ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-001 (a)-(f)
Page 1 of 2
Reference:
1 Consolidated Filing, 1.1 Introduction
Preamble:
The AS Article amendments proposed in the August 16 Application were then
incorporated into the AESO’s 2006 General Tariff Application (GTA) filed on
January 31, 2005, including the definition of Maximum TMR Compensation as
required by the Transmission Regulation (A.R. 174/2004, enacted August 12,
2004).
However, the considerations raised during discussions combined with other
factors (such as the ADOE Electricity Policy Framework paper discussed in
section 2.1) have led the AESO to make this filing to update and amend the AS
Article provisions included in the August 16 Application.
The Board letter of December 16, 2004 indicates “The Board grants the
requested relief in part and approves the existing Article 24 on an interim basis
effective December 17, 2004.”
During the period, AESO and ATCO Power have reached agreement on TMR
services from 40 Rainbow units 4 and 5, including settlement of AS Article
compensation issues since May 1, 2004 when AESO began conscripting the
units on an extended and uncontracted basis. Documentation of the agreement
has not been completed. However, both parties anticipate the agreement will be
completed within the next few weeks and receive approvals from their Board of
Directors in September.
Request:
(a)
Is the wording of Article 11 in the AESO’s 2006 GTA that was filed on January
31, 2005 exactly the same as the existing Article 24 that was approved on an
interim basis effective December 17, 2004. If not, please provide the current
Article 11 or 24 that is in effect on an interim basis.
(b)
Please provide a red-lined version of the AS Article provisions showing the
changes from the August 16 Application.
(c)
Assuming the ATCO Power agreement documentation will be complete please
provide the documentation and the details of the compensation effective May 1,
2004.
(d)
Please discuss the ATCO Power issues, with associated monetary values, that
were in contention and how these issues were resolved.
(e)
The AESO indicates that there are issues raised in previous applications that no
longer need to be addressed by the Board; please identify and describe these
issues.
Page 2 of 2
(f)
Response:
(a)
Is the ATCO Power settlement interim and subject to adjustment in accordance
with the EUB’s final determination on the August 16, 2004 Application.
Yes, the wording of Article 11 in the 2006 GTA is the same as that approved on
an interim basis effective December 17, 2004. In Part 6.4 of the 2006 GTA, dated
January 31, 2005, AESO proposed the following addition to the end of Article
11.1:
“Notwithstanding the foregoing, the compensation shall not exceed the Maximum
TMR Compensation.”
(b)
The only changes to Articles 11.1, 11.2 and 11.4 in Appendix A of the
Amendment Application as compared to Articles 24.1, 24.2 and 24.2 of the
August 16, 2004 Application, is the addition of the sentence noted in (a) above to
the end of Article 11.1.
Article 11.3 in Appendix A of the Amendment Application is based on a prorating
of fixed cost concept and was significantly changed compared to Article 24.3 of
the August 16, 2004 Application. The August 16, 2004 Application was based on
a Going Forward Cost model. As a result, a red-line of the significantly different
concepts is of no value.
Contrary to the expectation noted in the AESO’s application cover letter dated
August 4, 2005, a new agreement with ATCO Power regarding TMR services
from Rainbow 4 and 5 has not been completed. Typically, such contracts are
commercially sensitive or confidential. See FIRM.AESO-037.
(c) & (f)
(d)
Please refer to FIRM.AESO-038 (b).
(e)
Please refer to BR.AESO-001.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-002
Page 1 of 1
Reference:
2 Background
Preamble:
In its experience with the current AS Article, the AESO has generally been able
to manage situations of short-term emergency service. The current AS Article
was not, however, intended to address situations of foreseeable long-duration
services, and more specifically extended-duration transmission must-run (TMR)
services. Instances of extended-duration TMR services have occurred. AESO
and the supplier have recently agreed to compensation for the specific
circumstance. Compensation for such long-duration service remains a concern.
The AESO therefore proposes that the current AS Article be amended to address
concerns related to long-duration services, especially TMR, as well as
refinements to support these provisions and to remove elements that potentially
inhibit energy market efficiency.
Request:
Please provide the details of the extended-duration instances by supplier where
TMR services have occurred including dates, durations and compensation paid.
Response:
Please see FIRM.AESO-037 (a).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-003
Page 1 of 1
Reference:
2 Background, 2.1 ADOE-Endorsed Principles for Compensation of TMR
Services
Preamble:
AESO is proceeding with establishing processes aligned with the latter principles
(ie 2, 3, 4 and 7). Such processes are outside the scope of the current
application.
Request:
Please explain why the processes are outside the scope of the current
application.
Response:
Please refer to BR.AESO-003 (a).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-004
Page 1 of 1
Reference:
2 Background, 2.1.1 Cost Recovery
Preamble:
Out-of-merit costs should be compensated under a separate category of costs so
that the compensation is transparent and it is clear that such costs are always
covered. Some forms of compensation do not clearly cover such out-of-merit
costs. For example, in some situations under the current AS Article 24.3(b), a
generator is paid another form of compensation (in this case a 10% premium on
pool price) but the generator must absorb out-of-merit losses. Such a “netting”
formula results in the out-of-merit losses reducing total AS compensation, in
some cases to near zero. Separately identifying compensation for out of-merit
costs will ensure such costs are covered and will not create unfair situations
where a generator receives little compensation when providing TMR service.
Request:
If “netting” is eliminated how is over-compensation for in-merit situations
controlled by the AESO.
Response:
Please refer to FIRM.AESO-009.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-005 (a)-(c)
Page 1 of 1
Reference:
2 Background, 2.1.2 Minimal Market Interference
Preamble:
Further minimization of distortions preserves energy market signals as much as
possible. For in-merit generators, the energy market provides signals for
operation in the market. Appropriate AS Article compensation which is clearly
additional to and separate from energy market revenues is desirable in that the
in-merit generator will continue to receive the energy market signal and revenues
as well as supplemental AS compensation. AS Article options that call for in-merit
energy market revenues to be substituted or forfeited as part of the AS
compensation have the effect of reducing or completely canceling the energy
market signals. Such interruption of or interference with energy market signals
represents an undesirable distortion.
Request:
(a)
If the generator is in-merit and receiving pool price revenues why would that
generator be conscripted for TMR service and receive supplemental AS
compensation.
(b)
If a generator is in-merit in a particular hour and supplemental AS revenues are
provided to the generator for that same hour the generator appears to be paid
twice for the same service; how is this equitable to load customers.
(c)
Does the AESO consider that there would be no interference with the energy
market signal if the generator receives energy revenues and additional AS
compensation for the same time period.
Response:
(a) and (b)
(c)
Please refer to FIRM.AESO-009.
Such a circumstance would not be considered as interference in the energy
market since in-merit energy signals and revenues are not impacted and the
incentive to participate in the energy market is not skewed. Since energy market
signals and incentives have not been changed, participation in the energy market
would not be expected to change and thus there is no interference in the energy
market.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-006 (a)-(c)
Page 1 of 1
Reference:
2 Background, 2.2 Experience Since Decision 2002-103
Preamble:
There is no immediate alternative to negotiating to procure TMR services from
existing local generators, such as by initiating a competitive process, as the
existing transmission infrastructure is unable to accommodate new generation.
Request:
(a)
Please list the existing NW local generation by unit and their capacities for which
TMR service may be available.
(b)
Please provide the ownership of each of the generation units listed in a. above
and indicate which owners are also owners of load facilities and the size of these
load facilities.
(c)
Please list and discuss the current agreements between the local generators and
the AESO for procurement of AS and particularly TMR services.
Response:
(a)
Please refer to page 5 of the Report of Edward Kahn which is included in the
2005 Amendment Application in Appendix 2 of Appendix D.
(b)
Please refer to (a) above for ownership information. Please refer to FIRM.AESO050(c) for load information.
(c)
Please refer to FIRM.AESO-020 (a) and FIRM.AESO-021 (a).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-007 (a)-(d)
Page 1 of 2
Reference:
2 Background, 2.3 Experience With Current Ancillary Services Article, 2.3.1 Fair
Compensation, page 11 of 18
Preamble:
When pool prices are high Article 24.3(b) provides significant compensation
compared to the energy market alone, and when pool prices are low Article
24.3(c) provides significantly more compensation than the energy market.
However, when pool prices are moderate, both Articles provide relatively lower
levels of compensation compared to higher or lower pool prices. Such a result is
not considered fair, and is further illustrated in Appendix C.
Under other circumstances the current AS Article may overcompensate a
generator providing AS services. Specifically, Article 24.3(c) prescribes 10% to
be added to compensation for fixed and variable costs. This premium results in
an overpayment above costs. Article 24.3(b) prescribes 10% to be added to pool
price and may sometimes also result in an overpayment since the premium is not
related to either fixed or variable costs.
Request:
(a)
Please provide the supporting spreadsheet analysis for Appendix C with all
supporting assumptions.
(b)
Please provide illustrative examples with a spreadsheet example for each of the
scenarios of high pool prices and low pool prices and as well, of the “perverse
incentives” [as discussed at page 12 of 18] arising from the application of the
current AS Article.
(c)
Please explain if in AESO’s view, the “perverse incentives” have had an impact
on transmission planning.
(d)
Please provide a spreadsheet example of the scenario of overcompensation or
under-compensation with all assumptions included.
Response:
(a)
Please refer to IPPSA.AESO-017(a).
(b) and (d)
Please refer to BR.AESO-004 (a) for examples of each option under differing
scenarios. Attachment FIRM.AESO-007 is a spreadsheet illustrating the perverse
incentive. As shown, gas-fired units can increase contributions to cover their
fixed costs by 20% to 30% by reducing participation in energy markets. The
incentive does not pay-off for coal units as the loss of energy market revenue is
too great compared to the increase in AS Revenue.
Page 2 of 2
(c)
No impact as yet can be shown of the perverse incentive on transmission
planning. However, the concern exists that system congestion may increase due
to the incentive with an effect on future planning decisions to address congestion.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-008 (a)-(b)
Page 1 of 1
Reference:
2 Background, 2.3 Experience With Current Ancillary Services Article, 2.3.2 Cost
Recovery, page 11 of 18
Preamble:
However, even though pool prices are relatively high, directed out-of-merit
operation is likely. Since there is no out of-merit compensation under 24.3(b), the
generator must net off out-of-merit losses against compensation from the energy
market or ancillary services. A more desirable approach is to ensure all out-ofmerit costs are compensated so that a generator is always kept whole, at a
minimum, when out-of-merit operation is directed.
Request:
(a)
(b)
Please provide a numerical example of compensation pursuant to 24.3 (b) that
illustrates the issue of no out-of merit compensation.
Is compensation determined on an hourly basis.
Response:
(a)
Please refer to IPPSA.AESO-017(a).
(b)
Yes.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-009 (a)
Page 1 of 1
Reference:
2 Background, 2.3 Experience With Current Ancillary Services Article, 2.3.3
Minimal Market Interference, page 12 of 18
Preamble:
The August 16 Application described the perverse incentives that arise with the
current AS Article. The potential for extra TMR compensation can incent
generators to submit high offer prices or withdraw supplies from the energy
market to gain extra compensation.
As well, the current AS Article 24.3(c) requires AS compensation to be
substituted for market-based compensation. The formula in effect prescribes the
generator to receive a regulated form of compensation and to transfer to the
AESO any compensation from the energy market. The required substitution is an
unnecessary distortion of the market.
Request:
(a)
Response:
(a)
Please discuss whether the AESO considers that a generator can produce a
service for either for the energy market or the AS market but not for both markets
simultaneously.
Under certain circumstances a generator can produce a service for both markets.
One example is standby operating reserves and energy. The customer can
provide both products until the standby reserve product is called to be activated.
When standby is called, the energy products must be withdrawn to provide the
active operating reserve.
A second example is a unit providing regulating reserve. Such a unit receives
compensation for the capacity in MW of regulating range being provided. The
unit also produces energy while providing the service and receives and retains
energy market compensation.
Under such circumstances, a generator is producing two non-regulated services.
Compensation is market based, which is equitable to suppliers and customers.
Regarding TMR services, a unit that is dispatched in the energy market based on
the offer price for the unit would not be directed for TMR service.
Under AESO’s proposed AS Article, a generator that is out-of-merit according to
its offer price and therefore not dispatched in the energy market may receive a
TMR directive. Such a unit may be in-merit according to its Benchmark Price.
Compensation for such a unit is proposed to be determined based on the
Benchmark price such that it would not receive TMR compensation associated
with the period. The generator would receive and retain compensation from the
energy market.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-010 (a)-(c)
Page 1 of 1
Reference:
3 Options for the Ancillary Services Article, 3.2 Option 2: Out-of-Merit or Going
Forward Costs, page 13 of 18
Preamble:
The proportion of Going Forward Costs is pro-rated considering the amount of
directed service and the time the unit was in and out of merit. The determination
in-merit and out-of-merit was based on comparing pool prices to variable costs of
the unit. The generator’s offer prices did not affect the determination of in or out
of merit for TMR compensation purposes. Certain minimums or thresholds were
included as prerequisites to be met before compensating for Going Forward
Costs. Compensation under competitively procured or negotiated contracts was
a significant factor considered in the development of this option. Compensation
by the energy market was relied upon for recovery of fixed costs.
