Alberta Electric System Operator AESO 2006 General Tariff Application January 31, 2005

Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 1 of 42
6
5
10
15
20
25
2006 TERMS AND CONDITIONS OF SERVICE
The AESO proposes the following changes to its terms and conditions of service for 2006:
(a)
Extensive revision of the customer contribution policy, including a maximum local
investment level of $27,000 per MW of DTS contract capacity per year of contract
term, as well as waivers for contributions from distributors at multiple-user PODs;
(b)
Introduction of a $10,000-$50,000/MW system contribution for generators refundable
over ten years with satisfactory performance, in accordance with Part 4 of the
Transmission Regulation;
(c)
Revisions to streamline the system access application process concurrent with a
simplification and reduction of application fees;
(d)
Definition of Maximum TMR Compensation as a cost determination methodology to
limit the amount that can be paid for transmission must-run service, in accordance
with Section 23 of the Transmission Regulation; and
(e)
Updating and simplification throughout the terms and conditions.
Of those changes listed above, the following were originally filed as part of the AESO’s 2005
tariff application on October 3, 2004:
• revision of customer contribution policy,
• revisions to align with revised system application process, and
• updating and simplification throughout.
These items have been updated, revised if necessary, and refiled as part of this 2006 tariff
application, and are intended to replace in their entirety the similar material originally filed for
2005. The introduction of a system contribution for generators and the definition of Maximum
TMR Compensation are added to this application as required by the Transmission
Regulation.
The specific changes are described in more detail in the following sections.
30
6.1
35
40
Customer Contribution Policy
The AESO’s current customer contribution policy was approved in Decision 2001-6 on the
ESBI Alberta Ltd. (EAL) 2001 General Rate Application Customer Contribution Policy, and
was built on four major principles:
(a)
Harmonization with the contribution policies of distribution facility owners (DFOs)
inasmuch as the AESO’s contribution policy would be revenue-based and 80% of
transmission projects would not require a contribution, such that neither distribution
nor transmission contribution policy would provide an incentive for a customer to
prefer connection to one system over the other;
(b)
Imposition of an economic siting discipline on customers;
(c)
Consistency with the “postage stamp” principle set out in Section 30(3) of the Electric
Utilities Act (“The rates set out in the tariff shall not be different for owners of electric
distribution systems, customers who are industrial systems or a person who has
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 2 of 42
(d)
5
made an arrangement under section 101(2) as a result of the location of those
systems or persons on the transmission system….”); and
Consistent application to all load customers.
Decision 2001-6 also included approval for the classification of project costs as system costs
or customer-related costs, with allowance for discretionary application in unique
circumstances. Generally, system costs are not subject to a customer contribution and were
described as those associated with a looped extension. Customer-related costs may be
subject to a contribution and were described as those associated with a radial extension.
10
The EUB also provided the following direction in Decision 2001-6:
2.
15
20
25
In view of the growing experience with the new policy and its
interaction with the DISCO’s contribution policy, the Board directs EAL
to address any needed changes to the contribution policy at the next
GTA.
Since implementation of the current contribution policy as approved in that Decision, the
AESO considers that the policy can be refined to better meet the objectives noted above
and to reduce the need for discretionary classification of project costs. The AESO is
proposing changes to four specific areas of its customer contribution policy:
• classification of system and local costs;
• form and level of the local investment,
• waivers for multiple-user Points-of-Delivery (PODs); and
• applicability to dual-use (demand and supply service at the same point of connection)
customers.
The proposed change to the classification of system and local costs applies to both load
customers and generators, in the determination of customer-related costs. The remaining
changes to the AESO’s customer contribution policy apply to load customers only.
30
Generators will continue to pay all customer-related costs of their interconnection as in the
current contribution policy. In accordance with Part 4 of the Transmission Regulation, a
generator will also pay a system contribution. The system contribution is discussed in
Section 6.2 of this Application.
35
40
Classification of System and Customer-Related Costs — The initial step in determining
a customer contribution is classifying the project costs as system or customer-related, with
the resulting contribution based on the customer-related costs and the contribution policy.
Despite the defined classification of system and customer-related costs currently in use,
some discretion on the part of the AESO in assigning certain project costs has occasionally
been required. In particular, system enhancement costs, such as protection upgrades, may
be defined as system or customer-related depending upon who benefits from the
enhancement. This approach introduces a level of unpredictably for customers.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 3 of 42
5
10
15
There are essentially three approaches to classifying system and customer-related costs, as
illustrated in Figure 6.1.1. In these alternatives, “bulk system” refers to facilities that are used
to serve a large number of transmission customers, including looped facilities. “System
enhancements” refers to upgrades of existing facilities, including breakers, protection, and
communication systems, as well as shared portions of radial lines. “Local connection” refers
to all new facilities serving just the new customer, including all contiguous construction from
the customer substation along newly-constructed radial line, including a new breaker at an
existing substation if required.
In each alternative, local connection costs are classified as customer-related and bulk
system costs are classified as system. However, the classification of system enhancement
costs varies between the three alternatives.
Figure 6.1.1
Alternative Classifications of Project Costs
Customer-Related
20
1
Local Connection
System Costs
System
Enhancement
Customer-Related Costs
25
2
Local Connection
System
Enhancement
Bulk System
System Costs
Bulk System
30
Customer-Related Costs
35
40
3
Local Connection
System
Enhancement
System Costs
Bulk System
In Alternative 1, the customer-related cost is limited to local connection costs, and system
enhancement costs and bulk system costs are both classified as system costs. This
alternative provides a good level of predictability for customers and may be consistently
applied to both load and generation projects.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 4 of 42
5
In Alternative 2, the customer-related costs include all local connection costs as well as
system enhancement costs determined to benefit the interconnecting customer. The
balance of system enhancement costs and the bulk system costs are classified as system
costs. This alternative most closely resembles the current approach and was assumed not
to change the current level of unpredictability of customer-related costs.
10
In Alternative 3, the customer-related costs include all local connection and system
enhancement costs, and only bulk system costs are classified as system costs. This
alternative provides a good level of predictability for customers but results in inconsistency
between load and generation projects.
15
To reduce the need for discretionary cost classification in Alternative 2, to provide a high
level of predictability, and to provide consistency in the treatment of load and generator
projects, the AESO proposes to define all system enhancement costs as system costs, as
illustrated in Alternative 1.
20
25
Specifically, the AESO proposes that system costs be defined as those costs relating to
facilities constructed for the use and benefit of several individual points of connection,
including upgrading of such facilities arising from load or supply increases of one or more
customers. Costs will typically be classified as system when the facilities are non-contiguous
to the local connection or when construction consists of upgrades to the existing looped
network. System costs will include the cost of upgrading existing breakers and protection to
accommodate the customer and any upgrades to communications systems at existing
substations. In all cases, for costs to be considered system the interconnection configuration
must accord with AESO standards. Where the interconnection configuration requested by
the customer does not conform to AESO standards, the AESO will deem all excess costs
(that is, costs above those which would arise from facilities which do conform to AESO
standards) to be customer-related costs and payable by the customer in accordance with
Article 9.3(c)..
30
35
In addition to such non-standard configuration costs as set out above, customer-related
costs are defined as those costs relating to local connection facilities typically comprising
the customer substation and all contiguous construction from the customer substation back
along any newly constructed line, including a new breaker if required at an existing
substation. Where the local connection includes only facilities that tap into an existing
transmission line, the customer-related costs will not include any upgrades to existing
substations. The cost of communications both at the customer’s substation and back to the
existing system will be considered customer-related costs, but any other enhancements to
the existing system will be excluded from customer-related costs.
