Stakeholder Comment Form
ISO Rules Process
ISO OPP Rule Changes
Date of Request for Comment:
Period of Consultation:
September 10, 2009
September 10, 2009 through October 9, 2009
Comments From: _______________
Date: _______________
Contact: _______________
Phone: _______________
E-mail: _______________
OPP 303
Alberta – BC Interconnection Operation
1.
Purpose
To establish the requirements for operating the Alberta-BC interconnection. Matters related to transfer limits,
inadvertent energy management, available transfer capability (ATC) posting process and import load remedial action
schemes (ILRAS) utilization are dealt with in separate OPPs.
� Support
� Oppose
� Indifferent
Reason for Stakeholder Positions:
Alternate Proposal:
2.
Background
The Alberta-BC interconnection consists of the 500 kV line (1201L/5L94) between the Langdon substation (T102S) in
� Support
Alberta and the Cranbrook substation in BC, plus the 138 kV circuits between BC’s Natal substation and Alberta’s
� Oppose
Coleman (T799S) and Pocaterra (T48S) substations (1L275/786L and 1L274/887L, respectively) (“138 kv
� Indifferent
interconnection facilities”). A simplified single line diagram of the interconnections is shown in Figure 1. The AESO
is acknowledged as the Western Electricity Coordinating Council (WECC) Path Operator for the Alberta-BC
interconnection, also referred to as Path 1.
A computerized generation shedding system is incorporated into the Energy Management System (EMS) at the BCTC
System Control Centre ( BCTC SCC). The BCTC system power dispatcher has supervisory control of the remedial
action scheme (RAS) and can monitor generation shedding at the major South Interior plants and the status of the
Proposed ISO OPP Rule Changes: 2009-09-10
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RAS. The generation shedding system is designed so that the required amount of generation is shed to ensure that the
post-contingency transient overfrequency in the islanded area will not exceed 61 Hz per WECC criteria, and will settle
to below 60.5 Hz in less than 3 minutes.
Reason for Stakeholder Positions:
Alternate Proposal:
3.
Policy
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3.1
Outages

Planned Outages


BCTC and AltaLink must advise the ISO and the System Controller (SC) of any planned
maintenance outages for any BC interconnection facilities as set out in the requirements of OPP
601. The accountabilities of BCTC are shown under the heading of “Interconnected Members”, in
OPP 601.
Forced Outages

BCTC and AltaLink must inform the SC immediately of any forced outages for any BC
interconnection facilities. The SC must inform the Vancouver Reliability Coordinator (VRC) of the
forced outage as soon as possible after it has been notified, and advise the VRC of any change to
the system operating limit (SOL) as a result of change in path configuration. Refer to OPP 304 for
determining the SOL under specified system conditions.

When Path 1 experiences a forced outage, the SC, as Path 1 Operator, will be responsible for
curtailing e-tags for interconnection schedules on Alberta-BC interconnection.
3.2
138 kV Interconnection facilities Operation, when 1201L / 5L94 is out of service

The 138 kV interconnection facilities may be left in service if 1201L/5L94 is removed from service. If one
of the 138 kV lines must be removed from service (that is, either 1L275/786L or 1L274/887L) while
1201L/5L94 is out of service, then the other 138 kV line is to be opened between Alberta and BC, and
Alberta operated islanded from the WECC.
3.3
Alberta-BC interconnection switching

Switching – Planned Outages


Any switching involving planned outages of the Alberta-BC interconnection must be authorized
by the SC in real time. The SC, as Path 1 Operator, must inform the VRC before authorizing the
removal or restoration of Path 1. Once authorized by the SC, BCTC and AltaLink must coordinate
with each other directly any real-time switching of facilities (between the AltaLink CC and BCTC
SCC). The SC must be included in a conference call if generation changes are required to enable
synchronizing of the Alberta island to BC.
Switching – Forced Outages

If there has been a loss of 1201L/5L94, AltaLink must consult with the SC before undertaking or
coordinating any switching on the Alberta-BC interconnection. Once the SC has approved it,
AltaLink must undertake arrangements with BCTC for switching. BCTC and AltaLink must
coordinate with each other directly any real-time switching of facilities (between the AltaLink CC
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� Support
� Oppose
� Indifferent
and BCTC SCC).

3.4
1201L/5L94 restoration

3.5
AltaLink may coordinate directly with the BCTC SCC, without approval from the SC, for
switching following forced outages on the 138 kV interconnecting facilities (1L274/887L and
1L275/786L), if such events did not involve loss of synchronism between BC and Alberta. The SC
must be advised of such actions immediately following the forced outage or restoration of the 138
kV elements. If such events involve loss of synchronism between BC and Alberta, approval from
the SC is required before any switching to restore the lost circuits is undertaken. The SC, as Path 1
Operator, must obtain approval from the VRC before synchronization.
Table 2 must be followed for energizing and de-energizing 1201L/5L94.
Loss of teleprotection

AltaLink must advise the SC and BCTC SCC immediately upon the complete loss or unavailability of
teleprotection and communication elements associated with 1201L/5L94. Unavailability of the teleprotection
on 1201L/5L94 results in slow speed tripping under fault conditions, potential miscoordination with adjacent
line protections, and the terminal line-end reactors effectively unprotected.

For a catastrophic microwave failure or for a planned major microwave outage, all permissive and direct
tripping from line, overvoltage, undervoltage, breaker failure or reactor protection and open-end keying will
be lost. Even though the line would still be protected by slower channel independent back-up protection,
remote clearing for a reactor fault would be unavailable. Therefore, ISO and BCTC must, as agreed to,
remove the circuit as soon as this can practically be done following a major communications failure.
3.6
VAR control

Under zero interchange conditions, there will generally be a MVAr flow to each system due to the charging
effect of the lightly loaded 500 kV line portion of the Alberta-BC interconnection(1201L/5L94). The MVAr
flow should be equitably shared between the Alberta and the BC systems in proportion to the length of the
line located in each province.. Based on approximately +180 MVAr of net charging, the Alberta share is 120
MVAr and the BCTC share is 60 MVAr. The prime purpose must be to maintain adequate voltage levels at
both terminals.
3.7
Curtailment of import and export

3.8
If schedule curtailments are required within the hour on the Alberta-BC interconnection, they must be carried
out on a pro-rata basis, if the reason for the curtailment originates in Alberta. If such reason for curtailment
originates in BC, the curtailment order must be carried out by BCTC.
Alberta-BC interconnection (Alberta schemes)
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a.
Langdon underfrequency – overpower RAS
Underfrequency protection is installed at the Langdon substation T102S end.

Purpose:



Initiation:

If the T102S frequency is less than 59.0 Hz, and

The Alberta to BC power flow is greater than 940 MW.
Action:


This scheme is in place to prevent uncontrolled separations between the AIES and the rest of the
WECC, which could result in severe stability problems in the AIES. The underfrequency RAS
scheme must also protect the tie line from thermal overload conditions if the disturbance is outside
of the AIES.
Protection trips 1201L at Langdon substation T102S causing a transfer trip of 5L94 at BCTC
Cranbrook.
Arming Requirements:

No arming requirements.
The BC system does not have underfrequency tripping of 5L94 initiating at the Cranbrook substation.
This scheme is locally armed with the exception of alarm functionality through the SCADA.
b.

Langdon undervoltage – overpower RAS
Purpose:


The undervoltage relay trip scheme was installed at Langdon to avoid excessive load losses in
Southern Alberta due to low voltage conditions brought on by large power swing transfers to BC.
These swings can occur for certain major system disturbances within the WECC or the AIES.
Initiation:
At Langdon substation T102S:


If the 500 kV bus voltage is less than 425 kV on all three phases for 0.25 second, and

The Alberta to BC power flow is greater than 234 MW.
Action:
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

Protection trips 1201L at Langdon substation T102S causing a transfer trip of the Cranbrook
terminal
Arming Requirements:

No arming requirements.
This scheme is locally armed with the exception of alarm functionality through the SCADA.
c.
Langdon overvoltage

Notification:


Alarm: 575 kV for 0.4 second at T102S.
Initiation:
At Langdon:


Stage-1 trip: Bus voltage >575 kV for a further 5 minutes.

