ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-001 (a)-(c)
Page 1 of 2
Title:
Reference:
Application, Section 2, p.19
Preamble:
The Application states:
The 2006 volume forecast for Standby Regulating Reserve Activations is higher
than the 2005 Forecast due to the amount of intermittent generation that is
anticipated to come on line during 2005.
Request:
(a) Please define “intermittent generation” and confirm that intermittent
generation (IG) includes at least wind generation and run-of-river hydro
generation.
(b) Please provide the amount of IG in 2004 and the projected amounts for 2005,
2006 and later years if available. Provide a breakdown by asset class and
the historical and projected energy load factor (i.e. capacity factor) for each
asset class.
(c) Please provide a full explanation as to why Standby Regulating Reserve
Activations are affected by the amount of IG. Explain whether the cause of
activation is related to the capacity of IG or to the volatility and nondispatchable nature of the IG class of assets.
Response:
a) Intermittent generation includes wind, run of river hydro, co-gen, solar, etc.
This type of generation is intermittent for any number of reasons that cause
the generator output to vary in a manner that may not be consistent with
electricity market price or system demand. Often intermittent generation
contribution to the grid varies without a system controller dispatch.
b) Intermittent Generation, Actual and Projected MCR
Wind
Run-of-river hydro
Co-generation
2004 (MW)
2005 (MW)
2006 (MW)
251
186
2762
465
186
2892
1005
186
2892
Estimated
Capacity factor
30%
45%
80-85%
c) The amount of IG is expected to increase over the next number of years.
Based on observable behavior over past years, it is the AESO’s assessment
that ensuring moment to moment supply demand balance is being impacted
by increased amounts of IG. Regulating reserves are used to maintain
Page 2 of 2
moment to moment supply demand balance and are supplemented by energy
market dispatches in order to ensure regulating range in both directions.
Efforts to quantify impacts of IG are underway by AESO. In absence of
quantified impacts, AESO has chosen to forecast an increase of standby
activations in 2006 due to impacts of IG. It is difficult to predict in which
moments a co-gen will change output or in which hours the wind will blow,
forecasting standby regulating reserve activation is expected to be more
representative of system operator response to IG operation. IG impacts relate
to variability, non-dispatchability and the total volume of IG as a percentage
of total supply.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-002 (a)-(e)
Page 1 of 2
Title:
Reference:
Application, Section 2, p.19
Preamble:
The Application states:
The 2006 volume forecast for Standby Regulating Reserve Activations is higher
than the 2005 Forecast due to the amount of intermittent generation that is
anticipated to come on line during 2005.
Request:
(a) Please explain whether the level of Active Regulating Reserves is affected by
the amount of intermittent generation and, if so, whether this has been
reflected in the forecast for 2005 and 2006. If not, explain.
(b) Please explain whether the level of Active Spinning Reserves is affected by
the amount of intermittent generation and, if so, whether this has been
reflected in the forecast for 2005 and 2006. If not, explain.
(c) Please explain whether the level of Active Supplemental Reserves is affected
by the amount of intermittent generation and, if so, whether this has been
reflected in the forecast for 2005 and 2006. If not, explain.
(d) Please explain whether the level of Standby Spinning Reserves is affected by
the amount of intermittent generation and, if so, whether this has been
reflected in the forecast for 2005 and 2006. If not, explain.
(e) Please explain whether the level of Standby Supplemental Reserves is
affected by the amount of intermittent generation and, if so, whether this has
been reflected in the forecast for 2005 and 2006. If not, explain.
Response:
a) Active regulating reserves are not forecasted to be affected by intermittent
generation in 2005 or 2006.
b) Spinning Reserves, including Active, Standby and Supplemental, are part of
contingency reserves. AESO has implemented reserves requirement policy
consistent with North West Power Pool (NWPP) Policy. WECC Minimum
Operating Reliability Criteria Section 1 A 6 provides that members may form
reserve sharing groups. The NWPP is a member of WECC. NWPP operates
a reserve sharing group. AESO as the Alberta control area operator is a
member of the reserve sharing group. The NWPP Policy provides that 5% of
on line wind generation is required for contingency reserves. Previous policy
was silent on wind generation as distinct from the 5% reserve requirement for
hydro and the 7% requirement for thermal generation. This change is not
reflected in the 2005 GTA forecast and is reflected in the 2006 GTA forecast.
Page 2 of 2
Please refer to AESO OPPs 400 through 406 for details on operating reserve
services and requirements.
c) Please refer to b) above.
d) The forecast Standby Spinning Reserve has 2 components: the first
component provides for increased reserve capacity due to forecast error and
the second component provides additional reserve capacity due to an
unplanned outage of an Active Spinning Reserve provider.
e) The forecast Standby Supplemental Reserves are provided to cover an
unplanned outage of Active Supplemental Reserve provider.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-003 (a)-(e)
Page 1 of 2
Title:
Reference:
Application, Section 2, p.19
Preamble:
The Application states:
The small decrease in Standby Spinning Reserve Premium volumes between the
2006 Forecast and 2005 Forecast is due to a change in the calculation of
Operating Reserve requirements from 7% to 5% for load responsibility by
intermittent generation, and an increase in non-firm load in Alberta equating to a
decrease in the AESO’s responsibility for AIES load.
Request:
(a) Please explain the current calculation of Operating Reserve requirements
and the standards followed for this determination. (e.g. WECC Reliability
Criteria).
(b) Please explain the reasons why the AESO is changing the load responsibility
of intermittent generation from 7% to 5%. Please explain how this complies
with the WECC standards.
(c) Please define “non-firm load” and explain what types of load is included in
this class.
(d) Please provide the amount “non-firm load” in 2003, 2004 and the projected
amounts for 2005, 2006 and later years if available. Provide a breakdown by
sub-class if available.
(e) Please explain how the “non-firm load” is taken into consideration when
determining the amount of Standby Spinning Reserves. Please explain any
limitations or constraints to this determination as required by the
NERC/WECC reliability standards.
Response:
a) The calculation of the Alberta control area operating reserve requirements
are described in OPPs 401, 402, 403, 405, 406. Please refer to AESO
website for these OPPs. Further information on WECC operating criteria are
available on www.wecc.biz.
b) Please refer to ENCANA.AESO – 002 (b).
c) In context of operating reserve requirements, non-firm load is that portion of a
customer’s load that is not required to be included in AESO’s reserve
requirement. Please see OPP-406 for additional detail.
Page 2 of 2
d) Non-Firm Load Actual and Projection
2003a
2004a
2005f
2006f *
Firm load (MW)
6544
6656
7072
7084
Non-firm load (MW)
598
721
739
868
* A change to the non-firm load calculation was made in August 2004 and
reflected in OPP-406. The 2005 forecast was completed in June 2004. The 2006
forecast was completed in December 2004. The following table indicates the
change in non-firm load due to the change in calculation.
Non-firm load (MW)
2004Jan-Aug
639
2004Sep-Dec
887
e) Non-firm load is not required to be taken into account of Standby Spinning
Reserves. Therefore non-firm load is not forecast to be taken into account of
Standby Spinning Reserves Please see OPP-406 for additional detail.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-004 (a)-(e)
Page 1 of 2
Title:
Reference:
Application, Section 2, p.24
Preamble:
The Application states:
Under-Frequency Mitigation is configured to automatically trip a specified amount
of load if the system frequency drops below 59.5 Hz following a system
disturbance. The service mitigates the need to trip firm load following an underfrequency event and works together with ILRAS to increase the capacity of the
Alberta-BC interconnection. The AESO procures these services through
contracts with service providers.
Request:
(a) What is the “specified amount of load” that is expected to automatically trip if
the system frequency drops below 59.5 Hz?
(b) Using confidential labels provide a breakdown of the UFM load according to
service provider. Explain whether the service provider is a distribution Utility
or end-use customer.
(c) Who has the responsibility to monitor and test the operability of the
equipment used to automatically trip load when the system frequency drops
below 59.5Hz?
(d) Please confirm that in the past two years all such equipment has been tested
and certified as operating properly. If this cannot be confirmed, explain why
the AESO is relying on equipment that may not be operational.
(e) Please provide a summary of the under-frequency events that have occurred
in Alberta in the past 10 years and indicate for each event what type of underfrequency mitigation was triggered, the percentage of mitigation load that
actually responded (successful deployment rate) and the reasons why the
non-deployed load failed to operate as planned.
Response:
a) The specified amount of load is the load under contract.
b) Supplier A = 67 MW
(f) Supplier B = 42 MW
(g) Supplier C = 37 MW
(h) All suppliers are end-use customers.
c) The owner of the equipment is responsible to monitor and test the equipment.
Page 2 of 2
d) Not confirmed. The AESO provides, through means including; contracts,
standards and rules, that equipment supporting reliability meets performance
requirements. The AESO evaluates system performance and takes action to
correct any elements of the system that do not perform.
e) The following table provides a summary of events where system frequency
was less than or equal to 59.5 Hz. Data is provided from 1999 to present.
Date of event
October 25, 1999
April 16, 2000
June 26, 2000
August 4, 2000
June 14, 2004
Load Tripped
UFM
ILRAS
197 MW
0 MW
81 MW
59 MW
95 MW
0 MW
78 MW
0 MW
49 MW
0 MW
successful deployment rate
UFLS
0 MW
262 MW
182 MW
184 MW
0 MW
100%
100%
100%
100%
100%
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-005 (a)-(e)
Page 1 of 2
Title:
Reference:
Application, Section 2, p.24
Preamble:
The Application states:
Under-Frequency Mitigation is configured to automatically trip a specified amount
of load if the system frequency drops below 59.5 Hz following a system
disturbance. The service mitigates the need to trip firm load following an underfrequency event and works together with ILRAS to increase the capacity of the
Alberta-BC interconnection. The AESO procures these services through
contracts with service providers.
The 2006 Forecast, 2005 Forecast, 2004 Recorded and 2004 Forecast costs are
all similar. The majority of the costs arising from these agreements are fixed.
The AESO is currently reviewing technical requirements and commercial
arrangements related to Under-Frequency Mitigation.
Request:
(a) In what way does the UFM program “work together” with the ILRAS program
to increase the capacity of the Alberta-BC interconnection?
(b) Please list all under-frequency programs used by the AESO.
(c) When was the last time the AESO studied the need for and appropriate
amounts of each under-frequency mitigation program, including UFM 59.5,
BC-ILRAS and the Under-frequency Load Shed (UFLS) programs? Please
provide a copy of the study.
(d) Please confirm that the current review of UFM59.5 includes an examination
of the need for and appropriate amounts of each under-frequency mitigation
program, including UFM 59.5, BC-ILRAS and the Under-frequency Load
Shed (UFLS) programs? If not confirmed, explain why the AESO is reviewing
only one aspect of its under-frequency mitigation program.
(e) Please explain the AESO’s plans for implementation of the study results?
When will the current technical review be complete? Does the AESO intend
to present the results to stakeholders and to seek feedback? When does the
AESO expect to implement the changes, if any?
Response:
a) The UFM (also known as LSS) and ILRAS operation with respect to the
interconnection is described in OPP 312. The services work together to
increase the BC to Alberta import capability by ensuring an appropriate
amount of load is tripped for loss of interconnection such that under
Page 2 of 2
frequency load shed blocks are not tripped for a single contingency event. As
defined in OPP 312, when available, UFM (LSS) is used to reduce the
amount of ILRAS required.
b) There are three elements to AESOs under frequency program. They are;
 Under Frequency Load Shed (UFLS)
 Brazeau Fast Ramp (GRAS)
 Under Frequency Mitigation Program (UFM)
c) Import capability and UFM were re-evaluated in 2004. Brazeau Fast Ramp
was re-evaluated in 2003. The UFLS program is part of the larger WECC
program. The UFLS was studied in 2004 by WECC. Compliance to UFLS is
assessed by AESO annually. The AESO declines to provide copies of the
studies.
d) Not confirmed. Please see part c) above. It is not necessary to study all
programs at the same time. While the programs are electric system
frequency based, the required outcomes from the programs are different.
e)
The details regarding technical requirements and commercial arrangements
Under-Frequency Mitigation have not been finalized.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-006 (a)-(d)
Page 1 of 1
Reference:
Application, Section 5, Schedule 5.2
Preamble:
The list of “Revenue Offsets” includes Under Frequency Load Shed costs of $2.0
million.
Request:
(a) What is the amount of UFLS load forecast for 2005 and 2006? Compare this
to the historical load under UFLS for the past 5 years.
(b) Using confidential labels provide the number of service providers and the
amount of load for each service provider.
(c) Who has the responsibility to monitor and test the operability of the devices
used to automatically trip load at various frequencies?
(d) Please confirm that in the past two years all such devices has been tested
and certified as operating properly and in accordance with the relay trip
setting to which the customer is credited. If this cannot be confirmed, explain
why the AESO is relying on equipment that may not be operational.
Response:
a)
UFLS Forecast and Recorded Load
2006
Forecast
3387
2005
Forecast
3302
2004
Recorded
3421
2003
Recorded
2930
The AESO has consistent data for UFLS from 2003.
b) The providers of UFLS are DFOs. Each DFO is accountable for being
compliant with Table 1 as listed in OPP 804 Off Nominal Frequency Load
shedding and restoration.
c) The owner of the relay equipment has the obligation to test the operability of
the devices used to automatically trip load at various frequencies.
d) Not confirmed. The AESO expects the customer as outlined in part c) above
will meet their obligations.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-007 (a)
Page 1 of 3
Reference:
Application, Section 5, Schedule 5.2
Preamble:
Schedule 5.2 provides a list of “Revenue Offsets” totalling $37.3 million.
Request:
(a) For each line item in Schedule 5.2, provide an explanation for the forecasted
amounts and a review of the historical amounts using a format similar to
Section 2 of the Application.
Response:
Description
DTS Tariff Revenue Offsets
Power Factor Deficiency Revenue
Demand Opportunity Service Revenue
Export Opportunity Service Revenue
UFLS Credits
Primary Service Credits (COS pre 2006)
RGU Connection Costs
Fort Nelson Demand Service Revenue
Duplication Avoidance Adjustments
Demand Opportunity Service Losses
Export Opportunity Service Losses
Import Opportunity Service Losses
Import Opportunity Revenue
Total Tariff Revenue Offsets
2006
Forecast
Corrected
$ 000 000
$
2006
Forecast as
Filed
$ 000 000
(0.3)
(2.1)
(3.5)
2.0
4.3
(25.4)
(6.4)
(0.8)
(1.8)
(8.3)
3.3
(39.0) $
(0.3)
(2.1)
(2.0)
2.0
4.3
(25.2)
(6.4)
(0.8)
(1.8)
(8.3)
3.3
(37.3)
2004
Recorded
$000 000
(0.3)
(2.8)
(2.5)
2.0
7.6
(27.5)
(0.8)
(2.0)
(8.3)
3.3
(3.5)
(34.8)
Note: Shaded cells represent changes from the AESO’s 2006 GTA filed amounts.
Power Factor Deficiency
The Power Factor Deficiency revenue is forecast to be the same in 2006 as the
2004 Recorded amount, which has historically remained unchanged.
Demand Opportunity Service Revenue
The DOS forecast for 2006 has decreased by $0.7 million from the 2004
recorded amount, which is attributable to the usage of DOS being forecast to
continue to decrease over time. The DOS forecast was established both by
looking at historical volumes and in conversations with current DOS customers.
Export Opportunity Service Revenue
Page 2 of 3
The 2006 Forecast revenue offset has increased by $1.0 million from the 2004
recorded amount which is due to an increase in the proposed STS / export
energy charge, which is proposed to increase from $2.35 / MWh to $4.07 / MWh.
The 2006 Forecast was calculated by extracting the volumes from the revenues
for export service in 2004 and multiplying that value by the proposed rate STS /
export energy charge.
UFLS Credits
2006 Forecast from the 2004 Actual is unchanged because the UFLS credit is
based on the relay setting and UFLS Capacity for each relay setting and the
credit ($/MW of UFLS capacity/ month) is not proposed to change in the 2006
GTA.
Primary Service Credit - PSC (Customer Owned Substation Credit - COS
pre-2006)
2006 Forecast from the 2004 recorded revenue has decreased by $3.3 million
primarily prior period adjust (credit to a customer) that occurred in 2004. The
decrease is also due to the change in eligibility criteria from the COS to the
proposed PSC. Specifically, fewer customer facilities are eligible under the PSC
than the COS. The 2006 Forecast was calculated taking the total DTS contract
capacity of the facilities that are eligible for the PSC and multiplying that total by
the rate per month ($700/MW/month) and the number of months in a year (12
months).
RGU Connection Costs
Please refer to BR.AESO-39 (a-d)
Fort Nelson Demand Service Revenue
Please refer to BCH.AESO-12 (a). Prior to the AESO’s 2006 GTA there was not
a separate Fort Nelson Demand Service rate.
Duplication Avoidance Adjustment
Duplication Avoidance Adjustment (DAT) revenue has remained at $0.8 million
for the 2006 forecast from the 2004 recorded. The forecast is calculated as per
Riders A1, A2, A3, A4, as set out in Section 4 of the AESO’s 2006 GTA.
Export Opportunity Losses
Export Opportunity Losses forecast for 2006 is the same as the 2004 Recorded
amount.
Import Opportunity Losses
Export Opportunity Losses forecast for 2006 is the same as the 2004 Recorded
amount.
Import Opportunity Revenue
Import Opportunity revenue is not applicable under the proposed tariff, as import
opportunity customers are only eligible to pay their transaction fee and losses
charge as outlined in the AESO’s 2006 GTA, section 4, page 27 of 51,
“As the Transmission Regulation requires all costs of the transmission system
(except for losses and RGU connection costs) to be allocated to load customers
and exporters, it follows that no costs should be allocated to importers. The
2
Page 3 of 3
interconnection charge of the AESO’s Import Opportunity Service rate will
therefore be eliminated”.
3
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-008 (a)-(b)
Page 1 of 2
Title:
Reference:
Application, Section 2, p.26 and Section 8, p.3
Preamble:
In Section 8, the Application states:
The 2004 Preliminary Recorded losses costs decreased by $44.4 million from the
stakeholder session primarily due to:



Pool payments – an adjustment of ($9.1) million related to the accounting
process of finalizing 2004 recorded losses costs,
Prior period losses adjustment – an adjustment of ($7.8) million related to
prior period settlements, and
One-time settlement data adjustment – an adjustment of ($27.6) million
related to a restatement of customer meter data.
Pool Payments =
Prior Period Settlements =
Prior Period Metering Adjustment =
Total Difference
($9.1 million)
($7.8 million)
($27.5 million)
($44.4 million)
Please refer to Section 2.4 for further information regarding these losses
adjustments.
Request:
(a) Please provide a complete description of the nature of each of the three
adjustments.
i.Please explain why the costs were originally booked to the account of 2004
loss costs.
ii.Please explain where the costs are now booked, including whether such costs
will be accrued to 2003 losses or 2005 losses costs. Please explain why this
is appropriate.
(b) Please explain whether the adjustments will be consistent with the recording
of losses on a production month basis and the extent to which these
adjustments will impact the determination of costs on a production month
basis for purposes of the 2004 Deferral Account Reconciliation.
Response:
a. Pool Payments – The material for the January 19, 2005 AESO presentation
was prepared prior to processing the December 2004 energy market
settlement which would update the transmission line losses for the months of
May and September 2004 and provide the initial line loss costs for December
Page 2 of 2
2004. The December 2004 Final Pool Statements was available on January
24, 2005.
Prior Period Settlements and Prior Period Metering Adjustment – the
explanation for these two items is provided in Section 2 on page 28 of 53.
i) and ii) The adjustments for prior period losses (pre-2004) are included and
highlighted in the 2004 transmission line losses. These costs must be
incorporated into an annual deferral account reconciliation process and at this
time, all pre-2004 deferral accounts have been reconciled. As stated in
Section 2 on page 28 of 53, “These prior period adjustments to line losses will
be incorporated in to the 2004 annual deferral account reconciliation, subject
to the approved refund methodology in respect of which the AESO will be
consulting with industry.”
b. The 2004 Recorded costs for transmission line losses are recorded by
production month, with the exception of the highlighted adjustments that
relate to prior periods discussed above. The extent to which these
adjustments will impact the 2004 annual deferral account reconciliation will be
addressed in the consultation process that the AESO will conduct with
industry on the methodology to reconcile prior period adjustments.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-009 (a)
Page 1 of 1
Reference:
Application, Section 2, p.28
Preamble:
The Application states:
2006 Forecast volumes of 3,180 GWh are 194 GWh (or 6.4%) higher than the
2005 Forecast of 2,986 GWh, due to an expected increase in load growth of
2.4%, increased generation in the northern part of Alberta, and increased loading
on the transmission system without a physical increase in capacity.
Request:
(a) Please describe the nature of the increased loading on the transmission
system and compare it to the past five years? Has the loading increased in
all hours or only for certain times, of the day, of the week, of the month or of
the year?
Response:
a) The nature of the increased loading is due to the increase in
Alberta demand, the increased generator output to serve the demand, and
the distribution of generation on the system. For example, the loading on the
240 kV between Edmonton and Calgary and the lines south of Ft McMurray
have seen an increase in loading. Please refer to TCE.AESO-214 (c).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-010 (a)-(c)
Page 1 of 1
Title:
Reference:
Application, Section 2, p.29
Preamble:
The Application states:
The AESO will consider the input and advice received through the SAC when
developing its 2006 Own Cost forecast. As final AESO Board Member approval
regarding the AESO’s 2006 Forecast Own Costs will not likely occur before the
Board needs to make a decision on this Application, the AESO proposes that the
Board approve the placeholder for 2006 forecast rate setting purposes, and any
variances would be handled through the deferral accounts. The AESO sees this
issue as a one-time event for 2006. Upon AESO Board Member approval, the
AESO will file its 2006 Own Costs Forecast with the Board for information
purposes. [emphasis added]
Request:
(a) Please explain why the AESO believes that the current process of Board (i.e.
EUB) approval first, followed by a budget setting approval by the ISO
Members is only a one-time event for the 2006 rates.
(b) Please confirm that the AESO intends to file the 2007 GTA in Q4 of 2005.