40
The proposed clarification of customer-related and system costs as just discussed was
assumed to have no material effect on the contribution levels discussed in the next section,
although the AESO recognized that the change could impact the customer contributions
determined for individual projects. The proposed definitions would be implemented on the
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 5 of 42
effective date of the approved tariff, and contributions for projects already committed to prior
to that date would not be re-assessed to reflect the new definitions.
5
Calculation of Customer Contribution — The AESO proposes to change the calculation
of the Customer Contribution, as set out in paragraph 9.3 of the proposed terms and
conditions of service and reproduced below:
The Customer’s contribution to the Customer-related costs will be calculated as
follows:
10
Customer Contribution = Customer-related costs less the Local Investment
15
20
25
Where:
(a)
for a Customer taking service under Rate DTS:
(i)
the maximum Local Investment = $27,000/MW of DTS Contract
Capacity/Year of DTS contract term;
(ii)
the Local Investment will not exceed the Customer-related costs; and
(iii)
the DTS System Access Service Agreement term = 5 to 20 years, as
determined by the Customer;
and
(b)
for a Customer taking service under any other rate, the maximum Local
Investment = $0.
The proposed calculation is essentially a unit $/MW/year maximum, and is significantly
simpler than the current calculation as described in paragraph 9.4 of the current Terms and
Conditions of Service:
The Customer’s contribution to the demand-related costs shall be calculated as
follows:
30
(a)
35
40
Customer contribution = demand-related costs – roll-in ceiling, where:
(i)
roll-in ceiling = commitment term amount + revenue-related amount;
(ii)
commitment term amount = $400,000 for every one-year commitment
term after the first five-year commitment term. A commitment term is a
period within which the Customer commits to maintain its Contract
Capacity at or above its initial Contract Capacity. The maximum
commitment term amount is $6 million.
(iii)
revenue-related amount = three times the levelized annual revenue
from the new or expanded service, where the levelized revenue is
determined based on the projected Contract Capacities that are
contracted at the time of the calculation of the Customer contribution.
The discount rate to be used in the calculation of the levelized annual
revenue shall be that established under Article 9.12.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 6 of 42
(b)
If the calculation in (a) results in a negative Customer contribution, no
Customer contribution is payable. The AESO will make no payment to the
Customer with respect to any excess of the roll-in ceiling over the demandrelated costs.
5
(Note that the AESO is now using the more common term “maximum investment” rather
than “roll-in ceiling”, in response to stakeholder feedback on unfamiliarity with the “roll-in
ceiling” term. Both terms represent the same concept, recognizing that it is the transmission
facility owner (TFO) who would make the “investment” in facilities, not the AESO.)
10
15
20
25
30
35
40
The proposed form of the maximum local investment provides better harmonization with the
similarly-structured load-based investment policies of most distribution facility owners
(DFOs). By using an average unit investment that varies with contract term, the maximum
local investment also allows customers to lessen the effect of eliminating the current
commitment term amount by contracting for a longer DTS contract term.
The EUB previously stated (Decision 2001-6 on the ESBI Alberta Ltd. (EAL) 2001 General
Rate Application Customer Contribution Policy, page 60) that by including a revenue-related
amount in the roll-in ceiling EAL had followed “the Board’s direction to develop a contribution
policy based on the concept of excess of project cost over supporting revenue for the
connection of customer costs for customers….” However, the AESO notes that the
commitment term amount of the roll-in is generally substantially greater than the revenuerelated amount of the roll-in, and considers that moving to a maximum local investment
based on a unit $/MW/year amount more closely aligns with revenue based on $/MW and
$/MWh rate components.
The inclusion of a direct revenue-related amount in the current contribution calculation also
raises some concerns for the AESO with respect to the significant increases to DTS rate
levels resulting from the implementation of the Transmission Regulation’s requirement that
all costs of the transmission system (except for losses) be allocated to load customers and
exporters, as discussed in Sections 4.1 and 4.2 of this Application. In Decision 2001-38 on
ATCO Electric’s 2001-2002 Distribution Tariff Phase II, the EUB stated (page 120):
The Board also notes with concern the impact on investment levels of
potential changes in rate levels and structures…. The Board does not
consider that rate rebalancing or changes in revenue to cost ratios should
automatically result in a change in the investment levels for the affected rate
classes.
Moving to a maximum local investment based on a unit $/MW/year amount eliminates
changes to investment levels resulting directly from a change to rate levels.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 7 of 42
Finally, the AESO recognizes that the current commitment term amount provides customers
with the opportunity to select contract terms in yearly increments, and has therefore retained
that provision in the proposed contribution calculation.
5
10
15
Level of Proposed Unit Investment Amount — In the proceedings culminating in Decision
2001-6 on the EAL 2001 General Rate Application Customer Contribution Policy, EAL
provided background on the development of the current roll-in ceiling. In particular, EAL
noted its intention to minimize intergenerational inequities by setting a roll-in level so that
80% of transmission projects subject to a contribution calculation would not result in a
customer contribution. In Decision 2001-6 the EUB noted (page 70):
The level of the Roll-in Ceiling appears to have been chosen…so that 80% of
system expansion projects would not require a contribution. The Board
considers this to be a fair manner to set the roll-in level as it preserves a
balance between the need of new customers for service without a need for
subsidy from existing customers.
In practice, the current roll-in ceiling has not met that 80/20 target, as more than 90% of
such projects have not required a customer contribution.
20
25
30
Through analysis, the AESO has determined that a maximum local investment of
$27,000/MW/year can be expected to more closely reach the intended result where 80% of
transmission projects would not require a customer contribution. As the AESO has a limited
number of transmission projects subject to a customer contribution calculation in any year,
the analysis included a sample comprised of ten recent projects and fifty scenario projects.
The scenario project costs were estimated using various high level substation configurations
with differing line components and SCADA requirements.
Table 6.1.1 provides the results of the analysis for the proposed contribution policy. Data
from the table is also illustrated in Figure 6.1.2.
Based on the analysis and as illustrated in Table 6.1.1 and Figure 6.1.2, a maximum local
investment of $27,000/MW/year would more closely align the AESO’s contribution policy
with a goal where 80% of transmission projects do not require a contribution.
