WECC Policy
Unscheduled Flow Mitigation Policy
Document name
Unscheduled Flow Mitigation Policy
Category
( ) Regional Reliability Standard
( ) Regional Criteria
(X) Policy
( ) Guideline
( ) Report or other
( ) Charter
Document date
Adopted/approved by
Unscheduled Flow Administrative
Subcommittee/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( ) superseded by _____________________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
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WECC Unscheduled Flow Mitigation Policy
Introduction
Unscheduled 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 Criteria
The 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
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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
4
1.
Recitals
This 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
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on Qualified Transfer Paths caused by excessive amounts of USF.
2.
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.
Term
The 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.
Definitions
The 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, backto- 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
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
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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.
As defined in NERC’s Glossary of Terms Used in Reliability Standards, updated April 20, 2009.
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4.
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.
Administration
4.1.
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 Committee
4.1.3. Unscheduled Flow Administrative Subcommittee (UFAS)
reporting to the WECC Operating Committee
4.1.4. WECC staff
4.2.
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
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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
9
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. Protocol
The 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 Deletion
6.1.
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.
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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:
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1
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.
9.
Unscheduled Flow Reduction
8.1.
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.
Annual Unscheduled Flow Dues Allocation
In 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 Resolution
10.1.
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 Liability
11.1.
Except for the obligation to make payments hereunder, this Policy shall
not create or be interpreted as creating any duty to, any standard of
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2
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 Rights
Any 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.
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Western Electricity Coordinating Council Guideline
Unscheduled Flow Reduction Guideline
Document name
Date: March 09, 2012
Unscheduled Flow Reduction Guideline
Category
( ) Regional reliability standard
( ) Regional criteria
( ) Policy
(X) Guideline
( ) Report or other
( ) Charter
Document date
January 26, 2012
Adopted/approved by
Operating Committee/WECC Board
Date adopted/approved
March 09, 2012/ March 15, 2012
Custodian (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)
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WECC Guideline:
UNSCHEDULED FLOW REDUCTION GUIDELINE
Introduction
The 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.
Guideline
The 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)
Transmission Operator
These entities may also be impacted by the Guideline:
Interchange Authority
Load-Serving Entity
Purchasing-Selling Entity
Transmission Service Provider
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5
WECC UNSCHEDULED FLOW REDUCTION GUIDELINE
The 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 Qualification
Requests 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;
and
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6

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 STEP.

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, Section 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.
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2. Transfer Path Requalification
If 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 Deletion
If 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
Path
a. 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.
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5. Controllable Device Qualification
a. 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
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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 Deletion
a. 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 Terms
a. 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.
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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
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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 are
exempt 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 Rules
a. 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
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2

BAs may arrange to provide relief called for by this Guideline in a manner
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.
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9. Action Steps
The 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. Actions Taken

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
order is detailed in Attachment A. The approval of USF reduction shall be
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issued prior to 30 minutes before the start of the hour for which it is to be in
effect.
b. Rapid Advancement of the Steps
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.
Guidance

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 Paths
With 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.
Step 3 Guidance
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 from
normal system operation (two paths encounter congestion simultaneously as
load and generation patterns change).
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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:
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Schedule #
P-66 (4175 MW)
Contribution %
P-36 (1424 MW)
Contribution %
Adjusted
Contribution %
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 according
to 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.
Comment
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.
Additional Guidance for Schedule Curtailments (two Qualified Paths
constrained)
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 Action
The Qualified Transfer Path Operator will continue to take actions necessary to
reduce Actual Flow to a level at or below the SOL.
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12. Term
This Guideline will remain in effect for the duration of the Policy.
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WECC UNSCHEDULED FLOW GUIDELINE
Attachment A: Summary of Curtailment Actions
Detailed Process
The process to determine the curtailment priority essentially divides Confirmed eTags 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 4 – Priority 1 on-path
Group 5 – Priority 2 (Transmission Product - code 2-NH) off-path
Group 6 – Priority 2 on-path
Group 7 – Priority 3 (Transmission Product - code 3-ND) off-path
Group 8 – Priority 3 on-path
Group 9 – Priority 4 (Transmission Product - code 4-NW) off-path
Group 10 – Priority 4 on-path
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Group 11 – Priority 5 (Transmission Product - code 5-NM) off-path
Group 12 – Priority 5 on-path
Group 13 – Priority 6 (Transmission Product - codes 6-NN and 6-CF) off-path
Group 14 – Priority 6 on-path
Group 15 – Priority 7 (Transmission Product - codes 7-F and 7-FN) off-path
Group 16 – Priority 7 on-path
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Exhibit A:
List Of Qualified Transfer Paths as of January 26, 2012
Path Path
Code Opr
Qualified Transfer Path
Qualifying
Direction *
Path Transfer
Capability-MW **
CCW (north-south)
4800
66
CISO
California-Oregon Intertie
Malin-Round Mt. 500-kV lines 1&2
Captain Jack-Olinda 500-kV line
22
APS
Four Corners-Central Arizona
Four Corners-Moenkopi 500-kV line
Four 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 138kV Meeker-Rangely 138-kV Bears EarsBonanza 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
CW (north-south)
1680
Sidney- Spring Canyon 230-kV line SidneySterling 115-kV line Cheyenne-Owl Creek 115kV line Cheyenne-Ault 230-kV line
*
**
Direction in which the Path is qualified to request USF relief:
CCW = Counterclockwise direction
CW = 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
Operating Committee
Date
March 9, 2012
WECC Board
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March 15, 2012
Western Electricity Coordinating Council Guideline
Unscheduled Flow Mitigation:
Establishing Annual Membership Dues Guideline
Date:
Document Title:
Category
Unscheduled Flow Mitigation for Establishing
Annual Membership Dues
Guideline
Document date
July 30, 2001
Adopted/approved by
Date adopted/approved
Custodian (entity
responsible 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)
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Western Electricity Coordinating Council Guideline
Unscheduled Flow Mitigation:
Establishing Annual Membership Dues Guideline
Date:
Introduction
This 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).
Guideline
The 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
Purchasing-Selling Entity
Transmission Operator
Transmission Service Provider
Guideline Details
The 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.
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
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.
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Western Electricity Coordinating Council Guideline
UNSCHEDULED FLOW MITIGATION
FOR ESTABLISHING ANNUAL MEMBERSHIP DUES
General
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.
Objectives
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.
Entity System Information
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:
3
5

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 those entities 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 allocation.
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.
Relative Ranking of WECC Entities (Large vs. Small)
3
6
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
3
7
to the cap on dues, the total may be less.”
Cost Allocation Among Entities
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
3
8
final allocation to no greater than 1995 final allocation plus 15 percent, in the 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.
Changes Required in 2001 to Recover Costs at up to 4,000 Hours of Coordinated
Qualified Controllable Device Operation
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.
3
9
TABLE OF MULTIPLIERS AND CAPS
Multipliers (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
Multiplier
Cap
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
1.350
1.369
1.388
1.407
1.426
1.445
1.464
1.483
1.502
1.521
1.540
1.559
1.578
1.597
1.616
1.635
1.654
1.673
1.692
1.711
1.730
115.000%
115.671%
116.479%
119.482%
122.513%
125.643%
129.021%
132.440%
135.929%
139.444%
143.058%
146.617%
150.337%
154.127%
157.893%
161.847%
165.777%
169.725%
173.647%
177.454%
181.178%
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.
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
4
0
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.

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
Dues Allocation Changes Upon Losing Entities
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, but using a cap so they will not see a significant increase over their 1995
dues allocation. 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.
Dues Allocation Changes Upon Adding Entities
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.
4
1
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
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.
Procedure for Handling Significant Growth and Mergers
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.
Adding New Devices to the Policy
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
4
2
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
also
reduce costs.
Procedure for Estimating Annual Energy
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.
Alternative to Estimating the Energy
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
4
3
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
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.
Ranking Process
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.
Initial and Final Cost Allocations
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.