Please explain whether the AESO is planning for the ISO Members to
approve the Own Costs for the 2007-year prior to or after filing the 2007 GTA.
(c) Does the AESO intend to file a GTA on an annual basis or at least the Own
Costs portion? If yes, explain when the AESO plans to do so and how this
timing will correspond to the budgeting cycle of the AESO, including the
review of the ISO Members.
Response:
(a-c) Refer to ADC.AESO-2 and BR.AESO-33.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-011 (a)-(c)
Page 1 of 1
Title:
Reference:
Application, Section 2, p.29; Decision 2005-05, p.6
Preamble:
The Application states:
The AESO will consider the input and advice received through the SAC when
developing its 2006 Own Cost forecast. As final AESO Board Member approval
regarding the AESO’s 2006 Forecast Own Costs will not likely occur before the
Board needs to make a decision on this Application, the AESO proposes that
the Board approve the placeholder for 2006 forecast rate setting purposes,
and any variances would be handled through the deferral accounts. The
AESO sees this issue as a one-time event for 2006. Upon AESO Board Member
approval, the AESO will file its 2006 Own Costs Forecast with the Board for
information purposes. [emphasis added]
In Decision 2005-05, the Board states:
Actual costs accumulated in deferral accounts that have not been reviewed by
the Board for prudence cannot be said to have been approved by the Board in
the relevant sense so as to guarantee their recovery by the AESO.
Request:
(a) Please confirm that the AESO is proposing to move to a prospective deferral
account method (PDAM) for the recovery of Own Costs in the 2006-year.
(b) Please explain how the AESO intends for the Board to approve of
accumulated deferral account balances before they are allocated to
customers under a PDAM. If the AESO does not intend for the Board to
review and approve such costs for recovery, explain if the AESO intends to
bear the risk of non-recovery for Own Costs.
(c) Please explain what cost categories of the 2006 GTA are intended to be
recovered by PDAM and how the AESO envisions Board approval of such
costs.
Response:
a) Yes, for the total AESO’s revenue requirement excluding losses which the
AESO has proposed a different methodology for in the 2006 Application.
b) The AESO intends to address this concern with its stakeholders in 2005 prior
to applying for a 2006 prospective deferral account rider methodology. Also,
please refer to response FIRM.AESO-01 (b).
c) Please see (a) & (b) above.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-012 (a)-(b)
Page 1 of 1
Title:
Reference:
Application, Section 2, p.30
Preamble:
The Application includes a forecast of External Regulatory Costs for 2005 and
2006 of $5 million in contrast to a 2004 recorded amount of $2.3 million.
Request:
(a) Please provide a schedule reconciling the Regulatory Costs for 2004 and the
forecasted costs for 2005 and 2006, according to the hearing, the timing of
the Board cost approvals and the expensing of such costs by the AESO
(b) For each of the hearings identified in question a), please provide a schedule
of legal and consulting costs that will not be recovered under the Regulatory
Costs but will be recovered under the G&A costs of the AESO.
Response:
a. Please refer to the attached schedule ENCANA-AESO-012 (a) for a detailed
list of the 2004 Recorded External Regulatory Costs. The detail supporting
the 2005 forecast for External Regulatory Costs was provided in Section 2 for
the 2005 GTA on page 23 or 53. As stated in the 2006 GTA, Section 2.5 on
page 29 of 53, the “2005 AESO Own Costs Forecast has been used for
2006”.
b. Given the uncertainty of the regulatory issues and the timing and conclusion
of hearing proceedings, a detailed breakdown is not available. In determining
the annual General & Administrative forecast amounts, the AESO
incorporates legal and expert consulting costs anticipated to occur but would
not be recoverable into the annual G&A forecast using a lump sum estimate.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-013 (a-c)
Reference:
Application, Section 4, Rate Design, p.4
Preamble:
The Application states:
Page 1 of 1
In response to Direction 21, the AESO conducted a stakeholder consultation
process to review and comment on an Alberta Transmission System Wires Only
Cost Causation Study prepared for the AESO by PS Technologies Inc. The
AESO initially distributed copies to stakeholders and posted the study on the
AESO’s web site in September 2004. The study was also presented at an AESO
stakeholder conference on October 6, 2004, and at an AESO 2006 tariff
stakeholder session on December 3, 2004. Comments received during this
consultation process were reviewed and revisions to the Cost Causation Study
were made. A final version of the study is included as Appendix B to this
Application. (p.4)
Request:
(a) Is it the position of AESO that the function of the bulk transmission system
has not changed since the introduction of the Electric Utility Act in 1995? If
yes, explain. If no, explain the change in function and the reasons for this
change.
(b) Please confirm that the AESO initiated the stakeholder consultations after the
commissioning of the Cost Causation Study and not prior to its
commissioning. If no, explain the consultations conducted by the AESO and
the opportunities for stakeholders to provide a detailed consideration of the
DTS rate design.
(c) Does the AESO agree that there has not been unanimous agreement from
stakeholders in response to the Wires Costs Causation Study? Please
explain.
Response:
(a) The physical purpose of the transmission system has not changed throughout
industry restructuring. Prior to industry restructuring, transmission was
considered one of three functions in the vertically integrated structure.
(b) The AESO has held on going stakeholder discussions regarding its
transmission tariff, both prior to the commissioning of this study and
thereafter. Specific consultations on the Transmission Cost Causation Study
results were initiated after the final draft of the Study was released in
September 2004.
(c) The AESO agrees that there is not unanimous support for the Cost Causation
Study. This is not uncommon for many Phase II rates matters.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-014 (a-b)
Reference:
Application, Section 4, p.4 and p. 9.
Preamble:
The Application states:
Page 1 of 2
In response to Direction 21, the AESO conducted a stakeholder consultation
process to review and comment on an Alberta Transmission System Wires Only
Cost Causation Study prepared for the AESO by PS Technologies Inc. The
AESO initially distributed copies to stakeholders and posted the study on the
AESO’s web site in September 2004. The study was also presented at an AESO
stakeholder conference on October 6, 2004, and at an AESO 2006 tariff
stakeholder session on December 3, 2004. Comments received during this
consultation process were reviewed and revisions to the Cost Causation Study
were made. A final version of the study is included as Appendix B to this
Application. (p.4)
Finally, the AESO notes that it has had discussions with some customers on
other potential rates (such as a short-term backup supply rate) which may more
specifically address the needs of low load factor customers, as well as rates to
address other concerns that have been raised. However, such discussions
have been preliminary and have included only limited consultation. The
AESO proposes to engage in additional customer consultation on rate
design immediately after the decision on its 2006 tariff application is
issued, in preparation for filing its 2007 application. At that time the AESO
expects to examine rate structures including matters such as cost classification,
which may lead to further recommendations for 2007 rates. Given these plans for
additional consultation and rate review, the AESO does not recommend further
changes to rates based solely on cost causation at this time, as other rate design
considerations may affect the rate design ultimately developed for 2007. The
AESO does recognize, however, that rate design should generally reflect cost
causation, and expects that the results of the Cost Causation Study will be more
fully reflected in future tariff applications. (p.9) [Emphasis added]
Request:
(a) Does the AESO agree that the recommendations of the Cost Causation
Study has raised significant concerns amongst stakeholders regarding harm
and detriment to low load factor customers relative to the current rate
structure (net DTS and STS impact)? If no, explain.
(b) Does the AESO agree that it has not addressed such concerns in this
Application nor the potential relief from such detriment, including additional
rates such as standby or off-peak rates, and as a result any remedy remains
a future (uncertain) consideration that would not be available until 2007, or
later? If no, explain what the AESO proposes in this Application to allay the
concerns.
Page 2 of 2
Response:
(a) A cost of service or cost causation study on its own does not cause harm or
detriment to anyone. Such a study is a technical and objective analysis of
how costs are caused, accompanied by an allocation of these costs to rate
classes.
The next step in the process is rate design, where one of the primary inputs,
but not the only input, is usually a cost of service or cost causation study. The
actual result of the rate design can impact all customers including both high
load factor and low load factor customers. The goal of the process is to study
costs, to understand the nature of cost causation, and to have rates that
appropriately reflect costs and other rate design criteria.
The AESO did receive comments from some stakeholders expressing
concern about implementation of the results of the Transmission Cost
Causation Study. Please refer to Information Response ADC.AESO-017 for
additional information.
(b) No, the AESO has taken into account stakeholder concerns. These are
reflected in the AESO’s 2006 GTA as discussed on page 6-10 of section 4 of
the Application.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-015 (a)-(e)
Reference:
Application, Section 4, p. 9.
Preamble:
The Application states:
Page 1 of 3
The AESO proposes to engage in additional customer consultation on rate
design immediately after the decision on its 2006 tariff application is issued, in
preparation for filing its 2007 application. At that time the AESO expects to
examine rate structures including matters such as cost classification,
which may lead to further recommendations for 2007 rates. Given these
plans for additional consultation and rate review, the AESO does not
recommend further changes to rates based solely on cost causation at this
time, as other rate design considerations may affect the rate design
ultimately developed for 2007. The AESO does recognize, however, that rate
design should generally reflect cost causation, and expects that the results of the
Cost Causation Study will be more fully reflected in future tariff applications. (p.9)
[Emphasis added]
Request:
(a) Please explain if the AESO intends to await the Board’s directions from the
2006 GTA before initiating or filing the 2007 GTA.
(b) In what way does the AESO intend to “examine rate structures including
matters such as cost classification” in preparation for the 2007 GTA. Please
explain why the review of the rate structures conducted for the 2006 GTA is
inadequate and the specific aspects of the rate design to be considered in the
future.
(c) Please list the various “considerations” the AESO believes should be
incorporated into a holistic rate design review, including the various
considerations the AESO intends for the 2007 GTA. In the AESO’s view, how
much weight should the Board place on each consideration when approving a
rate design.
(d) When the AESO says, “results of the Cost Causation Study will be more fully
reflected in future tariff applications”, is it proposing that the DTS tariff should
be classified 80/20 demand/usage (as per Table 4.2.3) and charged in the
same manner? If no, explain the meaning of this statement.
(e) Please provide the AESO’s understanding of the “cost causation” principle to
rate-making. How is it to operate and to be applied?
Response:
(a) Yes, the AESO intends to await the EUB’s directions from the 2006 GTA
before initiating and filing its 2007 GTA. Given the EUB’s current schedule for
the AESO’s 2006 GTA and the Transmission Regulation’s requirement for
approval of a 2006 AESO tariff by September 1, 2005, the AESO expects
such directions to be included in the EUB’s 2006 GTA decision on or before
Page 2 of 3
September 1. The AESO also expects that evidence and opinions provided
by intervenors during the course of the 2006 GTA proceeding will be one
input into the rate discussions planned prior to filing its 2007 GTA.
(b) At this point the AESO has not determined the scope of the rate design
discussions it plans to hold prior to filing its 2007 GTA. The AESO has heard
from stakeholders that they generally want to be involved earlier in the
decision-making process, and hopes to reflect that through discussions
starting at a relatively “blank page” in the fall of 2005.
However, the AESO did propose two rate concepts in its December 3, 2004,
stakeholder session on its 2006 tariff: separate rates for single-user and
multiple-user points of delivery, and a short-term backup rate. The AESO
received comments from only one stakeholder for each of these rate
concepts, and decided to defer further development to its 2007 GTA to allow
for a more thorough consultation process.
Meeting the AESO’s previous commitment to file a 2005 Phase II application
in the fall of 2004, and then meeting the 2006 tariff filing deadline of
February 1, 2005, while addressing the other tariff requirements of the
Transmission Regulation, limited the ability of the AESO to fully explore all
aspects of the rates included in its tariff. As already mentioned, the AESO
intends to start future rate design consultation with stakeholders at a
relatively “blank page”, and is open to discussing all aspect of rate design.
(c) A comprehensive rate design review should consider the usual rate design
criteria applicable to a utility. Relying on the criteria of a desirable rate
structure as described in Principles of Public Utility Rates by Bonbright,
Danielsen, and Kamerschen (2nd ed., 1988, pp. 385-389), rate
considerations should include:
i.
Recovery of the total revenue requirement;
ii.
Provision of appropriate price signals that reflect all costs and benefits,
including in comparison with alternative sources of service;
iii.
Fairness, objectivity, and equity that avoids undue discrimination and
minimizes intercustomer subsidies; and
iv.
Stability and predictability of rates and revenue.
Bonbright et al identify the first three as primary criteria, and they should
therefore probably be given more weight when examining a rate design. The
fourth is identified as a secondary criterion, and should therefore probably be
given less weight. Beyond these general comments, the specific merits of
each case must be weighed individually when approving a rate design.
In addition, at the end of the process rates must remain practical — that is,
appropriately simple, convenient, understandable, acceptable, and billable.
(d) In general, cost-based rates appropriately reflect the three primary rate
design considerations discussed above. If transmission service continues to
be provided to almost all load customers under a single DTS tariff with only
demand and usage charges, then the AESO would expect the DTS rate to
eventually reflect the 80% demand and 20% usage modified classification
2
Page 3 of 3
resulting from the wires cost causation study. However, if additional rates,
different rate components, or additional billing determinants are proposed,
then the modified classification as presented in Table 4.2.3 may not be
appropriate.
(e) Again drawing from Principles of Public Utility Rates by Bonbright et al
(pp. 391), the principle of cost causation or “service at cost” means “the rates
for any given class of service…should cover the costs of supplying that class.
And so the rates charged to any single customer within that class should
cover the costs of supplying this one customer.” To apply the cost causation
principle, costs should first be classified to the greatest extent possible in
accordance with the relevant cost drivers. The classified costs should then be
allocated to rate classes and charged to individual customers in accordance
with the cost classification.
As Bonbright et al note, however, “no such simple identification of reasonable
rates with rates measured by costs of service is attainable.” Reasons for
deviations from a cost causation standard include excessive complexity of
cost relationships, differences between incremental costs and embedded
costs, and problems of joint and common costs. Cost causation principles
cannot therefore be mechanically applied without consideration of other
considerations affecting rate design.
3
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-016 (a-b)
Reference:
Application, Section 4, p.4.
Preamble:
The Application states:
Page 1 of 1
The Cost Causation Study also classified the costs as demand-related, usagerelated, or customer-related, based on zero intercept and minimum system
approaches to determine the principle drivers of costs within each function.
Request:
(a) Is the AESO aware of any other jurisdiction that has used the “zero-intercept”
or the “minimum system” approach to classify bulk transmission system
costs? If yes, provide a copy of the results from these jurisdictions.
(b) How does the minimum system approach recognise the pooling of costs
across the diversity of load inherent in the bulk transmission system?
Response:
(a) No.
(b) The minimum system approach for the bulk system is based on the premise
that a minimum system is a lower cost system than an optimized system. If
the minimum system were equal to the optimum system, then the costs would
all be classified as demand, and none would be classified on the basis of
usage or energy. The minimum system approach does not recognize any
pooling of costs.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-017 (a)-(e)
Page 1 of 1
Title:
Reference:
Application, Section 4, p.5.
Preamble:
The Application states:
The results presented in Table 4.2.2 can be considered the “pure” results of the
study, developed without regard for factors or criteria other than cost causation.
In practice, such “pure” results are frequently modified to account for such factors
and criteria.
Request:
(a) Please list the other factors or criteria that the Board should consider when
classifying costs and designing rates? In the AESO’s view, how much weight
should the Board place on each consideration when approving a rate design.
(b) Does the AESO agree that in approving a rate design, the Board should
consider whether such approval fosters or encumbers the policy and objects
of the Electric Utilities Act ?. If not, please explain. If yes, explain how its
proposed DTS rate design aligns with the objects and purposes of the
Electric Utilities Act.
(c) Does the AESO agree that attributes of a sound rate structure includes the
stability and predictability of rates and the rate structure, with a minimum of
unexpected changes seriously adverse to ratepayers and with a sense of
historical continuity? If no, explain.
(d) Does the AESO agree that a sound rate structure should foster efficient use
of the transmission system. If no, explain.
(e) Please explain how the AESO’s proposed rate structure satisfies all of the
criteria and factors discussed in questions a) to d).
Response:
(a-e) Please refer to ENCANA-AESO-15 (b-e) and Section 4, pages 7-8 of the
AESO’s 2006 GTA.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-018 (a-b)
Reference:
Application, Section 4, p.5.
Preamble:
The Application states:
Page 1 of 1
The results presented in Table 4.2.2 can be considered the “pure” results of the
study, developed without regard for factors or criteria other than cost causation.
In practice, such “pure” results are frequently modified to account for such factors
and criteria.
Request:
(a) If a “cost causation study” cannot take into account all the classes of
customers that in reality cause costs, is it a “pure” and “proper” study of the
causation and allocation of costs? Please explain.
(b) In the AESO’s view, is it preferable to change rate structures to satisfy an
arbitrary allocation of costs? Please explain.
Response:
(a) A “cost causation study” should take into account all factors that drive costs
on the transmission system, for all classes of customers. The allocation of
costs to classes of customers must also take other considerations into
account, such as the Transmission Regulation’s requirement that all costs of
the transmission system be recovered from load customers. That requirement
makes allocation of costs to other than the DTS rate class irrelevant.
(b) No. The functionalization and classification results of a cost causation study
should be as sound as possible and should be considered as one input into
the design of rates. If additional considerations result in modifications to the
allocation of costs during rate development, those considerations and
modifications should stand on their own merits separate from the cost
causation study. Please refer to Information Response ADC.AESO-006 (h)
for additional discussion.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-019 (a-d)
Reference:
Application, Section 4, p.5.
Preamble:
The Application states:
Page 1 of 2
The results presented in Table 4.2.2 can be considered the “pure” results of the
study, developed without regard for factors or criteria other than cost causation.
In practice, such “pure” results are frequently modified to account for such factors
and criteria. The Cost Causation Study noted one such factor, namely a rate
design implication with respect to the results summarized in Tables 4.2.1 and
4.2.2. The classification of the bulk system function was based on an
analysis of coincident load at time of maximum stress on the bulk system,
which was found to occur at times other than that of peak load on the bulk
system. However, coincident load at time of maximum stress is not a
practical demand-related billing parameter. The study concluded that if a
customer’s individual peak demand were used as the billing parameter, the
recovery of bulk system costs through demand charges should be less than the
33.4% of total costs determined in the study. [emphasis added]
Request:
(a) Please define “coincident load at time of maximum stress” (CLMS).
(b) Please confirm that neither the traditional “coincident peak load” or the “noncoincident peak load” metrics provide a reliable reference or correlation to
CLMS. If this cannot be confirmed, explain if this is the case for all load-factor
variations.
(c) Why does the AESO believe that there is no practical measure of CLMS?
(d) Please confirm that the Study did not conclude that a customer’s individual
peak demand (CP or NCP) was a useful measure of CLMS.
Response:
(a) The term coincident load at time of maximum stress is the load at the point in
time when the ratio of load to capacity is at its highest. As shown in Table 11
of the Transmission Cost Causation Study, the Bulk System may be stressed
at times other than the time of peak system load.
(b) Confirmed. The case of the Edmonton-Calgary Bulk System is one case
where coincident peak load and non-coincident peak load do not provide a
reliable reference for the need for system expansion.
(c) The timing of CLMS will be different for every transmission component.
Generally speaking, one would expect that a lot of components will be
stressed at the time of system peak, and less components will be stressed
during low load conditions.
Page 2 of 2
(d) Confirmed. It is the combination of all customers’ load and the location of
supply that results in the load flow seen in Alberta’s electric system.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-020 (a)-(b)
Reference:
Application, Section 4, p.6.
Preamble:
The Application states:
Page 1 of 1
The study included an analysis of maximum stress on the north of Calgary and
south of Keephills bulk system paths presented in the AESO’s EdmontonCalgary 500 kV Transmission Development Need Application dated May 7, 2004.
That analysis found that at the time of maximum stress on the bulk system, POD
loads totaled from 65.6% to 82.6% of the annual peak load on the bulk system.
For the eight cases analyzed, the average was 73.5% of peak load at time of
maximum stress. The AESO therefore proposes to reduce the demand-related
classification of bulk system costs to 24.6%, calculated as 73.5% times the
33.4% presented in Table 4.2.2. The usage-related classification of bulk system
costs would accordingly be increased to 16.4%. [emphasis added]
Request:
(a) Does the AESO believe that the maximum stress on the Edmonton-Calgary
path will occur only eight (8) times in each of the next five years? If no,
explain when the AESO expects “maximum stress” to occur in each of 2005
through to 2009 for the Edmonton-Calgary path and why this is expected to
be the case.
(b) Is it the AESO’s position that load levels alone contribute to the maximum
stress of the Edmonton-Calgary path? Please explain all the factors that the
AESO considers to contribute to the maximum stress on the EdmontonCalgary path.
Response:
(a) No analysis was completed regarding the number of times the EdmontonCalgary path will be at maximum stress over the next number of years. The
data extracted from the AESO Need Application, and used to compile Table
11 in the Cost Causation Study, is illustrative of the load on the bulk system
not coinciding with Alberta peak load. As such it is also illustrative of the
comparable magnitudes of total POD load and annual system peak at time of
maximum stress.
(b) No. Load levels alone do not define maximum stress. The capacity of the
system must also be considered.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-021 (a)
Page 1 of 1
Title:
Reference:
Application, Section 4, p.7.
Preamble:
The Application states:
The discussion paper which preceded the policy paper quoted above in August
2003, although not representing approved government policy, provided further
comment. It stated, “Customers should be neutral to the combined Pool
price and grid costs, if STS is phased out for generators.” (p. 12) For
customers to be neutral to the combined pool price and grid costs, the reduction
in the price of energy they will see with the phasing out of STS charges to
generators should offset the corresponding increase in DTS charges. For all
AESO customers to be neutral to this transition from STS charges to DTS
charges, the increase in DTS charges must be of the same nature as the
decrease in STS charges — that is, as a usage charge. [emphasis added]
Request:
(a) In the AESO’s view, is the neutrality of customer bills the only objective the
Government intended to achieve when shifting transmission costs from
being directly paid by generation to being paid by load? If not, please explain
the AESO’s understanding as to the other objectives.
