 0BARC 0 353 0 353 0 0 0 0BCHA 47990 12243 0 5427 0 54805 54805 0BEAR (JP Morgan) 0 259 0 259 0 0 0 0BEPC 4798 1192 0 2723 0 3268 3268 0BHCE 262 1801 0 148 0 1914 1914 0BHPL 2611 1753 540 1490 84 3330 3330 0BPA 105791 23897 63 84611 0 45139 45139 0BURB 1612 1949 609 1868 1121 1180 1180 0CALP 34948 0 0 34948 0 0 0 0CAWC 0 2600 0 0 0 2600 2600 0CCG 61 8899 0 8960 0 0 0 0CDWR 4215 5261 1657 4494 108 6532 6532 0CEI 0 701 0 701 0 0 0 0CEOE 2693 0 0 2693 0 0 0 0CGX 32 0 0 32 0 0 0 0CFE 11491 280 0 676 328 10768 10768 0CHPD 8057 341 0 5165 0 3232 3232 0COSL 0 102 0 0 0 102 102 0CRGL 0 6456 0 6456 0 0 0 0CSU 4736 566 0 633 0 4668 4668 0DBET 0 830 0 830 0 0 0 0DEGS 237 0 0 237 0 0 0 0DGT 4315 1727 0 3487 134 2421 2421 0DOPD 3678 380 182 1476 2098 666 666 0DYN 7092 0 0 7092 0 0 0 0EMC 11613 320 0 150 0 11784 11784 0EPE 2639 3431 5504 3766 0 7808 7808 0EWEB 629 4557 88 2717 0 2556 2556 0FARM 730 296 259 63 0 1222 1222 0FBC 5801 2438 0 3269 0 4969 4969 0FPLE 1615 0 0 1615 0 0 0 0GCPD 8766 3410 0 4566 3727 3883 3883 0GLEN 190 1046 260 311 0 1186 1186 0HGC 2603 0 0 2603 0 0 0 0HHWP (CCSF) 1493 155 0 552 0 1097 1097 0IID 854 6858 309 4381 0 3640 3640 0IPC 8913 8345 7021 7085 304 16891 16891 0LAC 317 178 74 26 0 543 543 0

62

3-year avg. G I RGI E RGE L Cross Check Load



GenExports

Energy

LoadLoad diff.

LDWP 23034 22418 6455 18964 5938 27005 27005 0LMUD 0 143 0 0 0 143 143 0MCPI 0 1583 0 1583 0 0 0 0MEID 0 462 246 12 246 449 449 0MID 585 1789 300 92 0 2582 2582 0MLCI 0 34931 0 34931 0 0 0 0MWD 0 764 1294 0 0 2058 2058 0MWEC 0 1658 0 1658 0 0 0 0NAPG 443 0 0 443 0 0 0 0NAT 270 0 0 270 0 0 0 0NCPA 1346 1528 0 39 735 2100 2100 0NEVP 29728 7716 3735 320 6547 34312 34312 0NRG 2474 0 0 2474 0 0 0 0NWMT 23758 3331 0 4847 10238 12005 12005 0OCES 128 0 0 128 0 0 0 0PAC 56878 38069 17460 52403 1930 58075 58075 0PASA 113 352 1003 209 0 1260 1260 0PG&E 28590 59265 0 1823 0 86032 86032 0PGE 11434 12958 2585 8282 565 18131 18131 0PGR 4763 0 0 4763 0 0 0 0PNM 15796 4233 2355 3016 9513 9854 9854 0POC 423 32 660 111 0 1004 1004 0PPLE 0 11221 328 11549 0 0 0 0PPLM 16828 0 0 5461 11367 0 0 0PPM 6259 0 0 6259 0 0 0 0PRPA 3534 766 0 1087 0 3212 3212 0PSCO 39044 10711 1049 3542 2572 44691 44691 0PSE 15236 25791 1949 11715 202 31059 31059 0PWX 0 25794 0 25794 0 0 0 0RDNG 94 717 15 0 0 825 825 0RVE 651 886 0 269 425 843 843 0RVSD 855 355 1409 153 0 2467 2467 0SCE 42967 38298 10888 3628 3376 85149 85149 0SCL 6390 9072 0 4950 370 10143 10143 0SDGE 7905 9139 3035 0 0 20079 20079 0SER 17283 0 0 17283 0 0 0 0SMUD 7312 5254 94 1241 0 11418 11418 0SNCL 505 2446 0 0 0 2951 2951 0SNPD 648 7972 0 1748 0 6872 6872 0SPP 9796 3496 0 105 1554 11632 11632 0SRP 29783 8726 9406 6987 12959 27970 27970 0STGP 328 816 0 1144 0 0 0 0TEP 6195 5212 4576 5011 0 10972 10972 0TID 1979 805 345 1045 12 2072 2072 0TNSK 710 3 0 711 0 2 2 0TPWR 2778 4098 0 1869 0 5006 5006 0TSGT 15241 6350 3177 10788 5137 8843 8843 0UAMP 1730 2177 243 0 0 4149 4149 0

63

3-year avg. G I RGI E RGE L Cross Check Load



GenExports

Energy

LoadLoad diff.