4
4
WECC USF MITIGATION POLICY (ANNUAL MEMBERSHIP DUES)
Table 1
Unscheduled Flow Dues Scenarios - Increasing Coordinated Operation Hours To
4000
Multiply 13 largest
entities' Interim
Allocation 2) by:
Entity (1995)
AEPC
AES
ANHM
APS
APX
ATCO
AVA
AXIA
BCHA
BEPC
BHPL
BPA
BPAP
BURB
CALP
CDWR
CFE
CHPD
CINE
CISO
CPS (EMMT)
CPSI
CPX
CRGL
CSU
DENA
DETM
DGT
DOPD
DYN
EAL
EPE
EPMI
EWEB
FARM
FPLE
GCPD
GLEN
HHWP
IGI
IID
IPC
LAC
LDWP
MID
MIEC
MIR
MPC
MWD
1995
Allocation 1)
$1,000
$4,000
$1,000
$69,663
$4,000
$0
$35,000
$4,000
$168,187
$5,330
$963
$331,518
$0
$719
$975
$10,844
$703
$3,122
$4,000
$555,249
$4,000
$4,000
$4,000
$4,000
$1,000
$4,000
$11,000
$1,000
$1,000
$1,000
$1,000
$9,654
$20,000
$1,000
$362
$4,000
$4,889
$677
$4,000
$4,000
$7,634
$30,000
$323
$98,283
$1,000
$4,000
$4,000
$46,614
$1,000
> 135.0%
Cap 115%
of 1995
2000 Hrs
$1,150
$2,411
$1,150
$80,112
$0
$0
$40,250
$2,243
$178,075
$6,130
$1,108
$260,444
$0
$827
$1,121
$12,471
$605
$3,590
$1,403
$592,976
$4,600
$120
$4,600
$394
$1,150
$1,875
$12,650
$1,150
$1,150
$1,150
$0
$11,102
$23,000
$1,150
$416
$0
$5,622
$779
$4,441
$120
$8,779
$34,500
$371
$97,777
$1,150
$218
$4,600
$23,200
$1,150
144.5%
Cap 126%
of 1995
2500 Hrs
$1,256
$2,842
$1,256
$87,527
$0
$0
$43,975
$2,644
$211,316
$6,697
$1,210
$328,587
$0
$904
$1,225
$13,625
$713
$3,923
$1,654
$697,631
$5,026
$142
$5,026
$464
$1,256
$2,210
$13,821
$1,256
$1,256
$1,256
$0
$12,130
$25,129
$1,256
$455
$0
$6,143
$851
$5,026
$141
$9,591
$37,693
$406
$123,359
$1,256
$257
$5,026
$27,346
$1,256
4
5
154.0%
Cap 143%
of 1995
3000 Hrs
$1,431
$3,300
$1,431
$99,658
$0
$0
$50,070
$3,070
$240,605
$7,625
$1,378
$406,610
$0
$1,029
$1,395
$15,514
$828
$4,466
$1,920
$794,328
$5,722
$165
$5,722
$539
$1,431
$2,566
$15,736
$1,431
$1,431
$1,431
$0
$13,811
$28,612
$1,431
$518
$0
$6,994
$969
$5,722
$164
$10,920
$42,917
$462
$140,601
$1,431
$298
$5,722
$31,751
$1,431
163.5%
Cap 162%
of 1995
3500 Hrs
$1,618
$3,788
$1,618
$112,747
$0
$0
$56,646
$3,524
$272,206
$8,626
$1,559
$495,578
$0
$1,164
$1,578
$17,551
$951
$5,053
$2,204
$898,653
$6,474
$189
$6,474
$619
$1,618
$2,946
$17,803
$1,618
$1,618
$1,618
$0
$15,625
$32,369
$1,618
$586
$0
$7,913
$1,096
$6,474
$188
$12,355
$48,554
$522
$159,068
$1,618
$343
$6,474
$36,450
$1,618
173.0%
Cap 181%
of 1995
4000 Hrs
$1,812
$4,304
$1,812
$126,214
$0
$0
$63,412
$4,004
$304,718
$9,657
$1,745
$595,767
$0
$1,304
$1,766
$19,647
$1,080
$5,656
$2,504
$1,005,989
$7,247
$215
$7,247
$703
$1,812
$3,347
$19,930
$1,812
$1,812
$1,812
$0
$17,491
$36,236
$1,812
$656
$0
$8,858
$1,227
$7,247
$214
$13,830
$54,353
$585
$178,067
$1,812
$389
$7,247
$41,413
$1,812
Multiply 13 largest
entities' Interim
Allocation 2) by:
Entity (1995)
MWEC
NAPG
NCPA
NEVP
OXGC (CAE)
PACE
PACW
PASA
PECO (EXPT)
PG&E
PGE
PNEG
PNM
POPD
PPA
PPLM
PRPA
PSC
PSE
PWX
RDNG
REI
RVSD
SCE
SCL
SDGE
SETC
SFG
SMUD
SNCL
SNPD
SPP
SRP
TANC
TAUC
TCP
TEP
TID
TNP
TNSK
TPWR
TSGT
UAMP
UMPA
USBR
VERN
WAPA
WEMT
WKP
WPE
Total
1995
Allocation 1)
$1,000
$1,000
$4,000
$14,177
$473
$128,788
$130,380
$827
$4,000
$257,856
$80,417
$1,000
$8,458
$1,000
$1,000
$4,000
$3,941
$86,513
$79,872
$4,000
$456
$4,000
$627
$279,578
$12,254
$17,815
$4,000
$406
$12,342
$1,000
$8,223
$8,303
$80,004
$0
$328
$4,000
$12,531
$823
$922
$431
$8,488
$10,543
$1,000
$1,000
$0
$723
$118,610
$8,000
$5,721
$751
$2,893,290
> 135.0%
Cap 115%
of 1995
2000 Hrs
$612
$128
$4,600
$16,303
$544
$87,193
$87,744
$951
$4,600
$0
$92,480
$953
$9,727
$1,150
$1,150
$0
$4,532
$80,984
$81,849
$4,600
$524
$1,624
$721
$0
$14,092
$0
$4,600
$467
$14,193
$1,150
$9,456
$9,548
$77,095
$0
$0
$1
$14,411
$946
$1,060
$496
$9,761
$12,124
$1,150
$1,150
$0
$831
$68,020
$3,067
$6,579
$864
$2,167,313
144.5%
Cap 126%
of 1995
2500 Hrs
$721
$151
$5,026
$17,812
$594
$102,774
$103,424
$1,039
$5,026
$0
$101,039
$1,123
$10,627
$1,256
$1,256
$0
$4,951
$102,172
$100,354
$5,026
$573
$1,915
$788
$0
$15,396
$0
$5,026
$510
$15,507
$1,256
$10,332
$10,432
$97,266
$0
$0
$1
$15,744
$1,034
$1,158
$542
$10,665
$13,247
$1,256
$1,256
$0
$908
$85,817
$10,051
$7,188
$944
$2,569,205
154.0%
Cap 143%
of 1995
3000 Hrs
$837
$175
$5,722
$20,281
$676
$119,332
$120,087
$1,184
$5,722
$0
$115,044
$1,304
$12,100
$1,431
$1,431
$0
$5,638
$123,763
$114,264
$5,722
$652
$2,223
$897
$0
$17,530
$0
$5,722
$581
$17,656
$1,431
$11,764
$11,878
$114,452
$0
$0
$1
$17,927
$1,177
$1,319
$617
$12,143
$15,083
$1,431
$1,431
$0
$1,034
$106,195
$11,445
$8,184
$1,074
$2,983,146
163.5%
Cap 162%
of 1995
3500 Hrs
$961
$201
$6,474
$22,945
$765
$136,992
$137,858
$1,339
$6,474
$0
$130,153
$1,497
$13,689
$1,618
$1,618
$0
$6,378
$140,018
$129,271
$6,474
$738
$2,552
$1,015
$0
$19,833
$0
$6,474
$657
$19,975
$1,618
$13,309
$13,438
$129,484
$0
$0
$2
$20,281
$1,332
$1,492
$698
$13,738
$17,064
$1,618
$1,618
$0
$1,170
$129,431
$12,948
$9,259
$1,215
$3,424,604
173.0%
Cap 181%
of 1995
4000 Hrs
$1,092
$228
$7,247
$25,685
$856
$155,644
$156,628
$1,499
$7,247
$0
$145,699
$1,701
$15,324
$1,812
$1,812
$0
$7,140
$156,742
$144,711
$7,247
$826
$2,900
$1,136
$0
$22,202
$0
$7,247
$736
$22,361
$1,812
$14,898
$15,043
$144,950
$0
$0
$2
$22,703
$1,491
$1,670
$781
$15,378
$19,102
$1,812
$1,812
$0
$1,310
$155,597
$14,494
$10,365
$1,361
$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,
4
6
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.