35
40
The AESO also examined ten recent projects to assess whether the proposed change to the
classification of system and customer-related costs (as discussed previously) would shift
costs from customer-related to system. Based on that analysis, customer-related costs are
not materially reduced as a direct result of the proposed classification and the level of the
proposed unit investment amount does not need to be adjusted to accommodate the
proposed classification of system and customer-related costs.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 8 of 42
Table 6.1.1
5
10
15
20
25
30
35
40
DTS
Capacity
MW
3.0
3.0
3.0
3.0
4.0
4.0
4.0
4.0
5.0
5.0
5.6
5.6
6.0
6.0
6.0
6.0
6.0
6.1
6.1
6.4
7.0
7.0
7.9
7.9
8.0
9.0
10.0
10.0
10.0
10.0
10.0
10.5
10.5
11.0
11.0
12.0
13.0
20.0
Comparison of Customer Contributions Under Current and Proposed
Contribution Policies for Analyzed Projects
Project
Cost
$ 000 000
$ 1.8
1.8
2.1
2.1
1.9
2.0
2.1
2.2
1.8
2.4
3.4
3.4
2.0
2.0
3.1
3.2
5.1
2.5
2.5
5.1
1.8
1.8
3.2
3.5
3.7
1.8
5.2
5.2
10.8
10.9
10.9
3.9
4.0
2.2
2.2
2.8
4.8
2.2
Current Contribution Policy Proposed Contribution Policy
Maximum
Actual
Maximum
Actual
Roll-In
Contribution Investment Contribution
$ 000 000
$ 000 000
$ 000 000
$ 000 000
$ 6.3
$
$ 1.6
$ 0.1
6.3
1.6
0.2
6.3
1.6
0.5
6.3
1.6
0.5
6.5
2.2
6.5
2.2
6.5
2.2
6.5
2.2
6.6
2.7
6.6
2.7
6.6
3.0
0.4
6.6
3.0
0.4
6.7
3.2
6.7
3.2
6.7
3.2
6.7
3.2
6.7
3.2
1.8
6.7
3.3
6.7
3.3
6.7
3.5
1.6
6.8
3.8
6.8
3.8
6.9
4.3
6.9
4.3
6.9
4.3
7.0
4.9
7.1
5.4
7.1
5.4
7.1
3.7
5.4
5.4
7.1
3.7
5.4
5.5
7.1
5.4
7.2
5.7
7.2
5.7
7.2
5.9
7.2
5.9
7.4
6.5
7.5
7.0
8.3
10.8
-
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 9 of 42
Table 6.1.1
5
10
15
20
25
30
Comparison of Customer Contributions Under Current and Proposed
Contribution Policies for Analyzed Projects (continued)
Current Contribution Policy Proposed Contribution Policy
DTS
Project
Maximum
Actual
Maximum
Actual
Capacity
Cost
Roll-In
Contribution Investment Contribution
MW
$ 000 000
$ 000 000
$ 000 000
$ 000 000
$ 000 000
20.0
2.3
8.3
10.8
23.0
4.5
8.6
12.4
25.0
2.0
8.8
13.5
25.0
2.1
8.8
13.5
30.0
4.5
9.4
16.2
30.0
4.6
9.4
16.2
35.0
4.5
9.9
18.9
35.0
4.5
9.9
18.9
35.0
5.9
9.9
18.9
35.0
6.0
9.9
18.9
39.1
8.7
10.4
21.1
40.0
3.2
10.5
21.6
40.0
3.2
10.5
21.6
40.0
5.9
10.5
21.6
40.0
5.9
10.5
21.6
40.0
6.7
10.5
21.6
40.0
6.8
10.5
21.6
40.0
9.0
10.5
21.6
55.0
14.3
12.2
2.2
29.7
55.0
14.4
12.2
2.2
29.7
60.0
5.8
12.8
32.4
60.0
5.8
12.8
32.4
Totals
$263.4
$486.7
$ 11.7
$607.3
$ 16.4
Projects
60
5
12
Percentage Not Requiring Contribution
92%
80%
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 10 of 42
Figure 6.1.2
Alternative Classification of Project Costs
Cost and TFO Investment
Project
5
Current Maximum Roll-In
Proposed Maximum Investment
10
15
20
Project Cost, Roll-In, and Investment, $ 000
000
$16
$14
$12
$10
$8
$6
$4
$2
$0
25
10
20
30
40
50
60
DTS Capacity (MW)
Local Investment at Dual-Use Sites — The AESO currently uses the following ratio to
determine dual-use customer costs that would be eligible for local investment:
30
35
40
[DTS ÷ (DTS + STS)] × customer-related costs
The dual-use ratio was intended to provide a reasonable sharing of customer-related costs
between load and supply given that load costs are, for the most part, rolled into rates while
generator costs are paid fully by the generator as a customer contribution. In particular, the
dual-use ratio was introduced to limit the AESO’s commitment term amount, which was not
revenue based, to help minimize the potential for investment without a corresponding
revenue stream.
As the proposed maximum local investment will be based on DTS contract capacity, a
revenue stream is assured through the DTS rate and application of the dual-use ratio is no
longer required to address potential mismatches between investment and revenue. The
AESO therefore recommends that its proposed customer contribution policy be applied at
dual-use sites on a “load first” principle, based on providing least-cost standard service to
meet the DTS load requirement.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 11 of 42
For example, if a concurrent load and supply interconnection is requested, the AESO would
estimate the customer-related cost in respect of the DTS load based on the least-cost
standard of providing service. The local investment would then be calculated as:
5
local investment for load = $27,000/MW × DTS contract capacity × contract term,
up to the estimate of least-cost standard service
customer contribution
10
15
= total customer-related costs for load and generator
less local investment for load
If the project accommodates an increase in generation capacity at an existing dual-use site
or the addition of a generator at an existing load site, the generator will simply be required to
pay the resulting customer-related costs as a customer contribution. As there is no increase
in DTS capacity, there is no additional local investment available.
Conversely, if the project accommodates an increase in load capacity at an existing dualuse site or the addition of a load at an existing generation site, local investment will be
available based on the incremental DTS capacity being added at the site.
20
local investment for load = $27,000/MW × incremental DTS contract capacity
× contract term, up to the estimate of least-cost standard
service to serve the load
25
The recommended “load first” approach is consistent with the AESO’s proposed customer
contribution policy whereby the costs rolled into rates are proportional to the expected
revenue from the service. Eliminating the dual-use ratio ensures that all load is treated
equitably, regardless of location on the system and whether or not a generator shares the
same point of connection.
30
35
Staged Load — The AESO proposes to apply the customer contribution policy to
accommodate material increases or decreases in a customer’s load, provided the customer
signs a corresponding System Access Service Agreement with a contract term that extends
a minimum of five years after the start date of the last staged contract capacity. The local
investment will be made available to the customer at the start of the project but will be
adjusted to accommodate the staged load by taking the present value of the investment in
the incremental load for the remaining contract term.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 12 of 42
The following example provides an illustration of the investment in staged load:
5
Stage
Stage 1
Stage 2
Year
1
5
Incremental Load
10 MW
5 MW
Incremental Cost
$5,000,000
$
-
Remaining Term
20 years
16 years
As indicated, the total project cost occurs in Year 1. A discount rate of 10% is used in this
example.
10
15
Stage 1 maximum local investment = $27,000 × 10 MW × 20 years
= $5,400,000 million
Stage 2 maximum local investment = PV ($27,000 × 5 MW × 16 years)
= PV (2,160,000)
= $1,475,000
Total maximum local investment
= $6,875,000 available in Year 1
Discount Rate — In Decision 2001-25 on the ESBI Alberta Ltd. (EAL) 2001 General Rate
Application Refiling Customer Contribution Policy, the EUB provided the following direction
(pages 4-5):
20
Accordingly, the Board directs EAL to delete subsections (a) and (b) and
substitute the following wording for Article 9.12:
9.12
25
30
35
40
The discount rate applicable to payments due under this Article shall
be determined as follows:
(a)
For unassigned transmission facilities, for transmission
facilities supplied to the TA by an investor owned
Transmission Facility Owner or for facilities supplied to the TA
by an income tax paying municipally owned Transmission
facility Owner:
.
.65(GCB + 1%) + .35(GCB + 3.5%)/(1 - T)
where GCB is equal to the yield on 30-year Government of
Canada bonds and T is equal to combined federal and
provincial income tax rate for investor owned TFOs.