Response:
(a) No, as the Transmission Development The Right Path for Alberta A Policy
Paper, November 2003, Page 5 of 19, states,
“The 50/50 pricing regime currently used for embedded costs will be
discontinued effective January 1, 2006. Three important objectives are met by
removing this pricing regime; (a) price distortions are not introduced into the
wholesale market from the regulated transmission business, (b) consumers
receive transparent pricing for transmission service, and (c) the market and
pricing rules of Alberta are further aligned with those of neighboring
jurisdictions”.
Also the fundamental goal of the Transmission Policy, as stated on Page 2 of
19 if the Policy Paper and on Page 4 of 38 of the Discussion Paper, “The
fundamental goal of the transmission policy is to ensure that consumers are
served with reliable, reasonably priced electricity, and to support continued
economic growth in Alberta”.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-022 (a)-(b)
Reference:
Application, Section 4, p.8.
Preamble:
The Application states:
Page 1 of 1
The AESO recommends that transmission wires costs be classified 46.6% as
demand-related and 53.4% as usage-related in the 2006 DTS rate design.
Beyond maintaining customer neutrality to the phasing out of STS charges,
classifying the pre-2006 STS charges as usage-related recognizes other criteria
that should be considered when designing rates, including impacts on
customer bills, rate stability and history, orderly transition to final rate
structures and levels, and potential impact of new rates or rate structures.
[Emphasis added]
Request:
(a) Please describe the way each of these “other criteria” is to be implemented or
used when considering a change in rate design. Please include in the
description the AESO’s position as to any guidelines for the use of each criterion.
(E.g. no more than a 5% bill impact.)
(b) When considering bill impacts and the potential impact of new rates or rate
structures is it the AESO’s view that such criteria need only examine the
immediate impact of an initial change or the aggregate impact from the initial
change through to the final change, which may be several years into the future.
Please explain.
Response:
(a) Please refer to ENCANA.AESO-15 (b-e). At this time the AESO has not
established the guidelines for the use of each criterion.
(b) When considering bill impacts and the potential impacts of new rates or rate
structures it is the AESO’s view that such criteria needs to examine the
immediate impact and the aggregate impact from the initial change through to
the final change as much as possible. However, at this time the final change is
not know and therefore it is difficult to examine the aggregate impact.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-023 (a)-(c)
Page 1 of 1
Reference:
Application, Section 4, p.10, Figure 4.2.1
Preamble:
Figure 4.2.1 show various bill impacts of rate design changes under different
cases.
Request:
(a) Please explain how the AESO calculated the bill impacts in Figure 4.2.1
(b) Please provide a working spreadsheet with the calculations behind Figure 4.2.1.
(c) For each decade of load factors in Figure 4.2.1, please provide a table and graph
comparing the DTS bills using recorded costs for 2004 with and without the
proposed rate design change. For the “with” calculations, use the recommended
demand/usage classification (46.6/53.4). For the “without” classification assume
that STS costs are a 100% flow-through to DTS customers such that the
demand/usage classification is 34.8/65.2 (Line 3, Table 4.2.5). Please attach a
working spreadsheet of the calculations.
Response:
(a) The bill impacts in Figure 4.2.1 are calculated by:
 Using the Rate Calculation Sheets in Schedule 5 of the AESO’s 2006
GTA to calculate the rates which correspond with the allocation and the
forecast costs.
 The 2005 interim rates are then compared to the 2006 proposed rates at
each load factor (10% increments) using the different allocation factors as
outlined in Section 4, pages 3 -11, of the AESO’s 2006 GTA.
(b) Please refer to attached Schedule ENCANA.AESO-023-A.
(c) Please refer to attached:
i. Schedule ENCANA.AESO-023-B for the rate calculations associated with
the “with” calculations (46.6 / 53.4) using preliminary recorded costs for
2004.
ii. Schedule ENCANA.AESO-023-C for the rate calculations associated with
the “without” calculations (34.8 / 65.2) using preliminary recorded costs
for 2004.
iii. Schedule ENCANA.AESO-023-D for the bill impact tables and graphs for
both the (46.6 / 53.4) and (34.8 / 65.2) demand energy splits, using
preliminary recorded costs for 2004.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-024 (a-d)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.2.
Preamble:
The Study says:
Page 1 of 1
The transmission system wires costs are currently recovered from both supply
and demand customers. Following implementation of Transmission Regulation,
transmission wire costs will be recovered from demand customers (except the
point of supply costs associated with the generating units). This change adds
focus to the review of causation of transmission wires costs.
Request:
(a) Please explain when PSTI conducted the original version of the study.
(b) Please explain how the Study took into consider the Government’s
Transmission Development Policy, the Transmission Regulation and the
objects or purposes of the EU Act.
(c) Please explain how the change to recover wires costs only from demand
customers “adds focus” to the review.
(d) In the opinion of PSTI, how would the conclusion of the review differed if the
transmission wires costs were to be recovered from both load and generation
customers.
Response:
(a) The final draft of the Study was completed and released on September 17,
2004. Following a Stakeholder Consultation process, and receiving input from
interested parties, the Study was upgraded on January 25, 2005 and was
filed as part of the AESO 2006 GTA.
(b) The Transmission Cost Causation Study does not rely on the Transmission
Development Policy or the EU Act. The Transmission Regulation specifies
that the cost of the transmission system be charged to load and therefore
there is only one rate class (load) to which costs must be allocated.
(c) The change in recovering the cost of the transmission system from load will
result in increased costs to load. Increasing costs were seen to add focus to
consumers who see one part of their electrical bill increasing.
(d) Considering more than one rate class was beyond the scope of the
Transmission Cost Causation Study.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-025 (a-b)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.2.
Preamble:
The Study says:
Page 1 of 1
The findings of this report are summarized as follows:
Request:
(a) Please explain if the Net Book Value (NBV) of Property used in the study
included transmission wire costs of local systems serving generation
customers and the Point-of-Supply (POS) costs that are owned by the
Transmission Facility Owners (TFOs).
(b) If the answer to (a) is “yes”, please explain how the study functionalized these
costs and included these amounts in the above note categories.
Response:
(a) The net book value of property used in the study includes all property that is
in the TFOs’ regulated rate bases. It is not clear what is meant by local
systems serving generators, but if a generator owns and operates a POS or
other facilities, those facilities will not be owned by a TFO and will not be
included in rate base.
(b) Where a TFO owns POS facilities that provide service to previously regulated
generation, those facilities were considered Bulk. Likewise, the revenue from
the RGUCC charge offsets the cost of the Bulk system.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-026 (a)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.3.
Preamble:
The Study says:
Page 1 of 1
PSTI also reviewed planning practices that result in the addition of new facilities.
Request:
(a) Was the observation of planning practices limited to the AESO’s need
application for the 500kV Edmonton-Calgary reinforcement? If not, explain
the other planning practices reviewed by PSTI and explain how these
practices bear on the conclusions of the study.
Response:
(a) No, the review of planning practices was not limited to the 500 kV EdmontonCalgary reinforcement. PSTI conducted interviews with transmission planners
to help understand the planning process. This information was used to
develop functions and classification of the functions. The AESO’s Need
Application for the 500 kV Edmonton-Calgary reinforcement was not
reviewed as a basis of planning, but was used to illustrate the concept that
components on the Bulk system may not experience peak load conditions at
the same time that the overall load in Alberta is highest.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-027 (a)
Page 1 of 1
Reference:
Appendix B, Wires Only - Cost Causation Study, Section 2 and 2.1, pp.3-4
Preamble:
Section 2 and 2.1 discuss the evolution of transmission wire cost of service and
Alberta’s allocation of transmission wires costs
Request:
(a) Is it the position of PSTI that the function of the (bulk) transmission system
has not changed since the introduction of the Electric Utility Act in 1995? If
yes, explain. If no, explain the change in function and the reasons for this
change.
Response:
(a) Please refer to Information Response ENCANA.AESO-13 (a).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-028 (a-b)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.10.
Preamble:
The Study says:
Page 1 of 1
Two approaches are used to classify the costs associated with the transmission
functions, and these approaches are the zero intercept approach, and the
minimum system approach. These approaches have been used to classify
the costs of distribution systems, but have not been used in the case of
transmission systems. However, transmission systems have similarities to
distribution systems with respect to the fixed nature of wires costs, and the
approaches to classifying costs for distribution systems, can also be used for
transmission systems. The zero intercept approach is used to determine
customer related costs, and the remaining costs are classified as demand and
energy on the basis of the minimum system approach. [emphasis added]
Request:
(a) Please confirm that PSTI is not aware of any jurisdiction that has used the
zero-intercept and minimum system approaches to classify costs of bulk
transmission systems. If not confirm, please provide copies of the studies
used in other jurisdictions.
(b) Does PSTI agree that bulk transmission systems are not similar to distribution
systems because bulk transmission systems benefit from the diversity of load
patterns and therefore do not have to be sized to serve the sum of individual
peak demands? If no, please explain.
Response:
(a) Confirmed.
(b) While bulk transmission systems and distribution systems are dissimilar in
some respects, diversity in load is not one of these. Both bulk transmission
systems and distribution systems benefit from diversity of load. A primary
distribution feeder may feed residential, street lights, and commercial
services, all of which have different load profiles that contribute to diversity of
load on one feeder.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-029 (a)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.11.
Preamble:
The Study says:
Page 1 of 1
Cost accountability (generation and load) varies across Europe [2]. Transmission
rates varies widely across Europe where some countries impose a small fixed
charge on consumers, to countries where demand charges consists of more than
80% of the total rate (Germany), to countries where the entire transmission rate
consists of a variable charge (energy based) [3]
[2] Benchmarking of Transmission Pricing in Europe, European Transmission
Operators Task Force, March 2003.
[3] Benchmark of Electricity Transmission Tariffs, DG TREN/European
Commission, October 2002.
Request:
(a) Please file a table or graph similar to the slide presented at the December 3,
2004 stakeholder workshop showing the tariff structures of the European
transmission providers. Please include any additional jurisdictions from the
above noted studies if they were not included in the December 3, 2004
presentation.
Response:
(a) Please find the complete report as attachment ENCANA.AESO-029 from
which the extract was taken at the December 3 Stakeholder Session.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-030 (a-c)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.35.
Preamble:
The Study says:
Page 1 of 2
The minimum system approach is used for the Local and Bulk functions to
determine demand and energy related costs. The minimum system is based on
the smallest standard construction that is currently installed as the base cost and
using the optimized standard construction as the total cost. The minimum
system cost is considered demand related, instead of customer related as
it is used in distribution systems, because the Bulk and Local systems are
designed primarily to meet the total load, and design is relatively
independent of the number of customers. The additional cost of upgrading the
design to optimize the system (optimum from a perspective of minimization of the
total cost of capital and energy losses) is considered energy related because it is
the transportation of additional energy that drives this cost. While the additional
costs are incurred to reduce energy losses, the costs are fixed capital costs.
[Emphasis added]
Request:
(a) In the context of the bulk system, please define “demand” and “demand
related” and explain how a system cost is related to demand.
(b) Please explain how the bulk system is “designed primarily to meet the total
load”. In this context, explain which “load” characteristic that the system is
designed to meet, including the frequency and duration.
(c) In the context of the bulk system, what does PSTI mean when it says the
“design is relatively independent of the number of customers”? Does PSTI
agree that the bulk system would be designed the same way if the number of
customers were one-half or double the current amount so long as the energy
flows across the bulk system followed the same pattern.
Response:
(a) Demand is synonymous with power and is either measured in kVA or kW.
Costs are demand related when the cost of installing capacity is related to the
amount of capacity installed. For example, consider buying two pieces of
similar equipment, with one piece rated for 10 kVA and costing $5,000 and
the other rated for 100 kVA and costing $10,000. In that case you could say
the $5,000 cost difference between the similar pieces of equipment is
demand related.
(b) Electric transmission systems are typically rated by demand in kVA. As
shown in Table 11, the transmission planners have rated the capacity of
certain paths in MVA (kVA × 1,000). These ratings may be seasonal to reflect
the ability to keep equipment at normal operating temperatures at different
times of the year. Normal ratings are based on steady state operation and do
not specify the frequency or duration of safely exceeding the ratings.
Page 2 of 2
(c) Yes, the bulk system is relatively independent of the number of points of
delivery, and is designed to have sufficient capacity to transport the forecast
demand (or power).
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-031 (a)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.35.
Preamble:
The Study says:
Page 1 of 1
Demand related costs have additional complexity. While demand related costs
apply to the maximum demand at a POD (NCP), the demand related costs
further back in the system must take into account diversity. The diversity of load
in Alberta is demonstrated in Figure 7. The peak system load, or CP in 2003 was
8,570 MW, while the sum of loads at the transmission points of delivery was
9,860 MW (sum of NCP’s), or 15% higher. The two additional points in the figure
include the sum of loads measured on each transformer measured in MW (Sum
of Tx Load), and the sum of transformer capacities in MVA (Sum of Tx Cap).
[Emphasis added]
Request:
(a) PSTI uses the phrase “demand related costs apply to the maximum demand
at a POD (NCP)”. Does PSTI mean to say that “demand related costs” are to
be recovered using an NCP billing determinant? If not, explain. If yes, is the
use of an NCP billing determinant based solely on the basis that the
“minimum system approach” as it is used in distribution systems uses NCP
as the billing determinant for demand related costs? Please explain.
Response:
(a) No, PSTI is referring to cost causation and not rate design.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-032 (a-c)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.37.
Preamble:
The Study says:
Page 1 of 1
A further additional complicating factor is that the time of maximum system
stress on the bulk system does not coincide with peak load conditions. The
time of maximum stress on the Bulk System is typically during light load periods
and results from the combination of little or no import from BC to support the
southern load, a condition when gas fired generation in the Calgary area is
dispatched down, and base load coal fired facilities west of Edmonton are
dispatched to full load. The timing of these occurrences cannot be accurately
predicted. [Emphasis added]
Request:
Response:
(a)
Please define “maximum system stress” and explain how this relates to
i.
energy flows over the bulk transmission system;
ii.
voltage and stability limits;
iii.
the potential breach of other reliability criteria; and
iv.
the non-coincident peak (NCP) of individual customers.
(b)
If the timing of “maximum system stress” cannot be predicted, explain how
NCP provides a reasonable measure as to how a load customer will
contribute to the occurrence of stress. Consider the situation of a high,
medium and low load factor customer.
(c)
What factors influence the occurrence and timing of “maximum system
stress”? Of these factors, which if removed or reduced could lessen the
occurrence of “maximum system stress”?
(a)
Please refer to Information Response ENCANA.AESO-019. Also, voltage,
thermal, stability, and other planning criteria come into play in the
development of the capacity of the system.
(b-c) The report indicates that the timing of these occurrences cannot be
accurately predicted, whereas the question implies the timing cannot be
predicted at all. The timing of maximum system stress results from a
combination of customer load (and exports) and location, as well as
generation (and imports) and location.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-033 (a-b)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.38.
Preamble:
The Study says:
Page 1 of 1
Based on the data in Table 11, and the Chart in Figure 8, it is apparent that other
factors, in addition to coincident peak load, contribute to maximum stress on the
Bulk System. The magnitude of the maximum stress on the Bulk System
drives the need for new transmission facilities and is the cost driver, and
the coincident system peak load currently does not drive the need for new Bulk
System facilities and therefore, is not a cost driver. [Emphasis added]
Request:
(a) Please explain what is meant by “the magnitude of the maximum stress”.
Can the “maximum stress” be of small, medium or large magnitude? If yes,
explain how the degree of maximum stress has an influence on the
development of bulk system facilities and costs.
(b) Does peak load coincident at the time of maximum stress contribute to the
stress and therefore to the need for new facilities? Please explain.
Response:
(a) The magnitude of the maximum stress is the highest ratio of the load to the
capacity of a component in the transmission system as shown in Table 11. If
a transmission component has a small capacity, then a small load (larger
than the capacity) can cause stress to that component. When the load on a
component of the transmission system exceeds its capacity, then planners
will consider means to alleviate the overload.
(b) Yes, the load at the time of maximum stress is the load that contributes to the
stress and the need for new facilities.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-034 (a-e)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.38.
Preamble:
The Study says:
Page 1 of 1
Factors that cause the peak stress on the Bulk System to occur at times other
than the peak coincident system load include:
- Location of generation,
- Dispatch of generation,
- Imports and exports.
Not withstanding the fact that the time of peak stress on the Bulk System does
not coincide with the time of peak system load, the Bulk System is designed to
meet the peak stress when the peak stress occurs.
Request:
Response:
(a)
Does PSTI agree that because generators, importers and exporters cause
maximum stress on the Bulk System they too are drivers of Bulk system
costs?
(b)
Does PSTI agree that in a “pure” cost causation study generators,
importers and exporters would be allocated costs in relation to their
contribution to Bulk System costs?
(c)
Does PSTI agree that as a result of the Transmission Regulation, none of
these customer classes will be charged rates that are reflective of the
extent to which they drive Bulk System costs?
(d)
Does PSTI agree that because of the above noted situation the
classification and allocation of costs to DTS rates as proposed in this study
are arbitrary?
(e)
If PSTI does not agree with any of the above, please explain.
(a)
Transmission costs are caused when the load exceeds the capacity of the
system to deliver it. The load on the system is a function of the combination
of customer load (and exports) and location, and well as the generation
(and imports) and its location.
(b-e) No. The Transmission Cost Causation Study was a study of how costs are
incurred, not who they are allocated to. A cost of service study usually also
includes the final step of allocating costs to rate classes. However, the
Transmission Regulation requires that all wires costs be recovered from
load, and therefore the step of allocating costs is not relevant.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-035 (a-b)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.39.
Preamble:
The Study says:
Page 1 of 1
A simple minimum system approach was taken to differentiate demand related
and energy related costs for the Bulk System. The approach taken was on the
basis of a 240 kV line built to the minimum standards currently in place,
which is a circuit with bundled 477 kcmil conductor. A bundle of two
conductors of 477 kcmil conductor is the smallest conductor that complies
with all applicable codes. The 240 kV line is then optimized with respect to
capital and line loss costs. The optimized system cost is the average of a 240
kV circuit with bundled 795 and 1590. The demand related costs are those costs
associated with the minimum sized conductor, and the energy related costs are
those costs associated with upgrading the line to an optimal system.
…
Bulk substations were also considered on a minimum system basis.
…
[Emphasis added]
Request:
(a) Please explain how the analogy of building a single 240kV line is compatible
with Bulk System developments that must account for load diversity and
variable load patterns at the time of “maximum stress”, the variable location
of generation, the variable dispatch of generation, the variable amounts of
imports and exports, and the various degrees of “maximum stress”.
(b) Is the simple minimum system approach the sole reason used by PSTI to
define certain portions of the Bulk system as “demand-related”? If no, explain.
Response:
(a) The analogy of a single circuit is compatible with Bulk System developments
because the Bulk System is made up of a number of discrete components.
When planners add a component to the Bulk System, such as a single
240 kV circuit, they will forecast the load on the line and determine the
optimum conductor for the circuit. The variables of location of generation,
dispatch, import, and export will all be considered when the planner
determines the forecast of load on the line.
(b) The minimum system approach was the method used to classify a portion of
the Bulk System as demand related, and the remainder to be energy related.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-036 (a-c)
Reference:
Appendix B, Wires Only - Cost Causation Study, p.40.
Preamble:
The Study says:
Page 1 of 1
The minimum system approach results in demand related costs accounting for
80% of the total costs of the Bulk System. The demand related costs are
associated with the coincident load at the time of maximum system stress
(CLMS). The demand at the time of peak system stress is not a practical
demand related billing parameter because customers do not generally have
visibility as to the time of maximum system stress (and further, the time of
peak stress will vary at different points in the system), and therefore cannot
react to the price signal. The customer demand coincident to the system peak
is not a practical demand related billing parameter because the demand
coincident to system peak is not a cost driver.
Customer demand may have a positive or negative correlation to peak
stress on the Bulk System. For example, low demand in the Edmonton area
contributes to peak stress on the NOC and SOK path. While demand related
costs (CLMS) consist of 80% of the total Bulk System costs, the recovery of
revenue through demand charges should be lower than 80% if the billing demand
is based on the customers peak demand at a time other than load coincident to
the time of maximums system stress. [Emphasis added]
Request:
Response:
(a)
Is it PSTI’s conclusion that because the Bulk system costs are demand
related and customer’s coincident peak demand (CP) is not a practical
demand related billing parameter, then customer’s non-coincident peak
load (NCP) should be the preferred demand related billing parameter?
(b)
If the answer to question (a) is yes, explain why NCP load is a cost driver of
bulk system costs.
(c)
When PSTI says “Customer demand may have a positive or negative
correlation to peak stress on the Bulk System,” does “customer demand”
refer to CP, NCP or both? Please explain.
(a-b) No, PSTI identified concerns with applying rates to the coincident load at
maximum stress. Rate design is beyond the scope of the Cost Causation
Study.
(c)
The reference to customer demand is to customer demand at the time of
peak stress, not the customer demand at some other point in time.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-037 (a)-(f)
Page 1 of 2
Title:
Reference:
Application, Section 4, p.14.
Preamble:
The Application states:
Customer self-supply of ancillary services — Customer self-supply is a
component of the Wholesale Market Review currently underway. The AESO
considers it prudent to wait for the outcome of this review and attendant
legislation before setting out a proposal for customer self-supply of ancillary
services. Consequently, the AESO seeks leave of the EUB to address customer
self-supply of ancillary services at a future date. [Emphasis in original]
Request:
(a) Please describe the work the AESO, and its predecessor, has conducted to
develop a proposal(s) for the self-supply of ancillary services since the Board
issued Directive 11 in Decision 2001-32 (May 2, 2001). Provide copies of the
working papers, internal memos, draft proposals, or like documents, related
to the AESO’s efforts to develop a proposal for the self-supply of ancillary
services. If there are no such documents, please explain.
(b) Please confirm that the issue of customer self-supply of ancillary services
(AS) has been raised by customers at various stakeholder conferences over
the past two years, especially as it relates to concerns over the AESO’s
position of being the sole buyer of AS and the attendant market power of this
situation. If this cannot be confirmed, explain what the AESO understands to
be the degree of customer interest in this issue and the reasons why.
(c) Is it the AESO’s understanding that it currently has the authority under the EU
Act to implement a program for the self-supply of AS? If yes, provide the
AESO’s views on this authority. If no, explain what the AESO believes are
the legislative changes required before customers can self-supply ancillary
services.
