ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005 General Tariff Application (1363012)
Friday, February 25, 2005
TAC.AESO-001 (a-g)
Page 1 of 3
Reference:
Study of Reactive Power, Application, p. 206
Preamble:
Producing VARs in Alberta units causes increased losses. The Calgary Area
Reactive Power Supply Reinforcement Application (Application No. 1371621)
proposes to add only enough MVARs to provide voltage stability at the load.
Request:
(a) Load flow case N1A-1 of the Edmonton-Calgary 500 kV Transmission
Development Need Application (Application No. 1346298) indicates that
voltages drop about 17kV between the thermal plants west of Edmonton and
the Calgary busses. Line losses appear to be in the order of 75 MW on the
N/S circuits in that study. What system loss reduction would be achieved if
the Calgary 240kV system could have been configured to have a 3 % higher
voltage than that shown for that same study, through either:
i.
the addition of high voltage capacitor banks at optimal locations in or
around the City of Calgary?
ii. power factor improvement of loads or, alternatively, distribution substation
capacitors?
(b) What quantity of capacitance would be necessary in each of (i) and (ii) in (a)
above?
(c) Assuming 1000 MW of load in the City of Calgary, what load factor
improvement would achieve the voltage increase posited in (a) above?
(d) What incentives currently exist, in the AESO tariff or otherwise, for loads or
DFOs to minimize VAR consumption and thereby contribute to loss
reduction?
(e) What new incentives could, in the view of the AESO, be created through the
AESO tariff, or otherwise, to provide such an incentive to loads or DFOs?
Please be specific as to form, cost and potential benefit of each such
incentive described.
(f) What incentive is there for a TFO to minimize losses under current tariff and
other arrangements?
(g) What new incentives could, in the view of the AESO, be created through the
AESO tariff, or otherwise, to provide such an incentive to TFOs? Please be
specific as to form, cost and potential benefit of each such incentive
described.
Page 2 of 3
Response:
(a) i.
To achieve a 3% higher pre-contingency voltage for Case N1A-1, about
450 MVAr of capacitors is required in the Calgary area – assuming that
they are connected to the Sarcee and Janet 240 kV buses. The total
system losses for this case would be reduced by about 13 MW as
compared to the N1A-1 case.
ii. To achieve the same voltage improvement as described above, the power
factor for loads in the City of Calgary must be improved from 0.925 to 0
.995. The total system losses for this case would be reduced about
15 MW as compared to the N1A-1 case.
(b) In (i), about 450 MVAr of capacitance would be necessary.
In (ii), about 440 MVAr of capacitance would be necessary.
(c) Assuming the system load in the City of Calgary load is at the 1000 MW level,
the voltage increase posited in (a) above would be achieved without load
factor improvement due to the fact that the power demand in the Calgary
area in Case N1A-1 was 1378 MW.
(d) The Other System Support Services Charge of both the current and proposed
DTS rates includes a power factor deficiency charge of $400/MVA applied to
the difference between the highest metered apparent power (measured in
MVA) and 111% of the highest metered demand (measured in MW) during
the same billing period. A customer minimizes the difference between
apparent power and metered demand by minimizing VAR consumption.
(e) There are many possible ways to increase prices to customers for VAR
consumption, which would presumably be considered as incentives to lower
such consumption. Possibilities include charges for demand measured in
MVA instead of MW, direct charges for VARs consumed, and power factor
deficiency charges for any difference between apparent power and metered
demand. Other less direct incentives could include subsidization of the
installation of capacitance and high power factor equipment by customers.
The current power factor deficiency charge in the DTS rate reflects traditional
tariffs in Alberta which have not penalized power factors above 90%, and the
AESO has not conducted any specific analysis of additional incentives.