Request:
(a)
Please provide a numeric example of the pro-ration of Going Forward costs;
does the total time the unit was in-merit and out-of merit total all hours in the
month or are other considerations such as down-time taken into account.
(b)
How does compensation under competitively procured or negotiated contracts
affect this option.
(c)
Unless a generator initially contracts to supply TMR service to the AESO how
can TMR compensation include any recovery of fixed costs.
Response:
(a)
Please refer to BR.AESO-004 (a). Only hours in which the unit is providing
Ancillary Services and out-of-merit are compensated for. If the unit was not
operating it would not be providing Ancillary Services so such hours would not be
counted.
(b)
AESO’s contracting experience had significant influence on the structure of
Option 2. If Option 2 was adopted for the AS Article, compensation of conscripted
Ancillary Service under Article 11.3 would accord with the terms of Option 2.
Actual compensation under ongoing contracts would have no ongoing impact on
settlements under Article 11.3. In all options, compensation under ongoing
contracts can establish a reference for settlements under Article 11.2 or Article
11.3(a).
(c)
A conscripted generator will be compensated in accordance with the AS Article. If
the AS Article calls for compensation of fixed costs, a conscripted generator will
be compensated for fixed costs in accordance with the AS Article.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-011 (a)
Page 1 of 1
Reference:
3 Options for the Ancillary Services Article, 3.3 Option 3: Out-of-Merit and
Prorated Fixed Costs, page 13 of 18
Preamble:
In this option, compensation is provided for out-of-merit costs and a proportion of
fixed costs, prorated based on the time the unit was directed to provide out-ofmerit service and the time the unit was in-merit. The determination of in-merit and
out-of-merit is based on the pool price and variable costs in a similar manner as
Option 2. When the unit is in-merit, pool revenues are not deducted and the
generator therefore retains all in-merit pool revenue in addition to TMR
compensation.
Request:
(a)
Response:
(a)
When the unit is in-merit please discuss why the generator is not compensated
twice for the same service if pool revenues are not deducted.
Please refer to FIRM.AESO-009.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-012 (a)-(d)
Page 1 of 1
Reference:
3 Options for the Ancillary Services Article, 3.3 Option 3: Out-of-Merit and
Prorated Fixed Costs, page 14 of 18
Preamble:
Fixed cost compensation is based on a pro-rating of fixed costs between the two
uses of the unit, namely, in-merit energy market service and the conscripted
ancillary service. The portion of fixed costs assigned to energy market service is
based on in-merit hours. The portion assigned to directed service is based on
out-of-merit directed service hours. By basing the energy market share on inmerit hours, the generator is not discouraged from operating during such in-merit
periods to capture and retain as much revenue from the energy market as
possible, and the incentive to operate during in-merit periods is common to all
generators. If a generator is unable to capture in-merit hours due to limitations of
the generating unit (for example, start-up times), the number of in-merit hours will
be reasonably adjusted to reflect the physical characteristics of the generating
unit and its ability to capture revenues from in-merit hours. Such adjustment
would be determined on a case-by-case basis after examining the particular
circumstances of each case.
Request:
(a)
What is the basis for determining economic life of a unit in order to determine an
allocation of fixed costs to a particular hour.
(b)
Please list and describe the economic lives of generation units that are currently
contracted to the AESO for TMR service including the recently completed
agreements with ATCO Power for the Rainbow 4 and 5 units.
(c)
What fixed costs are prorated to the unit when it is not in-service due to
maintenance or failure.
(d)
Why are fixed costs not simply prorated to out-of-merit operation based on the
hours the unit is out-of-merit and directed to provide TMR service.
Response:
(a)
Please refer to FIRM.AESO-046.
(b)
None of the AESO’s existing TMR contracts specify or rely on an economic life
for a generation unit. Please refer to FIRM.AESO-001(c).
(c)
AESO has interpreted the question as “What fixed costs are prorated to TMR …”.
If the unit is not in-service for an hour, the unit will not be providing TMR service
in that hour so no fixed costs would be prorated to TMR service.
(d)
In Option 3, the prorating to TMR service is based on hours the unit is out-ofmerit and directed to provide TMR service.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-013 (a)
Page 1 of 1
Reference:
3 Options for the Ancillary Services Article, 3.3 Option 3: Out-of-Merit and
Prorated Fixed Costs, page 14 of 18
Preamble:
The determination of fixed costs will be made following the principles proposed
for Maximum TMR Compensation in the AESO’s 2006 GTA and as required by
Section 23 of the Transmission Regulation, modified such that the pro-rating will
be according to the Directed Out-of-Merit ratio as detailed in Appendix A rather
than the joint use formula proposed for Maximum TMR Compensation.
Request:
(a)
Response:
(a)
What was the basis and reasons for changing from the joint-use formula to the
Directed Out-of-Merit ratio.
Please refer to IPPSA.AESO-025 (a).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-014 (a)-(b)
Page 1 of 1
Reference:
3 Options for the Ancillary Services Article, 3.3 Option 3: Out-of-Merit and
Prorated Fixed Costs, page 14 of 18
Preamble:
Appendix E provides illustrative examples of Maximum TMR Compensation, in
the same format as the response to Information Request BR-AESO-42 from the
AESO’s 2006 GTA.The total fixed cost intended to be used in Option 3 is shown
at line 55 of Appendix E.
Request:
(a)
(b)
Response:
(a)
(b)
Will the average maximum MCR, average MW directed for TMR and hours of
TMR service in the month all be determined on an actual basis for the month by
summing hourly quantities.
Is there a minimum duration amount that the AESO can conscript TMR service
such as 1 hour or 2 hours.
Yes.
There is no minimum duration for TMR directives.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-015 (a)-(b)
Page 1 of 1
Reference:
3 Options for the Ancillary Services Article, 3.4 Assessment of Options 2 and 3,
3.4.2 Fair Compensation, page 14 of 18
Preamble:
Option 2 results in no additional TMR compensation above revenues from the
energy market in moderate and high pool price scenarios, due to the minimums
and triggers contained in that option. In lower pool price scenarios, the additional
TMR compensation is likely to be lower than other options due to the focus on
Going Forward Costs. Option 2 will also not exceed the proposed Maximum TMR
Compensation level.
Option 3 does not affect a generator’s in-merit energy revenues and, in addition
to energy market revenues, the option provides TMR compensation for out-ofmerit directed operations and a TMR contribution to fixed costs unless a
generator is 100% in-merit. Option 3 will also not exceed the proposed Maximum
TMR Compensation level.
Under extended duration conscriptions, a generator’s aggregate compensation
from the energy market and TMR appears to be generally comparable under
Options 1 and 3. Aggregate compensation under Options 1 and 3 for short-term
conscriptions may differ according to the specific short-term circumstances.
Request:
(a)
(b)
Response:
(a)
(b)
In order to assess fair compensation for the options please provide an example
of a unit that is capable of providing both energy market and TMR market
services and show the individual and aggregate compensation levels pursuant to
each of Options 1, 2, and 3 and include low, moderate and high pool price
scenarios and short term and long term duration scenarios. Please provide a
spreadsheet analysis to support the compensation levels for all scenarios.
For Option 3 please elaborate on the provision of a TMR contribution to fixed
costs unless a generator is 100% in merit. Does this mean that the generator
receives a TMR contribution if it is only 90% in-merit.
Please refer to BR.AESO-004 (a).
A generator that is 100% in-merit would receive no fixed cost contribution. A
generator that is out-of-merit is providing a TMR service and as such a portion of
fixed costs are prorated to the TMR service. Any out-of-merit directed service
would result in TMR compensation for out-of-merit costs and for a prorated share
of fixed costs. See also response to IPPSA.AESO-25(a) and 26(b).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-016 (a)-(d)
Page 1 of 1
Reference:
3 Options for the Ancillary Services Article, 3.4 Assessment of Options 2 and 3,
3.4.5 Minimal Market Interference, pages 15 and 16 of 18
Preamble:
Option 2 contains features which require energy market compensation for inmerit periods to be used to offset other costs, such as out-of-merit costs in
conscripted periods. When the generator is directed to provide TMR service
during a period in which it is in-merit, revenues are deducted from TMR
compensation and the market signal is dulled. When the generator is directed to
provide TMR service and is out-of-merit, there is no distortion.
Figure 1.
Request:
(a)
Please provide the circumstances where a generation unit is directed to provide
TMR services where it is in-merit and absent such direction the unit would not be
supplying the energy market.
(b)
In the above circumstance is the generation unit holding the AESO hostage to
secure additional revenues over and above the pool price.
(c)
Please elaborate on why Option 2 is more difficult for Simplicity and
Transparency than either Option 1 or Option 3.
(d)
Please elaborate on why Options 1 and 2 are less desirable from the perspective
of Cost Recovery than Option 3.
Response:
(a)
The circumstance would occur if the offer price associated with the unit was
above the prevailing pool price such that it was not dispatched in the energy
market and where the offer price was above its variable cost of production.
(b)
The circumstance may reflect normal offer behaviour or be in response to an
incentive to achieve additional revenue.
(c)
The structure of Option 2 contained some thresholds or triggers and minimums in
the calculations which added complexity to the option.
(d)
For Option 1 see Amendment Application page 11, line 29.
For Option 2 see Amendment Application page 15 line 21.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-017 (a)
Page 1 of 1
Reference:
3 Options for the Ancillary Services Article, 3.5 Recommended Option, page 16
of 18.
Preamble:
Option 3 provides out-of-merit compensation to generators as well as a pro-rated
share of fixed costs. Out-of-merit compensation is linked only to out-of-merit
periods to keep the generator whole with respect to variable operating costs. Inmerit operation of the unit has no impact on the out-of-merit compensation.
Fixed costs are fairly allocated among the two services by the prorating method.
Pro-rating according to out-of-merit hours avoids perverse incentives with respect
to participation in the energy market. The prorating contains no minimums or
thresholds which aids transparency and reduces complexity.
Option 3 is based on fixed cost compensation which is aligned with the
Transmission Regulation and the Electricity Policy Framework paper, rather than
Going Forward Cost compensation.
Request:
(a)
Response:
(a)
What was the initial rationale in Option 1 to offset in-merit compensation against
out-of-merit compensation.
The netting which occurs in the transition between the two articles is not
discussed in Decision 2002-103, nor is rationale provided.
The effective netting of out-of-merit compensation from Article 24.3(b) amounts
occurs due to the transition from 24.3(b) compensation to 24.3(c) compensation.
The establishment of the 24.3(b) and 24.3(c) articles appears to be intended as
independent compensation options.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-018 (a)-(b)
Page 1 of 1
Reference:
4 Correction & Clarification of Previously Filed Information, 4.1 Maximum TMR
Compensation Definition – Correction, page 17 of 18
Preamble:
(f) a prorated share of total return costs reflecting one-twelfth of the sum of:
• annual amortization and depreciation amounts,
• the product of UCI time the debt percentage of capital structure times the
interest rate,
• the product of UCI times the equity percentage of capital structure times the
rate of return on equity, and
• the product of the tax rates times the equity return amount determined above,
unless the generating asset is at or near the end of its life and the UCI amount is
at zero, in which case total return costs will reflect a reasonable minimum return
amount and;
where the prorated share is based on the number of hours of TMR service
compared to the total of hours of TMR service and a reasonable portion of hours
in-merit in the energy market;
Request:
(a)
(b)
Response:
(a)
(b)
What is the basis for the proposed minimum return amount.
Please provide the treatment of PPAs at or near the end of their lives.
The intent of the proposed minimum return amount is to ensure that a supplier
with a very low UCI, and who will therefore receive very little compensation, will
receive a minimum amount for providing conscripted services. AESO has not
developed or formalized an approach for a minimum return amount. AESO will
determine such amounts on a case by case basis.
The IAT determined a minimum return amount as a minimum “return on common
equity (MROE) calculated with reference to this minimum return margin of 3.5%
of total cash expenses for EPGI and ATCO, or 2% of total cash expenses for
TAU, using the formulae set out in Appendix A in Volume X.” (IAT July 9, 1999
Report to the EUB Part 5, page 5)
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-019 (a)-(e)
Page 1 of 2
Reference:
4.2 Maximum TMR Compensation Definition - Clarification, page 18 of 18
Preamble:
1. A generator’s in-merit pool revenues would not be considered as
compensation for TMR service and therefore would not impact TMR maximum
compliance calculations. In other words, revenues received by a generator for inmerit energy production would be retained by the generator, as they would have
been if the generator had simply operated in the energy market and not provided
any TMR service.
2. Pool revenues related to out-of-merit TMR service would be considered as
part of TMR compensation. Such out-of-merit pool revenues would be included
with other forms of TMR compensation and the aggregate of such compensation
would be limited by the maximum TMR compensation level. Pool revenues for
out-of-merit TMR service would be included as part of TMR compensation
because the unit would not normally be expected to operate when out-of-merit.
Request:
(a)
For any hour can the generator receive in-merit pool revenues as well as TMR
compensation. If so how does the AESO justify double payment for the same
service in an hour.
(b)
For a unit that is providing in-merit service in an hour to the energy market how
can there be a requirement for TMR service by that same unit in that particular
hour.
(c)
Please elaborate if there can be an allocation of generation unit capacity
between energy market service and TMR service in a particular hour.
(d)
If a generation unit is operating in the energy market in-merit for partial capacity
of that unit can the AESO conscript TMR service for that unit for the balance of
the unit’s capacity.
(e)
Is it likely that a generation unit would only operate at partial capacity for in-merit
operation as required by the AESO.
Response:
(a)
Please refer to FIRM.AESO-009.
(b)
Please refer to FIRM.AESO-016(a).
(c)
Each hour would normally be determined to be entirely for an Energy Market use
or entirely for a TMR use. The conventions proposed are as follows:
Page 2 of 2