(d) Is it the AESO’s understanding that it currently has the authority under its
NERC/WECC agreements to implement a program for the self-supply of AS?
If yes, explain this authority. If no, explain what the AESO believes are the
changes required before customers can self-supply ancillary services.
(e) What impediments exist today to prevent a customer from self-supplying
i.
ii.
iii.
Regulating reserves;
Spinning reserves; or
Supplemental reserves.
Page 2 of 2
(f) In the AESO’s opinion, what aspects of the Wholesale Market Review are
expected to impact on the program for self-supply of ancillary services, and
why?
Response:
a) No additional work has been conducted by the AESO or its predecessor at
developing a proposal(s) for the self-procurement of operating reserves as
other industry requested enhancements to the existing operating reserves
market took precedence. The Wholesale-Retail Market Policy Paper will
identify operating reserve market design alternatives under consideration and
seek input from market participants on the need for multi-buyer market design
changes or enhancements to the current market design.
b) The AESO confirms that the topic of the AESO as single buyer has been
raised at various stakeholder conferences, and the topic of customer selfprocurement of operating reserves has been a topic of discussion during the
Wholesale Market Review.
c) Proper authority to implement a market design change allowing for selfprocurement of operating reserves will be assessed on the basis of the
current legislation subsequent to release of the final Wholesale-Retail Market
Policy Paper.
d) NERC/WECC agreements establish physical requirements for ancillary
services. NERC/WECC do not prescribe methods on how ancillary services
are to be procured or supplied, only the requirement that ancillary services
physically exist and physically perform.
e) Although the AESO does not register transactions for self-procurement of
operating reserves, the AESO is unaware of any impediments preventing
customers from establishing financial arrangements with other market
participants to provide any of the referenced operating reserves.
f)
The Wholesale Market Review, more specifically, the Wholesale-Retail
Market Policy Paper is expected to provide clear direction as to how selfprocurement of operating reserves will fit with any market changes that may
be implemented and may provide direction on a preferred transition plan for
those changes, possibly including customer self-procurement of operating
reserves.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-038 (a)-(d)
Reference:
Application, Section 4, p.18.
Preamble:
The Application states:
Page 1 of 2
As already discussed, the AESO has studied the question of demand ratchets
and proposes to reduce the ratchet period rather than waive ratchets when no
additional investment in local facilities was required. The waiver of demand
ratchets and billing based on metered demand were suggested in response to an
earlier concern raised by customers that billing based exclusively on a rigid
contract was punitive. The AESO believes that in the absence of contractbased billing, ratchets are appropriate to recover revenue from customers
who may be leaving the system. The revenue is required to balance the
financial impacts for the remaining customers who would otherwise bear
the full cost of facilities which become under-utilized due to other
customer’s actions. The ratchet provides a balance between flexibility for
customers and the need to recover any stranded system costs from remaining
customers. Further specific ratchet relief is provided to distribution utilities
through the peak metered demand waiver provisions of Article 16 of the
proposed terms and conditions of service. [Emphasis added]
Request:
(a) Please explain what the AESO means by “contract-based billing” and provide
examples in the context of DTS rates.
(b) When a customer leaves the system, what ‘revenue requirement’ does the
AESO believe it must recover from the customer? How does this relate to
bulk, local and POD costs.
(c) What facilities become under-utilized due to a customer departure?
(d) If the Load Contribution Policy was structured as a “security deposit with
refund” (similar to the Generator Contribution Policy, whereby upfront
payments were made to address incremental system costs associated with
the interconnection and this payment was refunded over time based on
customer usage), then could the concerns over stranded costs and the
discriminatory treatment between industrial and distribution utilities be
adequately addressed. Please explain.
Response:
(a) The AESO used the term “contract-based billing” to refer to billing in
accordance with contract capacities. An example of contract-based billing is
the GIS (Grid Interconnection Service) rate of the Transmission Administrator
in the late 1990s, which billed for capacity based on the greater of metered
peak capacity or 100% of contracted reserve capacity.
(b) The revenue requirement to be recovered from a load customer includes both
fixed and variable costs of wires, ancillary services, other industry, and
Page 2 of 2
general and administrative components associated with the service to the
customer, to the extent that average rates for a class of customers are able to
reflect the cost of the service provided to an individual customer. When a
customer leaves the system, variable costs also cease but fixed costs
remain. In general those fixed costs represent:
i.
the total capital costs associated with the POD serving the customer;
ii.
the incremental capital costs associated with any local system or bulk
system improvements that may be associated with the incremental load
of that customer; and
iii.
the incremental fixed costs associated with other industry and general
and administrative components associated with service to that customer.
(c) Facilities at a POD become unutilized when a customer departs the system, if
no new customer interconnects at the same POD. If a new customer does
interconnect, the POD would be under-utilized if the new customer’s load and
requirement for interconnection facilities is less than the departing
customer’s.
As well, local system and bulk system facilities become under-utilized to the
extent that they now serve less load than they were previously serving or
were constructed to be capable of serving.
(d) The generator contribution policy is based on zero investment (that is, full
customer contribution) for POD facilities and an additional refundable
contribution for general local system and bulk system improvements. The
AESO agrees that if the load contribution policy was also based on zero
investment for POD facilities and an additional system contribution, there
would be little concern over stranded costs. However, the concerns of
distribution utilities would remain, as full contributions for POD facilities
remain inappropriate when coordination between the AESO and distribution
utilities ensure the most effective and lowest cost facilities are constructed,
and when such a full contribution would impose no effective economic signal
or siting discipline with respect to multiple-user PODs.
The AESO also expects most load customers would object to zero
investment for POD facilities, given the long-standing investment policies of
utilities in Alberta and previous acceptance that “80% of system expansion
projects would not require a contribution” (Decision 2001-6, p. 70).
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-039 (a)-(d)
Reference:
Application, Section 4, p.22.
Preamble:
The Application states:
Page 1 of 2
The number of DOS customers has dropped over time since the rates were
initially implemented, such that only four customers currently take service under
a DOS rate. The only DOS rates currently in use are DOS 7 Minutes and DOS
Term.
As a result of the low usage of DOS rates, the AESO expects to include
discussion of DOS rates in the customer consultation on rate design planned
prior to its 2007 tariff application. In the meantime, based on the adequate
alternatives which appear to be provided by DOS 7 Minutes and DOS Term, the
AESO proposes to eliminate the DOS 1 Hour rate.
Request:
(a) What is the AESO’s understanding as to why the number of DOS customers
has dropped over time?
(b) Why does the low usage of DOS rate require discussions prior to the 2007
tariff application? What is the AESO’s intention or future plans respecting
DOS rates?
(c) Please explain the difference between the DOS 1 Hour rate and the DOS
Term rate options and clarify whether the later can be used to substitute for
the former.
(d) What harm is created if the AESO’s Terms and Conditions continued to
include the DOS 1 Hour option until at least the implementation of the 2007
GTA.?
Response:
a) The AESO’s understanding as to why the number of DOS customers has
dropped over time is as follows:


The AESO’s DOS qualification process has over time become more
stringent. A closer examination of potential customers’ business cases,
now takes place.
Customers have done more economic analysis on DOS, as well as
becoming more familiar with DTS and STS. This economic analysis has
led these customers to believe that DOS is not as an attractive alternative
as they once believed.
Page 2 of 2

The Disco (FortisAlberta Inc.) in 2002 / 2003 revised how it looked at
DOS and there is now a distribution cost with the transmission DOS
(there is no opportunity disco service).
b) Low usage of the DOS rate requires discussions prior to the 2007 tariff application,
because the AESO would like to hear its customers’ thoughts and ideas around
opportunity service. At this time the AESO does not have any intention or future
plans respecting DOS rates, beyond what was filed in its 2006 GTA.
c) The DOS 1 Hour Rate is $5.00 / MWh and the DOS Term (Standard) Rate is
$20.00 / MWh. Also, as stated in the Independent System Operator Operating
Policies and Procedures, OPP 901 page 2 of 2,
“DOS 1 Hour customers must curtail their DOS load within 1 hour of
receiving a directive from the SC.
DOS Standard customers must curtail their DOS load as directed by the
SC”.
d) Please refer to TCE.AESO-221 (c-d).
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-040 (a-d)
Reference:
Application, Section 4, p.23.
Preamble:
The Application states:
Page 1 of 1
The AESO currently offers Export Service (ES) and Import Service (IS) rates.
Both are opportunity service rates incorporating the interconnection charge of the
current STS rate, location-specific loss factors, incremental operating reserve
and system support service charges, and transaction fees. These rates appear
for the most part to satisfy the current needs of customers, with the exception
of interest expressed in late 2004 for firm export and import rates
applicable to “merchant” transmission lines interconnecting with
jurisdictions outside Alberta. [Emphasis added]
Request:
(a) What does AESO understand to be meaning of “firm” import or export rates?
Is it the AESO’s understanding that this is equivalent to a capacity reservation
for the use of an inter-tie, subject to physical operating availability?
(b) Is it the AESO’s understanding that the Montana-Alberta Tie Ltd (MATL)
proposal is a “merchant” transmission line?
(c) What issues and considerations have been identified by the AESO that
require resolution before it is able to arrange for “firm” import and export rates
to and from the MATL system. Please identify the parties responsible or the
mechanism required to resolve these issues and the expected timing.
(d) Is the AESO prepared to work with stakeholders to ensure the availability of
“firm” import and export rates to and from the MATL system as soon as
possible? If not, why not.
Response:
(a) The AESO agrees with the stated definition.
(b) Yes.
(c) Some of the matters that need to be addressed are discussed on pages 2324 of section 4 of the AESO’s 2006 GTA. In addition, implementation issues
will need to be identified and addressed.
(d) Yes.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-041 (a-c)
Reference:
Application, Section 4, p.23.
Preamble:
The Application states:
Page 1 of 1
Firm export and import services — In response to Direction 1, the AESO has
been investigating the potential for firm export and import services as well as
other interconnection matters. A number of aspects have been identified to
consider in order to offer firm services, as well as to improve efficient and
fair use of the Alberta-BC interconnection and to improve competitiveness
of the Alberta market. [Emphasis added]
Request:
(a) Please list the “aspects” that have been identified in order to offer firm
services. For each aspect, discuss the interested parties involved, the
responsibility or mechanism required to remove the aspect as a barrier to the
introduction of firm service and the timing of each.
(b) The AESO uses the phrase “as well as to improve efficient and fair use of the
Alberta BC interconnection and to improve competitiveness of the Alberta
market.” In what way is the introduction of firm rates predicated on these
other issues.
(c) Is the AESO prepared to develop firm rates on other inter-ties before it has
resolved the issues with the Alberta-BC inter-tie? If not, explain.
Response:
(a) Some of the matters that need to be addressed are discussed on pages 2324 of section 4 of the AESO’s 2006 GTA. In addition, implementation issues
will need to be identified and addressed.
(b) Firm export and import rates must align, integrate, and not conflict with other
firm and opportunity rates. As such the rates must be adequately developed
and examined to ensure such alignment, integration, and lack of conflict
exists.
(c) Yes, to the extent practical.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-042 (a-d)
Reference:
Application, Section 4, p.24.
Preamble:
The Application states:
Page 1 of 2
The key considerations resulting from this examination of firm export and import
services are:
 Firm export tariffs would add a new option for participants and may enhance
investment opportunities for new supplies. However, at present there appears
to be little demand for a firm export option and deferral of further detailed
development until after the Wholesale Market Review appears appropriate.
 A deferral of development of a firm export tariff will also allow careful
examination of issues such that the introduction avoids or minimizes negative
impacts on the market.
 Firm import tariffs appear inconsistent with the transmission cost allocation
principles in the Transmission Regulation and would disadvantage imports
compared to domestic supplies.
Request:
Response:
(a)
Please explain the role the AESO believes the Wholesale Market Review
should take in developing firm import and export rates. Further, explain
why the AESO’s normal ratemaking process cannot fulfill this role.
(b)
In what way does the AESO expect the introduction of firm export rates to
have a negative impact?
(c)
In what way does the AESO expect the introduction of firm import rates to
have a negative impact?
(d)
Please explain the AESO’s concern with the inconsistency of a firm import
tariff and the Transmission Regulation. Is this inconsistency isolated to
existing inter-ties only and not to new “merchant” inter-ties such a the MATL
project? If no, reconcile the AESO’s concerns with section 15(4) of the
Transmission Regulation.
(a)
The AESO does not believe the Wholesale Market Review has a specific
role in the development of firm export and import rates. However,
stakeholders indicated that deferring development until after the Market
Review was appropriate.
(b-c) The introduction of any rate that is poorly conceived, executed, or
implemented could have unforeseen negative impacts. Such possible
negative impacts is the principle reason the AESO supports a thorough and
careful examination of firm export and import issues.
Page 2 of 2
(d)
It is not clear from section 19(2) of the Transmission Regulation whether
the “common number” multiplier specified in subsection (f) is to apply to
generators only (as is the inference from subsection (d) or to firm imports
as well.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-043 (a-b)
Reference:
Application, Section 4, p.24.
Preamble:
The Application states:
Page 1 of 1
As a result of these considerations, the AESO proposes the following:
(a) A firm export tariff continue to be developed through 2005 with the objective
of including such a tariff in the AESO’s 2007 General Tariff Application
(expected to be filed in late 2005 or early 2006).
(b) No further action be taken on establishing a firm import tariff at this time.
Request:
Response:
(a)
Please explain why the AESO is proposing inaction on the development of
firm import tariffs when stakeholders have clearly indicated a desire to
develop and use such a rate.
(b)
Is it the AESO’s position that it is not feasible to create a firm import tariff at
this time? If yes, explain why it is not feasible. Does this situation apply to
both existing and new “merchant” transmission lines?
(a-b) During consultations during 2004, stakeholders did not indicate an urgency
to proceed with development of a firm import tariff. Interest in a firm import
tariff did not materialize until late in 2004, and the AESO was unable to
carry out the necessary consultation and appropriate examination of issues
in time to allow such a tariff to be fully developed for filing with its 2006
GTA. The AESO has proposed to continue consultation through 2005 to
allow a firm import tariff to be included, if appropriate, in its 2007 GTA.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-044 (a)
Reference:
Application, Section 4, p.23.
Preamble:
The Application states:
Page 1 of 1
As already noted, the AESO’s current export rate is an opportunity service.
In general, opportunity service rates are based on costs of a variable nature. The
AESO therefore proposes its Export Opportunity Service rate include an
interconnection charge equal to the usage component of the interconnection
charge of the Demand Transmission Service rate, proposed to be $4.07/MWh.
[Emphasis added]
Request:
(a) If export service is an opportunity service, then why is the rate different than
that for DOS service?
Response:
(a) Simply because a service is an opportunity service does not require it to be
priced on the same basis as another, different opportunity service. A
difference between EOS and DOS, for example, is that DOS is supplied at
services that also take firm DTS service, while EOS is not associated with
any firm rate.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-045 (a)-(f)
Reference:
Application, Section 6, Customer Contribution Policy.
Request:
(a) What is(are) the purpose(s) of a Customer Contribution Policy?
Page 1 of 2
(b) What are the attributes of a sound Customer Contribution Policy?
(c) What portion of the transmission system costs should a customer contribution
relate to? Why?
(d) What is(are) the purpose(s) of the AESO’s “maximum investment” (i.e. roll-in
ceiling)?
(e) What are the attributes of a sound AESO “maximum investment”?
(f) What portion of the transmission system costs should the AESO “maximum
investment” relate to? Why?
Response:
(a) The general purposes of a customer contribution policy are:
i.
To facilitate access to the electric system in a fair, equitable, and nondiscriminatory basis; and
ii.
To provide an economic discipline on customers reflective of the utility’s
economics.
(b) The attributes of a sound customer contribution policy include:
i.
Provision of appropriate price signals;
ii.
Fairness, equity, and reasonability for both existing and new customers;
iii.
Certainty, predictability, consistency, and objectivity in application; and
iv.
Compliance with applicable requirements of legislation.
An additional attribute of the AESO’s contribution policy was identified by the
EUB in Decision 2000-1, namely:
v.
Harmonization (that is, consistency) with the contribution policies of
distribution utilities.
(c) A customer contribution should relate to the capital costs of additional or
incremental facilities installed to provide service to that customer. For the
transmission system, those facilities would usually include the POD (including
radial line) as well as incremental improvements to the local system and bulk
system. To reduce the need for discretionary cost classification, to provide a
high level of predictability, and to provide consistency in the treatment of load
and generator projects, the AESO further proposes to exclude from customer
contribution the incremental costs associated with local system and bulk
system enhancements.
Page 2 of 2
(d) The purposes of the AESO’s maximum investment are the same as the
general purposes of a customer contribution policy as provided in part (a)
above.
(e) The attributes of a sound AESO maximum investment are the same as the
attributes of a sound customer contribution policy as provided in part (b)
above.
(f) The AESO maximum investment should relate to the same costs to which a
customer contribution relates as provided in part (c) above, with two
additional considerations.
First, the maximum investment should relate to the cost of the usual facilities
installed to provide service to customers — the “AESO Standard Facilities”
defined in the proposed tariff.
Second, the maximum investment should relate to the cost of facilities used
to provide service to most, but not all, customers, to preserve “a balance
between the need of new customers for service without a need for subsidy
from existing customers.” (Decision 2001-6, p. 70)
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-046 (a)-(d)
Reference:
Application, Section 4.5, DTS Billing Capacity Ratchet Levels, p.4-16.
Preamble:
The Application states:
Page 1 of 1
Demand ratchets are firmly established in Alberta as an effective short-term
means to both equitable cost recovery and revenue stability. Billing in
accordance with contract minimums is a long-term means to similarly ensure cost
recovery and revenue stability.
Request:
(a) What is(are) the purpose(s) of the DTS Billing Capacity ratchet?
(b) What costs is the AESO trying to recover using Billing Ratchets.
(c) What does the AESO mean by “revenue stability” and explain why this is an
issue to the AESO when all cost categories are subject to deferral accounts?
(d) Does the DTS contract (System Services Agreement) include any “ratchet” or
‘take-or-pay’ provisions in addition to those of the DTS Billing Capacity
ratchet? If yes, explain what they are and how they work.
Response:
(a-b) Please refer to ENCANA.AESO-047 (e) and 048 (b).
c) Revenue stability means that regardless of fluctuations in usage a certain
level of revenue is recovered. The revenue stability should reflect the fixed
nature of the transmission system.
d) No the DTS contract does not include any “ratchet” or ‘take-or-pay’ provision
in addition to the DTS billing ratchet. Please refer to Section 7, page 2 of 84,
of the AESO’s 2006 GTA, to review the DTS (Demand Transmission Service)
rate schedule.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-047 (a)-(e)
Page 1 of 2
Reference:
Application, Section 4.5 (Ratchets), Section 6.1 (Customer Contribution)
Preamble:
Assume a 20 MW load customer connects to the transmission system in Year 0.
Further, assume that the local connection costs are $10 million and the customer
signs a 20-year DTS contract (SAS Agreement). Finally, assume that at the end
of Year 5 the customer departs the system.
Request:
a) Calculate the “maximum investment” using the AESO’s proposal.
b) What is the economic burden of connecting the new customer for (i) the new
customer and (ii) for other existing customers?
c) When the customer departs the system, what revenue can the AESO recover
from the customer and how does this compare to the stranded local costs?
d) Is the answer to c) any different if the customer is insolvent when it departs
the system? Please explain.
e) Please explain how the AESO’s proposal for the Customer Contribution
Policy and DTS billing ratchet manages the risk of stranded transmission
costs.
Response:
a) Local interconnection costs:
$10.0m
Maximum Investment: 20MW x $27,000 x 20 years:
$10.8m
Customer Contribution:
$ 0.0
b) The economic burden for:
i)
the new customer: will be the requirement to pay 20 years of DTS
rate charges
ii)
other existing customers: will see an increase to their DTS rate
required to recover the increase in the transmission facility owners
annual revenue requirement
c) If the customer provided their five year notice the very day they signed their
system access service agreement, the AESO would then recalculate the
customer contribution calculation for the customer, which in this case would
be $7.3m.
Local interconnection costs:
Maximum Investment: 20MW x $27,000 x 5 years:
Customer Contribution:
$10.0m
$ 2.7m
$ 7.3m
Page 2 of 2
If on the other hand the customer failed to provide their five years notice the
customer would be required to provide a contribution of $4.6m and five years
of DTS charges.
Local interconnection costs:
Maximum Investment: 20MW x $27,000 x 10 years:
Customer Contribution:
$10.0m
$ 5.4m
$ 4.6m
(plus) 5 years of DTS charges
d) If the customer is unable to pay for the charges outlined in part (c) above then
the AESO would retain the financial security as outlined in Article 15 and the
remaining costs would become stranded and paid by the Alberta rate payer.
e) The DTS billing ratchet is not stranded asset management tool. The DTS
ratchet manages costs associated with the short term use of the system by
the customer over their contracted capacity. Article 9.7 of the customer
contribution policy and Articles 6 and 15 manage and reduce the chances of
stranding transmission assets but there are rare cases where stranding
facilities can happen no matter how many policies or terms and conditions
are developed and employed by the AESO.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-048 (a)-(d)
Page 1 of 2
Reference:
Application, Section 4.5 (Ratchets), Section 6.1 (Customer Contribution)
Preamble:
Assume a 20 MW load customer connects to the transmission system in Year 0.
Further, assume that the local connection costs are $10 million and the customer
signs a 20-year DTS contract (SAS Agreement). Finally, assume that at the end
of Year 5 the customer departs the system.
Consider a situation where the DTS Customer Contribution Policy is similar to the
STS Contribution Policy; the customer is required to pay all local interconnection
costs and these costs are refunded over a period of 10 years (subject to
adequate performance).
Request:
a) Does the AESO agree that in this situation, if the customer departed the
system there are no stranded costs to be borne by other customers? If not,
explain.
b) Does the AESO agree that in this situation, there is no need for billing
ratchets since there can be no stranded costs? If not, explain.
c) Does the AESO agree that with this type of front-loaded contribution policy
there would be no need to provide waivers for multiple-user PODs, i.e.
distribution utility interconnections? If not, explain.
d) Does the AESO agree that if the DTS and STS contribution policy worked
similarly, there would be no need to create separate rules for contributions in
dual-use customer situations?