(f) There are presently no explicit incentives for TFOs to minimize transmission
system losses under the current TFO tariffs. The AESO notes that the
relationship between the AESO and the TFO is defined in the TFOs’ tariffs,
also approved by the AEUB, and not the AESO’s tariffs applicable to system
access service customers. Transmission losses are impacted by the
configuration of the transmission system, operating voltages and other
related parameters, and by load and generation patterns on the system at
each moment in time. As the AESO is responsible for the planning of capital
additions to the transmission system as well as overseeing the day to day
voltage dispatch of the transmission system, the AESO sees limited
opportunity for TFOs to materially affect transmission system losses and thus
warrant the development of a specific incentive plan focused on this result.
The AESO considers transmission losses savings as a key component in
planning transmission system reinforcements and additions, and has also
2
Page 3 of 3
been supplementing the capability of the System Coordination Centre to
improve the ability to optimize voltage profiles and thus manage transmission
system losses more effectively.
(g) Please refer to part (f) above.
3
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005 General Tariff Application (1363012)
Friday, February 25, 2005
TAC.AESO-002 (a-h)
Reference:
Page 1 of 4
Application, p. 194:
“… the AESO is in the process of studying the interconnection transfer limits
based on the system additions and changes that have occurred over the past few
years. Completion of that study is a pre-requisite to studying the system for
possible generator out-of-merit dispatch volumes that may create additional
export ATC. As stated earlier, it is only the Calgary area generators that are likely
to be able to create additional export ATC through out-of-merit dispatch. The
AESO considers that for the suggested service to be effective at facilitating
export of in-merit generation, the amount of out-of-merit generation required to
increase export capabilities must be far less than the amount of incremental
export capability created. While these scenarios have not been studied, the past
trends observed by the AESO in preparation of operational studies have led the
AESO to conclude that unfortunately, the ratio is approximately 1:1, or,
expressed differently, an incremental MW of Calgary generation dispatched outof-merit only increases the export capability by approximately 1 MW. In effect,
the Calgary area generation is only creating enough export capability for that
energy in turn to be exported.
Given these issues, the AESO concludes that an open offer to dispatch out-ofmerit generationto create additional export capability is not reasonable at this
time. However, the AESO has been contacted by Calgary area generation
interested in exporting that generation, when it is out-of-merit, over the
incremental export capacity the generation could create. The AESO will explore
this issue on a case-by-case basis, but is not proposing to change the existing
opportunity rates in this application.”
Preamble:
At times the price differential between Alberta and the BC / PACNW markets is
substantial, but sufficient export capability does not always exist. The AESO has
an obligation to restore export capabilities to path rating levels. North / South
transmission constraints are a part of the current problem. Until there is enough
additional MVAR support in the Calgary area that steady state voltage stability
ceases to be a binding export capacity constraint, each MVAR added in the
Calgary area increases the N/S transfer capability by 1 MW. TMR is, according to
the above passage from the Application, not the solution. Meanwhile, TMR needs
are increasing pending upgrade of the N/S path. TransAlta wishes to explore the
extent to which TMR costs could be reduced, while export / import capability
restored, through other means.
Request:
(a) What order of magnitude of TMR cost reduction could be achieved as a result
of the increased N/S transfer capability posited in TAU.AESO-001 (a)(i) and
(ii), respectively, by the high voltage capacitor bank additions and power
factor improvements of loads / distribution station capacitors there
considered?
Page 2 of 4
(b) What effect on increased export capacity through the B.C. Tie would the
AESO anticipate to occur through the increased N/S transfer capability
posited in TAU.AESO-001 (a)(i) and (ii), respectively, by the high voltage
capacitor bank additions and power factor improvements of loads /
distribution station capacitors there considered?
(c) The addition of the N/S facilities currently proposed by means of the 500 KV
Transmission System Reinforcement Edmonton – Calgary Area Need
Application (Application No. 1346298) will, when installed, only partially
restore the capability to use the B.C. Tie export path ratings. What studies
has the AESO performed with respect to the ability of increased N/S transfer
capability posited in TAU.AESO-001 (a)(i) and (ii), respectively, by the high
voltage capacitor bank additions and power factor improvements of loads /
distribution station capacitors there considered, to be part of the means to
achieve full restoration of the capability to use the B.C. Tie export path
ratings?