4
7
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)
I=RGI+E
L+G RGE
L Only
Ave.
all 115
Ave. top
13
Rank
Member
Initial
Allocation
New 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%
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%
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%
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
$5,414.83
CCG
1.62%
0.00%
0.00%
0.54%
44
$34,764
$15,000
$20,306
$20,305.61
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
2.72%
8.21%
14.63%
4
8
I=RGI+E
L+G RGE
L Only
Ave.
all 115
Ave. top
13
Rank
Member
Initial
Allocation
New RGE
Allocation
Interim
Allocation
Final
Allocation
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
$5,414.83
HHWP
(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%
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%
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
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%
PAC
9.77%
6.97%
6.66%
7.80%
PASA
0.14%
0.08%
0.14%
0.12%
PG&E
5.53%
7.06%
9.87%
7.49%
PGE
2.16%
1.79%
2.08%
2.01%
PGR
0.43%
0.29%
0.00%
PNM
0.87%
0.99%
POC
0.07%
0.09%
PPLE
2.09%
PPLM
PPM
3.30%
6.09%
92
$417
$4,000
$417
$417.10
1
$501,941
$259,168
$350,837
$350,837.10
75
$7,953
$827
$1,120
$1,119.91
13.15%
9
$481,881
$257,856
$349,062
$349,061.72
3.58%
10
$129,225
$80,417
$108,862
$108,861.73
0.24%
57
$15,547
$4,000
$5,415
$5,414.83
1.13%
1.00%
21
$64,235
$8,458
$11,450
$11,449.58
0.12%
0.09%
80
$5,919
$4,000
$5,415
$5,414.83
0.00%
0.00%
0.70%
42
$44,858
$4,000
$5,415
$5,414.83
0.49%
0.34%
0.00%
0.28%
53
$17,825
$4,000
$5,415
$5,414.83
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%
11
$246,996
$86,513
$117,113
$117,112.99
14.05%
6.65%
4
9
I=RGI+E
L+G RGE
L Only
Ave.
all 115
Ave. top
13
5.93%
Rank
Member
Initial
Allocation
New RGE
Allocation
Interim
Allocation
Final
Allocation
PSE
3.57%
2.84%
3.56%
3.32%
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%
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
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%
SRP
2.27%
2.76%
3.21%
2.75%
STGP
0.18%
0.02%
0.00%
TEP
1.34%
1.06%
TID
0.20%
0.25%
TNSK
0.06%
TPWR
TSGT
12.98%
30
$61,891
$8,303
$11,240
$11,239.83
7
$176,830
$80,004
$108,302
$108,302.02
0.07%
73
$4,239
$4,000
$4,239
$4,239.14
1.26%
1.22%
16
$78,434
$12,531
$16,963
$16,963.31
0.24%
0.23%
54
$14,703
$823
$1,114
$1,114.10
0.04%
0.00%
0.04%
79
$2,332
$431
$583
$583.45
0.54%
0.48%
0.57%
0.53%
28
$34,197
$8,488
$11,490
$11,490.27
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%
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%
$6,436,070
$2,399,562
Capped
1995
$3,148,521
$3,171,388.87
4.85%
3.84%
100%
Initial
5
0
Interim
Final
Table 2: 2008
2008
Gwh
Gwh
Gwh
Gwh
Gwh
Gwh
Company
Generation
Imports
Remote
Gen
Imports
Exports
Remote
Gen
Exports
Energy
Load
Data Diff
Data
Check
Source of
Estimate
AEPC
2779.77
1362.16
0.00
2680.88
0.00
1461.05
1461.05
0.00
AES
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
0.00
BARC
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
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
0.00
BHCE
268.41
2082.02
0.00
394.41
0.00
1956.02
1956.02
0.00
BHPL
1974.90
1983.14
558.79
1200.86
1.36
3314.61
3314.61
0.00
110841.60
26090.20
73.13
89142.70
0.00
47862.23
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
0.00
CCG
0.00
2917.01
0.00
2917.01
0.00
0.00
0.00
0.00
4023.78
4114.93
1906.44
2482.15
157.32
7405.67
7405.67
0.00
0.00
1342.58
0.00
1342.58
0.00
0.00
0.00
0.00
CEOE
2695.10
0.00
0.00
2695.10
0.00
0.00
0.00
0.00
CEPM
30.23
0.00
0.00
30.23
0.00
0.00
0.00
0.00
11869.01
339.76
0.00
715.78
481.20
11011.79
11011.79
(0.01)
8591.20
253.66
0.00
5555.13
0.00
3289.73
3289.73
0.00
0.00
0.00
BEAR (JP
Morgan)
BPA
CDWR
CEI
CFE
CHPD
COSL
CRGL
CSU
0.00
6403.29
0.00
6403.29
0.00
0.00
0.00
0.00
4747.57
684.55
0.00
677.47
0.00
4754.65
4754.65
0.00
460.80
0.00
0.00
24.90
0.00
0.00
DBET
DEGS
460.80
24.90
DGT
4584.48
1855.66
0.00
3858.54
139.86
2441.74
2441.74
0.00
DOPD
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
2679.68
3924.59
5343.79
4278.91
0.00
7669.16
7669.16
0.00
EWEB
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
0.00
EPE
5
1
2008
Gwh
Gwh
Gwh
Gwh
Gwh
Gwh
Company
Generation
Imports
Remote
Gen
Imports
Exports
Remote
Gen
Exports
Energy
Load
Data Diff
Data
Check
Source of
Estimate
FBC
6078.15
2429.96
0.00
3504.55
0.00
5003.57
5003.57
0.00
FPLE
1494.22
0.00
0.00
1494.22
0.00
0.00
0.00
0.00
GCPD
9394.96
3667.44
0.00
4973.34
4359.67
3729.39
3729.39
0.00
GLEN
203.29
1065.76
257.86
287.85
0.00
1239.05
1239.05
0.00
HGC
3013.58
0.00
0.00
3013.58
0.00
0.00
0.00
0.00
HHWP (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
24515.79
24342.12
6528.29
20597.04
6668.79
28120.37
28120.37
0.00
146.38
146.38
0.00
0.00
0.00
LDWP
LMUD
146.38
MCPI
324.25
MEID
465.43
189.19
13.11
189.19
452.32
452.32
0.00
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
0.00
MWEC
0.00
2013.23
0.00
2013.23
0.00
0.00
0.00
0.00
406.67
0.00
0.00
406.67
0.00
0.00
0.00
0.00
39.21
0.46
0.00
38.75
0.00
0.92
0.92
0.00
NCPA
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
59502.82
38986.38
16949.91
54104.32
2118.21
59216.58
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
0.00
PNM
15830.49
6079.48
2173.94
4890.56
9456.16
9737.19
9737.19
0.00
POC
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
27647.29
27647.29
0.00
PWX
0.00
23312.82
0.00
23312.82
0.00
0.00
0.00
0.00
MID
NAPG
NAT
PAC
324.25
5
2
2008
Gwh
Gwh
Gwh
Gwh
Gwh
Gwh
Company
Generation
Imports
Remote
Gen
Imports
Exports
Remote
Gen
Exports
Energy
Load
Data Diff
Data
Check
Source of
Estimate
RDNG
194.48
620.86
27.62
0.00
0.00
842.96
842.96
0.00
RVE
720.54
954.02
0.00
370.72
0.00
1303.84
1303.84
0.00
RVSD
697.39
511.98
1370.70
109.09
0.00
2470.98
2470.98
0.00
SCE
41868.26
50356.46
10503.45
10195.42
3623.42
88909.35
88909.35
0.00
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
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
0.00
SNPD
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
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
0.00
TNSK
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
0.00
UMPA
10.74
1230.14
494.97
514.50
0.00
1221.36
1221.36
0.00
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)
SER
STGP
VEA
5
3
Table 3: 2009
2009
Gwh
Gwh
Gwh
Gwh
Gwh
Gwh