If a generating unit was used solely for TMR for any part of the
hour, the entire hour would be considered as a TMR directed
hour.
If a unit was dispatched in the energy market at partial output, and
for a reliability reason, the unit was directed to operate at a higher
level of output, the full output would be deemed to be conscripted
for the full hour. For example, if a 50 MW unit, operating at 20 MW
in the energy market, was directed to increase output by 5 MW to
25 MW for a reliability purpose, all 25 MW would be considered
conscripted and the hour would be considered as a TMR directed
hour.
If a unit was dispatched and used for an Energy Market purpose
for the entire hour, the entire hour would be considered as energy
market. Such is the case even if some portion of the unit’s
capacity had been directed for TMR service prior to the hour. As
long as the total output of the unit exceeded the TMR directed
level for the full hour, the unit is considered as operating for
energy market purposes and the hour would be considered as a
non-TMR directed hour. For example, if a 50 MW unit was
directed to operate at 20 MW of TMR prior to the start of an hour,
but an energy market dispatch raised the output of the unit to 35
MW prior to the start of the hour and the energy market dispatch
continued for the whole hour, the entire hour would be considered
as an energy market use and the hour would be a non-TMR
Directed hour.
(d)
Yes, if the reliability standards required the unit to operate at a higher level than
the energy market dispatch, the balance of the unit, or a portion of the balance of
unit, could be conscripted to meet the reliability requirement.
(e)
Based on experience, there is significant possibility that TMR directives would be
for a part of the capacity. However, significant occurrences of full unit directives
are expected as well.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-020 (a)-(b)
Page 1 of 1
Reference:
Appendix A, Article 11 with Proposed Option 3, Ancillary Services, page 1 of 2
Preamble:
11.1 During a state in which the AIES lacks sufficient Ancillary Services and for
the purposes of maintaining system security, the AESO may require a Customer
to operate its generating unit to provide Ancillary Services. For the period during
which the conscription persists, Customers required by AESO to provide
Ancillary Services shall be compensated as provided in Article 11.2 or Article
11.3, whichever is applicable. Notwithstanding the foregoing, the compensation
shall not exceed the Maximum TMR Compensation.
Request:
(a)
(b)
Response:
(a)
(b)
Please list and describe each Ancillary Service that pertains to this Article 11. Is
TMR the primary Ancillary Service for which the AESO would request compelled
service.
What are the minimum, maximum and average durations that the AESO may
request compelled Ancillary Services.
Ancillary Services were listed and described in the 2006 GTA in Section 4 at
pages 10 to 19. Please see Attachment FIRM.AESO-020 for a copy of those
pages.
There are no minimum or maximum durations defined for conscripted TMR
services.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-021 (a)-(b)
Page 1 of 2
Reference:
Appendix A, Article 11 with Proposed Option 3, Ancillary Services, page 1 of 2
Preamble:
11.2 If at the time the Customer is directed to provide Ancillary Services the
Customer has an existing contract with the AESO, either directly or indirectly, to
provide the Ancillary Services in question from the directed facility (the “Existing
Contract”), then the amount to be paid to the Customer by the AESO for the
Ancillary Services shall be determined according to the terms of the Existing
Contract.
Request:
(a)
(b)
Response:
(a)
Please list and describe the existing contracts (including capacity) for each
Ancillary Service and indicate whether these contracts were the result of
competitive procurement in the prior 12 months.
Please provide pro-forma contracts for each Ancillary Service that the AESO
currently has entered into.
Please refer to FIRM.AESO-020 (a) for a list of all ancillary services.
The following is a list of existing contracts with generators (and contracted
capacity) for TMR service:
 Contract with ATCO – Poplar Hill 47MW
 IBOC contract with TransCanada – Carseland 81MW
 LBC SO contract with TransCanada – Bearcreek 50MW
 LBC SO contract with Calpine – Calgary Energy Centre 125MW
 LBC SO contract with ATCO – Valleyview 40MW
 Contract with Duke Energy – Rainbow 2 40MW
 Contract with ATCO – Rainbow 4 47MW
 Contract with ATCO – Rainbow 5 47MW
 Contract with Powerex – Fort Nelson 47MW
 Contract with Calpine – Calgary Energy Centre additional 75MW
 Contract with TransAlta – Bow Hydro 160MW
 Contract with EPCOR – Rossdale 219MW
The TransAlta (160MW) and Calpine (75MW) agreements are the only
two agreements the AESO has entered in to as a result of a competitive
process within the last 12 months.
(b)
Please see the attached three pro-forma contracts the AESO has currently
entered in to. These attachments are:
Page 2 of 2