(d) What incentives currently exist, in the AESO tariff or otherwise, for loads or
DFOs to minimize TMR requirements on the system?
(e) To the extent that the current incentives as per (d) arise solely from the level
of ancillary services costs in DTS charges, what examination has the AESO
performed as to costs of further high voltage capacitor banks and/or power
factor improvements of loads / distribution system capacitors versus ancillary
services costs savings?
(f) What new incentives could, in the view of the AESO, be created through the
AESO tariff, or otherwise, to provide incentive to loads or DFOs to reduce
TMR need on the system? Please be specific as to form, cost and potential
benefit of each such incentive described.
(g) What incentive is there for a TFO to minimize TMR needs under current tariff
and other arrangements?
(h) What new incentives could, in the view of the AESO, be created through the
AESO tariff, or otherwise, to provide such an incentive to TFOs? Please be
specific as to form, cost and potential benefit of each such incentive
described.
Response:
(a) The requirement for TMR in the Calgary area is based on pre and post
contingency reactive requirements to maintain a sufficient voltage stability
margin. The level of reactive reinforcements posited in TAU.AESO-001 (a)(i)
and (ii) are similar to the 520 MVAr proposed by AESO for 2005. With this
level of reactive support, TMR requirements to maintain voltage stability in
the Calgary area should be reduced to zero to at least the summer of 2007.
(b) With the high voltage capacitor bank additions or the power factor
improvements posited in TAU.AESO-001 (a)(i) and (ii) respectively, the B.C.
Tie export capacity at the peak demand periods can be increased up to 700
MW. This is the maximum level permitted on the BC Tie to prevent over
frequency in Alberta following the loss of that tie. However, it should be noted
2
Page 3 of 4
that the thermal capability of the north-south lines may limit the ATC of the
BC Tie to a lower level.
(c) All of the studies performed for Application No. 1346298 included the addition
of sufficient reactive resources to satisfy the voltage stability margins of the
planning criteria. As such, high voltage capacitor bank additions are
considered in all studies to be "part of the means" to achieve full restoration
of the capability to use the B.C. Tie export path rating.
No studies have yet been completed to determine the impact of the capacitor
bank additions in Calgary to the existing OPP which set the limits for exports
to B.C.
As stated in Application No. 1346298, north-south transfer capability is
constrained by the thermal limits on the existing lines once the voltage
stability constraint has been removed. Furthermore, unless some form of
generation rejection scheme is implemented the 700 MW limit related to over
frequency concerns will still apply.
(d) The current AESO tariff recovers TMR costs as a percentage of pool price,
which the Ancillary Services Cost of Service Study (included as Appendix C
to the AESO’s 2006 GTA) concluded was an inappropriate approach. The
AESO’s proposed tariff recovers TMR costs as a flat usage ($/MWh) charge,
which is more reflective of the manner in which TMR costs are incurred as
discussed on page 13 of section 4 of the Application. With recovery of TMR
costs as a flat usage charge, customers are encouraged to minimize TMR
requirements on the system at all times.
(e) As discussed in part (c) above, studies performed by the AESO include the
addition of reactive resources. The costs of such resources, when
implemented, would be appropriately included in and recovered through the
AESO tariff.
(f) As explained in the Ancillary Services Cost of Service Study, TMR costs are
tied to a combination of hourly gas prices, pool prices, heat rate, and output.
Providing a direct incentive to customers to reduce TMR need on the system
would be complex. The AESO has instead proposed recovery of TMR costs
through a flat usage charge, which generally aligns with cost incurrence and
provides a clear price signal to customers. The AESO has not conducted any
specific analysis of additional incentives that may be possible but at the same
time impractical.