(b)
For transmission facilities supplied to the TA by a non income
tax paying municipally owned Transmission Facility Owners:
the yield on 30-year Government of Canada bonds plus 1.9
percent.
The Board expects that EAL will monitor any changes in the typical Board
approved capital structure or cost of equity and will bring forward proposed
changes, as necessary, to Article 9.12 in a future GTA.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 13 of 42
5
10
The Board directs EAL, at the next GTA, to provide examples of the use of
the investor owned TFO discount rate and the municipally owned TFO
discount rate for each of the following calculations:
• The cost of advancement under Article 9.2
• The calculation of levelized annual revenue under Article 9.4(a)(iii)
• Credit arrangements under Article 9.5
• Recalculations of Customer contributions under Article 9.7
The AESO notes that the discount rate provisions directed by the EUB appear essentially
unchanged as Article 9.9 in the proposed terms and conditions of service. As directed, the
AESO has updated capital structure to 33% equity and 67% debt (the values for ATCO
Electric Transmission, a fully-taxable TFO) as determined in EUB Decision 2004-052 on
Generic Cost of Capital, and cost of equity to 9.50% as determined in EUB Order U2004423 on 2005 Return on Equity.
15
The AESO further provides the following examples of the use of the discount rate in respect
of the proposed customer contribution policy.
20
25
30
Discount rate assumptions
• Canadian Government 30 year bond rate:
• Combined federal and provincial tax rates:
• Return on equity
• Taxable TFO equity ratio
• Taxable TFO discount rate
• Non-taxable TFO equity structure
• Non-taxable TFO Discount Rate:
5.68%
33.87%
9.50%
33.0%
9.27%
35.0%
7.70%
Cost of Advancement
Cost of advancement assumptions:
• Planned transmission expansion
• CPI (inflation to determine future cost)
Cost of advancement calculation:
4 years
2%
35
40
(a) Current value of advanced system cost
(b) Future value of system-related costs
(current cost plus inflation: $2.0 × 1.024)
(c) Present value of inflated system-related costs
($2.2 ÷ discount rate4)
(d) Cost of advancement (a – c)
Taxable
TFO
$ 000 000
$2.0
$2.2
Non-Taxable
TFO
$ 000 000
$2.0
$2.2
$1.5
$1.6
$0.5
$0.4
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 14 of 42
The proposed contribution policy no longer relies on a levelized revenue calculation. The
AESO therefore requests relief from the EUB in respect of its direction to provide “The
calculation of levelized annual revenue under Article 9.4(a)(iii)” and “Recalculations of
Customer contributions under Article 9.7”.
5
10
15
20
With respect to credit arrangements, the proposed interconnection process anticipates the
customer and the TFO working more closely together, with the customer paying the required
customer contribution directly to the TFO. As such, the AESO does not expect to arrange
credit with customers. As well, the AESO notes that although credit arrangements have
been possible under the terms of Article 9.5 of the current terms and conditions, no such
credit arrangements have been made to-date. The AESO therefore does not offer credit
arrangements in the proposed terms and conditions, and requests relief from the EUB in
respect of its direction to provide examples related to such credit arrangements.
Waivers for Multiple-User Points of Delivery (PODs) — The AESO proposes to waive
customer contributions in respect of transmission projects at PODs where multiple users are
served by a distribution utility, as set out in Article 9.5 of the proposed terms and conditions
of service:
(a)
Effective January 1, 2006, the AESO will waive all or part of a Customer
Contribution in respect of a transmission expansion project at a multiple-user
POD where a Distributor is the Customer and where the Distributor:
(i)
provides sufficient documentation to satisfy the AESO that, subject to
Articles 9.5(b) and (c), the Customer Contribution results from a
transmission expansion project required by multiple end-use sites
served by the Distributor; and
(ii)
executes a twenty year System Access Service Agreement in respect
of the multiple–user POD.
(b)
The AESO will not consent to such waiver for any portion of a transmission
expansion project that is attributable to the requirements of one or more
single end-use sites each with a load of 2 MW or greater, or an identifiable
group of end-use sites with a single owner (including Affiliates) with an
aggregate load of 2 MW or greater, where such site(s) are served by the
Distributor. In such cases, where a portion of the project can be attributed to
multiple end-use sites served by the Distributor, the AESO will prorate the
Customer Contribution in proportion to the loads of the single, group, and
multiple end-use sites accordingly.
(c)
The AESO will not consent to such waiver for any portion of a transmission
expansion project that exceeds the AESO Standard Facilities required to
provide service to the Customer.
25
30
35
40
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 15 of 42
The AESO is proposing this waiver to address distinctions relating to the principles
underlying its customer contribution policy, as presented in the opening of Section 6.1.
(a)
As regulated utilities with a right and obligation to serve, owners of distribution
facilities coordinate with the AESO in planning transmission and distribution facilities
to arrive at the most effective solution to end-user electricity needs at the lowest
overall cost, regardless of any local investment limitations imposed by the AESO
customer contribution policy.
(b)
No effective economic signal or siting discipline can be imposed on a distribution
utility in respect of transmission projects where that project is caused by increasing
load from multiple end-use customers. The distribution utility has little if any influence
over the amount, timing, or location of end-user load growth. In general, any growthrelated transmission project contributions required from a distribution utility would be
rolled into the utility’s distribution tariff in accordance with utility-specific practices,
and spread across all the utility’s customers with no effect on siting or load growth.
(The AESO appreciates that distribution end-use customers are subject to local
distribution connection costs, where the price signal is effective.)
5
10
15
20
25
30
35
40
The main impact of transmission project contributions, if recovered through a distribution
utility’s distribution tariffs, is the potential for disparities in the price paid for transmission
access by different distribution utilities’ end-use customers. For example, service area
obligations may require a distribution utility to provide transmission access to multiple enduse customers at remote sites or sites which incur high project costs for other reasons. As a
result, that distribution utility’s customers will pay a higher rate for transmission access than
customers of other distribution utilities in the province. Such a result may be inconsistent
with the principle stated in Section 30(3)(a) of the Electric Utilities Act that the AESO’s tariff
“shall not be different for owners of electric distribution systems, customers who are
industrial systems or a person who has made an arrangement under section 101(2) as a
result of the location of those systems or persons on the transmission system.”
(emphasis added).
In general, the AESO does not look beyond the service provided at its point of delivery to
treat all load customers consistently, for the purpose of achieving a fair and reasonable
application of its contribution policy. However, the AESO’s tariff does impact all electricity
consumers in Alberta. Waiver of customer contributions at multiple-user PODs, as proposed,
would result in fair and equitable transmission access rates to all load customers.
In Decision 2001-6 on the EAL 2001 General Rate Application Customer Contribution
Policy, the EUB provided the following directions:
6.
In order to have empirical data, the Board directs EAL to provide at
the next GTA, for each of the years 1998, 1999, and 2000, the
following information for those multiple customer PODs that would
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 16 of 42
have required a transmission contribution using the proposed
contribution policy:
• the number of customers downstream of the POD,
• the initial (or reinforcement) cost of the radial line
• the transmission contribution
The above information should be supplied for each of the following:
• Each new multiple customer POD installed.
• Each existing multiple customer POD where increased capacity
was installed.
• the impact that the above annual transmission contributions
associated with multiple customer PODs would have had on that
DISCO’s total annual transmission access payments.