Company
Generation
Imports
Remote
Gen
Imports
Exports
Remote
Gen
Exports
Energy
Load
AEPC
2099.29
AES
1513.71
1928.77
1684.23
Data Diff
Data Check
Source of
Estimate
0.00
0.00
3473.89
3473.89
0.00
0.00
AESO
54958.93
2018.61
513.16
56464.37
56464.37
0.00
ANHM
68.13
690.56
2772.23
976.74
2554.17
2554.17
0.00
APS
58707.22
13127.63
2099.68
1642.77
40958.92
40958.92
0.00
AVA
5118.46
10613.47
3682.54
6968.77
12445.70
12445.70
0.00
55.92
179.98
22.37
258.27
258.27
0.00
0.00
0.00
54468.99
0.00
0.00
0.00
AZUA
BARC
BCHA
BEAR (JP
Morgan)
BEPC
47229.32
323.74
323.74
12255.60
5015.94
211.25
211.25
31332.85
54468.99
4732.85
1197.99
3222.10
3222.10
0.00
BHCE
257.32
1637.53
0.00
32.23
0.00
1862.62
1862.62
0.00
BHPL
2710.45
1764.27
542.71
1578.00
99.66
3339.76
3339.76
0.00
44337.52
44337.52
0.00
1141.69
1141.69
0.00
0.00
0.00
2644.15
0.00
0.00
0.00
5416.44
0.00
BPA
2708.74
104149.47
22634.54
66.19
82512.67
BURB
1583.37
1897.61
590.32
1828.96
CALP
36850.87
CAWC
36850.87
2644.15
CCG
CDWR
1100.64
2644.15
23781.36
4052.13
CEI
4640.60
23781.36
1709.42
4915.33
5416.44
439.04
0.00
0.00
CEOE
2695.19
2695.19
0.00
0.00
CEPM
30.95
30.95
0.00
0.00
10693.97
10693.97
0.00
3256.83
3256.83
0.00
204.00
204.00
0.00
0.00
0.00
4565.62
4565.62
0.00
CFE
CHPD
439.04
70.37
11397.56
280.29
659.17
7928.86
381.58
5053.61
COSL
204.00
CRGL
CSU
4597.81
DBET
DEGS
7534.35
7534.35
592.34
624.53
901.58
901.58
0.00
0.00
147.45
0.00
0.00
147.45
DGT
4071.80
1773.07
DOPD
3534.21
380.93
DYN
6732.59
EMCU
EPE
EWEB
FARM
324.70
172.37
3343.94
125.52
2375.40
2375.40
0.00
1438.21
1981.65
667.64
667.64
0.00
0.00
0.00
0.00
6732.59
12064.11
303.54
241.49
12126.16
12126.16
2362.57
3317.67
5593.66
3567.46
7706.44
7706.44
0.00
621.64
4046.99
87.50
2262.70
2493.42
2493.42
(0.00)
279.36
12.40
1201.27
1201.27
0.00
3123.59
4973.70
4973.70
0.00
0.00
0.00
3880.93
3880.93
0.00
1182.35
1182.35
0.00
733.61
200.70
FBC
5702.92
2394.37
FPLE
1638.94
GCPD
8710.61
3470.05
GLEN
180.53
1023.99
HGC
3102.16
HHWP (CCSF)
1456.03
171.23
IID
826.89
6963.07
317.76
4445.92
IPC
9985.67
7704.46
6940.84
7496.89
1638.94
4414.75
253.26
3884.98
275.43
3102.16
597.89
5
4
0.00
0.00
1029.37
(0.00)
3661.80
3661.80
0.00
16811.55
16811.55
0.00
1029.37
322.53
2009
Gwh
Gwh
Gwh
Gwh
Gwh
Gwh
Company
Generation
Imports
Remote
Gen
Imports
Exports
Remote
Gen
Exports
Energy
Load
LAC
LDWP
337.96
156.04
70.79
17.79
22684.72
22096.38
6404.49
18582.30
LMUD
147.91
MCPI
2060.83
MEID
458.88
225.36
1781.00
372.51
MID
543.42
MLCI
37426.25
MWD
900.33
MWEC
Data Check
Source of
Estimate
547.01
547.01
0.00
26780.30
26780.30
0.00
147.91
147.91
0.00
0.00
0.00
446.58
446.58
0.00
2588.01
2588.01
0.00
0.00
0.00
2194.53
0.00
1479.82
0.00
0.00
5822.98
2060.83
12.30
225.36
108.93
37426.25
1294.20
2194.53
1479.82
Data Diff
NAPG
471.13
471.13
0.00
0.00
NAT
313.52
313.52
0.00
0.00
NCPA
1366.49
1960.00
NEVP
30985.01
7040.72
NRG
2186.94
NWMT
OCES
PAC
22333.45
4133.00
49.48
757.80
2519.21
2519.21
0.00
306.64
6873.58
34978.50
34978.50
0.00
2186.94
3629.24
4664.56
125.75
37122.93
18121.20
51286.29
PASA
109.08
299.34
1011.53
161.20
PG&E
28113.84
59514.79
PGE
10527.20
13419.51
PGR
4673.99
PNM
16537.61
3427.47
2156.08
2549.79
POC
433.48
35.51
655.76
126.13
9016.52
388.50
9405.03
PPLE
8067.90
17723.49
PPM
6292.86
PRPA
3635.41
782.44
PSCO
37350.47
10557.78
1031.74
2893.41
PSE
15587.19
21894.73
1857.88
12203.78
RDNG
13203.31
(0.00)
0.00
0.00
1906.56
57236.66
57236.66
0.00
1258.74
1258.74
0.00
85763.29
85763.29
0.00
18043.46
18043.46
0.00
0.00
0.00
9786.91
9786.91
0.00
998.62
998.62
0.00
0.00
0.00
0.00
0.00
467.28
4673.99
PPLM
PWX
13203.31
1865.34
2631.94
8120.03
9784.46
9603.46
6292.86
0.00
0.00
3250.44
3250.44
0.00
2259.13
43787.45
43787.45
0.00
163.54
26972.48
26972.48
0.00
0.00
0.00
827.02
827.02
0.00
0.00
0.00
2315.11
2315.11
0.00
1167.40
23553.88
0.00
8094.82
125.75
55185.38
0.00
23553.88
36.50
772.79
RVE
733.68
910.18
RVSD
621.52
458.61
1421.38
186.40
SCE
42151.78
35255.00
11663.42
58.02
3477.79
85534.38
85534.38
0.00
SCL
6328.72
8666.43
4458.31
368.93
10167.92
10167.92
0.00
SDGE
6438.68
10444.29
20111.00
20111.00
0.00
0.00
0.00
11447.94
11447.94
0.00
2933.36
2933.36
0.00
6897.94
6897.94
0.00
SER
17.73
368.40
1275.46
3228.03
16780.70
16780.70
SMUD
6949.41
5408.00
SNCL
471.34
2462.01
SNPD
623.87
8087.85
1813.78
SPP
10027.43
3087.67
66.24
1579.80
11469.06
11469.06
0.00
SRP
28131.85
9464.45
7078.52
12496.63
27638.96
27638.96
0.00
0.00
0.00
10313.17
10313.17
0.00
2064.07
2064.07
0.00
3.01
3.01
(0.00)
STGP
5.00
914.47
9617.81
983.07
983.07
TEP
5858.19
4562.75
4407.39
4515.16
TID
1874.28
623.83
318.62
749.27
869.42
3.01
TNSK
869.42
5
5
3.39
2009
Gwh
Gwh
Gwh
Gwh
Gwh
Gwh
Company
Generation
Imports
Remote
Gen
Imports
Exports
Remote
Gen
Exports
Energy
Load
TPWR
2803.54
4012.72
TSGT
15086.23
6292.18
3172.30
UAMP
1849.64
2012.96
256.57
UMPA
9.79
1024.13
469.15
VEA
1800.76
6912.74
5151.54
322.51
470.24
WAPA
26073.29
WEMT
446.25
Total
863763
11776.79
521248
395.49
13087.79
100458
497182
5
6
9042.05
120282
Data Diff
Data Check
Source of
Estimate
5015.50
5015.50
0.00
12486.42
12486.43
0.00
4119.17
4119.17
0.00
1180.57
1180.57
0.00
470.24
470.24
0.00
16115.73
16115.73
0.00
446.25
446.25
0.00
868005
868005
0.01
Table 4: 2010
2010
Gwh
Gwh
Company
Generation
Imports
AEPC
AES
AESO
ANHM
APS
AVA
AZUA
BARC
BCHA
BEAR (JP
Morgan)
BEPC
BHCE
BHPL
BPA
BURB
CALP
CAWC
CCG
CDWR
CEI
CEOE
CEPM
CFE
CHPD
COSL
CRGL
CSU
DBET
DEGS
DGT
DOPD
DYN
EMCU
EPE
EWEB
FARM
FBC
FPLE
GCPD
GLEN
HGC
HHWP (CCSF)
IID
IPC
LAC
LDWP
LMUD
MCPI
MEID
MID
MLCI
MWD
MWEC
NAPG
NAT
NCPA
NEVP
NRG
NWMT
OCES
2187.39
1948.47
55718.38
41.39
57174.09
4850.65
57.79
0.00
46253.89
0.00
1410.09
0.00
2205.01
636.29
5241.22
10671.60
169.10
405.00
12719.07
354.99
4809.57
258.83
3146.47
102381.88
1661.85
30837.34
0.00
182.93
4570.53
0.00
2689.42
34.60
11207.86
7651.01
0.00
0.00
4863.20
0.00
540.13
4288.56
3534.21
3681.18
11747.05
2874.16
586.54
709.11
5620.93
1712.80
8193.90
186.44
1692.23
1739.05
878.94
8245.71
282.88
21901.95
0.00
0.00
0.00
618.31
0.00
0.00
0.00
450.83
458.39
1366.49
28676.08
1223.31
26222.88
157.00
1174.35
1681.99
1511.93
22965.04
1466.87
0.00
2651.24
0.00
7027.56
320.24
0.00
0.00
220.66
386.59
0.17
5429.29
420.25
1127.00
0.00
1551.92
380.93
0.00
306.03
3050.99
4419.81
257.54
2488.86
0.00
3091.76
1049.71
0.00
173.94
6784.92
8253.40
207.54
20814.34
133.89