Att. FIRM.AESO-021 – Attachment A
Att. FIRM.AESO-021 – Attachment B
Att. FIRM.AESO-021 – Attachment C
The majority of the AESO’s contracts are not pro-forma contracts, but bi-laterally
negotiated.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-022 (a)
Page 1 of 1
Reference:
Appendix A, Article 11 with Proposed Option 3, Ancillary Services, page 1 of 2
Preamble:
11.3 If at the time the Customer is directed to provide an Ancillary Service, the
Customer does not have an Existing Contract, then the amount to be paid to the
Customer by the AESO in respect of each Ancillary Service provided shall be the
greater of the following monthly amounts. Each amount is the sum for the month
of hourly compensation amounts.
(a) The product of the MW hour directed and the highest price paid in the hour to
Customers providing the same Ancillary Service pursuant to Article 11.2 provided
the service was not a TMR service and that the Existing Contract was the result
of a competitive process conducted in the prior 12 months; or
(b) For thermal units, the sum of the following:
I. An out-of-merit payment, when Pool Price is less than the Benchmark Price;
(Benchmark Price minus Pool Price) multiplied by the energy generated (MWh)
in compliance with the directive; plus
II. A capacity payment equal to Average Monthly Fixed costs multiplied by
Directed Out-of-Merit Ratio as defined below.
(c) The verifiable net opportunity cost related to foregone electricity sales
incurred by the Customer to supply the directed Ancillary Services taking into
account all offsetting revenues from any source, such as pool energy receipts.
Request:
(a)
Response:
(a)
If a gas fired unit provides TMR service if 11.3 (c) the only applicable provision
for calculating compensation; please elaborate.
Gas-fired units providing TMR services could be compensated under 11.2 or
11.3(b). It is unlikely that a gas-fired unit would forego other electricity sales due
to TMR service, therefore a determination under 11.3(c) would likely be zero or at
best not exceed the amounts in 11.3(b).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-023 (a)-(b)
Page 1 of 1
Reference:
Appendix A, Article 11 with Proposed Option 3, Ancillary Services, page 1 of 2
Preamble:
11.4 For the purposes of this Article, MW directed means the amount of an
Ancillary Service (expressed in MW) that is provided by the Customer in
response to a direction by the AESO.
Request:
(a)
(b)
Response:
(a)
(b)
How is the AESO directive provided to the generation unit in terms of capacity
and duration.
Can the directive be provided in terms of reactive power (VARS); if so does the
Article language need this reference.
ISO Rule 6.5, OPP 501 and OPP 510 provides the ISO form and protocol for
directives. In practice, the duration may not be included in a directive as a
specified time but rather as 'until further notice'.
Yes, refer to ISO rule 6.5, specifically 6.5.1(d) and 6.5.3(c). The AS Article does
not require amendment since the pool rules cover the requirements and since
there is no compensation associated with a reactive power directive.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-024 (a)-(j)
Page 1 of 3
Reference:
Appendix A, Article 11 with Proposed Option 3, Ancillary Services, page 2 of 2
Preamble:
Defined Terms:
Benchmark Price ($/MWh) equals (Heat Rate multiplied by Fuel Cost) plus
Variable STS Charges plus Variable O&M Proxy
Where:
Heat Rate (GJ/MWh) equals the actual heat rate of the Customer’s generating
unit during the period when the unit was complying with the directive;
Fuel Cost for a gas generating unit is Market Gas Price ($/GJ) is the “Daily Spot
Price at AECO C and NIT”, excluding weekends, as published in Canadian Gas
Price Reporter, for natural gas on the applicable day;
Fuel Cost for a coal generating unit will be provided by the Customer.
Variable STS Charges ($/MWh) is the actual cost of all variable charges from
Rate Schedule STS of the AESO’s applicable tariff, including the applicable loss
factor charge or credit;
Variable O&M Proxy ($/MWh) is the all in cost, fixed at $4/MWh, of providing
incremental output from the unit, excluding fuel costs and STS charges.
Directed Out-of-Merit Ratio (%) is the ratio for all hours of the month, including
hours when TMR service was not directed, of (1) the number of hours in the
month when TMR service was directed and the Benchmark price exceeded the
pool price; to (2) the sum of the number of hours in (1) above, and the number of
remaining hours in the month that the pool price exceeded the average
benchmark price for the month. The number of hours in the month that the pool
price exceeds the average benchmark will be reasonably adjusted to reflect the
physical characteristics of the Customer’s unit and its ability to capture the “inmerit” hours.
Average Monthly Fixed Cost is equal to the maximum amount of TMR
compensation as defined for purposes of Section 23 of the Transmission
Regulation, before prorating for joint use, and less the variable portion of such
costs, a portion of all of which may be included in the Benchmark Price.
Request:
(a)
(b)
Are Defined Terms part of Article 11.4.
How is the actual heat rate of a unit verified by the AESO.
Page 2 of 3
(c)
Is the heat rate specified for different operating ranges of the unit; please provide
an example.
(d)
How is the fuel cost for a gas generating unit determined on weekends.
(e)
How is the fuel cost for a coal generating unit determined and verified by the
AESO.
(f)
Is the benchmark price determined for each hour of the month.
(g)
Please provide the derivation of the $4.00/MWh variable O&M proxy cost,
specify and describe the cost components comprising this cost and indicate how
the incremental costs are differentiated from the base costs. Please provide the
derivation of the base costs for comparison.
(h)
Please provide a numerical example of the Directed Out-of-Merit Ratio for a
month showing all assumptions including benchmark prices and pool prices.
(i)
Please provide a numerical example of the contemplated adjustment to the
Directed Out-of-Merit Ratio to reflect the physical characteristics of the
Customer’s unit and the ability to capture “in-merit” hours. What is the potential
range of this adjustment.
(j)
Please provide a numerical example of the “average monthly fixed cost”
calculation and show the variable portion and any part included in the Benchmark
Price.
Response:
(a)
The defined terms are intended to apply to Article 11. In particular the defined
terms are referenced only in Article 11.3.
(b)
The approach to audits or verifications will be determined on an individual basis.
(c)
No, the AESO has not specified heat rate range requirements. The customer is
expected to provide actual heat rate information in an appropriate form for the
unit.
(d)
The Canadian Gas Price Recorder publishes daily prices for weekend days,
which would be used to determine the benchmark price on weekends.
(e)
As noted in the article, coal costs will be provided by the customer. Please see
(b) above.
(f)
Yes, the Benchmark price is determined hourly.
(g)
Please refer to IPPSA.AESO-032 (d).
(h)
Illustrative examples of Directed OOM Ratio follow:
2
Page 3 of 3
Non-Directed
In-Merit Hours
Case A
Case B
Case C
Case D
Directed InMerit Hours
Pool Price > Benchmark Price
400
100
200
100
100
100
20
20
Directed Outof-Merit Hours
Non-Directed
Out-of-Merit
Hours
Pool Price < Benchmark Price
100
120
100
320
100
420
100
580
Directed OOM
Ratio
17%
25%
33%
71%
Directed OOM Ratio = Directed OOM Hours/ (Non-Directed IM Hours + Directed
IM Hours + Directed OOM Hours)
(i)
The following table shows the Directed OOM Ratio assuming a 20% adjustment
has been made to the Non-Directed In-Merit Hours:
Case A
Case B
Case C
Case D
Non-Directed
Directed InIn-Merit Hours
Merit Hours
Pool Price > Benchmark Price
320
100
160
100
80
100
16
20
Non-Directed
Directed Out-ofOut-of-Merit
Merit Hours
Hours
Pool Price < Benchmark Price
100
120
100
320
100
420
100
580
Directed OOM
Ratio
19%
28%
36%
74%
The adjustment is limited to reasonable adjustments which reflect the physical
characteristics of the unit. AESO will determine any adjustment on a case by
case basis.
(j)
Please refer to IPCAA.AESO-012 (c) for a revised copy of Schedule E of the
2005 Amendment Application.
3
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-025 (a)-(e)
Page 1 of 2
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation,
Undepreciated Capital Investment (UCI), page 3 of 8
Preamble:
The following principles will be applied in determining the relevant UCI.
• Firstly, UCI for TMR compensation should only be based on the generating unit
providing the TMR service and should not include any costs for administration or
head office facilities. In the case where facilities are only used to generate
electric power, such as simple cycle gas turbines, the UCI for the generating unit
should be used in determining the return of and on investment.
• Secondly, the UCI amount should be based on the Customer’s property, plant,
and equipment costs for the specific generating unit providing the TMR service.
These costs must be consistent with the amounts reported in the Customer’s
audited financial statements. In cases where specific generating unit costs are
not individually reported in such financial statements, the Customer should be
required to provide upon request the necessary documentation to the AESO so
that these amounts may be independently verified and affirmed for their
accuracy.
• Thirdly, the UCI amount should be net of all accumulated depreciation. The
accumulated depreciation amount would also be consistent with the calculation
methods and amounts reported in the Customer’s audited financial statements.
Upon request, the Customer should be required to provide the necessary
documentation to the AESO so that accumulated depreciation amounts may be
independently verified and affirmed for their accuracy.
• Fourth, if the AESO or its predecessor has provided the Customer with prior
capital contributions towards the facilities used to provide the TMR service in
prior periods, these amounts should be deducted from the UCI calculation.
Without such a reduction, a Customer would receive excessive compensation.
Given the long-term economic life of generating units and in order to simplify the
applicable calculations, the AESO proposes to use the UCI at the start of a
calendar year and to determine the value for each month in which TMR services
are provided. In cases where TMR service is provided by a generating unit at or
near the end of its life and the UCI amount is at zero, return will reflect a
reasonable minimum return amount.
Request:
(a)
(b)
Does the AESO propose to include these principles as part of the Maximum
Compensation definition.
Does the UCI pertain to facilities that specifically provide TMR service or does it
apply to any facilities that provide Ancillary Services in the proposed Article 11.
Page 2 of 2
(c)
The UCI is proposed to be based on opening year balances in the accounts; why
is the utility convention of mid-year balances not used to determine the cost of
facilities in-service for a particular year. Opening year balances for UCI provide
excessive returns relative to mid-year balances; please discuss.
(d)
Are the capital contributions similar to CCIA in the utility accounting world; please
discuss. to How is the actual heat rate of a unit verified by the AESO.
(e)
What is the AESO proposal for a reasonable minimum return amount for facilities
at the end of their economic lives; what are the principles to be applied.
Response:
(a)
AESO will follow the principles in administrating Article 11. It is not proposed to
expand the definition of Maximum TMR Compensation to include the principles.
(b)
For TMR Maximum calculations, such calculations only pertain to TMR services.
The UCI is also used to calculate a Capacity Payment as referenced in Article
11.3(b)II, which could apply to any Ancillary Service, including TMR, required to
be conscripted.
(c)
AESO does not agree that using opening year balances will provide excessive
returns. The use of the opening balance is to reduce complexity and simplify
administration and reduce potential verification and audit costs. Simplified
methods are reasonable for periodic TMR compensation of non-regulated
generators compared to methods employed in the ongoing regulation of
regulated entities. For any conscription during a year, the UCI will be based on
the opening balance which will be available early in the year for verification and
audit. It is acknowledged that capital expenditures and depreciation during the
year may result in a net increase or decrease in UCI from the opening balance to
the time of the TMR service but such changes is not expected to render
compensation based on opening balances unreasonable.
(d)
The recognition of contributions to capital costs, and that an owner’s investment
is reduced by such contributions, is similar to CIAC for regulated utilities.
AESO's proposal to simply reduce the UCI by the amount of the contributions
may differ from the approach taken for regulated utilities but the purpose and
result are similar. Please refer to FIRM.AESO-024 (b).
(e)
Please refer to FIRM.AESO-018 (a).
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-026 (a)-(b)
Page 1 of 2
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Capital
Structure, page 5 of 8
Preamble:
This step determines an appropriate capital structure or the means of financing
the Customer’s investment in the generating unit providing TMR service. Such
financing typically includes debt financing, common equity financing, and
possibly other methods.
For simplicity the AESO proposes that a deemed capital structure is used with
70% debt and 30% common equity. This debt-equity ratio is consistent with the
evidence of the Ancillary Services Group dated February 21, 2002, filed in the
Board’s proceeding into Decision 2002-103.
Request:
(a)
(b)
Response:
(a)
(b)
Please provide any other considerations the AESO has taken into account other
than the 70/30 capital ratio and provide the assessments.
In App D [Pages 3-6], the AESO refers to several instances where the TMR
providers have the ability to earn significantly more compensation as a result of
the generator providing TMR service than it would providing service to the energy
market only. This appears to be even more so when TMR is provided by a
generator where there is little or no competition (as noted by Dr. Kahn). In light of
the ability to earn such excess revenues, please explain why a debt equity ratio
of 70/30 is considered appropriate. Please discuss the merits of an 80/20 debt
equity ratio to mitigate some of the additional returns available to the Customer
providing TMR service.
The question has been interpreted as “What considerations were taken into
account with respect to the proposal to use a 70/30 capital structure.” The key
considerations were fairness and simplicity. AESO has approached the
reasonableness of capital structure, rates of return, interest rates and tax costs
on an aggregate basis, with the intent being to ensure that the overall TMR
compensation is fair and reasonable. AESO did not retain experts to recommend
financial parameters, including capital structure, for compensation or conscripted