5
10
7.
15
20
25
The Board directs EAL to provide the above same information, at the
next GTA, on an actual basis for each month in 2001 during which the
new TA contribution policy was in place.
The AESO’s records of transmission projects associated with multiple-user PODs for 1998
through 2000 do not provide sufficient detail to respond fully to Direction 6. The AESO
instead offers the requested information for 2001 through 2003, plus one project from early
2004, as provided in Table 6.1.2.
The data in Table 6.1.2 shows one payment of a customer contribution by a distribution
utility under the AESO’s current contribution policy, at ATCO Kinosis. The Table also shows
the AESO’s proposed contribution policy applied to the same projects would result in the
payment of two customer contributions, at ATCO Brintnell and at ATCO Kinosis. At ATCO
Brintnell, the contribution would be flowed through to specific customers. At ATCO Kinosis,
72% of the contribution would be flowed through to specific customers and 28% would be
waived for multiple users, based on the proportion of load at the site.
30
35
The end result is that there would be no effect on annual transmission access payments by
distribution utilities under the AESO’s proposed customer contribution policy compared to
the current policy, except at ATCO Kinosis. At ATCO Kinosis, transmission access
payments would actually be reduced by the elimination of a $256,000 contribution required
under the current contribution policy.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 17 of 42
Table 6.1.2 Contribution Data for Multiple-User PODs
CustomerNumber of
Actual
Proposed 2005 Policy
Related
End-Use
Customer
Calculated
After
Cost
Customers Contribution Contribution
Waiver
Note
$7,180,262 $
269
$
- $ 700,262 $ 700,262 (1)
262
2,051
523,000
7,410
98,000
134
255,000
911
785,000
11,517
245,000
72,000
2
61,200
- (2)
280,000
143
810,000
592
270,000
1,500,000
29,005
508,000
353
508,000
496,000
522
496,000
280,700
2,727
280,700
287,100
15,109
287,100
384,000
1,332
384,000
1,995,000
9,119
4,799,395
2,247
1,630,000
622
427,000
21,076
465,000
3,449
725,000
17,809
412,000
4,647
325,000
1,929
374,000
3,920
6,749
2,929,422
1
3,796,210
1
7,178,000
181
256,000
3,128,000
2,252,160 (3)
Project
Description
Year
ATCO Brintnell
New Substation
2001
ATCO Cranberry Lake to Kidney Lake
New Substation/Line
2001
ENMAX #24
New Substation
2001
FortisAlberta High River 65S
Breaker Addition
2002
FortisAlberta Leismer 72S
Meter Addition
2002
FortisAlberta Lac La Nonne 994S
Station Regulator
2002
FortisAlberta Nisku 139S
Breaker Addition
2002
FortisAlberta CP Rail 945S
2002
ATCO Sulphur Point
Breaker Addition
2002
ATCO Veteran
Substation Upgrade
2002
ENMAX #11
Substation Upgrade
2002
FortisAlberta Hayter 277S
Breaker Addition
2002
FortisAlberta Hughenden 213S
Breaker Addition
2002
FortisAlberta Benbow 297S
Breaker Addition
2002
FortisAlberta North Calder 37S
Breaker Addition
2002
FortisAlberta Warner 344S
Breaker Addition
2002
FortisAlberta St. Albert 99S
Transformer/Breaker Addition
2003
FortisAlberta Pinedale
New Substation
2003
FortisAlberta Suffield (Phase 1-2)
Transformer/Regulator Addition
2003
FortisAlberta Sherwood Park
Breaker Addition
2003
FortisAlberta Acheson
Breaker Addition
2003
FortisAlberta Stony Plain
Breaker Addition
2003
FortisAlberta Blackfalds
Breaker Addition
2003
FortisAlberta Plamondon
Breaker Addition
2003
FortisAlberta Whitecourt
Breaker Addition
2003
ENMAX #22
Substation Upgrade
2003
ATCO Corridor Crow Lake
New Substation
2003
ATCO Corridor Gregoire
New Substation
2003
ATCO Kinosis
New Substation
2004
(1) ATCO Brintnell contribution would be flowed through to specific customer
(2) Aquila CP Rail contribution would be waived for a single site smaller than 2 MW
(3) ATCO Kinosis contribution would be prorated on share of 7.5 MW load: 2.1 MW waived for multiple-users, 5.4 MW flowed through to two specific customers
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 18 of 42
The effect of the proposed contribution policy on AESO rates is summarized in Table 6.1.3.
Table 6.1.3
5
10
15
20
25
30
35
40
Effect of Contribution Policy on Revenue Requirement
Current Policy
Customer Cost
Year
Rolled into Tariff
2001
$ 7,180,262
2002
6,278,800
2003
19,508,027
2004 (1 project)
6,922,000
Total
$39,889,089
Proposed Policy
Customer Cost
Rolled into Tariff
$ 6,480,000
6,278,800
19,508,027
4,925,840
$37,192,667
Proposed Policy
Revenue Requirement
Reduction
$ 700,262
0
0
1,996,160
$ 2,696,422
The proposed multiple-user waivers will result in “systemizing” transmission project costs
that would otherwise be paid through customer contributions. However, such costs are
customer-related, not system, costs. The AESO therefore plans to calculate a contribution
for customer-related costs at multiple-user PODs, and if such contributions are waived they
will be recorded and tracked. Where contributions have been waived at PODs shared
between large individual users and multiple users, refunds of contributions to the individual
users will continue to be available if additional multiple-user transmission projects are
completed at the POD.
In the absence of any other factors, the waivers could influence the DISCO’s preference for
transmission projects or distribution projects to meet load growth since the cost of a
transmission solution would be recovered from all consumers through the AESO tariff while
the cost of a distribution solution would increase the DISCO’s rate base and be recovered
from just the DISCO’s consumers. Although the waiver adds another difference between
transmission and distribution solutions, such a concern is not new. Current processes,
especially joint planning between the AESO and the DISCOs and the subsequent needs
applications to the EUB, impose the necessary cost discipline on the DISCOs and ensures
that engineering solutions consider the economics of Alberta consumers as a whole.
Alberta consumers are further protected by the specific exclusion from the waiver, in Article
9.5(c), of aspects of projects that exceed the AESO standard facilities required to service the
distributor. As defined in the proposed terms and conditions, AESO standard facilities
“generally consist of a single radial transmission circuit and a single transformer to supply an
individual Point of Connection.” However, DISCOs frequently have multiple Points of
Delivery in relatively close proximity, such that service may be provided from alternate or
multiple PODs. Through the joint planning between the AESO and the DISCOs, the AESO
expects the optimal solution to be determined based on consideration of the technical and
economic feasibility of transmission service through existing capacity at existing PODs,
transmission service through new capacity at an existing or new POD, or a distribution
solution, and having regard for the applicable reliability, protection, and operating criteria
and standards. Again, this concern is not new, and Article 9.5(c) simply makes explicit, with
respect to contribution waivers, the ineligibility of above-standard facilities addressed in
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 19 of 42
Article 9.13(c) and previously addressed in Article 22 of the current terms and conditions.
Also, Article 9.1 expressly excludes shifts of demand from an existing POD from being
eligible for local investment.
5
Changes Requiring Adjustments to Customer Contributions — In Decision 2001-6 on
the EAL 2001 General Rate Application Customer Contribution Policy, the EUB provided the
following direction:
28.