2364.48
460.31
1597.15
37426.25
931.79
1480.20
0.00
0.00
1960.00
7789.24
0.00
3270.37
0.00
Gwh
Remote
Gen
Imports
0.00
0.00
0.00
2709.22
2204.31
4089.06
22.47
0.00
0.00
0.00
0.00
0.00
517.63
48.41
600.54
0.00
0.00
0.00
1354.26
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
172.37
0.00
0.00
5575.55
84.18
222.68
0.00
0.00
0.00
269.39
0.00
0.00
331.25
6844.71
77.68
6432.44
0.00
0.00
324.03
366.76
0.00
1258.33
0.00
0.00
0.00
4201.32
0.00
0.00
0.00
Gwh
Gwh
1962.45
0.00
467.90
1018.66
2273.62
7371.49
0.00
405.00
5577.25
354.99
Remote
Gen
Exports
0.00
0.00
0.00
0.00
30346.42
0.00
0.00
0.00
0.00
0.00
2770.64
18.35
1690.31
82178.38
1408.81
30837.34
0.00
182.93
6083.05
320.24
2689.42
34.60
651.66
4886.93
0.00
5429.29
598.35
1127.00
540.13
3259.05
1438.21
3681.18
47.10
3452.93
2627.52
0.82
3178.82
1712.80
4311.11
369.92
1692.23
700.56
4442.03
6700.11
17.51
17711.23
0.00
2364.48
12.05
84.76
37426.25
0.00
1480.20
450.83
458.39
49.48
381.93
1223.31
5305.27
157.00
0.00
0.00
151.13
0.00
1167.92
0.00
0.00
0.00
96.44
0.00
0.00
0.00
178.40
0.00
0.00
0.00
0.00
0.00
0.00
135.15
1981.65
0.00
0.00
0.00
0.00
0.00
0.00
0.00
2936.59
0.00
0.00
0.00
0.00
285.85
0.00
5322.48
0.00
0.00
324.03
0.00
0.00
0.00
0.00
0.00
0.00
757.80
5479.81
0.00
12488.97
0.00
Exports
5
7
Gwh
Energy
Load
Data Diff
Data Check
Source of
Estimate
1635.04
1948.47
57455.49
2368.24
31955.80
12239.82
249.35
0.00
53395.71
0.00
1635.04
1948.47
57455.49
2368.24
31999.58
12239.82
249.35
0.00
53395.71
0.00
0.00
0.00
0.00
0.00
43.78
0.00
0.00
0.00
0.00
0.00
3213.28
1922.47
3334.60
43216.95
1152.52
0.00
2651.24
0.00
6772.85
0.00
0.00
0.00
10598.47
3150.67
0.17
0.00
4685.11
0.00
0.00
2446.27
667.64
0.00
12005.97
8047.77
2463.01
1188.51
4930.98
0.00
4037.96
1135.63
0.00
1212.43
3553.09
16357.86
550.59
26115.02
133.89
0.00
448.26
2497.46
0.00
2190.12
0.00
0.00
0.00
2519.21
34804.89
0.00
11699.00
0.00
3213.28
1922.47
3334.60
43216.95
1152.52
0.00
2651.24
0.00
6772.85
0.00
0.00
0.00
10598.47
3150.67
0.17
0.00
4685.11
0.00
0.00
2446.27
667.64
0.00
12005.97
8047.77
2463.01
1188.51
4930.98
0.00
4037.96
1135.63
0.00
1212.43
3553.09
16357.86
550.59
26115.02
133.89
0.00
448.26
2497.46
0.00
2190.12
0.00
0.00
0.00
2519.21
34804.89
0.00
11699.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
2010
Company
PAC
PASA
PG&E
PGE
PGR
PNM
POC
PPLE
PPLM
PPM
PRPA
PSCO
PSE
PWX
RDNG
RVE
RVSD
SCE
SCL
SDGE
SER
SMUD
SNCL
SNPD
SPP
SRP
STGP
TEP
TID
TNSK
TPWR
TSGT
UAMP
UMPA
VEA
WAPA
WEMT
Total
Gwh
Generation
55945.10
107.24
32176.75
11875.25
4182.25
15018.46
411.92
0.00
12312.83
6562.72
3477.14
40243.46
15604.34
0.00
49.78
500.06
1247.23
44881.47
6055.70
8158.05
15779.00
7741.66
553.96
612.53
9949.60
29836.19
0.00
6037.48
2165.91
652.86
2745.87
15023.14
1660.25
9.14
0.00
23948.39
400.11
856042
Gwh
Imports
38099.10
279.22
53495.33
11803.72
0.00
3193.45
37.95
9775.62
0.00
0.00
763.77
10746.00
34071.75
30515.51
755.86
792.32
95.74
29283.80
9094.44
8548.44
0.00
4060.31
2362.00
7645.17
3062.46
7542.45
523.51
6369.77
636.34
3.20
4196.86
6452.27
2234.61
1017.71
458.49
16324.85
0.00
494683
Gwh
Remote
Gen
Imports
17309.89
995.18
0.00
2268.71
0.00
2733.91
642.70
206.29
0.00
0.00
0
1024.20
1778.10
0.00
0.32
0.00
1434.21
10496.82
0.00
2776.50
0.00
0.00
0.00
0.00
0.00
9370.91
0.00
4555.29
432.70
0.00
0.00
3198.92
219.94
460.66
0.00
339.74
0.00
97952
Gwh
Exports
51817.70
181.64
1607.60
7336.96
4182.25
1608.57
107.67
9981.91
84.62
6562.72
1062.48
3962.73
12629.97
30515.51
0.00
66.85
162.76
630.73
4882.77
0.00
15779.00
714.76
0.00
1516.59
235.42
6485.64
523.51
4738.97
1159.78
652.86
2058.72
6722.60
0.00
270.64
0.00
15740.66
0.00
459600
5
8
Gwh
Remote
Gen
Exports
1765.93
0.00
0.00
601.32
0.00
9298.74
0.00
0.00
12228.21
0.00
0.00
3479.51
267.43
0.00
0.00
0.00
0.00
3027.55
369.57
0.00
0.00
0.00
0.00
0.00
1431.71
12746.49
0.00
0.00
32.39
0.00
0.00
4949.75
0.00
0.00
0.00
12189.49
0.00
124041
Gwh
Energy
Load
57770.45
1200.00
84064.48
18009.39
0.00
10038.52
984.91
0.00
0.00
0.00
3178.42
44571.42
38556.80
0.00
805.97
1225.53
2614.41
81003.81
9897.80
19483.00
0.00
11087.21
2915.96
6741.12
11344.93
27517.42
0.00
12223.58
2042.77
3.20
4884.01
13001.99
4114.80
1216.87
458.49
12682.83
400.11
864992
Data Diff
Data Check
Source of
Estimate
57770.45
1200.00
84064.48
18009.39
0.00
10038.52
984.91
0.00
0.00
0.00
3178.42
44571.42
38556.80
0.00
805.97
1225.53
2614.41
81003.81
9897.80
19483.00
0.00
11087.21
2915.96
6741.12
11344.93
27517.42
0.00
12223.58
2042.77
3.20
4884.01
13001.99
4114.80
1216.87
458.49
12682.83
400.11
865036
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
(0.00)
0.00
0.00
0.00
0.00
0.00
(0.00)
0.00
43.80
Table 5: Three-Year Average
3-year avg.
G
I
Company
Generation
Imports
AEPC
AES
RGI
E
Remote
Gen
Imports
Exports
RGE
L
Remote
Gen
Exports
Energy
Load
2355
1429
0
2191
561
Cross Check Load
1032
Load
diff.
1032
0
2111
1158
0
1158
0
2111
2111
0
AESO
55677
2157
0
513
0
57321
57321
0
ANHM
54
611
2787
916
0
2536
2536
0
APS
57811
7697
2224
1833
30398
35485
35500
-15
AVA
5036
10835
4011
7456
0
12426
12426
0
79
157
22
0
0
258
258
0
0
353
0
353
0
0
0
0
47990
12243
0
5427
0
54805
54805
0
AZUA
BARC
BCHA
BEAR (JP
Morgan)
0
259
0
259
0
0
0
0
BEPC
4798
1192
0
2723
0
3268
3268
0
BHCE
262
1801
0
148
0
1914
1914
0
BHPL
2611
1753
540
1490
84
3330
3330
0
105791
23897
63
84611
0
45139
45139
0
BURB
1612
1949
609
1868
1121
1180
1180
0
CALP
34948
0
0
34948
0
0
0
0
0
2600
0
0
0
2600
2600
0
61
8899
0
8960
0
0
0
0
4215
5261
1657
4494
108
6532
6532
0
BPA
CAWC
CCG
CDWR
CEI
0
701
0
701
0
0
0
0
2693
0
0
2693
0
0
0
0
CGX
32
0
0
32
0
0
0
0
CFE
CEOE
11491
280
0
676
328
10768
10768
0
CHPD
8057
341
0
5165
0
3232
3232
0
COSL
0
102
0
0
0
102
102
0
CRGL
CSU
DBET
DEGS
0
6456
0
6456
0
0
0
0
4736
566
0
633
0
4668
4668
0
0
830
0
830
0
0
0
0
237
0
0
237
0
0
0
0
DGT
4315
1727
0
3487
134
2421
2421
0
DOPD
3678
380
182
1476
2098
666
666
0
DYN
7092
0
0
7092
0
0
0
0
EMC
11613
320
0
150
0
11784
11784
0
EPE
2639
3431
5504
3766
0
7808
7808
0
629
4557
88
2717
0
2556
2556
0
EWEB
FARM
730
296
259
63
0
1222
1222
0
FBC
5801
2438
0
3269
0
4969
4969
0
FPLE
1615
0
0
1615
0
0
0
0
GCPD
8766
3410
0
4566
3727
3883
3883
0
GLEN
190
1046
260
311
0
1186
1186
0
HGC
2603
0
0
2603
0
0
0
0
HHWP (CCSF)
1493
155
0
552
0
1097
1097
0
IID
854
6858
309
4381
0
3640
3640
0
IPC
8913
8345
7021
7085
304
16891
16891
0
5
9
3-year avg.