Response:
a) For clarification the local interconnection costs for an interconnecting
generator are not refunded. It is the System Contribution that is refunded
over a maximum of 10 years (subject to adequate performance), where the
System Contribution is a locational charge paid by generators for non specific
upgrades to the existing transmission system. Local interconnection costs for
generators continue to be fully funded by the customer and are refunded
under the conditions outlined in Articles 9.7 and 9.8.
The AESO agrees that if the DTS customer fully funded their interconnection
and subsequently departed the system there would be no stranded costs
borne by other customers.
b) For clarification the DTS billing ratchet is not stranded asset management
tool. The DTS ratchet manages costs associated with the short term use of
the system by the customer over their contracted capacity. If the customer
exceeded their contract capacity prior to departing the system, the DTS
Page 2 of 2
ratchet would cover the costs of using system facilities in excess of their
contracted load.
c) The AESO disagrees. A zero investment policy requiring full customer
contributions sends the strongest possible economic signal and siting
discipline to the customer. Distribution utilities remain unable to respond to
such a signal, and the AESO would expect the need for waivers at multiple
customer PODs would continue.
d) A zero investment policy requiring full customer contributions sends the
strongest possible economic signal and siting discipline to the customer. The
AESO agrees that there would be no need to create separate rules for
contributions in dual-use customer situations.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-049 (a)-(d)
Reference:
Application, Section 6.1 (DTS Customer Contribution), p.3.
Preamble:
The Application states:
Page 1 of 2
There are essentially three approaches to classifying system and customerrelated costs, as illustrated in Figure 6.1.1. In these alternatives, “bulk system”
refers to facilities that are used to serve a large number of transmission
customers, including looped facilities. “System enhancements” refers to
upgrades of existing facilities, including breakers, protection, and
communication systems, as well as shared portions of radial lines. “Local
connection” refers to all new facilities serving just the new customer, including all
contiguous construction from the customer substation along newly-constructed
radial line, including a new breaker at an existing substation if required.
[emphasis added]
Request:
a) The construction of the highlighted phrase may be interpreted to mean that
only communication systems at existing facilities will be considered system
enhancements. Please clarify if this is the case, or whether all
communication system components, including the equipment installed at the
new POD, is to be included in the definition of “System Enhancements”.
b) What planning and cost standards does the AESO have in place to ensure
that the interconnection of a new customer does not lead to overbuilding or
unnecessary enhancement of TFO communication facilities. Please provide a
copy.
c) What planning and cost standards does the AESO have in place to guide
TFOs in the addition of breakers and protection equipment so as to ensure
that the interconnection of a new customer does not lead to overbuilding or
unnecessary enhancement of TFO facilities. Please provide a copy.
d) Please explain why the proposed version of Article 9 of the T&Cs does not
contain the same definition of “System Enhancements”.
Response:
a) No, communication equipment at the new POD are not included in the
definition of system enhancements.
b) Please refer to CITIES.AESO.010 (a)
c) The above mentioned documentation along with the standards being
developed as part of the new interconnection process will guide the
Page 2 of 2
transmission facility owners in designing the most viable interconnection
alternatives. The standards are still in development and cannot be provided
at this time. The AESO will make them public when they become available.
d) The AESO felt the definition of customer-related costs and system-related
costs as outlined in Article 9.3 were sufficient.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-050 (a)-(d)
Page 1 of 2
Reference:
Application, Section 6.1 (DTS Customer Contribution), p.3; Decision 2001-6,
p.63.
Preamble:
The Application states:
There are essentially three approaches to classifying system and customerrelated costs, as illustrated in Figure 6.1.1. In these alternatives, “bulk system”
refers to facilities that are used to serve a large number of transmission
customers, including looped facilities. “System enhancements” refers to
upgrades of existing facilities, including breakers, protection, and
communication systems, as well as shared portions of radial lines. “Local
connection” refers to all new facilities serving just the new customer, including all
contiguous construction from the customer substation along newly-constructed
radial line, including a new breaker at an existing substation if required.
[emphasis added]
In Decision 2001-6, the Board said:
The Board does not see a need to change the definition of a radial line where
that line or a portion thereof serves more than one POD. The Board notes that
the second POD may benefit from a lower contribution from the presence of the
first POD and vice versa through the refund mechanism. For these reasons, the
Board will not require EAL to redefine the portion of a radial line serving multiple
PODS as system.
Request:
a) Please confirm that the AESO’s proposal intends to change the definition of a
radial line from “customer costs” to “system costs” whenever there is a
shared portion of the radial line. If not, please explain.
b) Please explain how the AESO’s proposal is different from the proposal by
EAL in the 2001 GRA, especially in light of the Board’s rejection of this
concept.
c) Does the AESO agree that “systemizing” the shared radial line increases the
stranded cost risk borne by other customers? If not, explain.
d) Does the AESO agree that if the DTS contribution policy followed a “security
deposit plus refund” concept (similar to the STS contribution policy), it could
avoid reclassifying shared radial extensions from “customer” to “system”
costs and rely instead on a refund/rebalancing mechanism to share the
burden of the capital costs between the original customer and the new
customer? If not, explain.
Response:
Page 2 of 2
a) Confirmed
b) Please refer to BR.AESO.26.
c) The AESO suggests that risk of stranded costs is the same in both the
existing and proposed contribution policies. Whether the facilities are
classified as customer-related and covered by the AESO’s investment policy
or classified system-related at the outset, the same risk exists of that
customer not to being capable of completing their contractual term or funding
contributions if they leave the system prematurely.
d) A zero investment policy (that is, full customer contribution) for POD facilities
would create a much bigger incentive for a customer to want costs classified
as system-related. The AESO does not believe a re/rebalancing mechanism
aligns with the requirements of the Transmission Regulation as discussed in
BR.AESO.26 (b-c).
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-051 (a)-(d)
Reference:
Application, Section 6.1 (DTS Customer Contribution), pp.3-4.
Preamble:
The Application states:
Page 1 of 2
There are essentially three approaches to classifying system and customerrelated costs, as illustrated in Figure 6.1.1. In these alternatives, “bulk system”
refers to facilities that are used to serve a large number of transmission
customers, including looped facilities. “System enhancements” refers to
upgrades of existing facilities, including breakers, protection, and
communication systems, as well as shared portions of radial lines. “Local
connection” refers to all new facilities serving just the new customer, including all
contiguous construction from the customer substation along newly-constructed
radial line, including a new breaker at an existing substation if required.
[emphasis added]
To reduce the need for discretionary cost classification in Alternative 2, to provide
a high level of predictability, and to provide consistency in the treatment of
load and generator projects, the AESO proposes to define all system
enhancement costs as system costs, as illustrated in Alternative 1. [emphasis
added]
Request:
a) Please explain why the proposed version of Article 9 of the T&Cs does not
contain the same definition of “System Enhancements”.
b) Please provide a list of all the types of equipment that the AESO intends to
included in the category of “system enhancements”.
c) Please explain if the location of this equipment changes has a bearing on
whether it will be classified as “system enhancement”.
d) Please provide a full and unambiguous definition of “system enhancements”
that can be applied in Article 9 of the T&Cs that makes clear what equipment
is included in this category regardless of whether it is located at the new POD
or at an existing facility.
Response:
a) System enhancements are defined as system-related costs in Article 9.3 (b).
b) Please refer to Article 9.3 (b).
c) As outlined in Article 9.3, customer related costs “are those costs of a
contiguous project in respect of radial transmission extensions. Such costs
will normally include the point of interconnection, new transmission line,
Page 2 of 2
communications at the point of interconnection back to the existing system
and a new breaker at an existing substation if required” and all other costs
required to interconnect the customer would be considered system-related
costs.
d) The AESO feels the definition of system-related costs as provided in Article
9.3 (b) is sufficient.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-052 (a)-(b)
Reference:
Application, Section 6.1 (DTS Customer Contribution), p.4.
Preamble:
The Application states:
Page 1 of 2
To reduce the need for discretionary cost classification in Alternative 2, to provide
a high level of predictability, and to provide consistency in the treatment of load
and generator projects, the AESO proposes to define all system enhancement
costs as system costs, as illustrated in Alternative 1. [emphasis added]
Specifically, the AESO proposes that system costs be defined as those costs
relating to facilities constructed for the use and benefit of several individual points
of connection, including upgrading of such facilities arising from load or supply
increases of one or more customers. Costs will typically be classified as system
when the facilities are non-contiguous to the local connection or when
construction consists of upgrades to the existing looped network. System costs
will include the cost of upgrading existing breakers and protection to
accommodate the customer and any upgrades to communications systems at
existing substations. In all cases, for costs to be considered system the
interconnection configuration must accord with AESO standards. Where the
interconnection configuration requested by the customer does not conform to
AESO standards, the AESO will deem all excess costs (that is, costs above
those which would arise from facilities which do conform to AESO standards) to
be customer-related costs and payable by the customer in accordance with
Article 9.3(c).
Request:
(a)
If the objective is to reduce the application of discretion, to increase
predictability and consistency in the classification of costs, explain why the
AESO has not included the definition of system costs as noted above into
the proposed Article 9 of the T&Cs.
(b) Provide a clear and unambiguous definition of “system costs” that can be
applied in the proposed Article 9 of the T&Cs.
Response:
(a-b) Article 9.3 of the proposed terms and conditions is reproduced below with
particular phrases emphasized. The AESO considers the emphasized
phrases to provide clarity and unambiguity equivalent or superior to the
quoted section of the AESO’s application.
9.3
Classification of System and Customer-Related Costs
The AESO will classify project costs as either system-related costs or
Customer-related costs, as follows.
(a) Subject to Article 9.3(b), Customer-related costs are those costs
of a contiguous project in respect of Radial transmission
extensions. Such costs will normally include the point of
interconnection, new transmission line, communications at
Page 2 of 2
(b)
(c)
the point of interconnection back to the existing system,
and a new breaker at an existing substation, if required.
System-related costs are those project costs associated with:
(i)
Looped transmission facilities;
(ii) Enhancements to existing transmission infrastructure
including communications at existing substations;
(iii) Radial transmission extensions if the transmission
development plan (as that plan exists on the date the
project is Commissioned) proposes that the Radial
transmission extension becomes Looped within five
years. The Customer will pay the cost of advancing that
part of the project from the date established in the
transmission development plan, calculated as the
difference between the present values of the capital costs
of the advanced and as-planned projects using the
discount rate as determined under Article 9.9; and
(iv) Where, in the sole opinion of the AESO, economics or
system planning dictate that a facility larger than that
required to serve the Customer is to be installed, then
the AESO will classify that portion of the project deemed to
be in excess of the Customer’s needs as system-related
costs. As the need to serve additional POCs arises, these
system-related costs may be reclassified as Customerrelated costs and allocated to the new Customers. The
capacity between the Customer’s requirements and the
minimum size of facilities required to serve the Customer is
not considered to be in excess of the Customer’s
requirements.
Where the Customer requests an interconnection configuration
that, in the sole opinion of the AESO, exceeds AESO Standard
Facilities, the Customer must pay all customer and system
costs in excess of AESO Standard Facilities.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-053 (a)-(d)
Reference:
Application, Section 6.1 (DTS Customer Contribution), pp.3-4.
Preamble:
The Application states:
Page 1 of 2
“System enhancements” refers to upgrades of existing facilities, including
breakers, protection, and communication systems, as well as shared portions of
radial lines. (p.3) [emphasis added]
Specifically, the AESO proposes that system costs be defined as those costs
relating to facilities constructed for the use and benefit of several individual
points of connection, including upgrading of such facilities arising from load or
supply increases of one or more customers. Costs will typically be classified as
system when the facilities are non-contiguous to the local connection or when
construction consists of upgrades to the existing looped network. System costs
will include the cost of upgrading existing breakers and protection to
accommodate the customer and any upgrades to communications systems at
existing substations. (p.4). [emphasis added]
In addition to such non-standard configuration costs as set out above, customerrelated costs are defined as those costs relating to local connection facilities
typically comprising the customer substation and all contiguous construction
from the customer substation back along any newly constructed line,
including a new breaker if required at an existing substation. Where the
local connection includes only facilities that tap into an existing transmission line,
the customer-related costs will not include any upgrades to existing substations.
The cost of communications both at the customer’s substation and back to the
existing system will be considered customer-related costs, but any other
enhancements to the existing system will be excluded from customer-related
costs. (p.4) [emphasis added]
Request:
(a) Is the installation or upgrade of a breaker at an existing POD a “system” or
“customer” cost? Provide schematic diagrams to illustrate the response.
(b) What is the AESO’s standard for connecting a radial line to the existing
transmission system? Under what conditions is a T-tap acceptable and
under what conditions is a breaker-connection required?
(c) What is the purpose of a breaker and protection equipment? Who uses and
benefits from such devices. Provide schematic diagrams to illustrate the
situations.
(d) Please explain why the addition of a breaker at a non-contiguous substation
benefits several points of interconnection but the addition of a breaker at the
Page 2 of 2
connection of the new radial line cannot benefit other points of
interconnection? Provide schematic diagrams to illustrate the response.
Response:
a) The installation or upgrade of a breaker at an existing POD could be either a
“system” or “customer” cost depending on why the breaker is being added.
For example, if the breaker is being added to an existing POD as part of the
interconnection of a new customer then it will likely be a “customer” cost.
b) The AESO’s determination of the acceptability of a T-tap arrangement in lieu
of a breaker-connection is based on case specific assessments of the circuit
lengths involved (both of the tap as well as the segments of the T-tapped
circuit), the impact of additional exposure of the tapped circuit as well as the
tap itself, and the significance of the tapped circuit in serving other loads. As
well, there are technical limits regarding communication and protection issues
that may impact the decision.
c) Breakers, with the associated protection equipment, are relied upon to isolate
transmission or distribution equipment experiencing electrical faults. As such,
they are a necessary component to safely provide electrical service to
customers, thus benefiting customers either directly or indirectly.
d) The non-contiguous breaker is clearly providing service to a number of
customers, and may have required installation for a number of potential
customer interconnections. However, the contiguous breaker is being added
specifically to serve that new customer, and, especially in the case of a
simple bus connection, clearly forms a part of the radial supply to the new
customer.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-054 (a)-(b)
Reference:
Application, Section 6.1 (DTS Customer Contribution), p.4.
Preamble:
The Application states:
Page 1 of 1
To reduce the need for discretionary cost classification in Alternative 2, to provide
a high level of predictability, and to provide consistency in the treatment of load
and generator projects, the AESO proposes to define all system enhancement
costs as system costs, as illustrated in Alternative 1. [emphasis added]
In addition to such non-standard configuration costs as set out above, customerrelated costs are defined as those costs relating to local connection facilities
typically comprising the customer substation and all contiguous construction from
the customer substation back along any newly constructed line, including a new
breaker if required at an existing substation. Where the local connection includes
only facilities that tap into an existing transmission line, the customer-related
costs will not include any upgrades to existing substations. The cost of
communications both at the customer’s substation and back to the existing
system will be considered customer-related costs, but any other enhancements
to the existing system will be excluded from customer-related costs. (p.4)
[emphasis in original]
Request:
a) If the objective is to reduce the application of discretion, to increase
predictability and consistency in the classification of costs, explain why the
AESO has not included the definition of “customer related costs” as noted
above into the proposed Article 9.
b) Provide a clear and unambiguous definition of “customer costs” that can be
applied in the proposed Article 9
Response:
a) The AESO feels the definition of customer-related costs as provided in Article
9.3 is sufficient
b) Please see (a) above.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-055 (a)-(b)
Reference:
Application, Section 6.1 (DTS Customer Contribution), p.6.
Preamble:
The Application states:
Page 1 of 1
The proposed form of the maximum local investment provides better
harmonization with the similarly-structured load-based investment policies of
most distribution facility owners (DFOs). By using an average unit investment
that varies with contract term, the maximum local investment also allows
customers to lessen the effect of eliminating the current commitment term
amount by contracting for a longer DTS contract term.
Request:
a) Provide a tabular comparison of the AESO’s proposed investment policy to
the investment policies of each DFO in Alberta. Illustrate where the policies
are similar and where the policies are different.
b) From a technical (engineering) perspective, at what contract capacity does
the AESO and DFOs require the customer to interconnect directly to the
transmission system? If no such level of contract capacity exists, what is to
prevent a single large load customer from connecting behind a DISCO POD
in order to benefit from a lower contribution.
Response:
a) There are several similarities between the AESO’s proposed contribution
policy and the Distribution Facility Owners (“DFO”) policies. Each policy
contains a maximum dollar investment that varies with the level of contracted
capacity. Each policy also contains provisions for the level of investment to
vary with contractual term the customer is willing to sign. The policies are
dissimilar in the length of contractual term and the DFO policies vary with the
type of service required by the customer. Please refer to
Schedule.ENCANA.AESO.055 (a) for further detail.
b) There is not a specified contract capacity that requires the customer to
interconnect directly to the transmission system. The provisions outlined in
Article 9.5 (b-c) will ensure that a single large load customer that is greater
than 2 MW will receive the same treatment as a transmission customer of the
same size.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-056 (a)
Reference:
Application, Section 6.1 (DTS Customer Contribution), p.6.
Preamble:
The Application states:
Page 1 of 1
In Decision 2001-38 on ATCO Electric’s 2001-2002 Distribution Tariff Phase II,
the EUB stated (page 120):
The Board also notes with concern the impact on investment levels of
potential changes in rate levels and structures…. The Board does not
consider that rate rebalancing or changes in revenue to cost ratios should
automatically result in a change in the investment levels for the affected rate
classes.
Moving to a maximum local investment based on a unit $/MW/year amount
eliminates changes to investment levels resulting directly from a change to rate
levels.
Request:
(a) Does the AESO agree that a DTS contribution policy which follows a “security
deposit with refund” concept (similar to the STS contribution policy) has the
same attribute of independence from changes in rate levels? If not explain.
Response:
(a) The generator contribution policy is based on zero investment (that is, full
customer contribution) for POD facilities and an additional refundable
contribution for general local system and bulk system improvements. The
AESO agrees that if the load contribution policy was also based on zero
investment for POD facilities and an additional system contribution, it would
be independent of changes in rate levels.
Please refer to Information Response ENCANA.AESO-038 (d) for additional
discussion.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-057 (a)-(b)
Reference:
Application, Section 6.1 (DTS Customer Contribution), p.6.
Preamble:
The Application states:
Page 1 of 1
Through analysis, the AESO has determined that a maximum local investment of
$27,000/MW/year can be expected to more closely reach the intended result
where 80% of transmission projects would not require a customer contribution.
As the AESO has a limited number of transmission projects subject to a
customer contribution calculation in any year, the analysis included a sample
comprised of ten recent projects and fifty scenario projects. The scenario project
costs were estimated using various high level substation configurations with
differing line components and SCADA requirements.
Request:
a) Is the 80/20 criteria the sole basis for selecting the $27,000/MW/contract-year
investment level? If not explain what other criteria was used.
b) Please refile Table 6.1.1 clearly identifying and separating the ten recent
projects from the 50 scenario projects. Please do the same with Figure 6.1.2
by providing two diagrams showing the ten recent projects and the 50
scenario projects separately. In each of the table and diagrams clearly
identify the interconnections related to distribution utilities.
Response:
a) Please refer to information request responses ENCANA.AESO-015 and
ENCANA.AESO-045 (a-f)
b) Please refer to information request response FIRM.AESO-242
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-058 (a)-(b)
Page 1 of 2
Reference:
Application, Section 6.1 (DTS Customer Contribution); Decision 2000-1, p.271.
Preamble:
The Application states:
Therefore, the Board directs EAL, in its refiling, to develop its contribution policy
based on the excess of project cost over supporting revenue for the
connection of load costs for customers. The Board agrees with TransAlta
that the contract level of the load seeking connection should drive the investment
policy. EAL may express this in terms of investment per kW if convenience
directs. [emphasis added]
Request:
(a) Has the AESO conducted a comparison of the net present value (NPV) of
DTS revenue for local connection costs to the “maximum investment”
amount? If yes, please provide the analysis. If no, please explain how the
Board is to evaluate the balance between revenue supporting local
interconnection costs and the costs borne by the AESO.
(b) Does the AESO agree that a DTS contribution policy which follows a “security
deposit with refund” concept (similar to the STS contribution policy) has the
attribute of balancing revenue for the connection costs and the costs borne
by the AESO. If not explain.
Response:
(a) The AESO notes the referenced quotation is from Decision 2000-1 and not
from the AESO’s Application.
The AESO has not compared the net present value (NPV) of DTS revenue
for local connection costs to the “maximum investment” amount. At a high
level, DTS revenue is zero for zero load and increases linearly with load as
load increases (assuming constant load factor). The proposed maximum
investment (determined as dollars per MW of DTS contract capacity per year
of contract term) would be zero for zero contract capacity and would increase
linearly with capacity as capacity increases (assuming constant contract
term). The form of the contribution policy therefore aligns with the supporting
revenue. The level of the maximum contribution was determined such that
80% of projects would not require a contribution, in accordance with EUB
comments in Decision 2001-06 as discussed on page 7 of section 6 of the
AESO’s 2006 GTA. Given the alignment of contribution policy with supporting
revenue and the 80/20 target, the AESO believes its proposed contribution
policy adequately demonstrates a balance between revenue and costs.
(b) The generator contribution policy is based on zero investment (that is, full
customer contribution) for POD facilities and an additional refundable
contribution for general local system and bulk system improvements. The
AESO does not agree that if the load contribution policy was also based on
zero investment for POD facilities and an additional system contribution, the
Page 2 of 2
revenue for the connection costs would be balanced with the costs borne by
the AESO. The imbalance would arise from the significant change
represented by a “full customer contribution” policy compared to the current
and previous policies which resulted in 80% or more of projects not requiring
any customer contribution.
The AESO’s rates are based on embedded (or average) costs of the
transmission system, recover an average amount of investment in customer
facilities, and are paid by all DTS customers. Charging those rates for
facilities for which a full customer contribution was paid would over-recover
from those new customers. If the full contribution policy remained in place for
several years, AESO rates would gradually reflect the absence of investment
in new customer facilities. Customers who interconnected before the policy
changed would then benefit, from having received the earlier AESO
investment while now paying lower AESO rates. Such intergenerational
inequities are the usual result of large step-changes to investment policies or
rate structures.