service but rather relied on EUB determined parameters from regulatory
proceedings.
The principle of “Minimizing Market Interference” is discussed at page 8 of the
Amendment Application. Under that principle, AS Article compensation
approaches are favoured which are not influenced by performance in the energy
market whether such performance may be perceived as leading to revenue
excesses or shortfalls. Also, under the proposed AS Article, concerns with
Page 2 of 2
perverse incentives have been addressed. As such the proposed 70/30
debt/equity remains appropriate.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-027 (a)-(c)
Page 1 of 2
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Rate of return
on equity and interest rate on debt, page 5 of 8
Preamble:
The equity rate of return on the equity portion of financing should reflect a
general market based cost of supplying equity capital for investment in an IPP.
The AESO proposes to use a 12% rate of return as was proposed in the
evidence of the Ancillary Services Group dated February 21, 2002.
In selecting the rate of return level, the AESO considered other potential
references it was aware of. A rate of return formula has been approved for
regulated utilities in Alberta in Generic Cost of Capital Decision 2004-052.
Applying the formula yields a value of 9.5% for 2005. The method used in the
Power Purchase Arrangements (“PPAs”) as approved under Decision U99113
yields a value of about 9.5%, and is based on the average of daily close of
trading yields (%) for Canadian government bonds of 10 years or more maturity
plus an equity risk premium assumed constant over time at 4.5%.In the evidence
of the Ancillary Services Group dated February 21, 2002, a 12% rate of return
was proposed.
Request:
(a)
Please provide the calculation and supporting details for 2006 resulting from the
Generic Cost of Capital Decision and the PPA Decision.
(b)
At page 9 of Appendix D, AESO states that the ROCE percent “should be
established using the method contained in the Purchase Power Agreements
approved by the Board in Decision U99113.” Please quantify the return for 2004
and 2005 under Decision U99113 and discuss why in light of the detailed
assessment of the ROCE in recent Decision 2004-052, the AESO does not
consider the EUB-approved ROCE in Decision 2004-052 to be more appropriate
than that derived from Decision U99113.
(c)
In App D [Pages 3-6], the AESO refers to several instances where the TMR
providers have the ability to earn significantly more compensation as a result of
the generator providing TMR service than it would providing service to the energy
market only. This appears to be even more so when TMR is provided by a
generator where there is little or no competition (as noted by Dr. Kahn). In light of
the ability to earn such excess revenues, please explain why a ROCE as
determined by Decision U99113 is considered appropriate. Please discuss the
merits of a downward adjustment to the allowed ROCE to mitigate some of the
additional returns available to the Customer providing TMR service.
Response:
(a)
Interest rate information for 2006 calculations comes available late in 2005 and is
not available at present.
Page 2 of 2
The calculation of 2005 Generic ROE per EUB Order U2004-423 dated
November 30, 2004 is as follows:
ROE = 9.60%+ [0.75 x (YLD – 5.68%)]
where YLD = the forecast long-term Canada bond yield
For 2005, YLD = 5.05%
ROE for 2005 = 9.60%+ [0.75 x (5.05% – 5.68%)] = 9.5%.
The estimation of 2005 PPA ROE is described in Appendix 3 of AESO’s January
10, 2005 Additional Evidence which is included as Appendix D of the Amendment
Application.
ROE = GBY + 4.5%.
where GBY = average of daily close of trading yields (%) for
Canadian government bonds of 10 years or more maturity for all
trading days in the months of September, October and November
of the previous year (ie: y-1) published in the Bank of Canada’s
weekly Financial Statistics publication. (CANSIM code: B114022
for daily data).
For 2005, GBY = 5.0%
PPA ROE for 2005 = 5.0% + 4.5% = 9.5%.
(b)
For 2004, GBY = 5.3%, therefore PPA ROE for 2004 is estimated at 9.8%. The
2005 PPA ROE is shown in part (a) above.
The PPA return is favoured for the following reasons:
 The PPA return relates to compensation of generation units whereas the
Generic ROE per 2004-052 relates to transmission and distribution
functions.
 The PPA return is based on actual or historic bonds yields rather than
forecasts for upcoming periods. Article 11 settlements are for AS services
already provided rather than services forecast in an upcoming period.
(c)
Under option 3, issues with perverse incentives that cause increased
compensation are addressed. Secondary benefits associated with TMR service
remain available to the generator as noted in FIRM.AESO-043 (b), however the
overall level of compensation provided in Option 3 is within a reasonable range.
Please also see the response to FIRM.AESO-026 (a). No further ROEC
adjustment is proposed to take account of secondary benefits.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-028 (a)-(b)
Page 1 of 1
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Rate of return
on equity and interest rate on debt, page 5 of 8
Preamble:
The debt rate on the portion financed by debt should reflect a general marketbased cost of supplying debt to an IPP. The AESO proposes to use the debt rate
formula proposed in the evidence of the Ancillary Services Group dated February
21, 2002. The debt rate would be equal to a 10-year Government of Canada
Bond interest rate plus 0.5%.
Request:
(a)
(b)
Response:
(a)
(b)
Please provide the details and methodology of determining the 10-year
Government of Canada Bond interest rate to be used in the calculation including
the source of the information, whether it is at a single point in time or if future
forecasts of the interest rate is taken into account and whether there is any
averaging of historical and/or future interest rates.
What is the purpose of the 0.5% adder.
The interest rate to be referenced would be the average of published rates for the
period of the TMR service and not a forecast rate.
As noted, the 0.5% adder is taken from the Ancillary Services Group evidence. It
is AESO’s understanding that such adders have been included for other
regulated entities to reflect that interest rates available to commercial entities
exceed those available to the Government of Canada.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-029 (a)-(c)
Page 1 of 1
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Rate of return
on equity and interest rate on debt, Income Tax costs, page 6 of 8
Preamble:
Equity returns create an income tax cost. The income tax rates will be assumed
to be at marginal tax rates for both federal and provincial portions of tax.
Request:
(a)
Why will actual tax rates for the customer not be used in the calculations.
(b)
If the supplier has zero or lower rates of tax why will AESO load customers be
responsible for paying these notional income tax costs.
(c)
Please discuss the question of paying notional income taxes in the context of
previous EUB decisions on AltaLink on this issue.
Response:
(a) - (c) The use of marginal tax rates was assumed for simplicity. Determining the actual
tax associated with TMR services from a specific unit could require significant
examination of other parts of a customer’s business and determination of
average and marginal tax rates and the appropriate use of one or the other or a
combination. The approach proposed appears reasonable in aggregate. Please
see also FIRM.AESO-026(a).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-030 (a)
Page 1 of 1
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Total Return
Costs, page 6 of 8
Preamble:
Monthly returns are 1/12 of annual amounts for amortization and depreciation,
debt, equity and income tax amounts.
Request:
(a)
Response:
(a)
Please provide a numerical example to show the calculation of annual return
amounts based on the UCI with opening balances rather than the UCI with midyear balances.
Examples are included in Appendix E of the Amendment Application. A revised
Appendix E is attached to IPCAA.AESO-012(c). The examples are based on UCI
opening balances.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-031 (a)-(d)
Page 1 of 2
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Total Return
Costs, page 6 of 8
Preamble:
On a monthly basis, the TMR share of total monthly return costs will be a prorated share based on the number of hours of TMR service compared to the sum
of the number of hours of TMR service plus the number of non-TMR service
hours in which the unit was in merit in the energy market. The number of nonTMR, in-merit service hours will be reasonably reduced if the characteristics of
the Customer’s unit were such that the unit would not be capable of capturing the
benefits of all of the in-merit hours. The TMR share of total monthly return costs
may also be reduced if the unit was only partially used for TMR service.
Request:
(a)
Please explain why the pro-ration is not on the basis of all hours in the month.
(b)
Please explain the exclusion in the pro-ration of non-TMR hours in which the unit
was out-of-merit and provide a numerical example showing the impact on the
pro-ration if these excluded hours are taken into account.
(c)
Please describe the basis and circumstances of a unit not be able to capture the
benefits of all the in-merit hours.
(d)
Please describe the pro-ration changes if a unit is only used partially in the month
for TMR service.
Response:
(a)
(b)
The prorating is intended to start with or include all hours of the month. The
prorating calculation then determines which hours serve a TMR use and which of
the remaining hours that the unit was in-merit. In some hours, it appears that no
use of a unit is being made.
The pro-rating principle being proposed is to allocate costs among hours of use
for different purposes. When a unit is used for a particular purpose, the hour is
determined for that use. When a unit is not directed for an Ancillary Service and
is out-of-merit in the energy market, it appears not to be serving either use. The
unit may be shutdown in such an hour or it may be operating due to unit
characteristics which do not permit quick shutdown in such periods and restart
when it comes into merit. The revenues the generator is receiving in such hours
do not cover variable cost associated with operating the unit, so there is no
contribution being made to fixed costs. The prorating proposed refrains from
prorating fixed costs to periods when the unit is not fulfilling any use. If no use of
a unit occurs in an entire month, all fixed costs remain with the generator as
there is no TMR compensation in such a month.
Page 2 of 2
Please refer to example calculations in FIRM-AESO-24(h). If the Directed OOM
ratio was changed to include non-directed OOM hours in the denominator, the
Ratio would be as follows:
Directed OOM Ratio = Directed OOM Hours / (Non-Directed IM Hours +
Directed IM Hours + Directed OOM Hours + non-directed OOM
hours)
Such a change to the Directed OOM ratio would decrease the ratio in all
examples resulting in a lower allocation of costs to TMR service.
(c)
Please refer to page 14, line 12 of the Amendment Application.
(d)
The prorating formula would only count those hours where TMR service was
directed. Please see (a) above.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-032 (a)-(b)
Page 1 of 1
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Operation
and Maintenance costs, page 6 of 8
Preamble:
Pro-rated share.
Request:
(a)
(b)
Please explain why the pro-ration of operating and maintenance costs is not on
the basis of all hours in the month.
Please provide the details of step 10 that describes the pro-ration process for a
partially used unit for TMR service.
Response:
(a)
Direct O&M costs are not prorated. Indirect or fixed O&M costs are prorated in
the same manner as return costs. Please refer to FIRM.AESO-031(a).
(b)
Please refer to IPPSA.AESO-033(b).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-033 (a)-(b)
Page 1 of 1
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Credits for
common costs, page 7 of 8
Preamble:
The UCI of all common facilities up to the point where other services are sold or
provided would be included in the UCI under step one above. The depreciation
provisions, return on equity, etc. would be based on the UCI including all of the
common facilities. Similarly, all fuel, operating, and maintenance costs would be
included as costs.
Request:
(a)
(b)
Response:
(a)
(b)
Please provide a schematic of typical common facilities that illustrates the
facilities that would be included in UCI and the remaining facilities that are not
included. Explain why the pro-ration of operating and maintenance costs is not
on the basis of all hours in the month.
Please provide the details of step 10 that describes the pro-ration process for a
partially used unit for TMR service or when the unit is used to produce other
products such as steam or hot water as described on page 10 of App D.
Please refer to IPPSA.AESO-012 from the AESO 2005-06 GTA. A copy of this
response is included along with other TMR Maximum responses filed in
IPPSA.AESO-034(b). Please also see FIRM.AESO-031(a) and (b).
Step 10 is illustrated in Appendix E of the Amendment Application. Please refer
to IPCAA.AESO-012(c) for the revised Appendix E.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-034 (a)-(b)
Page 1 of 1
Reference:
Appendix B, 6.4 Maximum Transmission Must-Run Compensation, Adjustments
for partial use, page 8 of 8
Preamble:
The portion of the UCI of the unit and other fixed or indirect costs of the unit to be
considered for TMR compensation would be based on the average MW directed
for TMR service as a percentage of the average maximum MW capacity of the
unit.
Request:
(a)
(b)
Response:
(a)
(b)
Is the average maximum MW capacity of the unit equal to the hourly weighted
amount for the month?
Is the average MW directed for TMR service equal to the hourly weighted amount
for the month?
Please refer to FIRM.AESO-048 (a).
Please refer to FIRM.AESO-048 (b).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-035 (a)
Reference:
Appendix C, page 1 of 1
Preamble:
Transition Issues between Article 24.3 (b) and 24.3 (c)
Request:
(a)
Response:
(a)
Page 1 of 1
Please provide the spreadsheet and all assumptions that supports the
development of the graph provided.
Please refer to IPPSA.AESO-017(a).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-036 (a)
Reference:
Appendix E, Maximum TMR Compensation
Preamble:
Table provided
Request:
(a)
Response:
(a)
Page 1 of 1
Please provide the spreadsheet and all assumptions that supports the
development of the graph provided.
The spreadsheet was provided with the application. The assumptions are shown
on the top of the spreadsheet as “Input Amounts”. Please refer to IPCAA.AESO012(c) for a corrected spreadsheet.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-037 (a)
Page 1 of 4
Reference:
Appendix D General
Preamble:
The CG wishes to understand the nature and extent of the AS services provided
by various generators in 2004 and forecast for 2005-06.
Request:
(a)