G
I
Company
Generation
Imports
LAC
RGI
E
Remote
Gen
Imports
Exports
RGE
L
Cross Check Load
Remote
Gen
Exports
Energy
Load
Load
diff.
317
178
74
26
0
543
543
0
LDWP
23034
22418
6455
18964
5938
27005
27005
0
LMUD
0
143
0
0
0
143
143
0
MCPI
0
1583
0
1583
0
0
0
0
MEID
0
462
246
12
246
449
449
0
MID
585
1789
300
92
0
2582
2582
0
MLCI
0
34931
0
34931
0
0
0
0
MWD
0
764
1294
0
0
2058
2058
0
MWEC
0
1658
0
1658
0
0
0
0
NAPG
443
0
0
443
0
0
0
0
NAT
270
0
0
270
0
0
0
0
NCPA
1346
1528
0
39
735
2100
2100
0
NEVP
29728
7716
3735
320
6547
34312
34312
0
NRG
2474
0
0
2474
0
0
0
0
23758
3331
0
4847
10238
12005
12005
0
NWMT
OCES
128
0
0
128
0
0
0
0
56878
38069
17460
52403
1930
58075
58075
0
PASA
113
352
1003
209
0
1260
1260
0
PG&E
28590
59265
0
1823
0
86032
86032
0
PGE
11434
12958
2585
8282
565
18131
18131
0
PGR
4763
0
0
4763
0
0
0
0
PNM
15796
4233
2355
3016
9513
9854
9854
0
POC
423
32
660
111
0
1004
1004
0
PPLE
0
11221
328
11549
0
0
0
0
PPLM
16828
0
0
5461
11367
0
0
0
PPM
6259
0
0
6259
0
0
0
0
PRPA
3534
766
0
1087
0
3212
3212
0
PSCO
39044
10711
1049
3542
2572
44691
44691
0
PSE
15236
25791
1949
11715
202
31059
31059
0
PWX
0
25794
0
25794
0
0
0
0
PAC
RDNG
94
717
15
0
0
825
825
0
RVE
651
886
0
269
425
843
843
0
RVSD
855
355
1409
153
0
2467
2467
0
SCE
42967
38298
10888
3628
3376
85149
85149
0
SCL
6390
9072
0
4950
370
10143
10143
0
SDGE
7905
9139
3035
0
0
20079
20079
0
17283
0
0
17283
0
0
0
0
SMUD
7312
5254
94
1241
0
11418
11418
0
SNCL
505
2446
0
0
0
2951
2951
0
SNPD
648
7972
0
1748
0
6872
6872
0
SPP
9796
3496
0
105
1554
11632
11632
0
SRP
29783
8726
9406
6987
12959
27970
27970
0
328
816
0
1144
0
0
0
0
TEP
6195
5212
4576
5011
0
10972
10972
0
TID
1979
805
345
1045
12
2072
2072
0
710
3
0
711
0
2
2
0
SER
STGP
TNSK
6
0
3-year avg.
G
I
RGI
Company
Generation
Imports
E
Remote
Gen
Imports
Exports
RGE
L
Remote
Gen
Exports
Energy
Load
Cross Check Load
Load
diff.
TPWR
2778
4098
0
1869
0
5006
5006
0
TSGT
15241
6350
3177
10788
5137
8843
8843
0
UAMP
1730
2177
243
0
0
4149
4149
0
UMPA
10
1091
475
369
0
1206
1206
0
0
469
0
0
0
469
469
0
WAPA
26506
14220
372
12862
11259
16977
16977
0
WEMT
431
0
0
0
0
431
431
0
Total
874664
513785
99064
491867
123810
871821
Total Largest
441201
285777
61259
224783
39105
524349
VEA
6
1
Table 6: Rankings for Three-Year Averages
49
Average
Ranking
50.25
Final
Ranking
49
47
51.00
52
2
28.25
20
57
79
53.75
56
44
9
20.00
15
12
14
34
19.25
13
67
77
87
77
77.00
93
72
71
67
82
73.00
85
BCHA
5
14
21
4
11.00
6
BEAR (JP Morgan)
72
75
72
82
75.25
89
BEPC
37
56
36
35
41.00
34
BHCE
51
46
77
70
61.00
66
BHPL
36
42
50
45
43.25
39
Company
Load
Imp + RGI
Exports
Gen-RGE
AEPC
58
53
41
AES
47
57
53
AESO
4
43
64
ANHM
44
35
APS
8
19
AVA
17
AZUA
BARC
BPA
6
8
1
1
4.00
2
BURB
56
38
43
63
50.00
48
CALP
72
83
3
7
41.25
35
CAWC
41
37
87
82
61.75
67
CCG
72
24
12
78
46.50
44
CDWR
29
27
28
39
30.75
22
CEI
72
65
60
82
69.75
82
CEOE
72
83
38
42
58.75
62
CEPM
72
83
84
80
79.75
97
CFE
23
74
61
18
44.00
41
CHPD
38
72
22
23
38.75
30
COSL
69
80
87
82
79.50
96
CRGL
72
29
18
82
50.25
49
CSU
32
67
62
37
49.50
47
DBET
72
60
58
82
68.00
81
DEGS
72
83
73
71
74.75
88
DGT
46
48
33
38
41.25
35
DOPD
62
68
51
52
58.25
61
DYN
72
83
15
26
49.00
45
EMC
19
73
76
17
46.25
43
EPE
27
23
30
43
30.75
22
EWEB
43
31
37
59
42.50
38
FARM
53
69
82
56
65.00
76
FBC
31
40
34
31
34.00
26
FPLE
72
83
48
51
63.50
73
GCPD
34
34
27
33
32.00
24
GLEN
55
55
69
73
63.00
70
HGC
72
83
39
44
59.50
63
HHWP (CCSF)
57
78
63
53
62.75
69
IID
35
26
29
55
36.25
28
IPC
16
11
16
21
16.00
12
LAC
63
76
85
68
73.00
85
LDWP
12
5
6
12
8.75
3
6
2
82
Average
Ranking
79.00
Final
Ranking
95
49
82
63.25
72
86
97
78.00
94
81
61
57.00
59
4
4
82
40.50
33
45
87
82
66.00
78
49
47
82
62.50
68
72
83
65
64
71.00
83
71
82
70
69
73.00
85
48
52
83
60
60.75
65
NEVP
9
18
68
10
26.25
19
NRG
72
83
40
46
60.25
64
NWMT
18
36
25
16
23.75
17
OCES
72
83
78
74
76.75
92
Company
Load
Imp + RGI
Exports
Gen-RGE
LMUD
68
79
87
MCPI
72
50
MEID
65
64
MID
42
44
MLCI
72
MWD
50
MWEC
72
NAPG
NAT
NCPA
PAC
3
2
2
3
2.50
1
PASA
52
54
74
75
63.75
75
PG&E
1
1
45
8
13.75
9
PGE
14
10
13
19
14.00
10
PGR
72
83
26
36
54.25
57
PNM
25
28
35
27
28.75
21
POC
59
66
79
66
67.50
80
PPLE
72
17
10
82
45.25
42
PPLM
72
83
20
32
51.75
53
PPM
72
83
19
28
50.50
51
PRPA
39
62
55
40
49.00
45
PSCO
7
16
32
6
15.25
11
PSE
10
6
9
15
10.00
4
PWX
72
7
5
82
41.50
37
RDNG
61
63
87
76
71.75
84
RVE
60
59
71
72
65.50
77
RVSD
45
47
75
54
55.25
58
SCE
2
3
31
5
10.25
5
SCL
24
22
24
30
25.00
18
SDGE
13
15
87
24
34.75
27
SER
72
83
7
11
43.25
39
SMUD
21
30
52
25
32.00
24
SNCL
40
39
87
62
57.00
59
SNPD
28
25
46
58
39.25
32
SPP
20
33
80
22
38.75
30
SRP
11
9
17
13
12.50
7
STGP
72
61
54
67
63.50
73
TEP
22
20
23
29
23.50
16
TID
49
58
56
48
52.75
54
TNSK
70
81
59
57
66.75
79
TPWR
30
32
42
41
36.25
28
TSGT
26
21
11
20
19.50
14
UAMP
33
41
87
50
52.75
54
UMPA
54
51
66
81
63.00
70
6
3
Load
Imp + RGI
Exports
Gen-RGE
VEA
64
70
87
82
Average
Ranking
75.75
WAPA
15
13
8
14
12.50
7
WEMT
66
83
87
65
75.25
89
Company
Total
6
4
Final
Ranking
91
Table 7: Rankings
Ranking for Energy Load (L)
58 AEPC
47 AES
Ranking for Imports + RGI
Ranking for Generation –
RGE
1032
0.12%
53 AEPC
1429 0.23%
49 AEPC
47 AES
2111
0.24%
57 AES
1158 0.19%
4 AESO
57321
6.57%
43 AESO
2157 0.35%
2 AESO
44 ANHM
2536
0.29%
35 ANHM
3398 0.55%
79 ANHM
8 APS
35485
4.07%
19 APS
9921 1.62%
17 AVA
12426
1.43%
12 AVA
14846 2.42%
258
0.03%
77 AZUA
72 BARC
0
0.00%
5 BCHA
54805
6.29%
0
0.00%
1192 0.19%
82 BEAR (JP
Morgan)
35 BEPC
1801 0.29%
70 BHCE