UMPA 10 1091 475 369 0 1206 1206 0VEA 0 469 0 0 0 469 469 0WAPA 26506 14220 372 12862 11259 16977 16977 0WEMT 431 0 0 0 0 431 431 0

Total 874664 513785 99064 491867 12381087182

1

Total Largest 441201 285777 61259 224783 3910552434

9

64

Table 6: Rankings for Three-Year Averages

Company Load Imp + RGI Exports Gen-RGE Average Ranking

Final Rankin

gAEPC 58 53 41 49 50.25 49AES 47 57 53 47 51.00 52AESO 4 43 64 2 28.25 20ANHM 44 35 57 79 53.75 56APS 8 19 44 9 20.00 15AVA 17 12 14 34 19.25 13AZUA 67 77 87 77 77.00 93BARC 72 71 67 82 73.00 85BCHA 5 14 21 4 11.00 6BEAR (JP Morgan) 72 75 72 82 75.25 89BEPC 37 56 36 35 41.00 34BHCE 51 46 77 70 61.00 66BHPL 36 42 50 45 43.25 39BPA 6 8 1 1 4.00 2BURB 56 38 43 63 50.00 48CALP 72 83 3 7 41.25 35CAWC 41 37 87 82 61.75 67CCG 72 24 12 78 46.50 44CDWR 29 27 28 39 30.75 22CEI 72 65 60 82 69.75 82CEOE 72 83 38 42 58.75 62CEPM 72 83 84 80 79.75 97CFE 23 74 61 18 44.00 41CHPD 38 72 22 23 38.75 30COSL 69 80 87 82 79.50 96CRGL 72 29 18 82 50.25 49CSU 32 67 62 37 49.50 47DBET 72 60 58 82 68.00 81DEGS 72 83 73 71 74.75 88DGT 46 48 33 38 41.25 35DOPD 62 68 51 52 58.25 61DYN 72 83 15 26 49.00 45EMC 19 73 76 17 46.25 43EPE 27 23 30 43 30.75 22EWEB 43 31 37 59 42.50 38FARM 53 69 82 56 65.00 76FBC 31 40 34 31 34.00 26FPLE 72 83 48 51 63.50 73GCPD 34 34 27 33 32.00 24GLEN 55 55 69 73 63.00 70HGC 72 83 39 44 59.50 63HHWP (CCSF) 57 78 63 53 62.75 69IID 35 26 29 55 36.25 28IPC 16 11 16 21 16.00 12LAC 63 76 85 68 73.00 85LDWP 12 5 6 12 8.75 3LMUD 68 79 87 82 79.00 95MCPI 72 50 49 82 63.25 72

65


Final Rankin

gMEID 65 64 86 97 78.00 94MID 42 44 81 61 57.00 59MLCI 72 4 4 82 40.50 33MWD 50 45 87 82 66.00 78MWEC 72 49 47 82 62.50 68NAPG 72 83 65 64 71.00 83NAT 71 82 70 69 73.00 85NCPA 48 52 83 60 60.75 65NEVP 9 18 68 10 26.25 19NRG 72 83 40 46 60.25 64NWMT 18 36 25 16 23.75 17OCES 72 83 78 74 76.75 92PAC 3 2 2 3 2.50 1PASA 52 54 74 75 63.75 75PG&E 1 1 45 8 13.75 9PGE 14 10 13 19 14.00 10PGR 72 83 26 36 54.25 57PNM 25 28 35 27 28.75 21POC 59 66 79 66 67.50 80PPLE 72 17 10 82 45.25 42PPLM 72 83 20 32 51.75 53PPM 72 83 19 28 50.50 51PRPA 39 62 55 40 49.00 45PSCO 7 16 32 6 15.25 11PSE 10 6 9 15 10.00 4PWX 72 7 5 82 41.50 37RDNG 61 63 87 76 71.75 84RVE 60 59 71 72 65.50 77RVSD 45 47 75 54 55.25 58SCE 2 3 31 5 10.25 5SCL 24 22 24 30 25.00 18SDGE 13 15 87 24 34.75 27SER 72 83 7 11 43.25 39SMUD 21 30 52 25 32.00 24SNCL 40 39 87 62 57.00 59SNPD 28 25 46 58 39.25 32SPP 20 33 80 22 38.75 30SRP 11 9 17 13 12.50 7STGP 72 61 54 67 63.50 73TEP 22 20 23 29 23.50 16TID 49 58 56 48 52.75 54TNSK 70 81 59 57 66.75 79TPWR 30 32 42 41 36.25 28TSGT 26 21 11 20 19.50 14UAMP 33 41 87 50 52.75 54UMPA 54 51 66 81 63.00 70VEA 64 70 87 82 75.75 91WAPA 15 13 8 14 12.50 7WEMT 66 83 87 65 75.25 89