10
15
20
25
The Board considers that the handling of contributions prior to the
time the facilities are put into service is worthy of further examination
at the next GTA and therefore, the Board directs EAL, at the next
GTA, to submit revised practices for these circumstances.
Where a material change occurs related to any component of a customer contribution,
including a reallocation between system and customer-related costs, the AESO proposes to
recalculate and adjust the customer contribution as appropriate. For example, if a material
change occurs before the customer contribution is paid, the AESO will collect the adjusted
amount and not the original amount from the customer. The AESO proposes in Article 9.7 of
its terms and conditions of service that recalculation of the customer contribution can occur
at any time prior to the end of the twenty-year refund period. The AESO also identifies, as a
specific circumstance that may give rise to a contribution adjustment, that the AESO
subsequently deems all or part of a customer’s facilities to be system related. That specific
inclusion should address the concern expressed by the EUB in its view that timing of the
AESO’s annual planning update could result in some customers paying a contribution for
facilities that would be treated as a system expansion within five years of energization.
Common Facilities — Section 16(4) of the Transmission Regulation states:
30
35
40
16(4) If another person makes use of the facilities for which a local
interconnection cost has been paid,
(a)
the cost of the use of those facilities by that other person or
persons must be allocated to all users in accordance with the
ISO tariff, and
(b)
the original local interconnection cost, or a portion of it, must
be refunded to the person who paid it in accordance with the
ISO tariff.
Article 9.8 of the proposed terms and conditions of service has been revised to state that if
facilities are installed to serve a customer and later used to serve other customers, those
facilities will be deemed to be system-related and any customer contribution paid by the
original customer for those facilities will be refunded. These provisions address the
requirements of the quoted clause of the Transmission Regulation.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 20 of 42
Administrative Cost of Contribution Refunds — Decision 2001-6 on the EAL 2001 GRA
Customer Contribution Policy included the following direction:
11.
5
10
15
20
25
30
35
40
Further, the Board directs EAL, in the next GTA, to address any
change in the recommended project cost threshold for refunds beyond
the 10 year period or any administrative cost levy to compensate for
the extra administrative cost involved. The Board accepts TCE’s
argument that customers would be willing to pay for any incremental
administrative costs. Accordingly, at the time this issue is addressed,
the Board will consider whether the effective date for the requirement
for customers to pay the additional administrative costs should be the
effective date of the new contribution policy.
The AESO has determined that the administrative cost to refund load customer contributions
are relatively small, particularly in light of the need for a similar process described in the next
section of this Application in respect of generator system contributions as required by the
Transmission Regulation. Consequently, the AESO is prepared to track and refund load
customer contributions over a twenty year period, at no direct cost to customers. The
associated terms and conditions of service remain unchanged. However, given that the
above noted administrative cost is relatively small, the AESO proposes to eliminate the
$50,000 refund threshold in the AESO’s current terms and conditions, reproduced below:
9.8(c) Commencing in year 11, any project whose remaining adjustment is
less than $50,000 shall be deemed to have an adjustment balance of
zero, and no further refunds shall be due.
Prepaid Operations and Maintenance — Article 9.13 of the proposed terms and conditions
of service provides for the payment of an additional prepaid operations and maintenance
charge of 12% on customer related costs for STS customers and on facilities in excess of
AESO standard facilities for all customers.
Section 16(1)(a) of the Transmission Regulation requires owners of generating units to pay
all local interconnection costs for connecting to the transmission system. However,
interconnections incur on-going operations and maintenance costs beyond their initial capital
costs. The AESO therefore proposes to include a prepaid operations and maintenance
charge to ensure load customers do not pay these costs related to generator
interconnections.
Facilities in excess of AESO standard facilities will also have a prepaid operations and
maintenance charge applied. By definition, service can be provided through AESO standard
facilities, and all customers share in the on-going operations and maintenance costs
associated with such standard facilities the averaging of costs in the AESO’s rates.
However, it is inappropriate for all customer to share in on-going costs when an individual
customer elects facilities in excess of the standard.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 21 of 42
5
10
For this application, the AESO has proposed to charge prepaid operations and maintenance
at 12% of capital cost. This charge is not based on a detailed analysis by the AESO, but is
based on the minimum such charge used by other utilities in Alberta. A preliminary review by
the AESO indicates this is the minimum reasonable level, and additional analysis for each
TFO may result in higher prepaid operations and maintenance charges in future rate
applications.
Non-Standard Configurations — Article 9.14(c) of the proposed terms and conditions of
service replaces previous Article 22.4 and continues to recognize the long-standing practice
wherein facilities requested by the customer that exceed the AESO standard facilities
required to provide service to the Customer are at the customer’s cost. Costs arising from
customer-requested facilities that exceed the AESO standard facilities required to provide
service are also not eligible for the waivers for multiple-user PODs discussed earlier.
15
6.2
20
25
30
35
40
System Contributions for Generators
Part 4 of the Transmission Regulation requires the AESO to include in its tariff provisions
relating to the local interconnection costs of generating units and the generating unit owner’s
contribution:
Local interconnection costs
16(1) The ISO must include in the ISO tariff
(a)
local interconnection costs, as defined by the ISO, payable by
an owner of a generating unit for connecting to the
transmission system;
(b)
the terms and conditions of service and provisions for the
recovery of local interconnection costs from owners of
generating units.
(2)
The ISO must make reasonable efforts to ensure that the
interconnection of a generating unit to the transmission system is
undertaken in a timely manner.
(3)
The owner of a generating unit that interconnects with the
transmission system, and who has paid local interconnection costs,
may not prohibit interconnection or access to the interconnection
facilities by other market participants.
(4)
If another person makes use of the facilities for which a local
interconnection cost has been paid,
(a)
the cost of the use of those facilities by that other person or
persons must be allocated to all users in accordance with the
ISO tariff, and
(b)
the original local interconnection cost, or a portion of it, must
be refunded to the person who paid it in accordance with the
ISO tariff.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 22 of 42
5
10
15
20
25
30
35
40
Generating unit owner’s contribution
17(1) The ISO must include in the ISO tariff
(a)
the amount, determined under subsections (2) and (3),
payable by an owner of a generating unit to the ISO;
(b)
terms and conditions related to clause (a).
(2)
The amount payable by owners of generating units is the sum of the
following:
(a)
for upgrades to existing transmission facilities, a charge of
$10 000/MW;
(b)
a charge of not more than $40 000/MW, as provided in the
ISO tariff, payable by owners of generating units that locate in
an area of the transmission system where generation exceeds
load, and the amount of the charge is to be determined based
on the location of the generating unit relative to load.
(3)
A charge under subsection (2)(b) may be revised from time to time,
but must
(a)
be stable and predictable;
(b)
be calculated in a simple and transparent manner;
(c)
be based on generation size;
(d)
vary based on the generation location relative to load in
Alberta;
(e)
be determined and payable in accordance with the ISO rules
and ISO tariff, be paid before commencement of construction
of the local interconnection facility and be paid once only for
that specific location and generating unit;
(f)
not affect charges determined and paid by owners of
generating units or owners of prospective generating units
before such revisions.