67 AZUA
Ranking for
Average
1794
0.24%
41 AEPC
2191 0.45%
49 AEPC
50.25
1158 0.24%
2111
0.28%
53 AES
52 AES
51.00
55677
7.42%
64 AESO
513 0.10%
20 AESO
28.25
54
0.01%
57 ANHM
916 0.19%
56 ANHM
53.75
9 APS
27412
3.65%
44 APS
1833 0.37%
15 APS
20.00
34 AVA
5036
0.67%
14 AVA
7456 1.52%
13 AVA
19.25
79
0.01%
87 AZUA
0 0.00%
93 AZUA
77.00
179 0.03%
77 AZUA
71 BARC
353 0.06%
82 BARC
0
0.00%
67 BARC
353 0.07%
85 BARC
73.00
14 BCHA
12243 2.00%
4 BCHA
47990
6.39%
21 BCHA
5427 1.10%
6 BCHA
11.00
0
0.00%
259 0.05%
89 BEAR (JP
75.25
72 BEAR (JP
Morgan)
37 BEPC
3268
0.37%
75 BEAR (JP
Morgan)
56 BEPC
51 BHCE
1914
0.22%
46 BHCE
36 BHPL
3330
0.38%
42 BHPL
2293 0.37%
45 BHPL
6 BPA
45139
5.18%
8 BPA
23959 3.91%
1 BPA
56 BURB
1180
0.14%
38 BURB
2557 0.42%
63 BURB
491
0.07%
7 CALP
34948
0
72 CALP
Ranking for Exports (E)
259 0.04%
0.64%
262
0.03%
77 BHCE
2527
0.34%
Morgan)
2723 0.55%
34 BEPC
41.00
148 0.03%
66 BHCE
61.00
50 BHPL
1490 0.30%
39 BHPL
43.25
1 BPA
84611 17.20%
2 BPA
4.00
43 BURB
1868 0.38%
48 BURB
50.00
4.65%
3 CALP
34948 7.11%
35 CALP
41.25
0.00%
87 CAWC
67 CAWC
61.75
61
0.01%
12 CCG
8960 1.82%
44 CCG
46.50
4107
0.55%
28 CDWR
4494 0.91%
22 CDWR
30.75
105791 14.09%
0
0.00%
83 CALP
2600
0.30%
37 CAWC
2600 0.42%
82 CAWC
0
0.00%
24 CCG
8899 1.45%
78 CCG
6532
0.75%
27 CDWR
6918 1.13%
39 CDWR
72 CEI
0
0.00%
65 CEI
0
0.00%
60 CEI
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
41 CAWC
72 CCG
29 CDWR
23 CFE
0 0.00%
4798
72 BEAR (JP
Morgan)
36 BEPC
701 0.11%
82 CEI
0 0.00%
701 0.14%
10768
1.24%
74 CFE
280 0.05%
18 CFE
11163
1.49%
61 CFE
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
32 CSU
72 DBET
72 DEGS
0
0.00%
29 CRGL
6456 1.05%
82 CRGL
4668
0.54%
67 CSU
566 0.09%
37 CSU
0
0.00%
60 DBET
830 0.14%
82 DBET
0 0.00%
676 0.14%
0
0.00%
18 CRGL
6456 1.31%
49 CRGL
50.25
4736
0.63%
62 CSU
633 0.13%
47 CSU
49.50
0
0.00%
58 DBET
830 0.17%
81 DBET
68.00
71 DEGS
237
0.03%
73 DEGS
237 0.05%
88 DEGS
74.75
38 DGT
4181
0.56%
33 DGT
3487 0.71%
35 DGT
41.25
52 DOPD
1580
0.21%
51 DOPD
1476 0.30%
61 DOPD
58.25
0 0.00%
26 DYN
7092
0.94%
15 DYN
7092 1.44%
45 DYN
49.00
0
0.00%
83 DEGS
2421
0.28%
48 DGT
666
0.08%
68 DOPD
72 DYN
0
0.00%
83 DYN
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
63 0.01%
31 FBC
4969
0.57%
40 FBC
0
0.00%
83 FPLE
34 GCPD
3883
0.45%
34 GCPD
55 GLEN
1186
0.14%
55 GLEN
0
0.00%
83 HGC
1097
0.13%
3640
0.42%
78 HHWP
(CCSF)
26 IID
16 IPC
16891
1.94%
11 IPC
63 LAC
543
0.06%
76 LAC
46 DGT
62 DOPD
72 FPLE
72 HGC
57 HHWP
(CCSF)
35 IID
1727 0.28%
561 0.09%
730
0.10%
82 FARM
76 FARM
65.00
31 FBC
5801
0.77%
34 FBC
3269 0.66%
26 FBC
34.00
51 FPLE
1615
0.22%
48 FPLE
1615 0.33%
73 FPLE
63.50
3410 0.56%
33 GCPD
5039
0.67%
27 GCPD
4566 0.93%
24 GCPD
32.00
1307 0.21%
73 GLEN
190
0.03%
69 GLEN
311 0.06%
70 GLEN
63.00
44 HGC
2603
0.35%
39 HGC
2603 0.53%
63 HGC
59.50
53 HHWP
(CCSF)
55 IID
1493
0.20%
0.11%
4381 0.89%
69 HHWP
(CCSF)
28 IID
62.75
854
63 HHWP
(CCSF)
29 IID
15367 2.51%
21 IPC
8609
1.15%
16 IPC
7085 1.44%
12 IPC
16.00
252 0.04%
68 LAC
317
0.04%
85 LAC
26 0.01%
85 LAC
73.00
2438 0.40%
0 0.00%
0 0.00%
155 0.03%
7167 1.17%
6
5
552 0.11%
36.25
Ranking for Energy Load (L)
Ranking for Imports + RGI
Ranking for Generation –
RGE
Ranking for Exports (E)
Ranking for
Average
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
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
81 MID
92 0.02%
59 MID
57.00
72 MLCI
0
0.00%
4 MLCI
34931 5.70%
50 MWD
2058
0.24%
45 MWD
2058 0.34%
72 MWEC
0
0.00%
49 MWEC
1658 0.27%
72 NAPG
0
0.00%
83 NAPG
0 0.00%
71 NAT
0
0.00%
82 NAT
0 0.00%
48 NCPA
2100
0.24%
52 NCPA
9 NEVP
34312
3.94%
18 NEVP
0
0.00%
83 NRG
12005
1.38%
36 NWMT
0
0.00%
83 OCES
72 NRG
18 NWMT
72 OCES
585
0.08%
82 MLCI
0
0.00%
4 MLCI
34931 7.10%
33 MLCI
40.50
82 MWD
0
0.00%
87 MWD
0 0.00%
78 MWD
66.00
82 MWEC
0
0.00%
47 MWEC
1658 0.34%
68 MWEC
62.50
64 NAPG
443
0.06%
65 NAPG
443 0.09%
83 NAPG
71.00
69 NAT
270
0.04%
70 NAT
270 0.05%
85 NAT
73.00
1528 0.25%
60 NCPA
611
0.08%
83 NCPA
39 0.01%
65 NCPA
60.75
11451 1.87%
10 NEVP
23180
3.09%
68 NEVP
320 0.07%
19 NEVP
26.25
46 NRG
2474
0.33%
40 NRG
2474 0.50%
64 NRG
60.25
13520
1.80%
25 NWMT
4847 0.99%
17 NWMT
23.75
128
0.02%
78 OCES
92 OCES
76.75
0 0.00%
3331 0.54%
0 0.00%
16 NWMT
74 OCES
128 0.03%
3 PAC
58075
6.66%
2 PAC
55530 9.06%
3 PAC
54948
7.32%
2 PAC
1 PAC
2.50
52 PASA
1260
0.14%
54 PASA
1356 0.22%
75 PASA
113
0.02%
74 PASA
52403 10.65%
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
72 PPM
0
0.00%
39 PRPA
3212
0.37%
7 PSCO
44691
0 0.00%
32 PPLM
5461
0.73%
20 PPLM
5461 1.11%
53 PPLM
51.75
83 PPM
0 0.00%
28 PPM
6259
0.83%
19 PPM
6259 1.27%
51 PPM
50.50
62 PRPA
766 0.12%
40 PRPA
3534
0.47%
55 PRPA
1087 0.22%
45 PRPA
49.00
5.13%
16 PSCO
11760 1.92%
6 PSCO
36472
4.86%
32 PSCO
3542 0.72%
11 PSCO
15.25
31059
3.56%
6 PSE
27740 4.53%
15 PSE
15034
2.00%
9 PSE
11715 2.38%
4 PSE
10.00
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
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
27 SDGE
34.75
0
0.00%
83 SER
39 SER
43.25
21 SMUD
11418
1.31%
30 SMUD
5348 0.87%
24 SMUD
32.00
40 SNCL
2951
0.34%
39 SNCL
28 SNPD
6872
0.79%
25 SNPD
20 SPP
11632
1.33%
11 SRP
27970
0
22 TEP
49 TID
10 PSE
72 PWX
7905
1.05%
87 SDGE
17283
2.30%
7 SER
17283 3.51%
25 SMUD
7312
0.97%
52 SMUD
1241 0.25%
2446 0.40%
62 SNCL
505
0.07%
87 SNCL
0 0.00%
59 SNCL
57.00
7972 1.30%
58 SNPD
648
0.09%
46 SNPD
1748 0.36%
32 SNPD
39.25
33 SPP
3496 0.57%
22 SPP
8241
1.10%
80 SPP
105 0.02%
30 SPP
38.75
3.21%
9 SRP