66


Final Rankin

gTotal

67

Table 7: Rankings

Ranking for Energy Load (L) Ranking for Imports + RGI Ranking for Generation – RGE Ranking for Exports (E) Ranking for

Average

58 AEPC 1032 0.12% 53 AEPC 1429 0.23% 49 AEPC 1794 0.24% 41 AEPC 2191 0.45% 49 AEPC 50.25

47 AES 2111 0.24% 57 AES 1158 0.19% 47 AES 2111 0.28% 53 AES 1158 0.24% 52 AES 51.00

4 AESO 57321 6.57% 43 AESO 2157 0.35% 2 AESO 55677 7.42% 64 AESO 513 0.10% 20 AESO 28.25

44 ANHM 2536 0.29% 35 ANHM 3398 0.55% 79 ANHM 54 0.01% 57 ANHM 916 0.19% 56 ANHM 53.75

8 APS 35485 4.07% 19 APS 9921 1.62% 9 APS 27412 3.65% 44 APS 1833 0.37% 15 APS 20.00

17 AVA 12426 1.43% 12 AVA 14846 2.42% 34 AVA 5036 0.67% 14 AVA 7456 1.52% 13 AVA 19.25

67 AZUA 258 0.03% 77 AZUA 179 0.03% 77 AZUA 79 0.01% 87 AZUA 0 0.00% 93 AZUA 77.00

72 BARC 0 0.00% 71 BARC 353 0.06% 82 BARC 0 0.00% 67 BARC 353 0.07% 85 BARC 73.00

5 BCHA 54805 6.29% 14 BCHA 12243 2.00% 4 BCHA 47990 6.39% 21 BCHA 5427 1.10% 6 BCHA 11.00

72 BEAR (JP Morgan)

0 0.00% 75 BEAR (JP Morgan)