Stage-2 trip: Bus voltage >625 kV for 0.2 second.
Action:


Arming Requirements:

3.9
Protection trips 1201L at Langdon substation T102S causing a transfer trip of 5L94 at BCTC
Cranbrook.
No arming requirements.
Alberta-BC Interconnection (BCTC schemes)
a.
1201L/5L94 Tie Tripping RAS1

Purpose.
During certain conditions, BCTC SCC must arm this scheme to trip 1201L/5L94 for one contingency
condition being the loss of 5L92 at BCTC Selkirk). AltaLink and SC must receive a “B2S TIE TRIP
SCHEME ON”. The BCTC EMS display for B2S Cranbrook must indicate the status of this RAS. This
scheme uses teleprotection signals from Selkirk to Cranbrook and Langdon.
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
Initiation:


Action:


b.

Loss of 5L92 at BCTC Selkirk.
This RAS must trip 1201L/5L94.
Arming Requirements:

Transient stability analysis (TSA) must arm/disarm this RAS.

The BCTC South Interior Control Centre (SIC) SCADA can be used as a backup to arm/disarm
the RAS. The TSA auto download feature must be turned off, if the RAS is to remain manually
blocked. When armed, the operation of this RAS results in tripping of the 5L94 circuit (and the
BCTC Natal tie, if RAS3 is armed).
Natal overpower RAS 3
Purpose:

To avoid low voltage conditions at Natal and/or overloading on Natal T1 and T2 for loss of 5L94
circuit, whenever the loading on 5L94 circuit exceeds 45 MW from Cranbrook or 100 MW into
Cranbrook.
The RAS consists of two power relays (out and in) at Cranbrook substation that continually monitor the power
flow on the 5L94 circuit. If the power flow on 5L94 exceeds 45 MW from Cranbrook or 100 MW into Cranbrook,
the “out” power relay or “in” power relay allows a transfer trip signal to be sent to Pocaterra and Natal upon loss
of 5L94 to trip 1L274/887L at Pocaterra and trip 1L275/786L at Natal (1CB2).
There are two separate latch points at Cranbrook to independently arm/disarm the transfer trip of 1L274/887L at
Pocaterra and the transfer trip of 1L275/786L at Natal (1CB2). The first point, noted above, is called Pocaterra
RAS and the second is called Natal RAS. The two points can be controllable locally or from BCTC SCC or BCTC
SIC. Switching between BCTC SCC control mode and BCTC SIC control mode can be done either at BCTC SCC
or BCTC SIC.
In the BCTC SCC central control mode, only BCTC SCC has control of the two RAS arming points. In BCTC
SIC control mode (normal state), both BCTC SCC and BCTC SIC have control of the two RAS arming points and
the points must be armed/disarmed according to whoever accessed the point last. The BCTC-SCC dispatcher will
control the two supervisory points at Cranbrook. The BCTC TSA will arm and disarm the RAS as required. The
BCTC SCC dispatcher can manually block and “dispatcher set” the Natal and Pocaterra RAS independently.
BCTC SIC only has control if there is a failure of the BCTC SCC system. This will be done at the direction of the
BCTC SCC dispatcher.
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
Action:


To trip the two BCTC Natal 138 kV ties with Alberta.
Arming Requirements:

c.
This RAS is armed and disarmed by BCTC.
Natal undervoltage (backup to overpower) RAS
This old scheme remains in service as a backup to the BCTC Natal 138 kV tie tripping RAS3.

Initiation:



This scheme initiates at 0.85 p.u. (117.3 kV) voltage with a 0.50 second time delay.
Action:

It trips Pocaterra T48S887X

And trips BCTC Natal 1CB2 breakers.
Arming Requirements:

d.

No arming requirements.
Natal transformer protection scheme
Initiation:


For BCTC Natal transformer T1 or T2 thermal overload.
Action:

The inverse overload protection will trip Natal 66 kV breakers 60CB1 and 60CB2.
The RAS operation for each transformer bank is shown in Table 2.

Arming Requirements:

No arming requirements.
e.
2L294 RAS

Purpose:

To trip 5L94, 1L274 at Pocaterra and 1L275 at Natal for a controlled separation of the Alberta
system from BC on detection of a non-recoverable power swing on 2L294 during a 5L92 circuit
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outage.
This RAS makes use of the out-of-step detection function of the SEL321 relays at BCTC Cranbrook and Nelway
substations. These relays will determine if the power swing on 2L294 is non-recoverable and initiate tripping of
the 5L94 circuit, the 1L274 circuit at Pocaterra and the 1L275 circuit at Natal and blocking the tripping of the
2L294 circuit. With 5L92 circuit out of service, a power swing on 2L294 is generally due to a disturbance in
Alberta. Note that if the Pocaterra RAS arming point is blocked, the 2L294 RAS to trip 1L274 at Pocaterra will be
blocked automatically. Similarly, if the Natal RAS arming point is blocked, the 2L294 RAS to trip 1L275 at Natal
will be blocked automatically.

f.

Arming Requirements:

The BCTC TSA will monitor 5L92 status and automatically arm/disarm this RAS.

This RAS can be armed manually at BCTC SCC and BCTC SIC and should be armed only when
5L92 is out of service
5L91 and 5L98 RAS
Initiation:



g.

For a double contingency of 5L91 and 5L98 in the BC system when 1201L/5L94 is in service.
Action:

RAS will trip 2L112 (Nelway to Boundary) when Waneta is connected directly to Nelway, or
combined trip of 2L112 and 2L277 (Waneta to Boundary) when Waneta is connected directly to
Boundary.

The RAS effectively opens the BC–US eastern tie and islands part of the BC system (between 240
and 650 MW of load with almost 2,000 MW of generation) with the Alberta system.
Arming Requirements:

This RAS is armed by BCTC.

The arming status can be found on the EMS display # 6007 SEL (Selkirk) and on the video wall
display.
Alberta tie tripping RAS for loss of 5L51 and 5L52
Purpose:

To prevent the Alberta system frequency from dropping below 59 Hz, as required by the WECC.
This RAS allows the tripping of the BC–Alberta Interconnection for the loss of 5L51 and 5L52, or loss of 5L51
(or 5L52) with 5L52 (or 5L51) out of service during high US-to-BC transfers.
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
Initiation:


Loss of 5L51 and 5L52, or loss of 5L51 (or 5L52) with 5L52 (or 5L51) out of service during high
US-to-BC transfers.
Action:

RAS will trip the 5L94 tie if the frequency at Cranbrook is below 59.95 Hz for more than 3 cycles.

Tripping of the 5L94 tie will, in turn, trip the 1L274 tie at Pocaterra (by the Pocaterra RAS) and the
1L275 tie at Natal (by the Natal RAS) to separate BC from Alberta.
When armed during BC system moderate-to-heavy import conditions from the US and Alcan, this RAS will trip
the 5L94 tie if the frequency at Cranbrook is below 59.95 Hz for more than 3 cycles after loss of 5L51 and 5L52,
or loss of 5L51 (or 5L52) with 5L52 (or 5L51) out of service. Tripping of the 5L94 tie will, in turn, trip the 1L274
tie at Pocaterra (by the Pocaterra RAS) and the 1L275 tie at Natal (by the Natal RAS) to separate BC from
Alberta. The separation is to prevent the Alberta system frequency from dropping below 59 Hz, as required by the
WECC.