18132 2.96%
13 SRP
16824
2.24%
17 SRP
6987 1.42%
7 SRP
12.50
0.00%
61 STGP
328
0.04%
54 STGP
1144 0.23%
73 STGP
63.50
10972
1.26%
20 TEP
9788 1.60%
29 TEP
6195
0.83%
23 TEP
5011 1.02%
16 TEP
23.50
2072
0.24%
58 TID
1150 0.19%
48 TID
1045 0.21%
2
0.00%
81 TNSK
30 TPWR
5006
0.57%
32 TPWR
26 TSGT
8843
1.01%
33 UAMP
4149
0.48%
72 SER
72 STGP
70 TNSK
12174 1.99%
0 0.00%
816 0.13%
24 SDGE
0 0.00%
11 SER
67 STGP
0 0.00%
1967
0.26%
56 TID
54 TID
52.75
57 TNSK
710
0.09%
59 TNSK
711 0.14%
79 TNSK
66.75
4098 0.67%
41 TPWR
2778
0.37%
42 TPWR
1869 0.38%
28 TPWR
36.25
21 TSGT
9528 1.55%
20 TSGT
10104
1.35%
11 TSGT
10788 2.19%
14 TSGT
19.50
41 UAMP
2419 0.39%
50 UAMP
1730
0.23%
87 UAMP
54 UAMP
52.75
3 0.00%
6
6
0 0.00%
Ranking for Energy Load (L)
54 UMPA
Ranking for Imports + RGI
1206
0.14%
51 UMPA
469
0.05%
70 VEA
15 WAPA
16977
1.95%
13 WAPA
14592 2.38%
66 WEMT
431
0.05%
83 WEMT
0 0.00%
64 VEA
871821 100.00
%
1566 0.26%
469 0.08%
Ranking for Generation –
RGE
81 UMPA
Ranking for Exports (E)
10
0.00%
66 UMPA
0
0.00%
87 VEA
14 WAPA
15247
2.03%
8 WAPA
12862 2.61%
7 WAPA
12.50
65 WEMT
431
0.06%
87 WEMT
0 0.00%
89 WEMT
75.25
82 VEA
612849 100.00
%
750854 100.00
%
6
7
369 0.08%
Ranking for
Average
0 0.00%
491867 100.00
%
70 UMPA
63.00
91 VEA
75.75
Western Electricity Coordinating Council Guideline
UNSCHEDULED FLOW MITIGATION - CONTROLLABLE
DEVICES COMPENSATION
GUIDELINE
Date
:
Document Title:
Category
Document date
Adopted/approved by
Date adopted/approved
Custodian (entity
responsible for
maintenance and
upkeep)
Stored/filed
Previous name/number
Status
Unscheduled Flow Mitigation Controllable
Devices
Compensation Guideline
Guideline
July 30, 2001
Physical location:
Web URL:
(if any)
( ) in effect
( ) usable, minor formatting/editing required
( ) modification needed
( ) superseded by
( ) other
( ) obsolete/archived)
6
8
ECC Guideline UNSCHEDULED FLOW MITIGATION CONTROLLABLE DEVICES COMPENSATION
GUIDELINE
Date:
Introduction
The 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.
Guideline
The 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
Transmission Operator
Guideline Details
Compensation 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.
6
9
WECC CONTROLLABLE DEVICES COMPENSATION GUIDELINE
The 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.
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.
Adding New Devices to the Policy
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
7
1
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.
Deleting Qualified Controllable Devices From the Policy
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.
7
2
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
$10 million and 10.76 percent ................................................................................... 1.076
7
3
Part I
Phase-Shifter
Owners
Operator
Original
Cost
mm$
Designation
Lev. Annual
Fixed Cost%
Annual
Average %
Compensation
Cost
mm$
Effectiveness
Factor
1st
Year
CY 2011
Plan
Year
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
PAC/NEVP
NPC
9.600
13.77%
[2]
1.322
57.14%
57.14%
0.755
0.5891
1.344
MPC
MPC
5.215
14.72%
[2]
0.768
53.12%
53.12%
0.408
0.0023
0.410
Western
MPC
5.400
8.80%
[1]
0.475
53.12%
53.12%
0.252
0.0066
0.259
Harry Allen
Billings
Crossover
Totals
75.515
9.325
WECC Cost=
5.771
1.7428
6.436
[2] Levelized annual cost, taxable entity includes ROE prop tax and A&G. .............................. 1723.76
0.002
[1] Levelized annual cost, tax free financing, includes debt and A&G.
[3] Minimum compensation = the > of 10% of Levelized Annual cost or ..... $50,000
[4] Estimated at 2% of Original Cost.
Part II
Control
(Deg)
Phase-Shifter
+/-
Path Rating
30
Tot 2A
% path effectiveness
60
Pinto
% path effectiveness
30
Sigurd
% path effectiveness
30
Harry Allen
% path effectiveness
35
Billings/Crossover
% path effectiveness
Total MW Control
% path effect.
6
CA-OR
Interie
Path 66
4800
Qualified Path Control (MW per Degree)/%
effectiveness
MidwyEOR
FC
FC West
Vinct
Path
345/500
Path 22
Path 15
21
Path 23
3900
5700
0.0%
0.0%
2.98500
29.0%
3.20500
62.2%
0.0%
0.0%
0.0%
0.0%
0.99500
9.7%
4.20000
40.7%
0.0%
0.0%
2.04500
23.1%
0.0%
0.0%
509
0
0
100.0%
0.0%
0.0%
0
7
4
Tot 1A
Path 30
Tot 3
Path 36
TOT 2A
Path 31
Average
%
Control
2325
1000
650
1680
690
-3.13500
-1.83000
4.52000
-2.32000
-7.03500
62.8%
85.2%
100.0%
64.3%
100.0%
-4.53000
-2.59000
-1.72000
0.51000
1.71000
100.0%
100.0%
100.0%
28.3%
100.0%
0.43000
0.09500
-0.44000
0.11000
0.42000
8.6%
4.4%
31.5%
3.0%
28.3%
2.43500
1.51000
-1.36000
0.20500
1.18500
48.8%
70.3%
97.4%
5.7%
80.0%
-0.94500
-0.55000
-0.98500
-2.25000
-1.12500
22.1%
29.9%
82.3%
72.7%
88.6%
73.54%
81.74%
14.26%
57.14%
53.12%
485
278
327
188
401
0
100.0%
100.0%
100.0%
100.0%
100.0%
100.00%
Part III
Hourly 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
Plan Yr 17 – CY
2011
TOTAL COMPENSATION WITHOUT O&M
OPERATION
Variable Payment
Total ($550,000 +
Variable)
Operation
Operation
Operation
Operation
Operation
HRS/YR
0 hrs/yr
100 hrs/yr
500 hrs/yr
1000 hrs/yr
2000 hrs/yr
2784
$0
$102,901
$514,506
$1,029,013
$2,058,026
$5,986,069.89
$500,000
$552,901
$964,506
$1,479,013
$2,508,026
$6,436,069.89
TOTAL COMPENSATION WITH O&M
Variable Payment
Total ($500,000 +
Variable)
Operation
Operation
Operation
0 hrs/yr
100 hrs/yr
500 hrs/yr
Operation
Operation
1000 hrs/yr 2000 hrs/yr
$0
$299,303 $1,496,517
$2,993,035
$5,986,070
$500,000
$749,303 $1,946,517
$3,443,035
$6,436,070
7
5