75.25

37 BEPC 3268 0.37% 56 BEPC 1192 0.19% 35 BEPC 4798 0.64% 36 BEPC 2723 0.55% 34 BEPC 41.00

51 BHCE 1914 0.22% 46 BHCE 1801 0.29% 70 BHCE 262 0.03% 77 BHCE 148 0.03% 66 BHCE 61.00

36 BHPL 3330 0.38% 42 BHPL 2293 0.37% 45 BHPL 2527 0.34% 50 BHPL 1490 0.30% 39 BHPL 43.25

6 BPA 45139 5.18% 8 BPA 23959 3.91% 1 BPA 105791 14.09% 1 BPA 84611 17.20% 2 BPA 4.00

56 BURB 1180 0.14% 38 BURB 2557 0.42% 63 BURB 491 0.07% 43 BURB 1868 0.38% 48 BURB 50.00

72 CALP 0 0.00% 83 CALP 0 0.00% 7 CALP 34948 4.65% 3 CALP 34948 7.11% 35 CALP 41.25

41 CAWC 2600 0.30% 37 CAWC 2600 0.42% 82 CAWC 0 0.00% 87 CAWC 0 0.00% 67 CAWC 61.75

72 CCG 0 0.00% 24 CCG 8899 1.45% 78 CCG 61 0.01% 12 CCG 8960 1.82% 44 CCG 46.50

29 CDWR 6532 0.75% 27 CDWR 6918 1.13% 39 CDWR 4107 0.55% 28 CDWR 4494 0.91% 22 CDWR 30.75

72 CEI 0 0.00% 65 CEI 701 0.11% 82 CEI 0 0.00% 60 CEI 701 0.14% 82 CEI 69.75

72 CEOE 0 0.00% 83 CEOE 0 0.00% 42 CEOE 2693 0.36% 38 CEOE 2693 0.55% 62 CEOE 58.75

72 CEPM 0 0.00% 83 CEPM 0 0.00% 80 CEPM 32 0.00% 84 CEPM 32 0.01% 97 CEPM 79.75

23 CFE 10768 1.24% 74 CFE 280 0.05% 18 CFE 11163 1.49% 61 CFE 676 0.14% 41 CFE 44.00

38 CHPD 3232 0.37% 72 CHPD 341 0.06% 23 CHPD 8057 1.07% 22 CHPD 5165 1.05% 30 CHPD 38.75

69 COSL 102 0.01% 80 COSL 102 0.02% 82 COSL 0 0.00% 87 COSL 0 0.00% 96 COSL 79.50

72 CRGL 0 0.00% 29 CRGL 6456 1.05% 82 CRGL 0 0.00% 18 CRGL 6456 1.31% 49 CRGL 50.25

32 CSU 4668 0.54% 67 CSU 566 0.09% 37 CSU 4736 0.63% 62 CSU 633 0.13% 47 CSU 49.50

72 DBET 0 0.00% 60 DBET 830 0.14% 82 DBET 0 0.00% 58 DBET 830 0.17% 81 DBET 68.00

72 DEGS 0 0.00% 83 DEGS 0 0.00% 71 DEGS 237 0.03% 73 DEGS 237 0.05% 88 DEGS 74.75

46 DGT 2421 0.28% 48 DGT 1727 0.28% 38 DGT 4181 0.56% 33 DGT 3487 0.71% 35 DGT 41.25

62 DOPD 666 0.08% 68 DOPD 561 0.09% 52 DOPD 1580 0.21% 51 DOPD 1476 0.30% 61 DOPD 58.25

72 DYN 0 0.00% 83 DYN 0 0.00% 26 DYN 7092 0.94% 15 DYN 7092 1.44% 45 DYN 49.00

19 EMC 11784 1.35% 73 EMC 320 0.05% 17 EMC 11613 1.55% 76 EMC 150 0.03% 43 EMC 46.25

27 EPE 7808 0.90% 23 EPE 8935 1.46% 43 EPE 2639 0.35% 30 EPE 3766 0.77% 22 EPE 30.75

43 EWEB 2556 0.29% 31 EWEB 4645 0.76% 59 EWEB 629 0.08% 37 EWEB 2717 0.55% 38 EWEB 42.50

53 FARM 1222 0.14% 69 FARM 555 0.09% 56 FARM 730 0.10% 82 FARM 63 0.01% 76 FARM 65.00

31 FBC 4969 0.57% 40 FBC 2438 0.40% 31 FBC 5801 0.77% 34 FBC 3269 0.66% 26 FBC 34.00

72 FPLE 0 0.00% 83 FPLE 0 0.00% 51 FPLE 1615 0.22% 48 FPLE 1615 0.33% 73 FPLE 63.50

34 GCPD 3883 0.45% 34 GCPD 3410 0.56% 33 GCPD 5039 0.67% 27 GCPD 4566 0.93% 24 GCPD 32.00

55 GLEN 1186 0.14% 55 GLEN 1307 0.21% 73 GLEN 190 0.03% 69 GLEN 311 0.06% 70 GLEN 63.00

72 HGC 0 0.00% 83 HGC 0 0.00% 44 HGC 2603 0.35% 39 HGC 2603 0.53% 63 HGC 59.50

57 HHWP (CCSF)

1097 0.13% 78 HHWP (CCSF)

155 0.03% 53 HHWP (CCSF)

1493 0.20% 63 HHWP (CCSF)

552 0.11% 69 HHWP (CCSF)