Arming Requirements:

The BCTC SCC Energy Management System (EMS) TSA advanced application automatically
arms/disarms this RAS.
The BCTC SCC system power dispatcher is responsible for arming and disarming this RAS at BCTC
Cranbrook. When TSA is unavailable, the BCTC SCC System Power Dispatcher can manually arm/disarm this
RAS from the BCTC SCC EMS Generation Shedding display. BCTC SIC also has SCADA control for arming
and disarming this RAS at BCTC Cranbrook.
h.
Cranbrook undervoltage – overpower protection

Initiation:
At BCTC Cranbrook:,


If the 500 kV bus voltage is less than 421 kV for at least 0.50 second.

There is no power supervision of the undervoltage relay at BCTC Cranbrook.
Action:


Transfer trips 5L94 at BCTC Cranbrook.
Arming Requirements:

No arming requirements.
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i.
Cranbrook overvoltage protection scheme
Overvoltage protection will trip both ends of 5L94. The tripping settings are:

At Cranbrook:


Stage-1 trip: Bus voltage >575 kV for at least 5 second.

Stage-2 trip: Bus voltage >625 kV for at least 0.25 second.
Arming Requirements:


No arming requirements.
Action:
j.

Trips 1201L at T102S

Transfer trips 5L94 at BCTC Cranbrook.
1201L Open breaker (3-pole) transfer trip

Initiation:


Three-pole opening of either 500 kV terminals of 1201L /5L94.
Action:

By causes other than line protection, sends a three-pole direct transfer trip to the remote terminal.
This scheme uses teleprotection.

Arming Requirements:

k.

No arming requirements.
Direct transfer tripping of 5L94 for loss of 5L81 and 5L82 (5L81 and 5L82 RAS)
Purpose:


Initiation:


To disconnect the Cranbrook area from Alberta upon the loss of 5L81 and 5L82 when Alberta is
exporting heavily into BC, to avoid significant generation shedding in Cranbrook area.
Loss of 5L81 and 5L82 and high Alberta to BC transfer.
Action:
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

Transfer trip 5L94/1201L.
Arming Requirements:

BCTC will arm.
l.
Direct transfer tripping of Alberta – BC Ties for loss of 5L76 and 5L79 (5L76 and 5L79 RAS)

Purpose:


To disconnect 5L94, 1L274 at Pocaterra and 1L275 at Natal upon the loss of 5L76 and 5L79.
Initiation:


Action:


Loss of 5L76 and 5L79.
Transfer trip Alberta – BC Ties.
Arming Requirements:

BCTC will arm.
3.10 TRM/ATC adjustments when the Ford Elk area load is served by Alberta

When 887L/1L274 is open at Natal or open between Natal and Pocaterra (T48S), the TRM will be increased
and the ATC will be reduced by the flow on 887L/1L274 from Pocaterra to avoid exceeding the operating
limits.

When one of the following system conditions occurs, the TRM must be increased and the ATC must be
reduced by the sum of the flows on 887L/1L274 and 786L/1L275 to avoid exceeding the operating limits:
1.
Two parallel transformers at Natal are out of service; or
2.
2L113 in the BC system is out of service.
3.11 Transfer Operating Guides
Supporting information for the transfer limits and associated operating guides for the Alberta-BC interconnection
are outlined in OPP 304.
The transfer limits, may be subject to change due to various transmission element outages and operating
conditions in the BCTC system and AIES. The BCTC system outages are further defined in BCTC’s System
Operating Order 7T-17. Events that occur on the AIES that require the limits to be adjusted, beyond those
identified in OPP 304, will be dealt with via the AESO’s System Coordination Plan and by the SC in real time.
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Reason for Stakeholder Positions:
Alternate Proposal:
4.
Responsibilities
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4.1
ISO
The ISO must:

Review in cooperation with BCTC, as required from time to time, the operating requirements on the
Alberta-BC interconnection and updating this OPP.
System Controller
The SC must:
4.2

Authorize any switching involving planned outages of the BC interconnection (500 kV and 138 kV lines) in
real time.

Inform the VRC before directing the removal or restoration of Path 1.

Authorize AltaLink before undertaking or coordinating any switching on the BC interconnection.

For events that involve loss of synchronization between BC and Alberta, obtain approval from the VRC
before any switching to restore the lost circuits.

Direct any Alberta generation changes needed to enable synchronizing of Alberta to BC.

Authorize synchronization to the BC system.

Curtail e-tags when Path 1 experiences forced outage.

Inform the VRC as soon as possible of any forced outages on Path1 and advising the VRC of any change
to the SOL as a result of change in path configuration.
BCTC
BCTC must:

Restore any BC interconnection elements that have been automatically forced out of service, in accordance
with the recommended sequences shown in Table 2 and the switching policy set out in Section 3.3.

Advise the ISO and the SC of any planned maintenance or forced outages for any BC interconnection
facilities.

Coordinate with AltaLink directly after getting authorization from SC for any real time switching involving
planned outages of facilities (between the AltaLink CC and BCTC SCC).

Issue a curtailment order if the reason for curtailment of import and export originates on the BC side.

Conference with the SC for restoring of the first 500 kV circuits (either 5L91 or 5L98).
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� Support
� Oppose
� Indifferent

Arm the 5L94 Tie Tripping RAS via TSA to trip 5L94/1201L as indicated in Table 1.

Arm and disarm the Natal 138 kV Tie Tripping RAS via TSA.

Manually arm 2L294 RAS at SCC and South Interior Control Centre (SIC) only when 5L92 is out of
service. TSA must monitor 5L92 status and arm/disarm this RAS.

The BCTC SCC EMS TSA advanced application normally arms/disarms the Alberta Tie RAS (for loss of
5L51 and 5L52). When TSA is unavailable, the SCC system power dispatcher should manually arm/disarm
this RAS from the BCTC SCC EMS generation shedding display.

Arm the 5L91 and 5L98 RAS. The arming status is to be given on the EMS display # 6007 SEL (Selkirk)
and on the video wall display.
,
4.3
TFO
The TFO must:

Advise the ISO and the SC of any forced and planned maintenance outages for any BC interconnection
facilities.

Coordinate with BCTC directly after getting authorization from SC any real time switching involving
planned outages of facilities (between the AltaLink CC and BCTC SCC).

Coordinate with BCTC directly after getting authorization from SC any real time switching involving forced
outages of facilities (between the AltaLink CC and BCTC SCC).

Coordinate directly with the BCTC SCC, without approval from the SC, for switching following forced
outages on the 138 kV interconnecting circuits (1L274/887L and 1L275/786L), if such events did not
involve loss of synchronization between BC and Alberta.

Advise the SC of any actions immediately following the forced outage or restoration of the 138 kV
elements.

Restore any BC interconnection elements that have been automatically forced out of service, in accordance
with the recommended sequences shown in Table 2 and the switching policy set out in Section 3.2.