Please provide a summary of all contracted and conscripted TMR Services for
2004 (Actual), including the following details:
Generating Plant(s)
% of plant capacity
Number of hours
MWH conscripted versus contracted
CIAC associated with each plant
Fixed costs paid for plant other than costs associated with generating plant [e.g.
administrative/head office facilities as described on page 10, App D]
Other pertinent details affecting compensation payment
Response:
(a)
In 2002, 2003, 2004 and 2005 (to date) the AESO had or has under contract, forTMR
service, the following:
Plant
Poplar hill
Cavalier
Carseland
Balzac
Calpine
Calpine
Bearcreek
Valleyview
Fort
Nelson
Rainbow 2
Rainbow 3
Rainbow 4
Rainbow 5
HR Milner
Rossdale
Contracted
Capacity (MW)
47
103
81
97
100/125
Additional 75
50
40
47
40
21
47
47
143
209
2005 (to
date)
x
2002
x
x
x
x
x
2003
x
x
x
x
x
2004
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
Page 2 of 4
Bow Hydro
System
Calgary
area
TMR
Maxim 3
160
x
200
7
x
In 2002, 2003, 2004 and 2005 (to date) the AESO conscripted non-contracted TMR
service, from the following:
2002
Plant
Balzac
Cavalier
Valleyview
Rainbow 2
Rainbow 3
Rainbow 4
Rainbow 5
Sturgeon 1
Sturgeon 2
Cascade
2003
2004
2005 (to
date)
Unit
Capacity (MW)
120
120
47
40
21
x
x
x
x
x
x
x
x
x
10
8
20
x
x
x
x
For purposes of the AESO’s 2005/2006 GTA TMR Forecast, it was forecasted the AESO
would receive TMR service under contract from the following generating plants:
Plant
Poplar hill
Carseland
Calpine
Bearcreek
Valleyview
Fort
Nelson
Rainbow 2
Rainbow 4
Rainbow 5
Rossdale
Calgary
area
TMR
Contracted
Capacity (MW)
2005
x
x
2006
x
x
125
50
40
x
x
x
x
x
x
47
40
47
47
209
x
x
x
x
x
x
x
x
x
200
x
x
47
81
2
Page 3 of 4
For the AESO’s 2005/2006 GTA Forecast, the AESO did not forecast any TMR
conscriptions.
The AESO dispatched contracted TMR in 2002, 2003, 2004 and 2005 (to date) in each
hour of the year.
The AESO conscripted non-contracted TMR for approximately:

2000 hours in 2002

20 hours in 2003

5500 hours in 2004

100 hours in 2005 (to date)
The high number of conscriptions in 2002 was due to the Engage dispute that was ongoing from 2001.
The high number of conscriptions in 2004 was due to the ATCO dispute that commenced
on May 1, 2004.
The AESO dispatched contracted TMR for approximately:

1,500,000 MWhs in 2002

1,600,000 MWhs in 2003

850,000 MWhs in 2004

600,000 MWhs in 2005 (to date)
The AESO conscripted non-contracted TMR for approximately:

30,000 MWhs in 2002

200 MWhs in 2003

180,000 MWhs in 2004

1500 MWhs in 2005 (to date).
AESO considers the remainder of the requested information as being either commercially
sensitive or confidential pursuant to the terms of an agreement between the AESO and an
ancillary service provider. As a general practice, the AESO does not disclose ancillary
service information to a level of detail that would either impair the AESO’s ability to
procure ancillary services on reasonable terms in future or violate the AESO’s obligations
under the terms of an ancillary service agreement.
Most of the AESO’s ancillary service agreements contain confidentiality provisions that
restrict the disclosure of information unless such disclosure is required by law or by order
of a regulatory tribunal having jurisdiction unless specifically authorized by the counterparty or unless such information is already in the public domain.
If the requested information is commercially sensitive but not confidential, the AESO will
expeditiously disclose same in confidence to the AEUB if ordered to do so. If the
requested information is confidential pursuant to the terms of an ancillary services
agreement, the AESO will disclose same in confidence to the AEUB if ordered to do so
once the AESO has provided the counter-party with reasonable notice of the AEUB’s
3
Page 4 of 4
order to disclose so that they may exercise all of their rights, including those in law, to
prevent such disclosure.
4
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-038 (a)-(f)
Page 1 of 2
Reference:
Appendix D, Page 2, Resolution of dispute with ATCO Power
Preamble:
“Parties to this proceeding have become aware of a dispute arising between the
AESO and ATCO Power that concerns compensation payable for TMR service
conscripted from the Rainbow 4 and 5 units on a sustained basis for the period
May 1, 2004 to December 16, 2004. An issue in dispute for this time period
concerns the proper interpretation of the elements comprising Article 24.3(c)
used to determine compensation for conscripted services. The potential
magnitude of this dispute is significant. The AESO is aware of other potential
circumstances where similar interpretation issues may exist in respect of this
provision.” [App D, page 2]
At page 3 of the filed Application, AESO notes that the dispute with ATCO Power
has now been resolved, including agreement on TMR services from Rainbow
Units 3 and 4 and issues related to AS Article compensation since May 1, 2004.
Request:
(a)
Please provide the date of the agreement with ATCO Power as noted above.
(b)
Please quantify the magnitude of this dispute on a monthly basis for the
referenced period.
(c)
Please provide details of the interim compensation arrangements paid ATCO
Power pending the resolution of this issue for the period May 1, 2004 to
December 16, 2004.
(d)
Please provide details of all true-up adjustments between the interim payments
to ATCO Power and final payments based on the above noted agreement for the
period May 1, 2004 to December 16, 2004.
(e)
The AESO states that it “is aware of other potential circumstances where similar
interpretation issues may exist in respect of this provision.” Please explain if the
AESO has had discussions with other generators who face similar issues
surrounding the interpretation of Article 11/24, and the results of these
discussions (if any).
(f)
Please explain if the filed AS Amendment Application is consistent with the
settlement with ATCO Power. If not, please confirm that the Board-determined
solution will apply to all AS services provided by ATCO Power effective Dec 17,
2004.
Response:
(a), (d) & (f)
Please refer to FIRM.AESO-001(c).
Page 2 of 2
(b) & (c)For the May 1, 2004 to December 16, 2004 period, AESO’s compensated ATCO
Power at total of $13.7 million related to conscripted TMR services. Unless
satisfactory resolution on longer term issues occurs, ATCO Power is seeking
additional compensation for this period.
(e)
Interpretation issues with respect to Article 24.3 (c) are focused around
appropriate cost of service parameters, including amortization periods and return
on equity. The AESO has had discussions with other generation owners and
these discussions confirm similar interpretation issues, although all other
disputes have been settled.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-039 (a)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, page 2, A3.
Preamble:
Parties to this proceeding have become aware of a dispute arising between the
AESO and ATCO Power that concerns compensation payable for TMR service
conscripted from the Rainbow 4 and 5 units on a sustained basis for the period
May 1, 2004 to December 16, 2004. An issue in dispute for this time period
concerns the proper interpretation of the elements comprising Article 24.3(c)
used to determine compensation for conscripted services. The potential
magnitude of this dispute is significant.
Request:
(a)
Please quantify the magnitude of this dispute on a monthly basis for the
referenced period.
Response:
(a)
Please refer to FIRM.AESO-038 (b).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-040 (a)-(c)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, page 2, A4.
Preamble:
The AESO is seeking the Board to endorse certain principles that should be used
to quantify the level of compensation arising under Article 24.3(c).
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.
Request:
(a)
Does the AESO propose that the Board determined principles would apply to
TMR compensation levels for the period May 1, 2004 to December 16, 2004.
(b)
Are there ATCO Power TMR compensation payments for RB 4 and 5 units
during this period that would be subject to recalculation and potential refund to
the AESO based on applying the Board approved principles.
(c)
Would ATCO Power RB 4 and 5 TMR compensation payments during this period
be subject to the third party dispute resolution process or could the matter be
resolved by the Board upon application.
Response:
(a)
(b) & (c)
Yes.
ATCO Power has been compensated for TMR services during the referenced
period. ATCO Power has disputed the compensation amount. Following a Board
decision regarding compensation principles during the referenced period, the
Parties will attempt to resolve the dispute in accordance with Article 19 of
AESO’s Terms and Conditions of Service. AESO has not disputed the
compensation during the referenced period and is not seeking a refund.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-041 (a)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, page 3, A5.
Preamble:
The relief above should be viewed for a purpose different from that set forth in
the Amendment Application.
The relief set forth in this Additional Evidence addresses interpretation issues
arising during the period in which existing Article 24 remains in effect.
Request:
(a)
Response:
(a)
Do the interpretation issues arise only in the period May 1, 2004 to December 16,
2004 or could they apply to an earlier period.
There is only one dispute remaining with the existing Article 24 and it is for the
period referenced in the question.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-042 (a)-(b)
Reference:
Preamble:
Q6.
A6.
Request:
(a)
(b)
Response:
(a)
(b)
Page 1 of 1
Appendix D, Additional Evidence of January 10, 2005, page 3, Q6.
Is the AESO requesting the Board to make a determination of the compensation
payable under Article 24.3(c) in respect of the dispute arising with ATCO Power?
Not at this time. Subsequent to the Board’s December 16, 2004
correspondence, the AESO and ATCO Power were able to reach a short-term
agreement concerning the provision of TMR Service. The parties have agreed to
use the dispute resolution provisions of the Tariff to resolve any outstanding
disputes that may arise following the determination of this Application. Only after
the Board has provided its views on the proper principles to be used in respect of
Article 24.3(c) will it be possible for the parties to determine if any specific
quantification issues remain in dispute and require further and potentially formal
dispute resolution processes and procedures under Article 16 of the Terms and
Conditions.
Will the AESO request approval of the current agreement with ATCO Power in
conjunction with the Ancillary Services Article Amended Application.
Please provide the details of the short-term agreement reached with ATCO
Power. Include in this response the duration of this agreement, how it is different
from the compensation under Article 24 as amended in the Aug 16, 2004
Application, and whether any other parties were engaged in these discussions
Please refer to FIRM.AESO-001. Board approval of individual AS contracts is not
required.
The duration of the agreement is from December 17, 2004 to December 31,
2005.
Compensation under the agreement is of an interim nature. The interim
compensation is not consistent with the amendment as proposed in 2004
Amendment Application. Adjustments to compensation will be made to reflect a
decision by the Board on matters raised in this proceeding.
Compensation is limited by the TMR Maximum established under Section 23 of
the Transmission Regulation.
ATCO Power and AESO were parties to the agreement and the discussions
leading to the agreement.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-043 (a)-(c)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, page 3-4
Preamble:
The CG wishes to have a further understanding of the three areas noted at
pages 3-4 where generators stand to receive additional revenues under the
existing provisions of Article 24.
Request:
(a)
Please provide numerical examples illustrating how a generator could potentially
receive more compensation when conscripted under Article 24 than it would in
the energy market. Please explain if this potential also arises under conditions of
contracted services.
(b)
Please provide a numerical example of each of the 3 forms of indirect or
secondary benefits arising when TMR service is conscripted under Article 24.
(c)
At page 6 of App D, the Application refers to conscription of TMR services under
conditions of “poor or no-competition”. AESO discusses that under these
conditions, a customer is “assured of being conscripted” and will offer higher
prices and receive increased compensation as a result of increased volumes of
conscripted service. Under these conditions, please discuss the merits of the
Board establishing some guidelines or principles to minimize such perverse
incentives available to generators and suggest some mechanisms which would
service to mitigate such incentives. Also, please discuss if the AESO is aware of
such exercise of market power.
Response:
(a) and (b) Please refer to the illustrative examples in the attached spreadsheet (Att.
FIRM.AESO-043). The same secondary benefits can also arise for units under
TMR contracts.
(c)
The AESO believes that the proposed amendments to the AS Article represents
an appropriate tariff solution which eliminates the perverse incentive discussed.
The alternative approach as cited in the question would leave the perverse
incentive in place and establish guidelines and principles to mitigate the
incentives. Such an alternative approach appears to be less desirable as it does
not resolve the root issue, that being the perverse incentive in the tariff. It is also
likely that development and enforcement of such guidelines and principles would
require ongoing attention and processes and cause ongoing costs. Even given
significant attention and costs, such an approach may not resolve the issue.
AESO continues to suggest a tariff approach which removes the perverse
incentive is preferred.
Regarding the AESO’s awareness of market power, please refer to the Evidence
of Dr. Kahn in Appendix D of the 2005 Amendment Application and see also
PWX.AESO-011(b).
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-044 (a)-(c)
Page 1 of 2
Reference:
Appendix D, Additional Evidence of January 10, 2005, page 6
Preamble:
The AESO requested Dr. Edward Kahn, Managing Partner with Analysis Group
Inc., to consider the issue of market power as it affects conscriptions under
Article 24. Dr. Kahn was also asked to assess the competitiveness of the
northwest region of the province. This is an area where sustained conscriptions
have occurred.
Request:
(a)
To appreciate the extent of sustained conscriptions in the northwest area please
provide historical data on sustained conscriptions by unit and duration and by
month for each of the years 2002, 2003 and 2004.
(b)
To place a) in context please provide the total MWhs of conscriptions in the
northwest area by month for 2002, 2003 and 2004.
(c)
Dr. Kahn expresses the view that “conscriptions are influenced by market power
and that the Rainbow Lake area of the province is not conducive to market
competition for TMR service….In Dr. Kahn’s view, a regulated solution to
acquiring TMR service is necessary.” In light of this recommendations, please
explain the nature of “regulated solution” which would mitigate concerns of
market power in the Rainbow Lake area and when such solution(s) may be
implemented.
Response:
(a) and (b) Please refer to FIRM.AESO-037.
(c)
When local conditions in a particular area of a power market are not amenable to
competition, necessary generation can be acquired through various regulatory
schemes. Two common possibilities are mandatory contracting and controls on
bidding. The mandatory contract approach has been used in the U.S., where it is
referred to often as Reliability Must Run (RMR) contracting. RMR contracts
typically provide both fixed and variable payment components. These payments
are based on estimates of cost. The bid control approach can involve a “must
offer” requirement, coupled with some kind of upper bound, or cap, on offer
prices. The “must offer” requirement means that the designated generator cannot
refrain from bidding his capacity. The offer cap specifies the maximum price
allowable. Price caps are sometimes designed to allow generators to recover
going-forward costs. For example, in the Midwest ISO in load pockets known as
narrow constrained areas (NCAs), bid caps are related to the fixed and variable
costs of a typical peaking unit and the fraction of the year in which transmission
into each NCA is constrained. PJM’s market rules allow generators whose bids
Page 2 of 2
are capped for more than 80 percent of their run-hours to add a premium to their
bid that is designed to facilitate fixed-cost recovery.
The AESO has proposed amendments to the AS Article to be implemented.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-045 (a)-(c)
Page 1 of 2
Reference:
Additional Evidence, pages 10 and 11
Preamble:
A final complexity concerns whether contributions made in respect of the capital
costs of the facilities providing the conscripted service made by the AESO or its
predecessor in prior periods should be treated as a deduction to the UCI
calculation.
A16. Yes. If the AESO or its predecessor have provided the Customer with
contributions towards the capital of the facilities used to provide the conscripted
service in prior periods, these amounts should be deducted from the UCI
calculation. Without such a reduction, a Customer would receive excessive
compensation.
A17. Given the long-term economic life of generating units and in order to
simplify the applicable calculations, the AESO proposes to use the UCI at the
start of a calendar year and to determine the value for each month in which
services are conscripted.
Request:
(a)