62.75

35 IID 3640 0.42% 26 IID 7167 1.17% 55 IID 854 0.11% 29 IID 4381 0.89% 28 IID 36.25

16 IPC 16891 1.94% 11 IPC 15367 2.51% 21 IPC 8609 1.15% 16 IPC 7085 1.44% 12 IPC 16.00

63 LAC 543 0.06% 76 LAC 252 0.04% 68 LAC 317 0.04% 85 LAC 26 0.01% 85 LAC 73.00

12 LDWP 27005 3.10% 5 LDWP 28873 4.71% 12 LDWP 17096 2.28% 6 LDWP 18964 3.86% 3 LDWP 8.75

68 LMUD 143 0.02% 79 LMUD 143 0.02% 82 LMUD 0 0.00% 87 LMUD 0 0.00% 95 LMUD 79.00

68


Average

72 MCPI 0 0.00% 50 MCPI 1583 0.26% 82 MCPI 0 0.00% 49 MCPI 1583 0.32% 72 MCPI 63.25

65 MEID 449 0.05% 64 MEID 708 0.12% 97 MEID -246 -0.03% 86 MEID 12 0.00% 94 MEID 78.00

42 MID 2582 0.30% 44 MID 2089 0.34% 61 MID 585 0.08% 81 MID 92 0.02% 59 MID 57.00

72 MLCI 0 0.00% 4 MLCI 34931 5.70% 82 MLCI 0 0.00% 4 MLCI 34931 7.10% 33 MLCI 40.50

50 MWD 2058 0.24% 45 MWD 2058 0.34% 82 MWD 0 0.00% 87 MWD 0 0.00% 78 MWD 66.00

72 MWEC 0 0.00% 49 MWEC 1658 0.27% 82 MWEC 0 0.00% 47 MWEC 1658 0.34% 68 MWEC 62.50

72 NAPG 0 0.00% 83 NAPG 0 0.00% 64 NAPG 443 0.06% 65 NAPG 443 0.09% 83 NAPG 71.00

71 NAT 0 0.00% 82 NAT 0 0.00% 69 NAT 270 0.04% 70 NAT 270 0.05% 85 NAT 73.00

48 NCPA 2100 0.24% 52 NCPA 1528 0.25% 60 NCPA 611 0.08% 83 NCPA 39 0.01% 65 NCPA 60.75

9 NEVP 34312 3.94% 18 NEVP 11451 1.87% 10 NEVP 23180 3.09% 68 NEVP 320 0.07% 19 NEVP 26.25

72 NRG 0 0.00% 83 NRG 0 0.00% 46 NRG 2474 0.33% 40 NRG 2474 0.50% 64 NRG 60.25

18 NWMT 12005 1.38% 36 NWMT 3331 0.54% 16 NWMT 13520 1.80% 25 NWMT 4847 0.99% 17 NWMT 23.75

72 OCES 0 0.00% 83 OCES 0 0.00% 74 OCES 128 0.02% 78 OCES 128 0.03% 92 OCES 76.75

3 PAC 58075 6.66% 2 PAC 55530 9.06% 3 PAC 54948 7.32% 2 PAC 52403 10.65% 1 PAC 2.50

52 PASA 1260 0.14% 54 PASA 1356 0.22% 75 PASA 113 0.02% 74 PASA 209 0.04% 75 PASA 63.75

1 PG&E 86032 9.87% 1 PG&E 59265 9.67% 8 PG&E 28590 3.81% 45 PG&E 1823 0.37% 9 PG&E 13.75

14 PGE 18131 2.08% 10 PGE 15543 2.54% 19 PGE 10870 1.45% 13 PGE 8282 1.68% 10 PGE 14.00

72 PGR 0 0.00% 83 PGR 0 0.00% 36 PGR 4763 0.63% 26 PGR 4763 0.97% 57 PGR 54.25

25 PNM 9854 1.13% 28 PNM 6588 1.07% 27 PNM 6282 0.84% 35 PNM 3016 0.61% 21 PNM 28.75

59 POC 1004 0.12% 66 POC 693 0.11% 66 POC 423 0.06% 79 POC 111 0.02% 80 POC 67.50

72 PPLE 0 0.00% 17 PPLE 11549 1.88% 82 PPLE 0 0.00% 10 PPLE 11549 2.35% 42 PPLE 45.25

72 PPLM 0 0.00% 83 PPLM 0 0.00% 32 PPLM 5461 0.73% 20 PPLM 5461 1.11% 53 PPLM 51.75

72 PPM 0 0.00% 83 PPM 0 0.00% 28 PPM 6259 0.83% 19 PPM 6259 1.27% 51 PPM 50.50

39 PRPA 3212 0.37% 62 PRPA 766 0.12% 40 PRPA 3534 0.47% 55 PRPA 1087 0.22% 45 PRPA 49.00

7 PSCO 44691 5.13% 16 PSCO 11760 1.92% 6 PSCO 36472 4.86% 32 PSCO 3542 0.72% 11 PSCO 15.25

10 PSE 31059 3.56% 6 PSE 27740 4.53% 15 PSE 15034 2.00% 9 PSE 11715 2.38% 4 PSE 10.00

72 PWX 0 0.00% 7 PWX 25794 4.21% 82 PWX 0 0.00% 5 PWX 25794 5.24% 37 PWX 41.50

61 RDNG 825 0.09% 63 RDNG 732 0.12% 76 RDNG 94 0.01% 87 RDNG 0 0.00% 84 RDNG 71.75

60 RVE 843 0.10% 59 RVE 886 0.14% 72 RVE 226 0.03% 71 RVE 269 0.05% 77 RVE 65.50

45 RVSD 2467 0.28% 47 RVSD 1764 0.29% 54 RVSD 855 0.11% 75 RVSD 153 0.03% 58 RVSD 55.25

2 SCE 85149 9.77% 3 SCE 49186 8.03% 5 SCE 39591 5.27% 31 SCE 3628 0.74% 5 SCE 10.25

24 SCL 10143 1.16% 22 SCL 9072 1.48% 30 SCL 6020 0.80% 24 SCL 4950 1.01% 18 SCL 25.00

13 SDGE 20079 2.30% 15 SDGE 12174 1.99% 24 SDGE 7905 1.05% 87 SDGE 0 0.00% 27 SDGE 34.75

72 SER 0 0.00% 83 SER 0 0.00% 11 SER 17283 2.30% 7 SER 17283 3.51% 39 SER 43.25

21 SMUD 11418 1.31% 30 SMUD 5348 0.87% 25 SMUD 7312 0.97% 52 SMUD 1241 0.25% 24 SMUD 32.00

40 SNCL 2951 0.34% 39 SNCL 2446 0.40% 62 SNCL 505 0.07% 87 SNCL 0 0.00% 59 SNCL 57.00

28 SNPD 6872 0.79% 25 SNPD 7972 1.30% 58 SNPD 648 0.09% 46 SNPD 1748 0.36% 32 SNPD 39.25

20 SPP 11632 1.33% 33 SPP 3496 0.57% 22 SPP 8241 1.10% 80 SPP 105 0.02% 30 SPP 38.75

11 SRP 27970 3.21% 9 SRP 18132 2.96% 13 SRP 16824 2.24% 17 SRP 6987 1.42% 7 SRP 12.50

72 STGP 0 0.00% 61 STGP 816 0.13% 67 STGP 328 0.04% 54 STGP 1144 0.23% 73 STGP 63.50

22 TEP 10972 1.26% 20 TEP 9788 1.60% 29 TEP 6195 0.83% 23 TEP 5011 1.02% 16 TEP 23.50

49 TID 2072 0.24% 58 TID 1150 0.19% 48 TID 1967 0.26% 56 TID 1045 0.21% 54 TID 52.75

70 TNSK 2 0.00% 81 TNSK 3 0.00% 57 TNSK 710 0.09% 59 TNSK 711 0.14% 79 TNSK 66.75

30 TPWR 5006 0.57% 32 TPWR 4098 0.67% 41 TPWR 2778 0.37% 42 TPWR 1869 0.38% 28 TPWR 36.25

26 TSGT 8843 1.01% 21 TSGT 9528 1.55% 20 TSGT 10104 1.35% 11 TSGT 10788 2.19% 14 TSGT 19.50

33 UAMP 4149 0.48% 41 UAMP 2419 0.39% 50 UAMP 1730 0.23% 87 UAMP 0 0.00% 54 UAMP 52.75

54 UMPA 1206 0.14% 51 UMPA 1566 0.26% 81 UMPA 10 0.00% 66 UMPA 369 0.08% 70 UMPA 63.00

64 VEA 469 0.05% 70 VEA 469 0.08% 82 VEA 0 0.00% 87 VEA 0 0.00% 91 VEA 75.75