Advise the SC promptly that there are higher than normal risk conditions (such as equipment alarms,
equipment failures, teleprotection, communication, adverse weather, etc.) on BC interconnection facilities,
which could lead to loss of those elements and have an effect on the rating of the interconnection.
Reason for Stakeholder Positions:
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Alternate Proposal:
5.
System Controller Procedures
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5.1
Double contingency of 5L91 and 5L98 with 1201L in service
The SC must:
1.
Monitor the 5L91 and 5L98 RAS arming status. The arming status can be found on the EMS display #
6007 SEL (Selkirk) and on the video wall display. If the RAS is disarmed, call the BCTC system power
dispatcher to inquire.
2.
Upon receiving an alarm: “BCH Separation”, go to the EMS display # 6007 for SEL (Selkirk). Verify that
the statuses of 5L91 and 5L98 indicate open.
3.
Verify that the EMS system automatically switched to Balancing authority constant frequency (CF) control
mode. Otherwise, manually switch it to CF control mode immediately.
4.
Monitor system frequency to ensure that it does not exceed 61.0 Hz immediately following the trip.
5.
Contact the BCTC Operator (Generation Desk) to ensure that the automatic generation shedding scheme
and/or manual generation ramping will reduce the system frequency to below 60.5 Hz within 3 minutes,
which is required in order to prevent generation tripping in Alberta (refer to Table 3 in OPP 804). A loss of
5L91 and 5L98 does not suspend AGC.
6.
Request the BCTC Operator (Generation Desk) to continue generation manual ramping until the system
frequency stabilizes at 60.0 Hz.
7.
In the unlikely event that generation shedding/manual ramping fails to reduce the system frequency to an
acceptable level, such that it jeopardizes generation tripping and/or equipment damage, direct AltaLink
Operator to open the Alberta-BC tie. Take this extreme action only if required to prevent uncontrolled
Alberta generation tripping and cascading system outages. Consider the Alberta supply and demand
situation to ensure that this is not detrimental to the Alberta system before taking this action.
8.
After the system frequency has stabilized at 60.0 Hz, check the flow on the Alberta-BC interconnection.
Contact the BCTC Operator to agree on the acceptable tie flow. (BC may want to export to Alberta due to
the excess generation capability in the islanded BC area. The associated risk is the tripping of 1201L/5L94,
which will island the small portion of the BC South Interior system. The risk to the Alberta system is
acceptable as long as the import or export is no greater than the limits presented in OPP 304. This schedule
is good for the current hour only. For the next hour, resume normal scheduling procedures). Normal
scheduling procedures including e-Tags must be followed.
9.
Resume external spinning and contingency reserve schedules.
10.
Manually ramp Alberta generator(s) to achieve the agreed upon Alberta-BC interconnection tie flow, in
coordination with BCTC.
11.
Approve e-Tag curtailments of energy transactions over the Alberta-BC interconnection submitted by
BCTC. (If the e-Tag curtailments are not actively approved, they will be approved by default.)
Proposed ISO OPP Rule Changes: 2009-09-10
Page 17 of 43
� Support
� Oppose
� Indifferent
5.2
12.
Notify the Operations on-call person.
13.
If the islanded situation extends beyond the current hour, confirm with BCTC on the ATC for the
upcoming hours and re-post the ATC accordingly
14.
Coordinate with the BCTC Operator as 5L91 and 5L98 are restored.
15.
After the restoration of 5L91 and 5L98 and the islanded situation is removed, switch back to Tie Line
Biased (TLB) control mode and resume normal procedures for Alberta-BC interconnection scheduling and
operation.
TRM/ATC adjustments when the Ford Elk area load is served by Alberta
When the Ford Elk area load is served partially or entirely by Alberta, the SC must:
5.3
1.
Determine the flows on 887L/1L274.
2.
Increase TRM and decrease ATC by the flow on 887L/1L274 from Pocaterra (T48S). Keep TTC as
scheduled and re-post the hourly Alberta to BC ATC as described in OPP 304.
3.
When the outage element(s) have been returned to service, decrease TRM and increase ATC by the flow on
887L/1L274 from T48S and re-post the hourly Alberta to BC ATC as described in OPP 304.
TRM/ATC adjustments when two parallel transformers at Natal or 2L113 are out
of service
When two parallel transformers at Natal or 2L113 in BC Hydro’s system are out of service, the SC
must:
5.4
1.
Determine the flows on 887L/1L274 and 786L/1L275.
2.
Increase TRM and decrease ATC by the sum of the flows on 887L/1L274 and 786L/1L275. Keep TTC as
scheduled and re-post the hourly Alberta to BC ATC as described in OPP 304.
3.
When the outage element(s) have been returned to service, decrease TRM and increase ATC by the sum of
the flows on 887L/1L274 and 786L/1L275 and re-post the hourly Alberta to BC ATC as described in OPP
304.
138 kV Tie Line Operation, when 1201L / 5L94 is out of service
If 1201L/5L94 is out of service and one of the 138 kV lines (that is, either 1L275/786L or
1L274/887L) is also out of service then the SC will open the remaining 138 kV line (i.e., either
1L275/786L or 1L274/887L) between Alberta and BC.
5.5
Curtailing interconnection transactions within the hour
If an outage of the transmission/generation facility as referenced in OPP 304 Table 1, Table 4 or Table
Proposed ISO OPP Rule Changes: 2009-09-10
Page 18 of 43
5 occurs within the hour of the interconnection transaction and the net transaction exceeds the import
or export ATC limits, the SC will:
5.6
1.
Curtail the e-Tags on a pro-rata basis to the amount not exceeding the ATC limits.
2.
Notify the BCTC operator.
3.
Enter the revised schedule setting on EMS.
Curtailing E-Tags
When Path 1 experiences forced outage, the SC will curtail e-tags for the AB-BC interconnection.
5.7
Communication with the VRC
The SC must proactively maintain communication with the VRC, including without limitation the
following:
1.
Notify the VRC before removing or restoring an element of Path 1.
2.
Obtain approval from the VRC before synchronizing Path 1.
3.
Inform the VRC as soon as possible of any forced outages on Path1 and advise the VRC of any change to
the SOL as a result of change in path configuration.
Reason for Stakeholder Positions:
Alternate Proposal:
6.
Figures and Tables
Proposed ISO OPP Rule Changes: 2009-09-10
Page 19 of 43
� Support
� Oppose
� No Comment
Figure 1
Alberta-BC interconnection
Mica
Selkirk
500kV
Ashton
Creek
500 kV
5L82
5L79
138kV
5L92
2L2 94
~
5L98
Meridian
Ingledow
5RX5
BC Interconnection Metering Points
5L 94 ( 1201L)
5L96
Vaseux
Lake
Nelway
230kV Waneta
Kootenay Canal
230kV
5L52
~
~
5L51
5RX4
2L293
Alcan
Seven Mile
BC
2 L112
USA
Custer
BPA’s
Boundary
Substation
9L59
945L
951L
28S
927L
9L79
9L80
/9
L9
33
923L
163S
9L99
9L100
Sheerness
Generating
Station
275S
240kV
840S
5L91
5 L77
5L44
935L
923L
2L113
Revelstoke 5 L75
5L81
924L
370S
5L72
1L
93
240kV
Cranbrook
500kV
230kV
~
5L71
1201L (5L94)
138 kV
System
SVC
807S
~
132 S
830L
1L275/786L
500kV
924L
RX
777L
Nicola
500kV
102 S Langdon
240 kV
59S
138 kV
48S
138 kV
1L274 /887L
93
3L
240 kV
911L
230kV
937L
138kV
Natal
950L/9 L50
74S
917L
936L
916L
801 S
9 44L
5S
42 S
9L20
755S
64S
901L
925L
929L
918L
240kV
863S
9L27
9 14L
63S
928L
Alberta
912 L/ 9L912
900L
906L
B. C.
TO 87 S
Gaetz
934L/9L934
17S
766 S
TO 89 S
Ellerslie
910L
9 03L
926L
995L
TO 330 P
Keephills
922L
TO 310P
Sundance
995L
190L
995AL
62S
9L948/948L
~
Battle River 757S
Generating
Station
68S
2L277
USA
Proposed ISO OPP Rule Changes: 2009-09-10
Page 20 of 43
138kV
SASK DC
INTERTIE
Table 1
RAS in the AIES and BC system that affect the Alberta-BC interchange
Area
Name of the Scheme
Description
Alberta-BC
Interconnection
(Alberta
Schemes)
Langdon Underfrequency –
Overpower RAS
RAS operates if the Langdon 102S frequency <59.0 Hz and
the Alberta to BC power flow >940 MW.
Operation of RAS will trip 1201L / 5L94 at Langdon causing a
transfer trip of the Cranbrook terminal.
Langdon Undervoltage –
Overpower RAS
RAS operates at the Langdon substation 102S, if the 500 kV
bus voltage <425 kV on all three phases for 0.25 sec and the
Alberta to BC power flow >234 MW.
Operation of RAS will trip 1201L at T102S causing a transfer