(g) Similar to the AESO’s response to TAU.AESO-001 (f) regarding transmission
losses, there are presently no explicit incentives for TFOs to minimize TMR
costs under the current TFO tariffs. The AESO notes that the relationship
between the AESO and the TFO is defined in the TFOs’ tariffs, also approved
by the AEUB, and not the AESO’s tariffs applicable to system access service
customers. TMR costs are impacted by the configuration of the transmission
system and by load and generation patterns on the system at each moment
in time. As the AESO is responsible for the planning of capital additions to the
transmission system as well as overseeing the day to day operation of the
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Page 4 of 4
transmission system, the AESO sees limited opportunity for TFOs to
materially affect TMR costs and thus warrant the development of a specific
incentive plan focused on this result. The AESO considers the viability of
TMR arrangements and associated costs in planning and operating decisions
on a case-by-case basis and also, on a going forward basis, the conditions
placed on use of TMR through the Transmission Development Policy and the
Transmission Regulation.
(h) Please refer to (g) above.
4
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
February 25, 2005
TAC.AESO-003 (a-d)
Page 1 of 1
Reference:
Application Section 9, page 24, AESO 2003 Negotiated Settlement Agreement,
Item 3, Paragraph 23.
Preamble:
Among the items on Appendix 4 of the 2003 Negotiated Settlement was
consideration of the merits of the establishment of a reactive power market. The
current 2006 GTA Application indicates that ongoing consultations are continuing
with respect to items in the 2003 Negotiated Settlement.
Request:
(a) Please discuss the state of the ongoing consultations as they bear on the
establishment of a reactive power market, including the parties included in
such consultations, the date and outcome of the last consultative meeting,
and the anticipated date and agenda for the next such meeting.
(b) Please discuss the plan or intent of the AESO with respect to the
establishment of a reactive power market.
(c) Please summarize the benefits to the Alberta market that the AESO would
see in the establishment of a reactive power market.
(d) Please discuss any detriments to the Alberta market that the AESO would
see in the establishment of a reactive power market.
Response:
(a) Based upon the research documented in the March 18, 2003 report entitled
“Reactive Power as an Identifiable Ancillary Service” published on the
AESO’s website, the AESO has not been engaging in additional dialogue on
this topic. The AESO considers its present treatment of reactive power within
the more traditional generator output ranges to be reasonable and consistent
with other jurisdictions, and is not intending to pursue other potential
arrangements at this time. As area-specific requirements may occur in the
future and recognizing that reactive power is extremely localized and
therefore would create a somewhat illiquid market, the AESO would expect to
pursue solutions other than a development of a market in those regards. The
AESO is open to additional stakeholder input to continue pursuing such
possibilities if broad stakeholder support exists.
(b) Please refer to (a) above.
(c) Please refer to (a) above.
(d) Please refer to (a) above.
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
February 25, 2005
TAC.AESO-004 (a-e)
Page 1 of 2
Reference:
Appendix C, Ancillary Services Cost of Service Study.
Preamble:
Page 17 and 18 of the EnVision Cost of Service Study and the recent RFP for
reactive support in the Calgary region demonstrate voltage control causes
substantial and increasing Ancillary Services costs. The AESO states at page 13
of Section 4 that generators are not paid for reactive power dispatches.
Request:
(a) Please confirm that the terms of interconnection agreements and the pool
rules currently obligate generators to accept MVAR output dispatches up to
the maximums determined by the ratio of MVAR vs. MW output (a term
known as power factor).
(b) Please advise whether the matters in (a) are the factors that lead to nonpayment to generators for reactive power dispatches. If other matters
pertain, please describe such matters, and the rationale behind them as to
why generators are not paid for reactive power dispatches.
(c) Please confirm that generator MVAR capability is actually higher at low loads
when the maximum determined by the power factor requirement is lower.
(d) Would the AESO agree that generators could have additional reactive power
resources available at times when the market has not accepted their energy
offer?
(e) Would the AESO agree that it would be appropriate to enable generators to
respond to RFPs for reactive power or to enter into bilateral agreements for
reactive power with loads in their region?