15 WAPA 16977 1.95% 13 WAPA 14592 2.38% 14 WAPA 15247 2.03% 8 WAPA 12862 2.61% 7 WAPA 12.50

66 WEMT 431 0.05% 83 WEMT 0 0.00% 65 WEMT 431 0.06% 87 WEMT 0 0.00% 89 WEMT 75.25

69


Average

871821 100.00%

612849 100.00%

750854 100.00%

491867 100.00%

70

Western Electricity Coordinating Council GuidelineUNSCHEDULED FLOW MITIGATION - CONTROLLABLE

DEVICES COMPENSATIONGUIDELINE

Date:

Document Title: Unscheduled Flow Mitigation Controllable DevicesCompensation GuidelineCategory Guideline

Document date July 30, 2001Adopted/approved byDate adopted/approvedCustodian (entityresponsible for maintenance and upkeep)Stored/filed Physical location:

Web URL:Previous name/number (if any)Status ( ) in effect

( ) usable, minor formatting/editing required( ) modification needed( ) superseded by( ) other( ) obsolete/archived)

71

ECC Guideline UNSCHEDULED FLOW MITIGATION - CONTROLLABLE DEVICES COMPENSATION

GUIDELINEDate:

IntroductionThe Western Electricity Coordinating Council (WECC) Unscheduled Flow Mitigation Policy (Policy) provides compensation for the owner of a Controllable Device within the WECC interconnected system if the owner agrees to operate the Controllable Device as part of the WECC Controllable Devices Coordinated Operating Process. The owner will then be entitled to be compensated for a portion of its annual fixed and actual operation and maintenance (O&M) costs of ownership associated with such Controllable Device.

GuidelineThe WECC Controllable Devices Compensation Guideline (Guideline) addresses the prescribed method of determining the compensation to be paid to the owners of the Qualified Controllable Devices for their use in controlling Unscheduled Flow (USF). The entities that the Guideline applies to are listed below:

Transmission Owner


Guideline DetailsCompensation to phase shifter owners is split into two parts:

1. A minimum component to compensate the owners for making their devices available for USF mitigation.

2. An additional component based on actual use of the devices in controlling USF.

The overall approach reduces the annual costs members pay when coordinated Controllable Device operation is minimal and ensures that no one pays more than 1.15 times their 1995 allocation when the phase shifters are used more than 1,000 hours.

WECC CONTROLLABLE DEVICES COMPENSATION GUIDELINEThe WECC USF Policy uses the following approach for Controllable Device compensation:

1. Provide for a minimum payment (fixed payment component or "reservation fee") of $500,000 to device owners, whether the devices are used or not, subject to adjustment as Controllable Devices are added to or deleted from the Qualified Controllable Devices list. Therefore, in a year with no coordinated phase-shifter operation, total revenue would drop to 23% of the 1995 level.

2. Provide for increased payments when devices are used, using an hourly rate based on the devices’ annual fixed and O&M costs, and the maximum hours (4,000) per year the Controllable Devices could be required to operate according to the original Policy.

3. Determine total device compensation as the $500,000 minimum payment (adjusted up or down as Qualified Controllable Devices are added or removed) plus the hourly rate times the actual hours of coordinated device operation.

Parts I and II set forth the portion of annual fixed cost (levelized based on the original installed investment cost) and the variable O&M costs (estimated at two percent, but using actual costs where available) for the existing Controllable Devices and illustrates the methodology used in deriving an effectiveness factor for each Controllable Device.

Part II of the table sets forth the methodology for determining each Controllable Device's effectiveness factor on each of the existing Qualified Transfer Paths, based on the following computations:

A Controllable Device's effectiveness (for phase shifters, MW per degree) on each of the Qualified Transfer Paths is presented in Part II, on the first line associated with each device. This effectiveness is determined from incremental power flows using approved WECC base cases representing the appropriate system topology and time period.

This percent of effectiveness is then multiplied by the Controllable Device's control range (the first column – Control (Deg)) and divided by the Qualified Transfer Path's rating (listed under each path heading) to arrive at the percentage effectiveness (Average % Control) of each Controllable Device on each Qualified Transfer Path.