See Information Response ENCANA.AESO-038 (d) for additional comments.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-059 (a)-(b)
Page 1 of 1
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.14; Decision 2000-1,
p.271.
Preamble:
The Application states:
The AESO proposes to waive customer contributions in respect of transmission
projects at PODs where multiple users are served by a distribution utility, as set
out in Article 9.5 of the proposed terms and conditions of service:
In Decision 2001-6, the Board said:
In determining whether or not the contribution policy is just and reasonable, the
Board has applied a test that would see all demand customers, including
DISCOs, in the same light. That would mean any customer should be able to
approach the TA with their load information and their location and be given the
same answer as to the cost to connect. If the load and distance to connect were
identical then one would expect the cost to be identical.
Request:
(a) Was the Board wrong to apply a test that would see all demand customers in
the same light?
(b) How does the AESO’s proposal address the Board’s test?
Response:
a) – b) Please refer to BR-AESO-019 (a)
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-060 (a)-(d)
Page 1 of 2
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.15.
Preamble:
The Application states:
The AESO is proposing this waiver to address distinctions relating to the
principles underlying its customer contribution policy, as presented in the opening
of Section 6.1.
(a) As regulated utilities with a right and obligation to serve, owners of
distribution facilities coordinate with the AESO in planning transmission
and distribution facilities to arrive at the most effective solution to end-user
electricity needs at the lowest overall cost, regardless of any local investment
limitations imposed by the AESO customer contribution policy. [emphasis added]
Request:
a) Is it the position of the AESO that when developing a DISCO interconnection,
there is never more than one solution to meeting the needs of retail
customers?
b) If the answer to a) is yes, provide a table summarising the need application
for distribution utility PODs over the last year. For each application indicate
the number of technically viable options that were evaluated for each
interconnection.
c) Please explain how the planning of transmission interconnections for
distribution utilities is different from planning of transmission interconnections
for large industrial customers.
d) Is it the position of the AESO that large industrial customers are
interconnected without consideration to the lowest overall cost? Please
explain.
Response:
a) Alternatives may include multiple transmission, distribution or a combination
there of, the AESOs recommended solution will generally be the lowest cost
alternative that satisfies the technical and operational criteria of the AESO
and the needs of the customer.
b) Please refer to part a) above and to Schedule.ENCANA.AESO.060 (b)
c) Typically service to a large industrial customer can be achieved at a single
point of supply whereas projects that involve multiple number of points of
supply, generally are required to meet the needs of a distribution company in
a given area. The planning of transmission interconnections for distribution
utilities, needs to take into account the distributed nature of the load and load
Page 2 of 2
growth in an area, the capability of the lower capacity distribution lines to
supply the load over the area under consideration and what alternatives for
expansion are afforded by the existing points of supply.
d) Interconnection of large industrial customers does involve consideration of
overall costs. However, because the industrial customer is not regulated as
the TFOs and DFOs are it would not be appropriate to simply implement the
least-cost solution if it meant the transfer of some costs that might otherwise
be the responsibility of the industrial customer to the regulated TFO.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-061 (a)-(d)
Page 1 of 2
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.15.
Preamble:
The Application states:
The AESO is proposing this waiver to address distinctions relating to the
principles underlying its customer contribution policy, as presented in the opening
of Section 6.1.
…
(b) No effective economic signal or siting discipline can be imposed on a
distribution utility in respect of transmission projects where that project is
caused by increasing load from multiple end-use customers. The distribution
utility has little if any influence over the amount, timing, or location of end-user
load growth. In general, any growth-related transmission project contributions
required from a distribution utility would be rolled into the utility’s distribution tariff
in accordance with utility-specific practices, and spread across all the utility’s
customers with no effect on siting or load growth. (The AESO appreciates that
distribution end-use customers are subject to local distribution connection costs,
where the price signal is effective.) [Emphasis added]
Request:
a) Is it the position of the AESO that no distribution utility conducts advanced
planning to determine the optimal location of new PODs, where optimality is a
combination of cost management and technical performance? Please
explain.
b) Does the AESO agree that if there is no cost accountability through the use of
a contribution policy, the distribution utility has no incentive to (i) manage its
own capital costs, and (ii) to manage the TFO’s local or system-related costs
required to interconnect the new POD. If not, explain.
c) What evidence does the AESO provide to substantiate the highlight text?
d) Please explain how the locational predicament of a distribution utility is any
different from the locational predicament of a large industrial facility that must
locate at the source of its raw material feedstock or near the user of its
production outputs.
Response:
a) The statement in ENCANA.AESO.061(a) does not reflect the AESO’s
position. The AESO is of the view that such planning is limited by the
distribution utility’s legislated obligation to serve; its service area; and the
location of customer growth, which may well dictate constructing facilities that
do not contribute to optimal cost management.
Page 2 of 2
b) Although the AESO recognizes the concern implied in the request, it does not
consider that its proposed contribution policy annuls the distribution utilities’
accountability. Please refer to page 18, lines 22-30 of the Application where
the AESO notes the efficacy of current processes in that regard.
“In the absence of any other factors, the waivers could influence the
DISCO’s preference for transmission projects or distribution projects to
meet load growth since the cost of a transmission solution would be
recovered from all consumers through the AESO tariff while the cost of a
distribution solution would increase the DISCO’s rate base and be
recovered from just the DISCO’s consumers. Although the waiver adds
another difference between transmission and distribution solutions, such
a concern is not new. Current processes, especially joint planning
between the AESO and the DISCOs and the subsequent needs
applications to the EUB, impose the necessary cost discipline on the
DISCOs and ensures that engineering solutions consider the economics
of Alberta consumers as a whole.”
c) The AESO has provided no formal evidence in respect of the highlighted
section, but has relied on discussions with distribution utilities as well as its
knowledge and judgment as set out in the succeeding sentences.
d) Please refer to Information Request response ADC.AESO-016 (c)
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-062 (a)-(c)
Page 1 of 1
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.15; Decision 2001-6,
p.56.
Preamble:
The Application states:
The main impact of transmission project contributions, if recovered through a
distribution utility’s distribution tariffs, is the potential for disparities in the price
paid for transmission access by different distribution utilities’ end-use customers.
For example, service area obligations may require a distribution utility to provide
transmission access to multiple end-use customers at remote sites or sites which
incur high project costs for other reasons. As a result, that distribution utility’s
customers will pay a higher rate for transmission access than customers of other
distribution utilities in the province. Such a result may be inconsistent with the
principle stated in Section 30(3)(a) of the Electric Utilities Act that the AESO’s
tariff “shall not be different for owners of electric distribution systems, customers
who are industrial systems or a person who has made an arrangement under
section 101(2) as a result of the location of those systems or persons on the
transmission system.” [Emphasis in original]
In Decision 2001-6, the Board said:
In other words, the Board accepts that customer contributions may differ as a
result of factors peculiar to particular PODs. These factors may include the load
at the POD as well as the length and capacity of the customer connection serving
the POD, without violating section 27(2)(b) of the EU Act.
Request:
(a)
Please confirm that s.27(2)(b) of EU Act (2000) has the same meaning and
effect as s.101(2) of the EU Act (2003).
(b) Does the AESO agree that the Board has previously examined the question
of whether a contribution policy is inconsistent with the “postage stamp”
principle and concluded that it is not? If yes, explain why the AESO seeks to
revisit this question and identify what is new or novel about the AESO’s
position that was not addressed in Decision 2001-6. If no, explain.
(c)
Response:
What evidence can the AESO provide to show that the distance from the
transmission system for new multi-user PODs is systematically different for
each distribution utility in Alberta?
(a-c) Please refer to Information Response BR.AESO-19 (a).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-063 (a)-(e)
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.15;
Preamble:
The Application states:
Page 1 of 2
In general, the AESO does not look beyond the service provided at its point of
delivery to treat all load customers consistently, for the purpose of achieving a
fair and reasonable application of its contribution policy. However, the AESO’s
tariff does impact all electricity consumers in Alberta. Waiver of customer
contributions at multiple-user PODs, as proposed, would result in fair and
equitable transmission access rates to all load customers. [Emphasis
added]
Request:
a) Does the AESO agree the waiver for distribution utility (Multi-user POD)
interconnections is equivalent to and has the same effect as raising the level
of the “maximum investment” for such interconnections? If not, explain.
b) If the answer to a) is yes, please provide an estimate as to the level of the
“maximum investment” that would lead to the same effect as waiving a
contribution for distribution utility PODs. In other words, how high does the
“maximum investment” need to be to ensure that all distribution utility POD
interconnections do not require a customer contribution? (To develop this
estimate please use Table 6.1.2 augmented for all interconnection in 2004
and any scenarios the AESO considers necessary – in all cases provide a
complete explanation of the data used including the contract capacity (in
MW).)
c) When the AESO uses the phrase “fair and equitable transmission rates” in
the highlighted text, does it intend to mean that transmission access rates will
be the same for all customers? If yes, explain how charging customers “the
same” rate is sound ratemaking principle.
d) Is it the AESO’s position that cost-causation can be disregarded yet still
achieve rates that are fair and equitable?
e) Does the AESO agree that a DTS contribution policy that follows a “security
deposit with refund” concept (similar to the STS contribution policy) has the
attribute of not requiring a discriminatory application? If not, explain.
Response:
a) – b) The AESO can agree that its waiver has the same appearance as
systemizing facilities for multiple-user PODs, rather than that of increasing
the Maximum Investment to some all-inclusive level. At any rate, the effect of
Page 2 of 2
the waiver is 100% investment in multiple-user PODs, provided all tariff
conditions are met.
c) A contribution policy should provide a price signal that appropriately reflects
the utility’s economics and to which customers can respond as well as
displays other attributes discussed in Information Request response
ENCANA.AESO-045 (b). The price signal does not have to be the same for
all customers to result in fair and equitable transmission rates.
d) Please refer to Information Request response ENCANA.AESO-015 (c-e)
e) The generator contribution policy is based on zero investment (that is, full
customer contribution) for POD facilities and an additional refundable
contribution for general local system and bulk system improvements. The
AESO suggests that a zero investment policy would reduce the need to
differentiate between customers and may reduce the administrative
application of it’s contribution policy.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-064 (a)-(c)
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.16
Preamble:
The Application states:
Page 1 of 2
The data in Table 6.1.2 shows one payment of a customer contribution by a
distribution utility under the AESO’s current contribution policy, at ATCO Kinosis.
The Table also shows the AESO’s proposed contribution policy applied to the
same projects would result in the payment of two customer contributions, at
ATCO Brintnell and at ATCO Kinosis. At ATCO Brintnell, the contribution
would be flowed through to specific customers. At ATCO Kinosis, 72% of the
contribution would be flowed through to specific customers and 28% would be
waived for multiple users, based on the proportion of load at the site. [Emphasis
added]
Request:
a) Consider a circumstance in which a new POD will serve both a large single
load and the distribution utility service. Please confirm that in this
circumstance the AESO’s proposed Contribution Policy would calculate a
contribution amount based on the total load, allocate this amount on a pro
rata basis to each of the utility and the large load then waive the charge to the
utility but flow-through the charge to the single large load. If no, explain.
b) Please provide the AESO’s understanding as to its authority to impose a rate,
charge or fee on a party that is not connected to the transmission system and
is therefore not an AESO Customer.
c) Please provide the AESO’s understanding as to its authority to impose a rate,
charge or fee on a Customer (i.e. DISCO) in order for that Customer to
impose indirectly the rate, charge or fee on a party that is not connected to
the transmission system and is therefore not an AESO Customer.
Response:
a) The circumstance which the AESO is being requested to consider appears to
differ from situation with ATCO Britnell; where the AESO would assess a
contribution against ATCO Electric, which in turn would flow that contribution
through to specific distribution customers, in accordance with ATCO Electric’s
terms and conditions of service.
i. It would appear that the request assumes the single load to be a
transmission connected AESO customer, and the distribution utility
load to serve only multiple-user sites. Given these assumptions, then
the AESO can confirm the noted allocation of customer contribution.
Page 2 of 2
b) The AESO is not asserting authority in the manner suggested; any required
AESO Customer Contributions are assessed against AESO customers
(DISCOs).
c) The AESO is not asserting authority in the manner suggested; its proposed
contribution policy in respect of multiple-user PODs is not dependent on the
manner in which the Distributor recovers such costs; any Application
reference to flow-through to distribution customers was made in recognition
of the current Distributor terms and conditions of service.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-065 (a)
Page 1 of 1
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.18;
Preamble:
The Application states:
The proposed multiple-user waivers will result in “systemizing” transmission
project costs that would otherwise be paid through customer contributions.
However, such costs are customer-related, not system, costs. The AESO
therefore plans to calculate a contribution for customer-related costs at multipleuser PODs, and if such contributions are waived they will be recorded and
tracked. Where contributions have been waived at PODs shared between large
individual users and multiple users, refunds of contributions to the individual
users will continue to be available if additional multiple-user transmission projects
are completed at the POD. [Emphasis added]
Request:
a) Please clarify and provide numerical examples as to how the AESO proposes
a large individual user will be levied a customer contribution when it connects
i)
At the transmission voltage, at a different POD from the
distribution utility,
ii) at the transmission voltage, at the same POD as the
distribution utility;
iii) at the distribution voltage, at the same POD as the distribution
utility; and
iv) at the distribution voltage, behind the POD.
Response:
a) For all examples below, assume (1) the large industrial user solely triggered
the transmission upgrade; (2) the transmission upgrade has a $1.5 million
customer related project cost; (3) the additional DTS contract capacity is 2
MW; (4) the AESO customer signs a 20 year System Access Agreement for
the maximum $1.1 million investment (2 MW x $27,000 x 20 years).
i. The AESO would assess a $0.4 million Customer Contribution to the
AESO customer (the large individual user).
ii. The AESO would assess a $0.4 million Customer Contribution to the
AESO customer (the large individual user).
iii. The AESO would assess a $0.4 million Customer Contribution to the
AESO customer (the distribution utility).
iv. The AESO would assess a $0.4 million Customer Contribution to the
AESO customer (the distribution utility).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-066 (a)-(f)
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.18;
Preamble:
The Application states:
Page 1 of 3
Alberta consumers are further protected by the specific exclusion from the
waiver, in Article 9.5(c), of aspects of projects that exceed the AESO standard
facilities required to service the distributor. As defined in the proposed terms and
conditions, AESO standard facilities “generally consist of a single radial
transmission circuit and a single transformer to supply an individual Point of
Connection.” However, DISCOs frequently have multiple Points of Delivery in
relatively close proximity, such that service may be provided from alternate or
multiple PODs. Through the joint planning between the AESO and the DISCOs,
the AESO expects the optimal solution to be determined based on consideration
of the technical and economic feasibility of transmission service through existing
capacity at existing PODs, transmission service through new capacity at an
existing or new POD, or a distribution solution, and having regard for the
applicable reliability, protection, and operating criteria and standards. Again, this
concern is not new, and Article 9.5(c) simply makes explicit, with respect to
contribution waivers, the ineligibility of above-standard facilities addressed in
Article 9.13(c) and previously addressed in Article 22 of the current terms and
conditions. Also, Article 9.1 expressly excludes shifts of demand from an existing
POD from being eligible for local investment. [Emphasis added]
Request:
(a) Does the AESO agree that applying AESO standards simply means that each
option does not exceed the design limits imposed by the standards and does
not guarantee that the least cost among the feasible options will be selected?
If no, explain.
(b) Please confirm that a contribution requirement places an economic discipline
in addition to the joint planning initiative. If not explain.
(c) Please confirm that the combined effect of the waiver plus the ineligibility of
non-standard facilities creates a “pro-distance” bias in the development of
transmission facilities for distribution utilities. (e.g. transmission facilities that
comply with the standard design can be of any length and still obtain a
waiver; non-standard facilities can be very short and lower cost yet require a
distribution utility contribution.) If not confirmed, please explain.
(d) How does the AESO measure whether a distribution utility is shifting demand
from an existing POD?
(e) Does the AESO agree that a DTS contribution policy that follows a “security
deposit with refund” concept (similar to the STS contribution policy) would be
administratively easier to apply because there would be no need to establish
Page 2 of 3
rules about meeting or exceeding standard facility designs, the customer is
automatically incented to select the least-cost option.
(f) Does the AESO agree that a DTS contribution policy that follows a “security
deposit with refund” concept (similar to the STS contribution policy) would be
administratively easier to apply because there would be no need to establish
rules about POD shifting as the customer is automatically incented to avoid
unnecessary facility costs.
Response:
a) The AESO’s definition of Standard Facilities includes the requirement to
choose the least cost interconnection alternative to meet the customers
requirements all the while meeting necessary operating criteria and
standards. The AESO will generally choose the interconnection alternative
that meets the above criteria.
b) Confirmed, but the contribution policy is an ineffective economic signal to
distribution companies as they cannot respond to that signal.
c) The AESO does not agree. The Standard length of line to interconnect a
customer can vary project to project. It is the AESO intention to generally
recommend the most economic Standard Facilities alternative. In cases
where it exceed the AESO standard, then Article 9.3 (c) would apply:
if the customer requested an interconnection that in the sole opinion of
the AESO, exceeds AESO Standard Facilities, the Customer must pay all
customer and system costs in excess of the AESO Standard Facilities.
So if the customer preferred another alternative other than the AESO’s
Standard Facilities, the incremental costs would not be eligible for the waiver,
and would be fully funded by the customer.
d) The AESO compares the contracted capacity for the new POD with the
contracted and metered load from the neighboring PODs.
e) The generator contribution policy is based on zero investment (that is, full
customer contribution) for POD facilities and an additional refundable
contribution for general local system and bulk system improvements. The
AESO agrees that it would be administratively easier if no rules were needed
in relation to meeting or exceeding standard facilities because customers
would be incented to select the least cost option.
The AESO expects most load customers would object to zero investment for
POD facilities, given the long-standing investment policies of utilities in
Alberta and previous acceptance that “80% of system expansion projects
would not require a contribution” (Decision 2001-6, p. 70).
f)
The generator contribution policy is based on zero investment (that is, full
customer contribution) for POD facilities and an additional refundable
contribution for general local system and bulk system improvements. The
2
Page 3 of 3
AESO agrees that it would be administratively easier if no rules were required
for POD shifting as the customer is incented to avoid unnecessary facility
costs.
The AESO expects most load customers would object to zero investment for
POD facilities, given the long-standing investment policies of utilities in
Alberta and previous acceptance that “80% of system expansion projects
would not require a contribution” (Decision 2001-6, p. 70).
3
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-067 (a)
Reference:
Application, Section 6.1 (DTS Customer Contribution); p.18;
Preamble:
The Application states:
Page 1 of 1
Article 9.8 of the proposed terms and conditions of service has been revised to
state that if facilities are installed to serve a customer and later used to serve
other customers, those facilities will be deemed to be system-related and any
customer contribution paid by the original customer for those facilities will be
refunded. These provisions address the requirements of the quoted clause of the
Transmission Regulation [s.16(4)]. [Emphasis added]
Request:
a) Does the AESO agree that its approach is one way to meet the requirements
of s.16(4) but it is not the only way. If not, please explain.
Response:
a) The AESO choose this approach to ensure simple, transparent and
consistent application of the contribution policy. Please refer to
BR.AESO.026 for further information.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-068 (a)-(c)
Reference:
Application, Section 6.1 (Customer Contribution); p.20;
Preamble:
The Application states:
Page 1 of 1
Article 9.13 of the proposed terms and conditions of service provides for the
payment of an additional prepaid operations and maintenance charge of 12% on
customer related costs for STS customers and on facilities in excess of AESO
standard facilities for all customers.
Request:
(a)
Please explain why the costs of O&M must be of a pre-paid nature. Please
explain why customers cannot pay for such O&M charges on an annual
basis.
(b) Please explain how the AESO will apply such monies to offset the annual
TFO revenue requirement over the life of the asset.
Response:
(c)
If the AESO intends to apply such funds as a one-time offset explain how
this addresses inter-generational inequity.
(a)
The prepayment of O&M is consistent with the payment of customer and
system contributions prior to construction of transmission facilities, in
accordance with Article 9.2 of the proposed terms and conditions. In
general, prepayment reduces the risk of under-recovery of costs in the
event that customers could not fulfill ongoing financial obligations.
(b-c) Prepaid O&M will be paid to TFOs with other customer contributions and
will be amortized over time to offset the annual TFOs’ revenue
requirements.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-069 (a)-(e)
Page 1 of 2
Reference:
Application # 1357161 (Article 24 Amendment Application), Additional Evidence
(January 10, 2005), p. 2
Preamble:
The Additional Evidence states:
The AESO believes that by having the Board establish the overall principles that
parties must use to establish specific compensation amounts, the overall
objectives of consistency, certainty and transparency are achieved. Without
the Board’s determination of these principles, it would be possible for Article
24.3(c) to be interpreted and applied in an inconsistent fashion. This is
particularly so in the event disputes arising under Article 24.3(c) are ultimately
resolved through third party dispute resolution processes pursuant to Article 16 of
the AESO’s Tariff Terms and Conditions. While the AESO supports the use of
third party dispute resolution mechanisms, in these circumstances it is imperative
for the Board to confirm the intended purposes, objectives and principles that
should be used to apply Article 24.3(c). [Emphasis added]
Request:
(a) Is it the AESO’s position the objectives of consistency, certainty and
transparency should be limited strictly to the interpretation of Article 24.3(c)?
If no, please explain.
(b) Does the AESO agree that the objectives of consistency, certainty and
transparency are equally applicable and desirable in all aspects of its tariff? If
no, please explain.
(c) Does the AESO agree that the objectives of consistency, certainty and
transparency should also apply, in the greatest extent practical, to the way in
which the AESO conducts itself when implementing the tariff? If no, please
explain.
(d) Does the AESO agree that it is not in the public interest if any aspect of the
tariff is applied in an inconsistent, ambiguous or arbitrary fashion? If no,
please explain.
(e) Does the AESO agree that it is inappropriate for the AESO to apply the tariff
in a way that is inconsistent with the purposes, objectives and principles
established by the Board? If no, please explain.