Response:
(a) Confirmed. (Note that power factor = MW / MVA). As discussed in the
research paper on this topic referred to in TAC-AESO-03, it is common
practice for control areas to specify power factor ranges within which
interconnected generators must be able to operate.
(b) There is no payment for reactive power under the interconnection
requirements primarily because operating a generator within the specified
power factor range is considered generally a reasonable interconnection
obligation requirement, the provision of this level of reactive power (either as
dispatched or in response to a sudden change in system conditions) has a
minimal impact on generator real power production, and reactive power
requirements are generally extremely localized so compensation through a
market approach is not necessarily practical.
(c) At lower load levels, most generators have some additional reactive power
capability beyond the power factor range specified by the AESO, as the
thermal limitations on the generators are eased. Other limitations continue to
Page 2 of 2
impact the total available reactive power supply, including limitations in the
field exciter.
(d) Under certain conditions this may be possible.
(e) Depending on the nature of the RFP and the requirements of the AESO, it
may be reasonable for generators to offer reactive power capability beyond
that required by the AESO’s terms and conditions of service into RFP’s for
reactive power supply. The technical considerations will have to be taken
into account on a case by case basis. It may also be practical for generators
or loads that are having difficulty meeting their individual reactive power
requirements to contract directly with a generator within appropriate electrical
proximity for additional reactive support. These arrangements, as well, would
need to be considered on a case by case basis.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
February 25, 2005
TAC.AESO-005 (a-c)
Page 1 of 1
Reference:
Section 6.1 Customer Contribution Policy, page 13 re discount rate assumptions.
Request:
(a) Please confirm that the reference on line 10 of page 13 of section 6 of the
Application to “Article 9.9” of the proposed T&Cs should be a reference to
Article 9.12. If not, please explain the reference as made.
(b) The calculation as set out in Article 9.12 of the proposed T&C’s in section 7 of
the Application appears to apply the (1 - tax rate) tax adjustment to both the
debt and the equity portions of the assumed financing. Please confirm that
the formula as provided is incorrect, and provide the corrected formula.
(c) The example set out on page 13 of Section 6 of the Application, when
properly calculated, appears to arrive at an after-tax discount rate of 9.22%
rather than 9.27%. Please confirm, or if confirmation can not be made,
provide the calculation of the after-tax discount rate based on the example
parameters.
Response:
(a) Confirmed. The reference on page 13 of section 6 should be to Article 9.12.
(b) Confirmed. Please refer to Information Response ALPAC.AESO-002 (a).
(c) Confirmed. Please refer to Information Response ALPAC.AESO-002 (b).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
February 25, 2005
TAC.AESO-006 (a-f)
Page 1 of 2
Reference:
Section 4, page 40, calculation of Primary Service Credit.
Request:
In regard to Table 4.9.3:
(a) Please provide the detailed calculation showing the capital recovery factor
with a result of 11.94% given the following assumptions shown in the note.
% Debt:
% Equity:
Debt Rate:
ROE:
Tax Rate:
Life:
65%
35%
6.30%
9.5%
33.87%
32 years
(b) Please verify the annual costs shown in the Table. For example, a capital
cost of $750,000 * 11.94% = $89,550 rather than the $89,238 shown for
Transformer 1.
(c) If the CRF is incorrect then please provide revised calculations supporting the
$700 per MW per Month for the PSC.
(d) The average monthly credit as calculated in the table is $661 per MW per
month. The AESO then uses $700 per MW per month. Please explain how
the AESO gets from $661 to $700 per MW per month. In other areas such as
the DTS, calculations are detailed to the penny, for example, in the charge of
$1677.06 per MW per month (see page 2 of section 7 of the Application).
(e) In the definition of "System Contribution" please clarify whether this should
refer to Article 9.8 or 9.9. (see page 43 of Section 7 of the Application).
(f) In T&C Articles 14.4 (a) and (b), please confirm that the intent is not the
“mean metered power” but the “mean maximum metered power”. (see page
69 of Section 7 of the Application).
Response:
(a) Please refer to Information Response COSC.AESO-004 (b).