The Average % Control is then divided by the Effectiveness Test (e.g., 0.15). The Effectiveness Test is the reference percentage effectiveness deemed to provide sufficient control of Unscheduled Flow so as to qualify for 100 percent compensation.

The average percentage control factor for each Controllable Device is equal to the simple average of that Controllable Device's normalized percentage effectiveness on all of the Qualified Transfer Paths.

73

Part III of the table illustrates the hourly rate derivation and the resulting total compensation for various scenarios of Controllable Device operation.

The Effectiveness Test value of 15 percent was selected because it represents a high degree of control of historical Unscheduled Flow; i.e., an average of 700 MW of control of major loop Unscheduled Flow on the two major loop Transfer Paths (Path 66 and TOT2). It was agreed to assess the second and succeeding Policy Year's actual O&M costs for the previous Policy Year at the end of each calendar year thereafter. Thus, actual O&M incurred in any Policy Year will be collected during the following Policy Year.

As new Controllable Devices or Transfer Paths are qualified, requalified, or deleted the effectiveness factors and associated compensation levels will be established by the methodology described above. However, in order to provide the revenue stability needed for investment decisions, once a compensation level for a Qualified Controllable Device has been established, it will not be reduced unless otherwise agreed upon by the UFAS. New Qualified Controllable Devices will receive compensation commensurate with the increase in Unscheduled Flow control provided by each new Qualified Controllable Device. Additionally, a minimum compensation level for a Controllable Device is established equal to the greater of 10 percent of the annual cost or $50,000. Finally, the compensation level is subject to adjustment pursuant to the formula set forth in Section 7.6 of the Policy.

Add ing Ne w De vices to t he P o licy

The Policy provides for adding Controllable Devices eligible for compensation for coordinated operation. The UFAS has developed a procedure for Controllable Device Qualification in accordance with the Policy's provisions. Adding a device to the list for compensation will increase the total cost of the Policy and the applicable entities in the medium and large categories will see allocation increases to cover a large percent of the additional cost, unless caps are implemented. If increases over the applicable entities’ 1995 cost allocations are to be avoided, adding new devices will “dilute” the revenue to the existing device owners.

With the adoption of the allocation methodology (described in the document titled USF Mitigation Policy Annual Member Dues Guideline) the following compensation procedure is adopted as well. To avoid diluting the compensation available for device owners when a new Qualified Controllable Device is added to the Policy, the total minimum payment to device owners should be increased. The minimum compensation under the Policy for any device installation is the greater of 10% of the annual cost or $50,000. The total minimum payment should be increased by a corresponding amount.

Upon the addition of the first new device, the minimum payment level would become $550,000. Individual member cost allocation would then be calculated according to the guideline described in the document titled USF Mitigation Policy Annual Member Dues Guideline. If that dues allocation guideline results in a significant revenue shortfall, the shortfall itself would be allocated to the applicable entities in proportion to their original allocation. For example: suppose the original dues allocation has a target of $550,000 (zero hours of device use), but the final dues allocation is only $500,000 (a $50,000 shortfall) due to the ceiling on

74

allocations. A small entity with the 90% ceiling would have been allocated $900. As a percent of the total dues allocation, the $900 allocation is 0.16%. The entity’s dues allocation would be increased by 0.16% of $50,000, or by $80. A large applicable entity might have a dues allocation of $66,000 (12% of the total). That entity’s dues allocation would be increased by 12% of $50,000, or $6,000. In this scenario, large entities would still be well under their 1995 actual dues allocation.

The foregoing example is for adding one Qualified Controllable Device to the system. The addition of future devices eventually may cause the maximum annual entity’s cost allocations to increase above these levels. However, the addition of new transmission lines also tends to dilute the effectiveness factors of existing devices and reduce their revenue entitlement. This will partially offset the cost impact of new devices.

Dele tin g Qua lif ied Co ntrollab le Devices Fro m th e P o licy

If a Qualified Controllable Device is deleted from the Policy, the minimum payment will be reduced by the minimum payment for any device ($50,000). The deleted device's annual fixed and O&M costs will not be used in calculating the hourly rate of the remaining devices.

75

WECC PHASE SHIFTER

COMPENSATION PROPOSAL

15%/6.7%/2%

For PY 18 (CY 2012) with 2,784 hours PST operation

The following tables establish the actual cost and compensation factors. The modifications adopted by the NERC Board of Trustees on July 30, 1996 use a minimum total compensation level of $500,000 ($450,000 after Perkins and CalSub deleted) and add to that amount the hourly rate times the hours of actual use to arrive at total compensation.