trip of the Cranbrook terminal.
Langdon Overvoltage
Protection Scheme
RAS sends alarm if 500 kV bus voltage >575 kV for 0.4 sec at
Langdon 102S.
Tripping occurs at:
 Langdon Stage 1: 500 kV bus voltage >575 kV for a further 5
minutes.
 Langdon Stage 2: 500 kV bus voltage >625 kV for 0.2 sec.
1201L/5L94 Tie Tripping
RAS 1
RAS is armed for a possible contingency of 5L92 in the BCH
system.
AltaLink and SC will receive a “B2S TIE TRIP SCHEME ON”
Operation of the RAS results in a trip of 1201L/5L94.
Natal Overpower RAS 3
RAS prevents a low voltage condition at Natal and/or
overloading on Natal T1 and T2 for loss of 5L94 circuit.
RAS is armed whenever the loading on 1201L/5L94 exceeds
45 MW from Cranbrook or 100 MW into Cranbrook
Operation of the RAS results in a trip of the two Natal 138 kV
ties with Alberta for a loss of 1201L/5L94.
Natal Undervoltage (Backup
to RAS3) RAS
This scheme initiates at 0.85 p.u. (117.3 kV) voltage with a
0.50 second time delay.
Operation of the RAS results in a trip of the Pocaterra
48S887X and Natal 1CB2 breakers.
Natal Transformer
Protection Scheme
RAS operates on overloading Natal transformer T1 or T2.
Operation of RAS results in tripping 138 kV breakers 1CB1
and 1CB2.
Alberta-BC
Interconnection
(BCTC
Schemes)
Proposed ISO OPP Rule Changes: 2009-09-10
Page 21 of 43
2L294 RAS
RAS operates on detection of a non-recoverable power swing
on 2L294 during an outage of 5L92.
Operation of the RAS results in a trip of 1201L/5L94,
887L/1L274 at Pocaterra and 786L/1L275 at Natal.
5L91 and 5L98 RAS
RAS operates for a loss of 5L91 and 5L98 in the BC system
will result to trip 2L112 or combined trip of 2L112 and 2L277.
Operation of RAS results in opening the BC – US eastern tie
and islands part of the BC system with the Alberta system.
Alberta Tie Tripping RAS for
Loss of 5L51 and 5L52
RAS operates for a loss of 5L51 and 5L52 in the BC system
during high US to BC transfers.
Operation of RAS results in a trip of 1201L/5L94.
Cranbrook Undervoltage Overpower Protection
Tripping occurs at:
 Cranbrook, if the 500 kV bus voltage <421 kV for at least
0.50 sec.
 There is no power supervision of the undervoltage relay at
this terminal.
Operation of the RAS results in transfer trip of 5L94 at
Cranbrook.
Cranbrook Overvoltage
Protection Scheme
Tripping occurs at:
 Cranbrook Stage 1: 500 kV bus voltage >575 kV for at least
5 sec.
 Cranbrook Stage 2: 500 kV bus voltage >625 kV for at least
0.25 sec.
Operation of the RAS results in tripping 1201L at Langdon and
causes a transfer trip of 5L94 at Cranbrook.
1201L Open Breaker (3Pole) Transfer Trip RAS
Three-pole opening of either 500 kV terminal of 1201L /5L94,
by causes other than line protection, sends a three-pole direct
transfer trip to the remote terminal.
Direct Transfer Tripping of
5L94 for Loss of 5L81 and
5L82 (5L81 and 5L82 RAS)
This RAS allows direct tripping of 5L94 for the loss of 5L81
and 5L82, if both Alberta to BC transfer and the required
generation shedding are high.
Direct Transfer Tripping of
Alberta – BC Ties for Loss of
5L76 and 5L79 (5L76 and
5L79 RAS)
This RAS allows direct transfer tripping of 5L94, 1L274 at
Pocaterra and 1L275 at Natal for the loss of 5L76 and 5L79.
Proposed ISO OPP Rule Changes: 2009-09-10
Page 22 of 43
Table 2
Guidelines for 5L94 (1201L) line energizing sequences for various operating cases. Use the reverse sequence to deenergize the line
Condition
Line Energizing
Lead End Terminal
Maximum Voltage at Lead End
Before Energizing the Line
System Normal
Cranbrook (preferred)
530 kV
Langdon (second choice)
252 kV with –250 MVAr room on SVC
(i.e., SVC at or above 0 + MVAr)
Cranbrook (preferred)
530 kV
Langdon SVC Out of Service
Langdon (second choice)
248 kV
Langdon RX Out of Service
Langdon (only choice)(Note 1)
248 kV with –400 MVAr room on SVC
(i.e., SVC at or above +150 MVAr)
Cranbrook 5RX4 Out of Service
Cranbrook (preferred)
530 kV
Langdon (second choice) (Note1)
248 kV with –250 MVAr room on SVC
(i.e., SVC at or above 0 + MVAr)
Cranbrook (preferred) (Note 1)
510 kV
Langdon (second choice) (Note 1)
248 kV with –400 MVAr room on SVC
(i.e., SVC at or above +150 MVAr)
5L92 Out of Service
Langdon (only choice)
252 kV with –250 MVAr room on SVC
(i.e., SVC at or above 0 + MVAr)
Cranbrook 5RX4 and 5RX5 Out
of Service
Langdon (only choice) (Note 1 and 2)
248 kV with –400 MVAr room on SVC
(i.e., SVC at or above +150 MVAr)
Langdon SVC and Cranbrook
5RX4 Out of Service
Cranbrook (only choice)
530 kV
Langdon SVC and Cranbrook
5RX5 Out of Service
Cranbrook (only choice) (Note 1)
510 kV
Langdon SVC and Langdon RX
Out of Service
Langdon (only choice) (Note 1)
236 kV (Note 3).
Langdon RX and Cranbrook
5RX4 Out of Service
Langdon (only choice) (Note 1)
248 kV with –400 MVAr room on SVC
(i.e., SVC at or above +150 MVAr)
Langdon RX and Cranbrook
5RX5 Out of Service
DO NOT ATTEMPT TO ENERGIZE
Cranbrook 5RX5 Out of Service
Proposed ISO OPP Rule Changes: 2009-09-10
Page 23 of 43
BCTC System Normal,
Black out in Calgary including
Langdon, Langdon SVC OOS
(Cranbrook 5RX5 and Langdon
RX connected)
Cranbrook (only choice)
510 kV
(see Note 4 for operating procedure)
Note:
1. Single Pole Reclosing (SPR) on 5L94 (1201L) may not succeed if one of its two line reactors (with its associated neutral reactor) is not
available for service. Bypassing of only one neutral reactor at either end of the line is expected to result in an unsuccessful single pole
reclose.
2. Consider energizing for emergencies only. It will be difficult to keep Cranbrook voltage below 550 kV after 5L94 (1201L) is energized.
3. This is below the normal operating limit. Unless the voltage can be reduced to 236 kV at Langdon prior to picking up the line do not energize
the line.
4. Under the direction of the SC, the following operating procedure is for energizing 5L94 (1201L) from Cranbrook during restoration of the
Calgary Area:
 BCTC to block the Single Pole Trip and Reclose (SPTR) of 5L94 (1201L) at Cranbrook and the SC to confirm with AltaLink CC that the
SPTR of 5L94 (1201L) at Langdon (102S) is blocked.
 BCTC to adjust the Cranbrook 500 kV bus voltage to a level less than 510 kV. This may require all Ashton Creek reactors, Nicola reactors
and Cranbrook 12 kV reactors in service and the adjustment of Revelstoke, Mica, Seven Mile and Kootenay Canal generator terminal
voltages.
 ENMAX and AltaLink, following direction from the SC, to establish a de-energized system load island, consisting of a transmission path
from Langdon to ENMAX 2 Sub and connected load of approximately 20 MW at 2 Sub. The purpose of the load island is to control
voltages in the Calgary area, upon energization of 1201L.
 BCTC to energize 5L94 (1201L) from Cranbrook.
 After 5L94 (1201L) is energized, additional load may be picked up in the Calgary area to help control the high voltages and to provide
power to substations and generating plants.
 After Alberta generation has been connected and 5L94 (1201L) ceases to be a radial supply, then BCTC will enable the SPTR of 5L94
(1201L) at Cranbrook and the SC to confirm with AltaLink CC that the SPTR of 5L94 (1201L) at Langdon is enabled.
7.
Revision History
Issued
Description
2009-
Supersedes 2008-05-01
2008-05-01
Supersedes 2007-12-12
2007-12-12
Approved for interim implementation; supersedes 2006-04-27
2006-04-27
Supersedes 2005-07-27
2005-07-27
Supersedes 2004-12-07
2004-12-07
Supersedes 2003-07-28
2003-07-28
Revised to ISO Operating Policies and Procedures
Proposed ISO OPP Rule Changes: 2009-09-10
Page 24 of 43
OPP 304
Alberta-BC Interconnection Transfer Limits
1.
Purpose
To define the policies and procedures for establishing the transfer limits on the Alberta-BC interconnection while
ensuring system reliability on the AIES.
� Support
� Oppose
� Indifferent
Reason for Stakeholder Positions:
Alternate Proposal:
2.
Background
The north-south transfer limits, named the South of Keephills/Ellerslie/Genesee (KEG) or SOK-240 operating limits,
are defined in OPP 521. The SOK-240 operating limits, together with SOK generation and SOK load, will determine
the total Alberta export capability. The sum of net exports on the Alberta-BC interconnection and the AlbertaSaskatchewan interconnection must not exceed the total Alberta export capability.
Reason for Stakeholder Positions:
Alternate Proposal:
3.
Policy
Proposed ISO OPP Rule Changes: 2009-09-10
Page 25 of 43
� Support
� Oppose
� Indifferent
3.1
Transfer limits – general