Response:
(a) No. The AESO believes objectives of consistency, certainty, and
transparency are appropriate to any tariff matter.
(b) Agreed.
(c) Agreed, to the greatest extent practical and provided confidentiality of
customer information is not compromised.
Page 2 of 2
(d) Agreed.
(e) Agreed, to the greatest extent practical and provided the purposes,
objectives, and principles established by the EUB remain appropriate for
current circumstances.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-070 (a)-(i)
Reference:
Page 1 of 2
Application, Section 7 – Article 1 (Definitions and Interpretations)
Request:
a) The AESO introduced a new definition for “AESO Standard Facilities” and
states that these “generally consist of a single radial transmission circuit and
a single transformer to supply an individual Point of Connection”. Does the
AESO agree that a “Standard Facility” under certain circumstance may
require a different configuration? If no, explain why the noted configuration is
only “generally” applicable.
b) Provide a copy of the AESO’s planning guidelines, ‘business practices’ or like
documents, that instruct AESO staff as to the standards for designing
“Standard Facilities”.
c) Please explain whether the AESO will provide a public document outlining the
guidelines and standards used for determining “Standard Facilities”. If no
such document is available now or in the future, explain how the AESO will
ensure that this aspect of the tariff will be applied with consistency, certainty
and transparency.
d) The AESO introduced a new definition for “Demand Opportunity Service
Business Practices” and states that it has the meaning of business practices
contained in a document entitled “Business Practices – Demand Opportunity
Service (DOS). Please provide a copy of this document.
e) Please provide a list of all other “Business Practices” documents that are
used to instruct or guide AESO staff on the application or interpretation of the
AESO tariff.
f) Please file copies of all other “Business Practice” documents that are used to
instruct or guide AESO staff on the application or interpretation of the AESO
tariff.
g) If there is a conflict between a “Business Practice” and the approved tariff,
does the AESO agree that the approved tariff shall prevail? If not, explain.
h) Is it the AESO’s intention to amend, modify or otherwise change the
“Business Practice” documents outside of any formal approval process by the
Board? Please explain the protocol for updating these documents.
i) Please explain how the objectives of consistency, certainty and transparency
are achieved if material criteria, standards or rules for executing the AESO
tariff is disposed by the AESO unilaterally, and without stakeholder
consideration, through amendments of its “Business Practices”.
Response:
a) Please refer to EPCOR.AESO-003 (a).
b) The AESO does not currently have such a document available. However, as
part of the redesign of the Interconnection Process the AESO has posted a
number of Draft Interconnection Process Guideline documents to its website
Page 2 of 2
that discuss various aspects of the process. As the need for further process
guidelines are identified they will be developed using the same or a similar
stakeholder consultation process.
c) Please refer to part b) above and e) below.
d) Please refer to ENCANA.AESO.087 (a)
e) The AESO undertakes several forms of documentation during the normal
course of business. There are documents that are constantly updated and
revised to reflect the ever changing conditions and situations the AESO
encounters for instance;
1. the AESO may encounter deficiencies in internal processes
2. unique customer situations requiring specific solutions
3. education materials outlining specific roles of employees in different
AESO processes or,
4. instructions regarding specific procedural questions
Then there are business practices that are formal documents which are
discussed in a public forum, reviewed and vetted and finally presented to the
stakeholder community. For example the “Guiding Principles & Practices for
Managing / Administering Customer Interconnection Requests in
Transmission Capacity Constrained Areas” as presented by Ed de Palezieux,
vice-president, Customer and Communication Services in July 2004.
Finally there is the AESO’s terms and conditions of service which are
reviewed and debated through the regulatory process and approved by the
EUB. The AESO captures the experience gained during the application of
the tariff and then may propose updates or revisions to the terms and
conditions of service to meet industry needs, provide more detail to clarify
misunderstandings, adhere to legislation or harmonize with industry
processes or practice changes.
f) Please refer ENCANA.AESO.087 (a) and to Schedule.ENCANA.AESO.070(f)
g) Agreed.
h) Yes it is the AESO’s intent to modify “business practice” documents outside a
formal Board process but all amendments would be made public. “Business
practices” are traditionally required when specific customer situations not
envisioned in the tariff require resolution prior to the next approved tariff.
Once one of these situations has been identified, resolved and a solution
determined, the AESO will follow the process as outlined in part (e) above.
i) “Business Practices” are developed to ensure consistency in tariff application
for all customers in between tariff applications. By making the “business
practices” public the AESO is ensuring customers have certainty and
transparency to the materials developed, input into their development /
application and the opportunity to have the documents debated at the next
GTA.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-071 (a-e)
Page 1 of 2
Reference:
Application, Section 7 – Article 1 (Definitions and Interpretations
Request:
(a) The AESO defines a “Dispatch Instruction” but does not refer to “directives”
as these are defined in the ISO Rules. Please clarify whether “Dispatch
Instruction” is intended to convey both a “dispatch” and a “directive” as those
terms are defined in the ISO Rules. If no, please provide an appropriate
definition for both terms to be added into the AESO tariff.
(b) The AESO defines “Emergency”. A prima facia interpretation of this definition
does not include the condition present in OPP 801 for recalling DOS loads.
Please explain the need to align the Terms and Conditions of the Tariff and
the Operating Policies and Procedures, especially as it applies to an
“Emergency”. Please provide an amended definition as required.
(c) Please explain why the AESO proposes to remove the definitions of “OffPeak” and “On-Peak”. Please clarify whether these terms are used in any
“Business Practice” documents or other documents used by the AESO to
implement the Tariff.
(d) The AESO proposes to remove the definition of Operating Reserves and
refers to the EU Act to define Ancillary Services. The definition of Ancillary
Services in the Act is broad and unspecific. Please explain how this
approach achieves the objectives of consistency, certainty and transparency.
(e) Provide a copy or reference to the “Business Practice” or other
documentation used by the AESO to identify and define the specific Ancillary
Services used by the ASEO and for which costs are to be recovered
according to s.30(4) of the Act by (i) a rate within the Tariff and (ii) an ISO
Fee.
Response:
(a) The definition and use of the term “Dispatch Instruction” in the tariff is
specific. The tariff does use the word directive which would be implied to be
the same as that in the ISO rules.
(b) The AESO believes the definition for “Emergency” in the Terms and
Conditions includes recalling any loads including DOS loads.
(c) “Off Peak” and “On Peak” are no longer defined terms contained in the terms
and conditions of service.
(d) “Operating Reserves” is defined in the AESO rules. The AESO OPPs provide
details on operating reserves requirements and dispatch.
(e) The specific Ancillary Services are determined by either a) WECC/NERC
requirements or b) AESO studies for services. All Ancillary services are
Page 2 of 2
documented in the AESO’s OPP except for black start services which are not
publicly listed for security reasons.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-072 (a)-(c)
Reference:
Application, Section 7 – Article 2 (Application of the Tariff)
Preamble:
n/a
Page 1 of 1
Request:
a) Is it the AESO’s position that the Tariff, as approved by the Board, does not
bind the AESO? Please explain why the AESO has removed this
consideration from Article 2.
b) Please provide an amended Article 2.2 that expressly (i.e. not indirectly)
conveys the AESO’s requirement to abide by the Tariff.
c) The AESO proposes to add Article 2.4, which says, “Nothing in this Tariff
shall in any way restrict or limit the powers, duties, and responsibilities of the
AESO as described in the Act.” Please explain why the addition is necessary
and provide examples of the situations in which it will be used.
Response:
a) – b) The AESO confirms that it is bound by the Tariff and will amend Article
2.2 to accord with the current approved Tariff, as shown below.
EUB Approval
This Tariff has been approved by the EUB, defines service to be delivered
by the AESO and binds all of the AESO’s Customers. This Tariff defines
the basic rights of the AESO and all its Customers with respect to all
services provided by the AESO.
c) The AESO’s powers duties and responsibilities are set out in the Act and
these extend beyond the terms and conditions of the tariff. For example,
under the Act, the AESO has the power to charge ISO Fees under section
21(1) and issue Orders pursuant to section 22(1) of the Act. In this specific
example, the intent of the addition to Article 2.4 is to ensure parties
understand that the terms and conditions of service found in the Tariff in no
way limit or restrict the AESO from exercising its Fee or Order making
powers.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-073 (a)-(b)
Page 1 of 1
Reference:
Application, Section 7 – Article 3 (Provision of System Access Service)
Preamble:
The proposed Article 3.2 states:
The AESO, at its sole discretion, may withhold, limit, or discontinue System
Access Service if the Customer fails to abide by this Tariff. If requested by the
Customer, the AESO will provide a written explanation for withholding, limiting, or
discontinuing System Access Service. Any such withholding, limiting, or
discontinuing will not relieve the Customer from its obligation to pay any rate,
charge, or other amount that has accrued, or is accruing, to the AESO.
Request:
a) What are the rights of Customers to appeal a unilateral decision to withhold
service? What process is contemplated for appealing such an action?
b) How are Customers to be assured that the AESO will apply this discretion in
a consistent and certain manner and not in an arbitrary and ambiguous
manner?
Response:
a) Customers may appeal an AESO decision to withhold service under Terms
and Conditions Article 19, Dispute Resolution.
b) Please refer to information request response FIRM.AESO-235 (b-c).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-074 (a)-(b)
Reference:
Application, Section 7 – Article 5 (System Access Application)
Preamble:
The proposed Article 5.1(a) and 5.2(a) state:
Page 1 of 1
The AESO will work cooperatively with the Distributor and the TFO to determine
the most cost effective manner to facilitate System Access Service for the
Distributor’s request for new System Access Service or for expanded System
Access Service within an existing POD.
The Customer must work with both the AESO and the TFO who will
cooperatively determine the most cost effective manner to facilitate System
Access Service.
Request:
a) Please provide the AESO’s definition of the “most cost effective manner”. Is
cost effectiveness to be defined in terms of ‘least transmission costs’, ‘least
distribution costs’, ‘least total project cost’ or other metric? Please explain.
b) Please provide an amended version of the proposed Article 5.1(a) and 5.2(a)
that expressly identifies the “cost effective” standard to be applied in these
situations.
Response:
a) The use of the term “most cost effective manner” is used in the context of
determining the best overall technical solution, which involves either
distribution or transmission or a combination of both, and taking into account
a number of engineering design and operational considerations and the costs
of the various alternatives available. The AESO feels that it is not practical to
define a “cost effective standard” when customer interconnections vary from
customer to customer. As mentioned above the AESO will review each
alternative on a technical, operational and economic basis and file a
recommendation with the Board where the merits of the application can be
tested.
b) Please refer to part (a) above
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-075 (a)-(c)
Page 1 of 1
Titles:
Reference:
Application, Section 7 – Article 5 (System Access Application)
Preamble:
The proposed Article 5.2 requires a refundable application fee for Generators,
Industrial Systems and Industrial Loads.
Request:
a) Please explain the purpose and objective of the refundable Application Fee.
b) Why are all Customers, except Distributors, required to pay an Application
Fee?
c) Is it the AESO’s position that Distributors have privileged priority access to
AESO staff as it pertains to obtaining System Access Service? Please
explain.
Response:
(a) The purpose of the refundable application fee is to ensure customers are
serious about proceeding with an interconnection. If the customer cancels
the project, the application fee will be used to offset AESO costs related to
the interconnection.
(b) The refundable application fee for industrial customers has been established
to discourage non-serious applicants from tying up AESO resources for
projects that are unlikely to proceed.
(c) No, all customers are treated with the same level of priority in regards to
system access.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-076 (a)-(b)
Page 1 of 1
Reference:
Application, Section 7 – Article 5 (System Access Application)
Preamble:
The proposed Article 5.2(b) states:
The Customer must provide the AESO with a completed Preliminary Assessment
Application and the associated fee as set out in sub-paragraph (c).
Question:
(a) Please define “Preliminary Assessment Application” and file a copy of such
application form.
(b) Please explain why the AESO has not filed the Preliminary Assessment
Application as part of the Terms and Conditions of Service.
Response:
a) The Preliminary Assessment Application is currently being developed and will
be made publicly available when completed. The Preliminary Assessment
Application is envisioned to be similar to the current Stage 1 application,
where the AESO would collect the necessary information to develop an
preliminary interconnect proposal for the customers interconnection
requirements. Please refer to Schedule.ENCANA.AESO.79 (b).
b) Please refer to part (a) above.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-077 (a)-(c)
Page 1 of 1
Reference:
Application, Section 7 – Article 5 (System Access Application)
Preamble:
The proposed Article 5.3 states:
At the sole discretion of the AESO and only in exceptional circumstances, the
Customer may proceed with the application for System Access Service through
the AESO and, in conjunction therewith, must provide the information, financial
security, and Construction Commitment Agreement required by the AESO.
[Emphasis added]
Question:
(a) What is the purpose and objective of Article 5.3?
(b) If a Customer does not “proceed with the application for System Access
Service through the AESO”, how else are they to proceed and how is this
consistent with section 17(g) of the EU Act?
(c) Please provide an amended version of Article 5.3, or other amendment to the
T&Cs, to clarify the intended purpose.
Response:
a) Article 5.3 was included in direct response to stakeholder concerns regarding
general uncertainty of transitioning to a whole new interconnection process
and having customers deal more directly with Transmission Facility Owners
(TFO’s). Stakeholders suggested alternative arrangements should be
available to ensure their interconnection request remained on track if the
customer experienced some difficulties while dealing with the TFO’s. It is
intended that this article be invoked by the AESO as a last resort with the
intent of managing the transition period between the existing and new
interconnection processes.
b) The AESO is still accountable for providing system access as per section 17
(g) of the EU Act. The customer would continue to apply for system access
with the AESO as described in Articles 5.1 and 5.2.
c) At this time, the AESO believes this article does not require an amendment.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-078 (a)-(d)
Reference:
Application, Section 7 – Article 5 (System Access Application)
Preamble:
The proposed Article 5.4 states:
Page 1 of 1
Loss Factor Calculations and Other Studies
A Customer or potential Customer that requests a preliminary loss factor
calculation (only) must complete a loss factor calculation application form and
pay the AESO a non-refundable fee of twenty-five hundred dollars ($2,500). For
additional services requested by the Customer that the AESO agrees to
perform, the Customer must pay the AESO’s actual costs to prepare and
provide the requested information. The AESO will conduct all detailed
studies in the order that payment is received.
[Emphasis added]
Question:
(a) Please define “additional services”.
(b) What is the purpose and objective of charging for “additional services”?
(c) Please explain why “additional services” are not already addressed in the
studies and considerations of Article 5.2.
(d) Please explain why Article 5.2 and 5.4 are not in conflict.
Response:
a) Additional services are technical studies which may include, but are not
limited to, scenario loss factor calculations.
b) The objective is to ensure customers have a method of obtaining technical
studies beyond a standard interconnection study from the AESO. The fee is
to ensure that the costs of these incremental studies are covered by the
applicant and not recovered from all other load customers.
c) From the AESO’s perspective these studies are special requests that are not
required to fulfill the customers interconnection request.
d) Articles 5.2 and 5.4 are not in conflict. Article 5.4 is intended to provide
customers with another option for service above and beyond a standard
interconnection study.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-079 (a)-(b)
Reference:
Application, Section 7 – Article 5 (System Access Application)
Preamble:
The proposed Article 5.6 states:
Page 1 of 1
Disputes in respect of a Customer System Application must be referred to the
AESO, in writing. The AESO will review the dispute and provide the Customer
and any other affected parties with a proposed resolution within 30 Business
Days of receipt thereof. In the event mutual agreement cannot be reached, any
of the affected parties may then enter into the Dispute Resolution process as set
out in Article 19 of this Tariff. [Emphasis added]
Question:
(a) What is the purpose and objective of Article 5.6?
(b) Please define “Customer System Application” and file a copy of such
document.
(c) Explain the fairness of having the AESO resolve a dispute to which it is a
party.
Response:
a) Article 5.6 is to provide customers with a method of managing disputes that
may arise regarding their interconnection requests.
b) Customer System Application generally refers any customers application for
system access service. Please refer to Schedule.ENCANA.AESO.079 (b) for
a copy of the existing application form.
c) It is appropriate for the customer to discuss their concerns with the AESO as
the AESO is responsible for managing the interconnection process and
application of its tariff. If the customer fails to reach a satisfactory response
to their concerns in the process outlined in Article 5.6 the customer may then
seek additional dispute resolution as set out in Article 19.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-080 (a)-(d)
Reference:
Page 1 of 2
Application, Section 7 – Article 6 (Security and Customer Agreements)
Preamble:
Question:
a) Please define “Customer Commitment Agreement” and file a copy of such
document.
b) What is the purpose and objective of the Customer Commitment Agreement?
c) What protocol, standards or criteria is the AESO to employ when determining
an amount to be provided for security by the Customer? Why is this method
not referenced in Article 6.2(a)
d) Please explain how a potential Customer is expected to understand and to
estimate its exposure for security under the proposed form of Article 6. How
does this support the objectives of consistency, certainty and transparency?
Response:
(a) “Customer Commitment Agreement” as outlined in Article 6 is an error; it
should read “Construction Commitment Agreement”, the AESO will revise the
terms and conditions accordingly. Please refer to Article 1.1 for a definition of
Customer Commitment Agreement. Please refer to
Schedule.ENCANA.AESO.080 (a) for a copy of the agreement.
(b) The purpose of the Construction Commitment Agreement is to ensure the
customer has committed to the project and agrees to be liable for all
cancellation costs of the project. Please refer to part (a) above for further
details.
(c) The amount of security requested from the customer is dependent on the
status of the construction project and if the customer has been granted and
has available unsecured credit with the AESO. If a Customer Commitment
Agreement is entered into prior to a Needs Application being approved by the
EUB, the customer is required to provide security for the estimated amount of
cancellation costs, which includes both customer and system costs, less any
customer contributions paid by the customer. When a Final Customer
Contribution Agreement is entered into after the Needs Application has been
approved, the customer’s security requirement is the estimated amount of
cancellation costs for the customer’s component only, less any customer
contribution paid by the customer. The customer may not be required to
provide security to the AESO if the customer has been granted unsecured
credit by the AESO and the customer’s total liabilities to the AESO do not
Page 2 of 2
exceed the unsecured credit limit granted by the AESO. Unsecured credit
granted to a customer is based on a customer’s unsecured long term bond
rating. The customer must have at a minimum an unsecured long term bond
rating of BBB (flat) or better from a reputable ratings agency. Note that the
security can not exceed the estimated cost of construction as per 6.2 (a).
(d) The requirements discussed in response c) are consistently applied by the
AESO to all customers. At the time of preparation of the Construction
Commitment Agreement, the customer is made aware of the estimated
customer costs, system costs and the required security. The security
requirements are attached as Appendix B to the Construction Commitment
Agreement. Please refer to part (a) above for further details.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-081 (a)
Page 1 of 1
Reference:
Application, Section 7 – Article 8 (Provision of Information by Customers)
Preamble:
Section 8.3 states:
Failure to provide any other information reasonably requested by the AESO will
result in the AESO making application for approval of information sharing
arrangement pursuant to the Act and seeking to recover 100% of the actual
costs of pursuit of its application from the Customer whose actions necessitated
the application. [Emphasis added]
Question:
(a) Explain the “information sharing arrangement” and the authority under the Act
to make such arrangements. To whom will the AESO apply for such
arrangement.
Response:
a) The AESO has reviewed Section 8.3 and has determined that the proposed
wording was as provided in previous terms and conditions and may no
longer by mentioned in the amended Act. As such the AESO considers the
following amendment to be appropriate:
“Failure to provide information that ma have an impact on safety or
system security will result in suspension, termination or delay of System
Access Service until such time that the information is provided to the
AESO.”
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-082 (a)-(f)
Page 1 of 2
Reference:
Application, Section 7 – Article 9.3(b)(iii) ;
Preamble:
The proposed Article 9.3(b)(iii) states:
Radial transmission extensions if the transmission development plan (as that
plan exists on the date the project is Commissioned) proposes that the Radial
transmission extension becomes Looped within five years. The Customer will pay
the cost of advancing that part of the project from the date established in the
transmission development plan, calculated as the difference between the present
values of the capital costs of the advanced and as-planned projects using the
discount rate as determined under Article 9.9; and
Question:
a) If the Customer Contribution Policy (and Maximum investment) pertains
solely to the costs of local interconnection explain why the advancement of
system-related costs should be attributed to the customer.
b) Does the AESO agree that a tariff is uncertain and ambiguous if it cannot be
applied?
c) Please confirm that the AESO’s recently released 10 Year Plan (2005-2014
Transmission System Plan) does not establish specific target dates for the
development of transmission facilities. If this cannot be confirmed, provide a
list of the projects identified in the 10 Year Plan along with target in-service
dates.
d) Given the new approach to transmission development arising from the
Transmission Development Policy and the Transmission Regulation, can it be
said that a transmission facility development should not be developed before
a defined target date.
e) Is the discrepancy between the “target date” in the 10 Year Plan and the inservice date requested by the Customer due solely to the situation that the
AESO is unaware of the Customer’s interconnection requirement when it
prepares the Plan? If the AESO knew of the Customer’s request when
preparing the Plan, would the Plan reflect the earlier in-service date?
f)
Does the AESO agree that the proposed Article 9.3(b)(iii) is stale and
inconsistent with the Transmission Development Policy. If not, explain.