(b) Please refer to Information Response COSC.AESO-004 (a).
(c) Please refer to Information Response COSC.AESO-004 (a).
(d) The average monthly amount was simply rounded to $700/MW. The Primary
Service Credit amount is an average amount in respect of representative
transformer configurations. Additional precision is not appropriate given the
average nature of the calculation. The DTS rate, on the other hand, is
Page 2 of 2
determined from thorough and approved forecasts of costs and billing
determinants, and the additional precision is warranted.
(e) The reference in the definition should be to Article 9.9.
(f) Confirmed.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
February 25, 2005
TAC.AESO-007 (a-d)
Page 1 of 1
Reference:
Section 4, Rate Design.
Preamble:
At page 6, the AESO notes 8 cases were used as the basis for the conclusions
and that the average of percentage of POD peak load of all PODs at the time of
maximum transmission system stress was 73.5 %. The rate design proposes as
a result to allocate 73.5% of the 33.4% of costs caused by demand as demand
charges and the remainder as usage charges.
Page 9 of the same section notes that 500 MW of capacity and 6% of customers
have load factors of less than 20% and that the AESO recommendation would
result in those customers total bills increasing by between 3% and 20%. That
page goes on to propose addressing the specific needs of these customers in a
future proceeding reasoning that the stakeholder consultation done to date is
inadequate to make a proposal.
Request:
(a) What percentage of their total POD peak load were the 6% of customers with
less than 20% load factor taking in the eight cases upon which rate changes
proposed are based?
(b) What percentage of the 6% of customers with less than 20% load factor
would the AESO estimate take power from the grid only for standby
purposes?
(c) What number or percentage of low load factors customers were consulted on
the issues discussed on page 9?
(d) Please summarize the proposals made and concerns raised by low load
factor customers in the consultations.
Response:
(a) Please refer to attached Schedule TAC-AESO-007 A.
(b) Please refer to IOR.AESO-10 (a).
(c-d) Please refer to ADC.ASEO.17 (a-h).
ALBERTA ELECTRIC SYSTEM OPERATOR
AESO 2005-06 General Tariff Application (1363012)
Friday, February 25, 2005
TAC.AESO-008 (a-c)
Page 1 of 1
Titles:
Reference:
Application, Section 2.3.4, Other Ancillary Services
Preamble:
The AESO procures certain remedial action schemes (RAS) and includes in
tariffs the RAS costs. One such scheme is the Interruptible Load Remedial
Action Scheme (ILRAS), designed to support the import capability of the AlbertaBC interconnection, as described on p. 25 of section 2 of the Application.
Request:
a) Would the AESO concur that it has similar, if not identical, obligations to
support the export capability of the Alberta B.C. interconnection? If not, why
not?
b) The Keephills PPA provides for a “Keephills Tie Line RAS”, defined in
Schedule G – System Support Services to mean “the Remedial Action
Scheme in respect of Keephills Units 1 and 2 allowing for a unit trip following
a tie line trip or combination of tie line trips for tie lines identified as 5L91,
5L98, 5L92 or 1201L.” Please provide the AESO’s knowledge as to how
many times in each of 2004, 2003, 2002 and 2001 that the Keephills Tie Line
RAS has been armed?
c) Would the AESO consider procuring the Keephills Tie Line RAS or similar
arrangements with other generating units to support the export capability of
the BC Tie in an analogous manner to the support provided by the ILRAS for
imports. If not, why not?
Response:
a) The Transmission Regulation supports increasing intertie capabilities.
However the impact of exports on system reliability as compared to the
impact of imports is significantly different. This implies the cost to support
export capability is different than the cost to support import capability.
Therefore the obligations may not be identical.
b) To the best of AESO’s knowledge, the Keephills tie line has not been armed
in any of 2004, 2003, 2002 and 2001.
c) Yes the AESO would consider procuring a tie line RAS that would support
export. The AESO is currently completing feasibility study into RAS concepts
for extending export capabilities using a generator RAS.