The Alberta to BC (export) total transfer capability (TTC) and BC to Alberta (import) TTC, are defined as
the maximum transfer levels that meet all of the specified pre-contingency and post-contingency criteria.
The TTC levels are determined by system studies under various Alberta internal load (AIL) and contingency
conditions.

TTC is a Path 1 system operating limit (SOL). If the actual transfer exceeds the TTC, actions must be taken
to reduce the actual transfer to below the TTC value within 30 minutes.

The Alberta-BC import and export available transfer capability (ATC), both calculated as the TTC minus the
transmission reliability margin (TRM), are the transfer volumes that are available for commercial activity.
TRM is usually 65 MW except under certain system conditions as described in Table 1.

Events that occur on the AIES that require the limits to be adjusted, beyond those identified in this OPP,
will be addressed in the ISO’s System Coordination Plan or by the SC in real time.

The transfer limits on the Alberta-BC interconnection are determined as the lesser of:

3.2

Transfer limits as determined by the ISO based on Alberta’s system conditions and constraints (as
posted on the AESO web site).

Transfer limits as determined by BCTC (BC Transmission Corporation) based on BC’s system
conditions and constraints.
The AESO, as path operator, will perform the “lesser of” determination and send the transfer limits to
BCTC and the Vancouver Reliability Coordinator (VRC). BCTC will post the “lesser of” transfer limits on
its Open Access Same Time Information System (OASIS) .
Import TTC

The Alberta-BC import TTC, corresponding to various AIL ranges under system normal conditions, are
listed in Table 2.

The Alberta-BC import TTC, corresponding to various transmission element/generating unit status, are
listed in Table 3. This table will supersede Table 2 when any of the conditions in Table 3 exist.

The Alberta-BC import TTC may be constrained if the available load under the ILRAS and the LSS are
insufficient. Refer to OPP 312 for details.
Proposed ISO OPP Rule Changes: 2009-09-10
Page 26 of 43
� Support
� Oppose
� Indifferent
3.3
Export TTC

The Alberta-BC export TTC depends on the SOK-240 operating limits (refer to OPP 521), and is calculated
as:
[SOK-240 ATC minus Forecast SOK load plus Forecast SOK generation] multiplied by Export Conversion
Factor
where:

SOK-240 ATC is defined in OPP 521, and

Forecast SOK load is the sum of the forecast loads downstream of the SOK cut plane as defined in
OPP 521, and

Forecast SOK generation is the estimated in-merit generation downstream of the SOK cut plane as
defined in OPP 521, and

Export Conversion Factor is 0.95. It has been determined and confirmed by studies as a factor to
convert SOK capability to export capability and to account for the associated increase in losses.

For any given system condition, the export TTC can not exceed the maximum export TTC as specified in
Table 4.

For multiple outages to more than one transmission facility (Table 4), or for accumulated capacitor bank
unavailability in the Calgary area greater than 395 MVAr, the maximum export TTC limits must be
determined by studies based on the particular system conditions at the time of the multiple outages or
unavailability. If such studies are not available, the export TTC will be reduced to 65 MW.

If the total submitted e-tags for the Alberta-BC interconnection and the Alberta-Saskatchewan
interconnection exceeds the total Alberta export capability as determined by the SOK-240 operating limits,
then the exports on both interconnections must be managed in real-time. The SC must monitor the actual
SOK-240 flow. The export on both interconnections may be curtailed on a pro-rata basis based on the
actual schedule.
Reason for Stakeholder Positions:
Alternate Proposal:
4.
Responsibilities
Proposed ISO OPP Rule Changes: 2009-09-10
Page 27 of 43
4.1
� Support
� Oppose
� Indifferent
ISO
The ISO must:

Review the Alberta-BC interconnection transfer limits as required, ensuring the reliable operation of the
system. The review will be carried out in coordination with the TFOs and BCTC.

Submit the “OTC Certification Form (Form A.6)” to the WECC office within 30 days following the start of
the operating season.

Post the ATC for the Alberta-BC interconnection on the AESO website at www.aeso.ca.
System Controller
The SC must:


4.2
Determine the TTC, ATC and TRM on the Alberta-BC interconnection based on AIES conditions in realtime and:

Adjust the ATC posted on the AESO’s website, if required, in real-time.

Inform the BCTC transmission operator of any adjustment to the export or import ATC on the
Alberta-BC interconnection based on AIES conditions in real-time.
Report unusual operating conditions or difficulties in adhering to the transfer limits for review to the
manager, System Coordination Centre.
BC Transmission Corporation (BCTC)
The BCTC operator must:
4.3

Carry out engineering studies to establish TTC and ATC for the Alberta-BC interconnection.

Inform the SC of their transfer limits based on BC’s system conditions and constraints.