Response:
a) If system facilities have been identified and required for a specific future date,
but were advanced into service by the interconnection of a particular
customer, the carrying charges for these facilities have been pressed into
Page 2 of 2
service prior to their anticipated need and should not be funded by the
Alberta rate payer.
b) No. A tariff may be certain and unambiguous and may still be unable to be
applied for other reasons, for example due to a conflict with legislation.
c) Confirmed
d) The development of system facilities as outlined in the Transmission System
Plan is a representation of the anticipated need for such facilities over a 10
year period. The proposed target development dates as outlined in the Plan
may fluctuate from time to time with the change in load or generation
development throughout the province. There may be cases where the
expected load or generation projects may come on line earlier or later than
anticipated. The AESO develops the Plan with the best information it has
available and will revise that information as required by the Transmission
Regulation.
e) Please refer to part (d) above
f)
The AESO suggests the clause could be applicable in some circumstances
and should be retained. The AESO will review the application of Article 9.3
(b) (iii) and may recommend further revisions at the next GTA.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-083 (a)-(c)
Page 1 of 2
Reference:
Application, Section 7 – Article 9 (Customer and System Contribution Policy)
Preamble:
The proposed Article 9.3(b)(iv). states:
Where, in the sole opinion of the AESO, economics or system planning dictate
that a facility larger than that required to serve the Customer is to be installed,
then the AESO will classify that portion of the project deemed to be in excess of
the Customer’s needs as system-related costs. As the need to serve additional
POCs arises, these system-related costs may be reclassified as Customerrelated costs and allocated to the new Customers. The capacity between the
Customer’s requirements and the minimum size of facilities required to serve the
Customer is not considered to be in excess of the Customer’s requirements.
[Emphasis added]
Question:
(a) Provide some examples of situations in which excess facilities could be
classified as “system-related” and subsequently reclassified as “customerrelated”.
(b) When excess facilities are reclassified to Customer-related costs, is it the
intention of the AESO to increase the Customer Contribution amount payable
to the AESO? Is the answer the same regardless of the period since the
customer interconnection?
(c) If the answer to b) is yes, explain how this is fair.
Response:
a) Situations where system-related costs subsequently reclassified as customer
–related costs may include:
 Based upon current and future interconnecting customer capacity
requirements the AESO determines for economic reasons that a greater
circuit size should be installed for the expected customer project but it
exceeds the current interconnecting customers requirements or,
 Based upon current and future interconnecting customer capacity
requirements the AESO determines that for economic reasons that
higher capacity telecommunication equipment should be installed for
the expected customer project but it exceeds the current
interconnecting customers requirements
b) If the system-related costs were in anticipation of a specific customer project
and for economic reasons installed prior to that customers interconnection,
the reclassified costs would become part of their overall customer-related
Page 2 of 2
costs for interconnection. The customer contribution would increase if
investment was not available to cover the costs.
c) If the reclassified costs can be directly attributable to the new customer, then
that is a cost of their local interconnection and should become part of their
customer-related costs. This ensures all customers are treated in the same
manner, as each customer will be responsible for the cost of their
interconnection.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-084 (a)-(d)
Page 1 of 2
Reference:
Application, Section 7 – Article 9 (Customer and System Contribution Policy)
Preamble:
The proposed Article 9.5(b) states:
The AESO will not consent to such waiver for any portion of a transmission
expansion project that is attributable to the requirements of one or more single
end-use sites each with a load of 2 MW or greater, or an identifiable group of
end-use sites with a single owner (including Affiliates) with an aggregate load of
2 MW or greater, where such site(s) are served by the Distributor. In such cases,
where a portion of the project can be attributed to multiple end-use sites served
by the Distributor, the AESO will prorate the Customer Contribution in proportion
to the loads of the single, group, and multiple end-use sites accordingly.
[Emphasis added]
Question:
a) Why has the AESO selected 2 MW as the cut-off point for retaining or
rejecting a waiver?
b) How far past the POD, and deep into the distribution system, will the AESO
look to determine whether the new POD is “attributable to the requirements of
one or more single end-use sites”? How will the AESO obtain this
information?
c) Consider a situation in which a Distribution utility has requested a new POD
to serve a 5MW capacity and it costs $10MW. For each of the following
scenarios explain the application of the waiver and the levy of a contribution:
i)
3MW disco load, 2MW single owner load;
ii)
3MW disco load, 1MW single load (owner A), 1MW single load (owner
B) where owners A and B are independent of each other;
iii)
1.1 MW disco load, 1.9 MW single load (owner A), 1MW single load
(owner B); and
iv)
1MW disco load, 2 MW single load (owner A), 2 MW single load (owner
B).
d) To whom will the AESO directly charge the contribution in each of the above
scenarios?
Response:
a) Please refer to CITIES.AESO-011(a).
Page 2 of 2
b) Please refer to CITIES.AESO-011(g). As suggested in Article 9.5 the DFO is
responsible providing the necessary information to qualify for the waiver.
c) Given a 20 year contract term, $10m project costs and assuming that the
single loads in question are customers of the distribution utility; the AESO’s
maximum investment in the situation described would be $2.7 million,
resulting in a $7.3 million Customer Contribution. Assessment of this
contribution for each of the examples is shown below.
i. Waiver for multiple-user POD = $7.3 million x 3/5, or $4.4 million;
residual contribution of $2.9 million levied to the distribution utility.
ii. Waiver for multiple-user POD = $7.3 million x 5/5, or $7.3 million; no
contribution levied.
iii. Please note that the total load in this example only adds up to 4 MW.
The AESO maximum investment would be reduced to $2.2 million, with
a $7.8 million contribution. The 4 MW load at the POD would be
considered to be multiple-user and the waiver would apply to the entire
contribution amount; no contribution would be levied.
iv. Waiver for multiple-user POD = $7.3 million x 1/5, or $1.5 million;
residual contribution of $5.8 million levied to the distribution utility.
d) Direct charges of any contribution amounts not waived will be made to the
distribution utility in all case
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-085 (a)-(b)
Page 1 of 1
Reference:
Application, Section 7 – Article 9 (Customer and System Contribution Policy)
Preamble:
The proposed Article 9.11 states:
The AESO reserves the right to exercise its discretion, acting reasonably, in the
application of the contribution policy. [Emphasis added]
Question:
(a) Throughout the proposed Article 9, the AESO reserve the right to make
decisions “in the AESO’s sole opinion”. Does the AESO agree that the
requirements of Article 9.11, which compels the AESO to act reasonably,
applies to all facets of the proposed Article 9, including those times when the
AESO acts in accordance with its “sole opinion”? If not, explain why.
(b) Please explain the Customer’s rights to appeal a decision based on the
AESO’s use of its discretion. When can it happen? What process and to
whom can a Customer appeal?
Response:
a) Agreed
b) Customers may choose to enter dispute resolution as outlined Article 19 of
the AESO’s terms and conditions of service. If the customer is still not
satisfied they may engage the EUB for resolution.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-086 (a)-(b)
Page 1 of 1
Reference:
Application, Section 7 – Article 9 (Customer and System Contribution Policy)
Preamble:
The proposed Article 9.12(a) states:
The discount rate applicable to payments due under this Article will be
determined as follows:
(a) For unassigned transmission facilities, for transmission facilities supplied to
the AESO by an investor owned Transmission Facility Owner or for facilities
supplied to the AESO by an income tax paying municipally owned
Transmission facility Owner:
{[0.67 × (GCB + 1%)] + (0.33 × 9.50%)} ÷ (1 – T)
where GCB is equal to the yield on 30-year Government of Canada bonds
and T is equal to combined federal and provincial income tax rate for investor
owned TFOs.
Request:
(a) Besides the advancements costs calculation of 9.3(b)(iii), what other
payments require the use of a discount rate?
(b) Please confirm that it is inappropriate to include the “{ }“ brackets in the above
formula since debt costs are not taxable income? Please provide a corrected
formula.
Response:
(a) As explained by the AESO on pages 12-14 of section 6 of its Application, the
AESO anticipates the discount rate will only be used in cost of advancement
calculations.
(b) Confirmed. Please refer to Information Response TAC.AESO-005 (b).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-087 (a)-(c)
Page 1 of 1
Reference:
Application, Section 7 – Article 10 (Demand Opportunity Service)
Preamble:
The proposed Article 10.1 states:
To qualify for Demand Opportunity Service, the Customer must meet the
commercial eligibility criteria and submit the required applications as set out in
the Demand Opportunity Service Business Practices. The AESO must be
satisfied that the Customer’s use of the Demand Opportunity Service would not
proceed on any other applicable rate. [Emphasis added]
Question:
(a) Please explain and file a copy of the “commercial eligibility criteria” for DOS
service.
(b) Please explain why the eligibility criteria are not proposed to be part of the
approved tariff.
(c) Please explain how the exclusion of the eligibility criteria fosters the
objectives of consistency, certainty and transparency.
Response:
a) The commercial eligibility criteria is identified within Appendix A of the AESO
DOS Business Practices (please refer to Schedule.ENCANA.AESO.087 (a))
and outlines the criteria used to determine: 1) Economic Qualification, 2)
Opportunities That Can Qualify For DOS and 3) Circumstances That Do Not
Qualify For DOS.
b) Please refer to information request response ENCANA.AESO-070 (h)
c) Please refer to information request response ENCANA.AESO.070 (i)
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-088 (a)-(e)
Page 1 of 1
Reference:
Application, Section 7 – Article 10 (Demand Opportunity Service)
Preamble:
The proposed Article 10.2 states:
In conjunction with the DOS Stage 2 application, which must be submitted at
least 30 days prior to taking Demand Opportunity Service, the Customer must
pay a non-refundable $5,000 fee to the AESO for evaluation of the Customer’s
commercial eligibility for DOS. [Emphasis added]
Question:
a) Please define a “DOS Stage 2 application” and provide a copy of such
application.
b) Does a Customer have to pay the non-refundable $5,000 fee each time it
requests DOS service?
c) Please explain how the AESO arrived at a fee amount of $5,000.
d) For what duration of time is the evaluation valid?
e) Does the AESO agree that when a DOS load uses the system, all other
customers benefit from the incremental revenue that is used to offset the
base revenue requirement? If not, explain.
Response:
a) The DOS Stage 2 Application (please refer to Schedule.ENCANA.AESO-088
(a)) is the formal application by a potential user of DOS to request that the
AESO grant them pre-qualified status. The receipt of such status will enable
the user the ability to make a request to the AESO system controller to use
DOS.
b) The non-refundable $5,000 fee is specific to the AESO review of the Stage 2
application and does not apply to the ongoing use of DOS.
c) The fee is based on the average level of resources that are required by the
AESO in order to conduct an assessment of the Stage 2 application. It is
intended to function as only a cost recovery mechanism.
d) The pre-qualification period is valid up to the lesser of one-year or the length
of time DOS is required by the customer.
e) Yes, the AESO agrees with this position.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-089 (a)-(b)
Reference:
Application, Section 7 – Article 13 (Contract Capacity Allocation)
Preamble:
n/a
Page 1 of 1
Question:
a)
Please confirm that Articles 13.1, 13.2 are new additions to the Terms
and Conditions. If not explain.
b)
What is the purpose and objectives of Article 13.1?
c)
What rights and responsibilities fall on a Customer when the AESO
“Allocates Contract Capacity”, especially as it relates to real-time
management of congestion or constraints to the transmission system?
d)
What is the purpose and objectives of Article 13.2?
Response:
a) The AESO confirms that Articles 13.1 and 13.2 are new additions to the
Terms and Conditions.
b) Please refer to BR.AESO.044(a).
c) Customer responsibilities in respect of Capacity Allocation are set out in
Article 13 and in particular, Article 13.2 Requirement of Customer to Act.
Customers have the right to expect the AESO to act in a fair and consistent
manner, in accordance with the Terms and Conditions. Customers also have
the right to enter into a dispute resolution in accordance with Article 19.
d) Please refer to BR.AESO.044(a) and ALPAC.AESO.004 (g).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-090 (a)-(c)
Page 1 of 2
Reference:
Application, Section 7 – Article 14 (Reductions or Termination of Contract
Capacity)
Preamble:
The proposed Article 14.2 states:
Reductions of Contract Capacity at a POD or a POS will be made five years after
receipt of written notice from the Customer. The Contract Capacity immediately
following the five year notice period will be the maximum of:
(a) the pre-notice Contract Capacity less the reduction of Contract
Capacity requested by the Customer; or
(b) the highest Metered Demand during the five year notice period
less the reduction of Contract Capacity requested by the Customer.
Separate written notice must be provided for increases and reductions of
Contract Capacity at each respective POD and POS at a single
transmission station; no net reductions will be accepted or effected.
[Emphasis added]
.
Request:
a) Please explain why Article 14.2 is based on the highest Metered Demand
during the five year notice period when the DTS ratchet will be reduced to a
24 month period.
b) Please explain the relationship between the DTS ratchet and the five year
notice period in Article 14. Please provide numerical examples to illustrate the
purpose and application of each provision.
c) Please explain the meaning of “no net reductions” and provide a numerical
example to illustrate the meaning.
Response:
a) The DTS ratchet is a short term cost recovery tool, which recovers costs from
customers that use transmission facilities in excess of their contracted
capacity. The five year notice period on the other hand allows the AESO to
effectively plan the transmission system. To conduct effective system
planning, the AESO requires a clear understanding of how the system is
being used. The highest Metered Demand during the five year notice period
provides a more accurate view of the customers use and impact on the
system in that area.
b) Please refer to the table below.
Page 2 of 2
Notice Period
Scenario
Contract Capacity:
10 MW
Reduced Contract
Capacity (reduced
by 10MW): 0 MW
Previous 12 month
Highest Metered
Demand: 11 MW
Peak Demand
during notice
period: 8 MW
Contract Capacity:
10 MW
Reduced Contract
Capacity (reduced
by 10MW): 0 MW
Previous 12 month
Highest Metered
Demand: 11 MW
Peak Demand
during notice
period: 12 MW
Billing Capacity at
End of Notice
Period - DTS
Ratchet
Billing Capacity
Billing Capacity
Billing Capacity
First 11 months
Remaining
13 months
60 months
9.9 MW
9 MW
0 MW
(a) highest metered
demand:8 MW
(b) 90% of 10 MW
Contract Capacity:
9MW
(c) 90% of 11 MW 12
month peak: 9.9 MW
(a) highest metered
demand:8 MW
(b) 90% of 10 MW
Contract Capacity:
9MW
(c) 90% of 8 MW 12
month peak: 7.2 MW
First 11 months
Remaining
43 months
Remaining
6 months
24 months
9.9 MW
9 MW
12 MW
2 MW
(a) highest metered
demand:8 MW
(b) 90% of 10 MW
Contract Capacity:
9MW
(c) 90% of 11 MW 12
month peak: 9.9 MW
(a) highest metered
demand:8 MW
(b) 90% of 10 MW
Contract Capacity:
9MW
(c) 90% of 8 MW 12
month peak: 7.2 MW
(a) highest metered
demand:12 MW
(b) 90% of 10 MW
Contract Capacity:
9MW
(c) 90% of 8 MW 12
month peak: 7.2 MW
(a) pre-notice
contract Capacity
(10MW less
10MW)=0
(b) notice period
peak metered
demand (12MW less
10 MW)=2MW
(a) pre-notice
Contract Capacity
(10MW - 10MW)=0
(b) notice period
peak (8MW-10
MW)=0
c) At dual use sites the AESO requires clear delineation of the POD and POS
change in contract capacity not a cumulative amount. For example:
Current POD Contract Capacity:
Current POS Contract Capacity:
Proposed increase in POD Contract Capacity:
Proposed increase in POS Contract Capacity:
10 MW
20 MW
5 MW
5 MW
The notification must note for the existing POD, 10MW plus the incremental 5
MW and for the POS the existing 20 MW plus the incremental 5 MW not a
cumulative 10MW figure.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-091 (a)-(b)
Page 1 of 1
Reference:
Application, Section 7 – Article 14 (Reductions or Termination of Contract
Capacity)
Preamble:
The proposed Article 14.3 states:
Customers that wish to terminate their System Access Service Agreements may
choose to pay out the Contract Capacity as a lump sum payment.
Request:
(a) Please explain the meaning of “pay out the Contract Capacity”.
(b) What amounts does a Customer have to “pay out” in addition to the DTS
ratchet and any applicable Customer Contribution amount?
Response:
a) – b) Please refer to BR.AESO.46
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-092 (a)
Page 1 of 1
Reference:
Application, Section 7 – Article 14 (Reductions or Termination of Contract
Capacity)
Preamble:
The proposed Article 14.4 states:
At least once per year, the AESO will review the Contract Capacity of STS
customers. The AESO may reduce a customer’s STS Contract Capacity to:
(a)
The mean metered power delivered to the AIES in the preceding
twelve (12) months; or
(b)
For low capacity factor generators, the mean metered power
delivered to the AIES over recurrent periods that are shorter than twelve
(12) months, as determined by the AESO
if such deliveries are more than 10% below the existing Contract Capacity
or as mutually agreed between the Customer and the AESO.
Request:
a) What is the purpose and objectives of Article 14.4?
Response:
a) The AESO may rely on Article 14.4 to encourage Customers to release
unused Contract Capacity for use by other Customers. Article 14.4 (formerly
Article 15.4) has not changed from the current approved Terms and
Conditions.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-093 (a)-(c)
Page 1 of 1
Title:
Reference:
Application, Section 7 – Article 15 (Financial Security, Billing and Payments
Terms)
Preamble:
The proposed Article 15.3(e) states:
The AESO may, but is not required to, deduct from the Statements of Account
any amounts owing by the AESO to the Customer or its Affiliates.
Request:
(a) Please confirm that the proposed Article 15.3(e) is a new addition to the
Terms and Conditions.
(b) What is the purpose and objective of Article 15.3(e)?
(c) Please explain why the AESO is proposing to co-mingle Statements of
Account between Affiliates. What useful purpose does this serve that is not
already achieved elsewhere in the Tariff?
(d)
Response:
a) Article 15.3(e) is not a new addition to the Terms and Conditions. The
concept of deducting any amounts owing by the AESO to the Customer or its
Affiliates is found in the current General Tariff Agreement under Article 10.1.
b) The purpose and objective of the references to Affiliates referenced in 15.3
(e) is to ensure the AESO does not preclude any netting options available to
the AESO, which will allow the AESO, and its customers, to remain financially
whole should a customer default on its obligations to the AESO.
c) The AESO is not proposing to co-mingle Statements of Account between
Affiliates except in situations as discussed in (b) above.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-094 (a)-(d)
Page 1 of 2
Reference:
Application, Section 6.5, p.37 of 42; Section 7, Article 3.2 (Application of Tariff)
Preamble:
The Application states:
Provision of System Access Service (Article 3, Previously 3) — The list of
specific Articles under which the AESO reserves the right to withhold, limit, or
discontinue service has been amended to provide such right where the Customer
does not abide by the Tariff in its entirety. This change has been made to accord
with the AESO’s provision of service in Article 3.1, which relies on a similar level
of compliance. (p [Emphasis Added]
The proposed Article 3.2 states:
The AESO, at its sole discretion, may withhold, limit, or discontinue System
Access Service if the Customer fails to abide by this Tariff. If requested by the
Customer, the AESO will provide a written explanation for withholding, limiting, or
discontinuing System Access Service. Any such withholding, limiting, or
discontinuing will not relieve the Customer from its obligation to pay any rate,
charge, or other amount that has accrued, or is accruing, to the AESO.
Request:
a) Please explain the breadth of the AESO’s right to terminate System Access
Service. For example, if a Customer has failed to abide by the Tariff, does
the AESO expect that it has the right to terminate Service at only the POD or
POS that gave rise to the aberrant situation, or that it has the right to
terminate Service at any and all of the Customer’s PODs or POSs?
b) Please explain why the right to terminate does not contain an express
condition of materiality.
c) Please confirm that according to the proposed Article 3.2, the AESO would
have the right, at its discretion, to withhold, limit or discontinue System
Access Service if the Customer failed to, for example, include all of the listed
items under Article 19.1 when submitting a written dispute to the AESO. If
not explain.
d) Does the AESO agree that any actions it takes under Article 3.2 should be
qualified by a requirement of “reasonableness”? If yes, provide an amended
version of Article 3.2 that includes the qualification that the AESO must “act
reasonably”. If not, explain.
Response:
Page 2 of 2
a) With the exception of non-payment for amounts due the AESO, the AESO
confirms that it will consider withholding service only in respect of the POD or
POS that gives rise to the aberrant situation.
b) The tariffs terms and conditions of service are intended to provide clarity and
consistency in its application and inserting materiality thresholds would create
a level of ambiguity that inconsistent with the intent of the tariff.
c) Although the AESO cannot conceive of a circumstance where it would rely on
Article 3.2 to enforce Article 19.1 as suggested, the AESO acknowledges that
Article 3.2 does provide such rights.
d) Please refer to Information Request Response FIRM.AESO-235 (b-c).
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ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
ENCANA.AESO-095 (a)-(f)
Reference:
Page 1 of 2
Application, Section 6.5, p.42 of 42;
Preamble:
The Application states:
Deleted Appendices (Previously A, B, and C) — The AESO proposes to delete:
 Appendix A — Intentionally left Blank;
 Appendix B — System Access Service Agreement Proformas; and
 Appendix C — Construction Commitment Agreement Proforma.
The deletion of the agreement proformas will enable on-going, non-material
changes to these agreements without the time and expense of gaining regulatory
approval. The AESO will make such agreement proformas available to
customers upon request.
Request:
a) Does the AESO agree that the System Access Service Agreement (SASA) is
an integral part of the AESO tariff? If not, explain.
b) Does the AESO agree that the Construction Commitment Agreement (CAA)
is an integral part of the AESO tariff? If not, explain.
c) Please provide a copy of the SASA and the CCA.
d) Is the AESO opposed to the Board approving either or both of the SASA or
CCA? If yes, explain why.
e) Is the sole reason for removing the SASA and CAA from the Terms and
Conditions related to the regulatory burden associated with minor editing or
revising of these documents? If not, explain the other reasons.
f)
Explain why the AESO has not sought relief to file revisions of the SASA and
CCA for minor edits with the Board for information purposes and thence to
address any concerns on a complaints basis.
Response:
a) – b) The AESO agrees that the System Access Service Agreements (SASA)
and the Construction Commitment Agreement (CCA) are both important
documents. For instance they set out the logistics of system access service
(location, capacity, contribution, and notice provisions), financial security for
Page 2 of 2
transmission interconnection costs and trigger mechanisms for customer
commitment with regards to capacity allocation as per Article 13. But all the
circumstances outlined above rely on reference and detailed explanation from
the AESO’s Tariff. The AESO feels the relative importance or intent of these
documents diminish if they are removed from the tariff.
c) Please refer to Schedule.ENCANA.AESO.095 (c)
d) No, the AESO is not opposed to Board approval of either agreement so long
as this approval does not unduly impact customers.
e) Please refer to BR.AESO.043
f)
Please refer to Br.AESO.043
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