WECC Cost:

WECC Fixed Cost mm$ =............................................5.771

WECC estimated O&M Cost mm$ =...........................1.743

WECC total annual cost...............................................7.513

Assumptions:

Average percent effectiveness (of all qualified path ratings) needed for 100 percent compensation =............................................................................6.4436%

Minimum % effectiveness to qualify for compensation =.............................................6.7%

Annual Operation & Maintenance cost as a % of Original Cost =..............................2.0%

Minimum annual compensation for qualifying phase shifters (mm$) =......................0.050

Spare phase shifter NOT funded initially. Annual cost estimated at $10 million and 10.76 percent.....................................................................................1.076

76

Part I

Phase-Shifter Owners Operator Original Lev. Annual Annual Average % Compensation 1st Year CY 2011 Plan

Year

DesignationCost mm$ Fixed Cost% Cost

mm$ Effectiveness Factor Cost mm$ O&M Cost mm$ Cost

mm$

[3] [4]

Tot 2A Western Western 28.400 10.76%[1] 3.056 73.54% 73.54%

2.247 1.1196 2.289

Pinto PAC/SCE/PG&E PAC 17.000 13.77%[2] 2.341 81.74% 81.74%

1.913 0.0111 1.925

Sigurd PAC/SCE/PG&E PAC 9.900 13.77%[2] 1.363 14.26% 14.26%

0.194 0.0141 0.209

Harry Allen PAC/NEVP NPC 9.600 13.77%[2] 1.322 57.14% 57.14%

0.755 0.5891 1.344

Billings MPC MPC 5.215 14.72%[2] 0.768 53.12% 53.12%

0.408 0.0023 0.410

Crossover Western MPC 5.400 8.80%[1] 0.475 53.12% 53.12%

0.252 0.0066 0.259

Totals 75.515 9.325 WECC Cost=5.77

1 1.7428 6.436

[1] Levelized annual cost, tax free financing, includes debt and A&G.

[2] Levelized annual cost, taxable entity includes ROE prop tax and A&G................................1723.76 0.002

[3] Minimum compensation = the > of 10% of Levelized Annual cost or......$50,000

[4] Estimated at 2% of Original Cost.

Part II

6Qualified Path Control (MW per Degree)/% effectiveness

Control (Deg) Phase-Shifter

CA-OR InteriePath 66

Midwy-Vinct

Path 15

EORPath 21

FC WestPath 22

FC 345/500Path 23

Tot 1APath 30

Tot 3Path 36

TOT 2APath 31 Average

+/- Path Rating 4800 3900 5700 2325 1000 650 1680 690 % Control

30 Tot 2A 2.98500 -3.13500 -1.83000 4.52000 -2.32000 -7.03500% path effectiveness 29.0% 0.0% 0.0% 62.8% 85.2% 100.0% 64.3% 100.0% 73.54%

60 Pinto 3.20500 -4.53000 -2.59000 -1.72000 0.51000 1.71000% path effectiveness 62.2% 0.0% 0.0% 100.0% 100.0% 100.0% 28.3% 100.0% 81.74%

30 Sigurd 0.99500 0.43000 0.09500 -0.44000 0.11000 0.42000% path effectiveness 9.7% 0.0% 0.0% 8.6% 4.4% 31.5% 3.0% 28.3% 14.26%

30 Harry Allen 4.20000 2.43500 1.51000 -1.36000 0.20500 1.18500% path effectiveness 40.7% 0.0% 0.0% 48.8% 70.3% 97.4% 5.7% 80.0% 57.14%

35 Billings/Crossover 2.04500 -0.94500 -0.55000 -0.98500 -2.25000 -1.12500% path effectiveness 23.1% 0.0% 0.0% 22.1% 29.9% 82.3% 72.7% 88.6% 53.12%

Total MW Control 509 0 0 0 485 278 327 188 401 0% path effect. 100.0% 0.0% 0.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.00%

77

Part IIIHourly Rate Calculations

Hourly Rate = annual cost, less minimum payment, divided by 2000 hours.

Without O&M Cost With O&M Cost "Frozen" Value

Total Annual Cost =..........$2,508,026 Total Annual Cost =........$6,436,070 ........$4,750,338

Minimum Payment =.........$450,000 Minimum Payment =.......$450,000 ..............$450,000

Difference =......................$2,058,026 Difference =....................$5,986,070 ........$4,300,338

Hourly Rate =...................$1,029 Hourly Rate =..................$2,993 .......................$2,150

TOTAL COMPENSATION WITHOUT O&M Plan Yr 17 – CY 2011

OPERATION

Operation Operation Operation Operation Operation HRS/YR0 hrs/yr 100 hrs/yr 500 hrs/yr 1000 hrs/yr 2000 hrs/yr 2784

Variable Payment $0 $102,901 $514,506 $1,029,013 $2,058,026 $5,986,069.89Total ($550,000 +

Variable) $500,000 $552,901 $964,506 $1,479,013 $2,508,026 $6,436,069.89

TOTAL COMPENSATION WITH O&M

Operation Operation Operation Operation Operation

0 hrs/yr 100 hrs/yr 500 hrs/yr 1000 hrs/yr 2000 hrs/yr

Variable Payment $0 $299,303 $1,496,517 $2,993,035 $5,986,070Total ($500,000 +

Variable) $500,000 $749,303 $1,946,517 $3,443,035 $6,436,070

2013 unscheduled flow mitigation plan - combined … usfmp docs combined... · web viewdocument...

Documents