Post the transfer limit for the Alberta-BC interconnection on the BCTC OASIS as instructed by the SC.
Transmission Facility Operator
Each TFO operator must:

Inform the SC of the status of the transmission elements listed in Table 4.
Proposed ISO OPP Rule Changes: 2009-09-10
Page 28 of 43
Reason for Stakeholder Positions:
Alternate Proposal:
5.
System Controller Procedures
Proposed ISO OPP Rule Changes: 2009-09-10
Page 29 of 43
5.1
Determine export transfer limit
Prior to T-70 minutes before each scheduling hour, and also on an as required basis when operating
conditions change, the SC must:
1.
Determine the SOK-240 ATC as described in OPP 521.
2.
Determine the forecast SOK load and forecast SOK generation including wind generation for the next
scheduling hour.
3.
Calculate the export TTC using the following:
Export TTC = [SOK-240 ATC minus forecast SOK load plus forecast SOK generation including wind
generation] multiplied by 0.95.
5.2
4.
Determine the maximum export TTC based on the status of the transmission elements listed in Table 4. If
the transmission element status changes during the hour, use the status that poses greater constraint on the
TTC (i.e., assume that it is out of service for the entire hour).
5.
Determine the AESO’s export TRM using Table 1.
6.
Obtain from BCTC their import TTC and TRM limit based on BC’s system conditions and constraints.
7.
Determine the export TTC to be “the lesser” of the results from steps 3, 4 and 6.
8.
Determine the export TRM to be “the greater” of the results from steps 5 and 6.
9.
Calculate the export ATC by subtracting export TRM from export TTC.
Determine import transfer limit
The SC mustl:
1.
Forecast the minimum AIL for each hour.
2.
Establish the hourly import TTC as the lowest of the following:
a.
Import TTC based on transmission element/generating unit statuses for the hour, according to Table
3. If the transmission element status is expected to change during the hour, use the status that poses
greater constraint on the TTC limit (i.e., assume that it is out of service or on recloser block for the
entire hour).
b.
Import TTC based on system normal conditions and the forecast minimum AIL for the hour,
according to Table 2, if none of the transmission element/generating unit status in Table 3 exists.
c.
Import TTC based on the forecast minimum AIL and the available total ILRAS and LSS load,
according to Table 1 in OPP 312. The amount of ILRAS load available for arming and the amount of
Proposed ISO OPP Rule Changes: 2009-09-10
Page 30 of 43
� Support
� Oppose
� Indifferent
LSS load on-line can be obtained from the HIMP energy management system display (# 6975).
5.3
3.
Determine the AESO’s import TRM using Table 1.
4.
Obtain from BCTC their export TTC and TRM limit based on BC’s system conditions and constraints.
5.
Determine the import TTC to be “the lesser” of the results from steps 2 and 4.
6.
Determine the import TRM to be “the greater” of the results from steps 3 and 4.
7.
Calculate the import ATC by subtracting import TRM from import TTC.
Re-post the hourly BC to Alberta transfer limit
If the import or export ATC is changed from those posted on the AESO website, the SC will:
1.
2.
Revise the hourly ATC on the Alberta-BC interconnection by:
a.
Logging onto the Interconnection Transfer Capability Posting System (ITC) and follow the
instructions in the “ATC Postings Override Maintenance User Document” to enter the revised ATC.
b.
Confirming that the ATC posting has been updated on the AESO’s website.
Call and inform the BCTC operator of the revised limit parameters (TTC, ATC and TRM) on the AlbertaBC interconnection, considering the following guidelines:

For immediate transfer limit changes within the current hour, call immediately or as soon as possible.

For transfer limit changes effective the next scheduling hour, endeavour to call by hh:05.

For future hourly transfer limit changes, provide as much advance notice as possible.
Reason for Stakeholder Positions:
Alternate Proposal:
6.
Figures and Tables
Proposed ISO OPP Rule Changes: 2009-09-10
Page 31 of 43
Table 1
Transmission Reliability Margin (TRM) under various system conditions
** Under other system conditions that are not listed below, the SC may change the TRM if it is so required to ensure system reliability.
System Conditions
Import TRM (MW)
Export TRM (MW)
System Normal, or 1201L OOS
65
65
1201L in service and
Alberta single largest contingency (SLC) > contingency
reserve obligation (CRO) to the Northwest Power Pool
The greater of:
 65
 SLC – CRO
65
1201L in service and
the Ford Elk area load is served by Alberta1 and
 887L/1L274 open at Natal or open between Natal and
Pocaterra(T48S), or
 Both 887L/1L274 and 786L/1L275 open at Natal
65 + MW flow on
887L/1L274 at Pocaterra
65
1201L in service and
the Ford Elk area load is served by Alberta1 and
 Two parallel transformers at Natal OOS, or
 2L113 in the BC system is OOS
65 + MW flow on
887L/1L274 + MW flow on
786L/1L275
65
TTC using Table 2/Table
3 minus ATC as described
in Table 3 in OPP 517
65
When 1203L or 1209L OOS for various Genesee SLC
level2
Note:
1. For details refer to OPP 303, Section 3.8.
2. For details refer to OPP 517, Section 3.6.
Table 2
Import TTC during system normal condition for various Alberta internal load (AIL) levels
Alberta Internal Load (AIL) (MW)
From
To
Import TTC (MW)1
0
6,599
605
6,600
6,899
630
6,900
7,199
655
Proposed ISO OPP Rule Changes: 2009-09-10
Page 32 of 43
� Support
� Oppose
� Indifferent
7,200
7,499
680
7,500
7,799
705
7,800
8,099
730
8,100
8,399
755
8,400
And above
780
Note:
1. Limits are extrapolated from an import limits graph.
Table 3 1
Import TTC corresponding to system conditions at all Alberta internal load (AIL) levels
Transmission Element / Generating Unit
Import TTC (MW)
1201L (102S Langdon-Cranbrook) out of service (OOS) (see Note 1)
65
1201L (102S Langdon-Cranbrook) recloser block
As per Table 1 in OPP 312 with
ILRAS load = 0 MW
102S Langdon SVC OOS
465
BCTC 2L294 OOS2
As per Table 1 in OPP 312 with
ILRAS load = 0 MW
936L (102S Langdon-74S Janet) or
937L (102S Langdon-74S Janet) OOS
565
One of the following north-south 240 kV lines OOS
928L, 906L, 922L, 903L, 190L, 910L, 914L, 926L, 918L, 932L, 929L,
925L, 901L
565
Note:
1. If any of the transmission element/generating unit status exists, Table 3 supersedes Table 2.
2. For contingency reserve requirements refer to OPP 402 Supplemental and Spinning Reserve Services.
Table 4
Maximum Export TTC5 - summer season (May 1 to October 31)
All units in MW
Proposed ISO OPP Rule Changes: 2009-09-10 One
Alberta
Internal
Load (AIL)1
System
Normal
1201L
OOS
SVC
OOS
936L
or
937L
OOS
240 kV
Backbon
e Line
OOS2,4
Accumulated Capacitor Bank
Unavailability
in the Calgary Area3,5,6
Page 33 of 43
>81 MVAr
and
≤184 MVAr
184 MVAr
and
≤314 MVAr
>314 MVAr
and
≤395 MVAr
Reason for Stakeholder Positions:
Alternate Proposal:
OPP 808
Sabotage Event Reporting
1.
Purpose
To define the policies and procedures for identifying and reporting confirmed or suspected sabotage events,
including acts of cyber sabotage that could affect the safe and reliable operation of the Alberta
Interconnected Electric System (AIES).
� Support
� Oppose
� Indifferent
Reason for Stakeholder Positions:
Alternate Proposal:
2.
Background
“Sabotage event”, as used in this OPP, is as defined in the Alberta Reliability Standard’s Glossary.
Examples include but are not limited to, occurrences or resulting circumstances suspected or determined to
have been caused by the deliberate destruction, damage or degradation of equipment, facilities, computer
systems, communication systems and telecommunication systems used by the ISO, Transmission Facility
Owner (TFO) and Generation Facility Owner (GFO) and Wire Owner (WO).
The process and communication protocol outlined in this OPP addresses the assessment and reporting
aspects of confirmed or suspected acts of sabotage or cyber sabotage affecting the AIES. These reports to
the system controller (SC) may originate from entities internal to Alberta including but not limited to ISO
staff, TFO, GFO, and WO except those that only operate facilities below 25kV. External reports may
originate from adjacent balancing authorities or the Western Electric Coordinating Council’s (WECC)
Vancouver reliability coordinator (VRC).
Reason for Stakeholder Positions:
Alternate Proposal:
3.
Policy
Proposed ISO OPP Rule Changes: 2009-09-10
Page 34 of 43
� Support
� Oppose
� Indifferent

Sabotage events that pose, or may pose a direct threat to the AIES must be reported to the SC in
accordance with this OPP.