(4)
The ISO tariff must include terms and conditions
(a)
providing for the refund of money paid under this section, to
the owner who paid it, over a period of not more than 10 years
from the date it was paid, subject to satisfactory operation of
the generating unit determined under rules made under
subsection (5), where satisfactory operation may vary by
generation type;
(b)
providing for forfeiture to the ISO of money paid under this
section, or suspension of the refunds, if the generating unit is
not operated satisfactorily;
(c)
providing for the means and times at which the refunds are to
be made;
(d)
providing for the prudent administration, management and
investment of money held by the ISO under this section and
for the accounting for those funds;
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 23 of 42
(e)
(5)
providing for the disbursement of money earned on
investments.
The ISO must make rules to be used to assess the satisfactory
performance of a generating unit by generating unit type.
5
Application of sections 16 and 17 limited
18
Sections 16 and 17 do not apply to a generating unit connected to the
transmission system before this Regulation comes into force.
10
15
The requirements under Section 16 of the Transmission Regulation are already addressed
in the provisions relating to customer contributions in the proposed terms and conditions,
specifically:
(a)
Local interconnection costs payable by a generator are defined in Articles 9.3 and
9.4.
(b)
The timeliness of generator interconnections is addressed in Article 13.2.
(c)
Prohibition of other customer’s interconnections is not permitted by the Regulation,
and does not need to be further addressed in the AESO tariff.
(d)
Refunds when another customer connects to facilities for which a customer
contribution was paid are addressed in Article 9.8.
20
25
30
35
40
Section 17 of the Transmission Regulation requires the AESO to include terms and
conditions relating to the amount of and subsequent refund of a “generating unit owner’s
contribution”, in addition to the payment of local interconnection costs as required by Articles
9.3 and 9.4 of the terms and conditions. The AESO developed a generator contribution
policy to address the requirements of Section 17, published a Generator Contribution Policy
Discussion Paper on November 25, 2004, and presented at a stakeholder workshop on
December 3. Comments from that workshop and additional consultation resulted in revisions
to the proposed policy, which were presented at a stakeholder workshop on January 19,
2005. Additional comments received have resulted in the final Generator Contribution Policy
Recommendations included as Appendix D of this Application. The AESO notes that a
material revision to the proposal for rules regarding satisfactory performance is included in
the final policy, compared to the rules proposals presented in earlier stakeholder sessions.
Based on the Generator Contribution Policy Recommendations, the determination of the
“system contribution” required by the Transmission Regulation is described in Article 9.9 of
the terms and conditions of service and the refund based on satisfactory performance is
described in Article 9.10. Although the Generator Contribution Policy Recommendations
provide more background and detail on the system contribution provisions included in the
terms and conditions, in the event of a conflict in interpretation the terms and conditions
prevail.
Section 17(2) of the Transmission Regulation establishes that the system contribution shall
be the sum of $10,000/MW for upgrades to existing transmission facilities and $0/MW to
$40,000/MW payable in areas where generation exceeds load. Article 9.9(b) of the terms
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 24 of 42
5
and conditions states that STS Contract Capacity will be used to calculate the total system
contribution, and that areas of the transmission system where generation exceeds load and
the associated system contribution factors will be provided by the AESO in advance of their
effective dates. To meet the “stable and predictable” requirements of Section 17(3)(a) of the
Transmission Regulation, the AESO proposes to establish system contribution factors for
two-year periods. The first system contribution factors will apply for 2006 and 2007, and are
provided in Table 6.2.1. The detailed calculation of the factors and amounts are provided in
the Generator Contribution Policy Recommendations provided as Appendix D
10
Table 6.2.1
15
20
25
30
35
40
Area
Northwest
Northeast
Edmonton
Central
East
Calgary
Southwest
System Contribution Amounts for 2006-2007
System
Contribution
Factor
0.0000
1.0000
0.5333
0.0000
0.2558
0.0000
0.2517
Area
Contribution
$/MW
$
0
40,000
21,300
0
10,200
0
10,100
Base
Contribution
$/MW
$10,000
10,000
10,000
10,000
10,000
10,000
10,000
Total
System
Contribution
$/MW
$10,000
50,000
31,300
10,000
20,200
10,000
20,100
The area contribution — the first component of the system contribution — is simply
$40,000/MW multiplied by the system contribution factor, which is greater than zero only in
areas where generation exceeds load and which varies based on the location of generation
with respect to load, in accordance with Section 17(2)(b) of the Transmission Regulation.
The base contribution — the second component of the system contribution — is the
$10,000/MW amount specified by section 17(2)(a) of the Regulation.
The Generator Contribution Policy describes the calculation of the system contribution
factor, which is based on peak generation capacity and peak load in each area and can be a
simple and transparent calculation in accordance with section 17(3)(b) of the Transmission
Regulation. Determining the system contribution as a $/MW amount ensures the charge
varies with generator size in accordance with section 17(3)(c) of the Regulation, while the
variation of system contribution factors reflects the generation location relative to load in
accordance with section 17(3)(d).
Section 17(3)(e) of the Regulation requires that the system contribution be paid before
construction begins, and is addressed in Article 9.2 of the terms and conditions. Section
17(3)(e) also requires that a contribution be paid only once for a specific generator, which is
addressed in Article 9.9(a) of the terms and conditions. Section 17(2)(f) of the Regulation
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 25 of 42
requires that changes to the system contribution do not affect charges already paid, and no
retroactive application is provided for in the terms and conditions.
5
10
Section 17(4) of the Transmission Regulation provides for the refund of the system
contribution over a period of not more than 10 years from the date it was paid, subject to
satisfactory performance of the generator. The AESO proposes in Article 9.10 that the
contribution be refunded in nine equal annual amounts, with the possibility of skipping one
year due to unsatisfactory performance and receiving the final payment in the tenth year.
The possibility of skipping a year takes into account the possibility of a major disruption in
performance unforeseen by the generator.
allows for “Force Majeure” events, high rainfall years for irrigation system hydro generators,
low wind years for wind generators, and similar events out of the generator’s control, without
penalizing the refund of the system contribution.
15
20
25
30
The system contribution must be paid before construction and must be refunded within ten
years of payment subject to satisfactory performance. Since satisfactory performance can
only begin after construction is complete, and since construction of both the generating unit
and interconnection facilities takes time, Article 9.10(b) provides for the refund of the system
contribution in fewer than nine equal annual amounts, based on the number of years after
the commercial operation date of the generator and the ninth year after payment. However,
to ensure that the interconnection does proceed, if the commercial operation date is later
than five years after payment of the system contribution, one-fifth of the contribution is
forfeited for each additional year the commercial operation date is delayed beyond five
years. If the commercial operation date does not occur within ten years after the system
contribution is paid, the whole contribution is forfeited. These provisions are summarized in
Articles 9.10(b) and (c) of the terms and conditions.
For simplicity, the AESO proposes to administer the refund of system contributions on a
calendar year basis. Recognizing that few commercial operation dates occur on January 1,
Article 9.10(d) of the terms and conditions provide for the prorating of both the refund and
the satisfactory performance requirements in the first year of operation.