Does the AESO consider the prior contributions to capital costs in respect of the
Undepreciated Capital Investment (UCI) calculations to be similar to the
regulatory treatment of Contributions In Aid of Construction (CIAC); please
discuss.
(b)
Since calculations of return will be dependent on the UCI determination has the
AESO considered using a mid-year average for UCI; please discuss this
response in light of the fact that the opening balance may be overstated in
relation to the mid-year balance (assuming all other things being equal) due to
the recognition of depreciation expense for the year. As well, please include in
this discussion why AESO considers it appropriate to deviate from the traditional
“mid-year” approach used by the EUB in its rate base determinations.
(c)
At page 8 of App D, AESO proposes amounts related to UCI and accumulated
depreciation should be “consistent with the Customer’s most recent publicly
available financial statements.” Assume that the Customer has reflected a
significant change in its financial statements by recognizing accelerated
depreciation and the auditors have accepted this change to reflect “market” life
as opposed to “physical” life. Will AESO under these circumstances automatically
accept the accumulated depreciation as per the Customer’s financial statements
or will it question such a change which might be appropriate for GAAP purposes
but not for TMR compensation purposes? Please discuss.
Response:
Page 2 of 2
(a)
Please refer to FIRM.AESO-025 (d).
(b)
Please refer to FIRM.AESO-025 (c).
(c)
AESO proposes to adopt the depreciation methods and amounts consistent with
those used for the customer’s audited financial statements. In the example
above, if the auditors determine the change is appropriate in the circumstances,
AESO proposes to adopt the change. AESO has the opportunity to verify the
amounts on a case by case basis.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-046 (a)-(b)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, page 12
Preamble:
The AESO does not consider conscription of TMR to in any way reduce the
economic life of the asset. As a result, the amortization period included in Article
24.3(c) compensation should be equal to the economic life of the asset.
The applicable amortization period, depreciation rates and the resulting
depreciation amount for the asset should be consistent with how these amounts
have been reported in the Customer’s audited financial statements.
Request:
(a)
(b)
Please provide the AESO considerations in determining the economic life of a
unit.
If there is a difference between the AESO determined economic life and the life
determined pursuant to the Customer’s financial statements does the financial
statement data prevail; please discuss the procedure for reconciliation.
Response:
(a) & (b) AESO is not proposing to establish its own criteria for determining the economic
life of the unit nor conduct its own studies on the life of a customer's unit.
AESO's proposal is to adopt the economic life and the amortization period which
are consistent with those used by the customer in its audited financial
statements.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-047 (a)-(b)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, page 14
Preamble:
The UCI of all common facilities up to the point where other services are sold or
provided would be included in the UCI under Article 24.3(c).
Request:
(a)
(b)
Response:
(a)
(b)
Please provide a schematic of generating units with common facilities to illustrate
the cut-off point for common facilities to be considered as part of a unit UCI.
Please provide a numeric example illustrating how the AESO proposes to
recognize the capital and operating costs associated with common facilities, as
well as the determination of the net compensation costs from the provision of
other services.
Please refer to IPPSA.AESO-012 (b) from the 2006 GTA a copy of which is
attached to IPPSA.AESO-034(b).
Please refer to IPCAA.AESO-013 and Appendix E of the 2005 Amendment
Application. Please refer to IPPCA.AESO-012 (c) for a revised version on
Appendix E.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-048 (a)-(c)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, page 14
Preamble:
A29. In cases where the unit is only partially conscripted and the remainder of
the unit’s capacity is available to provide other electric services, the portion of the
UCI of the unit and other costs of the unit to be considered for Article 24
compensation would be based on the average MW conscripted as a percentage
of the average maximum MW capacity of the unit.
Request:
(a)
Please provide an example for the calculation of the average maximum MW
capacity of the unit.
(b)
Please explain what is meant by “average MW conscripted” and include in this
response if the average capacity computation takes into account down time of
the unit?
(c)
Is the average maximum capacity determined on a daily, monthly, or annual
basis?
Response:
(a)
Assume that a unit is available to operate for 700 hours in a month. Assume also
that for 350 of the 700 hours the maximum MW capacity was 45 MW. For the
remaining 350 hours assume the maximum MW capacity was 35 MW. The
average maximum MW capacity would be 40 MW [(350 hours x 45 MW + 350
hours x 35 MW) / 700 hours].
(b)
Average MW conscripted is the average of hourly levels of the Ancillary Service
provided in compliance with a directive. Down time of a unit would not be
included as the unit would not have been providing any Ancillary Services.
(c)
The average maximum capacity would be determined monthly on the basis of
hourly information for the hours that the unit was available to operate.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-049 (a)
Page 1 of 1
Reference:
Additional Evidence, Appendix 2, Report of Edward Kahn
Preamble:
General. Mr Kahn makes a number of references in footnotes to his report.
Request:
(a)
Please provide copies of the references included in footnotes that are not
supplied with an internet source reference.
Response:
(a)
Footnote # 12
These cases involve AES and Williams in one instance and Reliant in another.
The AES/Williams matter is discussed in “Order Approving Stipulation and
Consent Agreement,” Docket No. IN01-03-001, April 30, 2001, 95 FERC ¶61,
167 (http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=6014224). The
Reliant matter is discussed in “Order Approving Stipulation and Consent
Agreement,” Docket No. PA02-2-001, 102 FERC ¶ 61,108
(http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=9630506), January
31, 2003. In both cases, the settling supplier agreed to return money to
customers.
Footnote # 17
Federal Energy Regulatory Commission, Order on Rehearing and Modifying
Interim Generation Market Power Analysis and Mitigation Policy, April 14, 2004,
107 FERC ¶61, 018
(http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=10116044).
Footnote # 14
Attached separately as Att.FIRM.AESO-049 Attachment A - Economics of
Regulation and Antitrust.
Footnote # 15
Attached separately as Att.FIRM.AESO-049 Attachment B - Measuring Market
Inefficiencies in California’s Restructured Wholesale Electricity Market.
Footnote # 22
Attached separately as Att.FIRM.AESO-049 Attachment C – Auctions: Theory
and Practice.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-050 (a)-(c)
Page 1 of 1
Reference:
Additional Evidence, Appendix 2, Report of Edward Kahn, para 10, page 5
Preamble:
The controlling entity for each of the units, RB2, Ft. Nelson, RB4 and RB5 are
provided.
Request:
(a)
Please list the ownership entities and percentage of ownership for each of the
units referenced.
(b)
Please provide the load in the Rainbow Lake area on a MW and MWh basis for
2002, 2003 and 2004.
(c)
For co-owners of Rainbow Lake generation units please provide their load in the
Rainbow Lake area, if any, in MWs.
Response:
(a)
ATCO Power owns Rainbow units 1, 2 and 3. Rainbow 4 and 5 are jointly owned
by ATCO Power and Husky. BC Hydro owns the Fort Nelson unit.
(b)
Rainbow Lake Area Load data is as follows:
2002 2003 2004
Peak (MW)
143
137
142
Energy (GWh)
949
930
925
(c)
Husky load information is not available to AESO.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-051 (a)-(c)
Page 1 of 2
Reference:
Additional Evidence, Appendix 2, Report of Edward Kahn, para 16, page 8
Preamble:
The pivotal supplier concept is relevant to conditions in the Rainbow area. A
supplier is deemed pivotal if its capacity is required to meet demand. This
concept has been incorporated into the market power screening process adopted
by the Federal Energy Regulatory Commission. FERC adopts both the pivotal
supplier test and a market share test applied to geographic markets defined as
control areas. If a supplier fails either of these tests, then evidentiary hearings
are required to determine if such a supplier should be allowed to charge market
based rates for wholesale power or not. In implementing the pivotal supplier
concept, FERC relies on the notion of “uncommitted” capacity to reflect load
obligations that a generator may have.
Request:
(a)
Please provide details of the pivotal supplier test.
(b)
Please elaborate on the notion of “uncommitted” capacity and provide an
example.
(c)
Please elaborate and provide details on the FERC Delivered Price Test.
Response:
(a) & (b)
The pivotal supplier test used by FERC in assessing whether an entity should be
allowed to sell wholesale power at Market Based Rates is discussed in ¶94-99 of
the Commission’s April 14, 2004 Order in AEP Power Marketing, Inc., et al., 107
FERC ¶ 61,018 (2004) (“the April order”) approving the use of the screen.1 The
test involves determining whether the applicant’s uncommitted capacity is
necessary to meet peak load in the applicant’s own control area. The applicant’s
uncommitted capacity is calculated as the difference between his resources,
including owned generation and long-term firm purchases, and an estimate of his
obligations, including his native load obligation—which is estimated as the
average of his daily peak loads during the month of annual peak load for the
historical study year—and long-term firm contractual obligations. It is assumed
that the applicant also has an obligation to meet a reserve requirement for the
control area consistent with the standards established by NERC and/or the
relevant regional reliability council. The reserve requirement is calculated using
all control area load, not only the applicant’s native load. Wholesale load is
calculated as the difference between annual peak control area load and the
1
The order is available here: http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=10115277. FERC has also posted a
useful illustration of the screen here: http://www.ferc.gov/EventCalendar/Files/20040420154035-E-1-screens.pdf.
Page 2 of 2
average daily peak native load obligation of the applicant during the month of the
control area annual peak load. If the applicant’s uncommitted capacity is
necessary to meet wholesale load, i.e. if there is insufficient generation and
import capability controlled by parties independent of the applicant to meet
wholesale load in the event that the applicant’s uncommitted capacity is
completely withheld from the market, then the applicant fails the screen.
(c)
The Delivered Price Test (“DPT”) is essentially a concentration screen. It
involves defining individual “destination markets,” determining the “competitive
price” in each of these destination markets, and then measuring the
concentration (and, for merger analyses, transaction-induced changes in
concentration) of ownership or control of generating resources that are in or can
be delivered to each destination market at a delivered cost—taking into account
variable generation costs, transmission prices and losses—that is no more than
1.05 times the competitive price in that destination market. Concentration is
measured using the Herfindahl-Hirschman Index (HHI). 2 There are two versions
of the DPT. One uses “economic capacity,” i.e. all capacity with a delivered price
less than 5 percent above the competitive price. The other uses “available
economic capacity,” i.e. capacity not committed to serve native load. The
analysis is performed for a variety of season and load level scenarios.
There is also a version of the pivotal supplier screen that depends on the DPT. It
is described in ¶108 of the April Order. Available and available economic
capacity are calculated as they would be for the DPT. An applicant is considered
pivotal if his capacity is required to meet some measure of load, i.e. if there is not
sufficient capacity from other suppliers to meet load.
2 The details of the DPT are described in Appendix A of FERC’s Merger Policy Statement available here: http://www.ferc.gov/industries/electric/geninfo/mergers/rm96-6.pdf.
2
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-052 (a)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, Appendix 2, Report of
Edward Kahn, para 18, page 8
Preamble:
It is my understanding that the Rainbow area is essentially an island because the
line connecting it to the rest of Northwest Alberta is typically operated near zero
loading.
Request:
(a)
Response:
Please provide details of the maximum loading and duration on the line during
each of 2002, 2003 and 2004.
Details for flows on line 7L58 and 7L62 which connect the Rainbow area are as
follow:
MW Flow
Peak Southbound
Peak Northbound
Duration of Flow - Percent of time
Greater than 25 MW Southbound
10-25 MW Southbound
5-10 MW Sounthbound
Less than 5 MW
5-10 MW Northbound
10-25 MW Northbound
Greater than 25 MW Northbound
2002
61
43
2003
51
52
2004
74
52
2.2%
26.6%
13.0%
30.8%
10.7%
11.5%
2.2%
4.3%
12.3%
8.5%
44.3%
19.6%
9.9%
4.3%
0.7%
1.1%
2.4%
50.6%
30.7%
13.9%
0.7%
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-053 (a)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, Appendix 2, Report of
Edward Kahn, para 19, page 9
Preamble:
Assumption of 7,000 TMR hours per year.
Request:
(a)
Please provide historical Rainbow Lake area usage data that supports the 7,000
hours per year assumption.
Response:
(a)
Rainbow Lake area TMR usage in 2004 was in each hour of the year.
ALBERTA ELECTRIC SYSTEM OPERATOR
Ancillary Services Article Amendment (1357161)
Monday, September 26, 2005
FIRM.AESO-054 (a)
Page 1 of 1
Reference:
Appendix D, Additional Evidence of January 10, 2005, Appendix 2, Report of
Edward Kahn, para 22, page 10
Preamble:
The most appropriate regulated solution would be to have a contractual
approach, where Atco or any other entity would agree to enter into a TMR
contract for Atco owned and controlled units. In one of the withholding cases
referenced in ¶ 12 above, the owner agreed to auction capacity to third parties
based on “going forward” costs as the only compensation to the owner. The
going forward cost concept is a reasonable basis for compensating TMR owners
for contract service. FERC has adopted this concept.
Request:
(a)
Please provide other options for compensating TMR owners that the author has
considered.
Response:
(a)
See response to FIRM.AESO-044 (c). While the “must offer” and bid cap
approaches might be used to address non-competitive situations, it may be a
less straight-forward approach than a contract based on going-forward costs. In
either event there must be some determination of the appropriate level of
compensation, including the need to cover all operating costs.
determines the use for TMR and the energy market and prorates according to the
use. Any in-merit operation is considered to be for the energy market use and
therefore the AS Article prorating does not include in-merit hours. For examples,
please refer to BR.AESO-004(a).
(b)
Please refer to FIRM.AESO-024(i). The reasons for any adjustment for purposes
of TMR Maximum calculations are the same as for Article 11 conscripted
operation calculations.
(c)
The same definition is proposed as is proposed in Article 11.3 calculations, that
being the relationship of the pool price to the benchmark price.
(d)
Please refer to IPCAA.AESO-002(d).