The SC, Operations-On-Call (OOC) and the SC, Incident Commander (IC) must follow the process
outlined in Figure 2 and detailed in Section 4 of this OPP to communicate and file reports on sabotage
events.
Reason for Stakeholder Positions:
Alternate Proposal:
4.
Responsibilities
Proposed ISO OPP Rule Changes: 2009-09-10
Page 35 of 43
� Support
� Oppose
� Indifferent
4.1
� Support
� Oppose
� Indifferent
ISO
The ISO must:

Provide the SC with the capability to receive information on sabotage events on the
interconnection

Identify, report, and respond to multi-site sabotage events.

After a sabotage event has been reported to it, coordinate the security information exchange
with the RCMP and the Alberta Security and Strategic Intelligence Support Team (ASSIST) (see
Table 1).
OOC must, after it has been notified by the ISO of a sabotage event:

Notify the IC immediately.

Take direction from, and assist the IC.
IC must, after being notified by the OOC of a sabotage event:

Follow internal protocols established to deal with threats and sabotage events.

Consult and coordinate with ISO senior management, ISO security and communications staff.

Use where appropriate, the reference information posted on the NERC web site at
http://www.esisac.com pertaining to Threat and Incident Reporting, to develop the report for
the VRC/NERC.

Draft all reports including the preliminary report to be filed with the VRC.

Identify recipients who will receive the reports and updates from the ISO.
System Controller
The SC must after a sabotage event has been reported:

Gather details of the sabotage event.

Escalate immediately within the AESO. Refer to procedure found in section 5.
Proposed ISO OPP Rule Changes: 2009-09-10
Page 36 of 43
4.2

Submit the preliminary report developed by the IC to the VRC.

Communicate reports and updates received from the IC to recipients identified by the IC.
Transmission Facility Owners, Generation Facility Owners and Wire
Owners
Each TFO, GFO or WO, except those that only operate facilities below 25kV, must:

Have the ability to receive information about sabotage events on the interconnection.

Follow internal procedures for reporting sabotage events to the local police force.

Report sabotage events that may have a significant impact on the AIES to the SC. Examples
may include but are not limited to situations of heightened operational awareness or situations
that may result in a reconfiguration in the AIES in order to maintain system reliability. Single
events of vandalism or minor tampering of less critical components must be reported to the
SCC management on the next business day if the incident is escalated within the market
participant’s organization.
Reason for Stakeholder Positions:
Alternate Proposal:
5.
System Controller Procedures
When a sabotage event is reported to the SC, the SC must:
1.
Gather details of the sabotage event and complete as much information in the System Sabotage Event
Reporting Form or Cyber Sabotage Event Reporting Form (Figure 1) as possible.
2.
Notify the OOC immediately.
3.
Take direction from the IC on the information to report to the IC’s identified recipients. There are
security issues that must be considered before the SC can file any reports. See Figure 2.
4.
File the preliminary report developed by the IC with the VRC. Refer to 4.1 IC responsibilities.
5.
Log the sabotage event in the Shift Log (see OPP 1301), posting for internal use only.
6.
Disseminate reports and updates provided by the IC to the recipients that the IC has identified. This
dissemination could be on ADaMS if the IC directs that all market participants are to be notified or via
Global Talk if the IC directs such information is to be shared with each TFO and GFO only.
Proposed ISO OPP Rule Changes: 2009-09-10
Page 37 of 43
� Support
� Oppose
� Indifferent
Reason for Stakeholder Positions:
Alternate Proposal:
6.
Figures and Tables
Proposed ISO OPP Rule Changes: 2009-09-10
Page 38 of 43
� Support
� Oppose
� Indifferent
Figure 1
System Sabotage Event Reporting Form
Internal Contact Information
External Contact Information
Recorded by
Name/Title
Date
Organization
Time
Email
7 x 24 Contact Info
What assistance
is required?
Subject
System sabotage (continue on this page)
Cyber sabotage (2nd page)
Date and Time Event Occurred
Date and Time Event Resolved
Type of Incident (Where did the incident occur? What was affected?)
Generating station
Generating substation
Transmission substation
Distribution system
Control Centre
Energy Mgmt System
Information Systems
Other
Incident Summary
Damage (What were the consequences of the event?)
Numbers of systems affected
Nature of loss, if any
System downtime
Proposed ISO OPP Rule Changes: 2009-09-10
Page 39 of 43
Estimated incident cost
Additional Comments
Copies Sent To
Cyber Sabotage Event Reporting Form (continued)
Attack Vector
External
Infected web site
Software download
E-mail attachment
Removable media
(diskette, CD USB drive, etc.)
Other
Primary systems or infrastructure involved
Software affected
(e.g., ABB Ranger, AREVA e-terra)
Operating system and version
(Windows, UNIX, Linux)
Security software
(AntiVirus, IDS/IPS, etc.)
Firewall information
(Type/Version)
Network Equipment
(Make, model and version)
Other
Type of malicious code (include name if known):
Virus
Trojan horse
Worm
Joke program
Other
Operation method (for new malicious code)
Details
Type: Macro, boot memory resident, polymorphic,
Proposed ISO OPP Rule Changes: 2009-09-10
Page 40 of 43
self encrypting, stealth
Payload
Software infected
Files erased, modified, deleted, encrypted
Self propagating via e-mail
Detectable changes
Other features
Remediation (How was the event resolved?)
Details
Anti-virus product installed or updated
Firewall and/or server-based filtering updated
Software deleted, updated and/or restored
Network traffic rerouted or filtered
Update to security policies
Figure 2
Sabotage event notification flow chart
Proposed ISO OPP Rule Changes: 2009-09-10
Page 41 of 43
AESO staff
Event
considered
to be
Sabotage
or
Suspected
to be
Sabotage
Reported
by:
Operations on Call
(OOC)
TFO, GFO, WO
Adjacent BA
System
Controller
Director Operations
Integration or designate
IncidentCommander
ISO Executive
Corporate
Security
Communications
VRC
NERC
USA Homeland
Security
Canadian
Government
Agencies
Red solid straight arrows indicate the flow of information from the source to the
Incident Commander
Dash curved lines indicate the flow of information from the Incident Commander to
the VRC/NERC, adjacent balancing authorities, and to recipients
within the AIES, via the SC.
Proposed ISO OPP Rule Changes: 2009-09-10
Page 42 of 43
Table 1
Law enforcement contact information
7.
Agency
Contact
Calgary Police Service
911
Alberta Security and Strategic
Intelligence Support Team
(ASSIST)
Denis Huot Manager 780-427-4973, cell 780-966-4248
denis.c.huot@gov.ab.ca
Gord Beagle Field Officer 403-592-4062, cell 403-801-7510
gord.beagle@gov.ab.ca
Sarah Weis Administrative Support 780-427-5089
sarah.weis@gov.ab.ca
RCMP
National Security Investigation Section
Sgt. Terrance Zeniuk or David Bibeau (24/7) 403 292-8705
Revision History
Issued
Description
2009-xx-xx
Supersedes 2008-11-13
2008-11-13
Supersedes 2008-05-30; only confidential information changed
2008-05-30
New issue, approved for interim implementation
Reason for Stakeholder Positions:
Alternate Proposal:
Please return this form with your comments by October 9, 2009, to:
Jason Murray
Manager, Operations Services
E-mail: jason.murray@aeso.ca
Phone: (403) 705-5230
Fax: (403) 705-5252
Proposed ISO OPP Rule Changes: 2009-09-10
Page 43 of 43