Some possible refunds of system contributions are illustrated in Table 6.2.2
35
Table 6.2.2
40
Illustrative Examples of System Contributions and Refunds
Generator A
Year
Status Amount
0 Paid Jul 1 $100,000
Refunds
1 COD Jul 1 (5,882)
2
On
(11,765)
3
Off
0
Generator B
Status Amount
Paid Jul 1 $100,000
0
COD Jul 1 (6,667)
On
(13,333)
Generator C
Status Amount
Paid Jul 1 $100,000
0
0
0
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 26 of 42
5
10
15
20
25
4
5
6
7
8
9
10
Forfeit
On
On
On
On
On
On
On
(11,765)
(11,765)
(11,765)
(11,765)
(11,765)
(11,765)
(11,765)
$
0
Off
On
Off
On
On
On
On
0
(13,333)
0
(13,333)
(13,333)
(13,333)
(13,333)
$13,333
0
0
0
COD Jul 1 (10,000)
On
(20,000)
On
(20,000)
On
(20,000)
$30,000
Notes: “COD” refers to commercial operation date
Based on a mid-year COD, the first year’s refund is half the annual amount
“On” indicates a year in which generator performance was satisfactory
“Off” indicates a year in which generator performance was not satisfactory
The examples in Table 6.2.2 reflect the following events:
(a)
Generator A receives a prorated refund in the partial first year of operation (Year 1),
does not meet the performance standard for Year 3 and skips that refund, but
otherwise operates satisfactorily and is refunded the total system contribution over
ten years.
(b)
Generator B receives a prorated refund in the partial first year of operation (Year 2),
does not meet the performance standard for Year 4 and for Year 6, and therefore
forfeits one annual amount.
(c)
Generator C does not begin operating until mid-way through Year 7, and therefore
forfeits 1½ annual amounts reflecting that operation was delayed 1½ years beyond
Year 5.
The provisions of Articles 9.10(b), (c), and (d) of the terms and conditions, as described
above, therefore meet the requirements of Sections 17(4)(a) regarding refunds and 14(4)(b)
regarding forfeiture or suspension of the refunds.
30
Article 9.10(e) and (f) describes the process by which a generator reports annual
performance by January 31 and that refunds will be issued by February 28, thereby
satisfying the requirements of Section 17(4)(c) of the Regulation.
35
40
Section 17(4)(d) of the Transmission Regulation requires the AESO to prudently administer,
manage, and account for system contributions held. The AESO proposes to treat the system
contributions as no-cost capital, similar to the traditional treatment of customer contributions
by utilities in Alberta. The system contributions held would be reported in the general tariff
applications of the AESO. Such treatment would reduce the need for the AESO to borrow to
finance cash flows during the year, resulting in lower interest expense included in the
AESO’s general costs to the benefit of AESO load and export customers who pay all costs
of the transmission system (except for losses), and thereby satisfying the requirement in
Section 17(4)(e) for the disbursement of money earned through the system contributions.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 27 of 42
5
Section 17(5) of the Transmission Regulation requires the AESO to make rules to be used
to assess satisfactory performance of a generating unit. The AESO notes that the draft
performance criteria initially proposed received several comments during the consultation
process on the generator contribution policy. The AESO now intends to propose a draft rule
establishing an annual capacity factor for generating units based on resource type, based
on the ten-year history of electric energy capacity and generation by resource type provided
in the EUB’s Alberta Electric Industry Annual Statistics for 2002. The proposed annual
capacity factors are:
10
Table 6.2.3
Proposed Performance Standard for System Contribution Refunds
Resource Type
Coal
Natural Gas — Base Load
Natural Gas — Peaking
Hydro
Wind
Biomass & Waste
15
Annual Capacity Factor
75%
50%
10%
20%
20%
75%
20
The proposed performance criteria also include a requirement for commercial operation and
an undercontracting penalty; those provisions continue unchanged from the draft criteria
originally presented to stakeholders.
25
30
Although the proposed performance standard is presented in this Application for
completeness, the AESO notes the standard is to be established as an ISO Rule, not
through EUB regulation. The AESO intends to continue consultation on the performance
standard with the expectation that the rule-making process will begin in May 2005, will
include further consultation on the rules themselves, and will result in performance standard
rules being published in August 2005.
35
Finally, Section 18 of the Transmission Regulation states that Section 16 and 17 provisions
do not apply to a generating unit that was interconnected before the Regulation came into
force on August 12, 2004. Consistent with other aspects of its tariff, the AESO proposes that
the system contribution become effective with the rest of the tariff on January 1, 2006.
Article 9.9(c) of the terms and conditions expressly states that system contributions are not
required from generators who sign System Access Service Agreement before January 1,
2006.
40
6.3
System Access Applications
The AESO proposes to amend Article 5 (previously 7) of the terms and conditions of service
to accord with the AESO’s revised interconnection process. The new process has been
established through stakeholder collaboration that included representatives from the AESO,
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 28 of 42
the EUB, ENMAX, EPCOR, FortisAlberta, ATCO, AltaLink, VisionQuest, Canadian Natural
Resources Limited, and EnCana. Implementation of the transmission interconnection
process is continuing to be developed among those parties.
5
10
15
Essentially, the new single-stage process allows for a more active presence by the
transmission facilities owner (TFO) and a more direct working relationship between service
providers and customers, which is intended to streamline system access applications.
Although the AESO will retain oversight of all transmission interconnections, it will no longer
perform each of the day-to-day tasks related to such projects. For example, payment of
customer contributions will normally be made directly by the customer to the TFO, although
determination and administration of customer contributions will remain with the AESO.
As part of the new interconnection process, Article 5 includes the following three revisions to
the level and applicability of system application fees. The existing fee structure was
established through the AESO’s 2002 Negotiated Settlement and was intended to create a
manageable interconnection queue by introducing fees large enough to discourage
customers that did not seriously intend to proceed with interconnection.
The AESO proposes to revise three aspects of system application fee.
20
(a)
System application fees are proposed to be simplified and reduced. The current twostage application fee has been revised to a single charge in accordance with the new
single-stage interconnection process. Table 6.3.1 provides a comparison of
proposed and current fees.
25
Table 6.3.1
Proposed and Current Application Fees
Proposed Application Fees
Project Size
Fee
< 15 MW
$10,000
> 15 MW and ≤ 25 MW
$20,000
> 25 MW
$50,000
30
Current Application Fees
Project Size
Stage 1 Fee Stage 2 Fee
< 10 MW
$5,000
$5,000
> 10 MW and ≤ 15 MW
$8,000
$8,000
> 15 MW and ≤ 25 MW
$15,000
$15,000
> 25 MW
$40,000
$50,000
35
40
(b)
System application fees will be refundable upon energization of the customer’s
facilities. Implementing a refundable fee continues to discourage non-serious
applications, but will allow the cost of transmission system planning to be more
appropriately recognized in the AESO’s standard tariff.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 29 of 42
(c)
System application fees will be eliminated for transmission projects arising from
distribution load growth caused by multiple users. The elimination of such fees
recognizes that:
• distribution load growth can be better managed through the planning, rather than
the transmission interconnection, process; and
• application fees are unnecessary to discourage non-serious customers when the
expansion is due to load growth on a distribution network.
6.4
Maximum Transmission Must-Run Compensation
5
10
Section 23 of the Transmission Regulation includes the following provisions related to the
maximum amount to be paid for transmission must-run (TMR) service:
15
20
25
30
Recovery of must-run costs
23(1) For the purpose of section 30(2)(a)(ii) of the Act, the compensation
must be no greater than an amount that would result in the recovery
of fixed, operating and maintenance costs, including a reasonable rate
of return, using a methodology described in the ISO tariff.
(2)
The ISO must include in the ISO tariff a cost determination
methodology and related terms and conditions of service for the
purposes of subsection (1).
TMR service is real (in MW) or reactive (in VAR) support provided by a Customer in
response to a direction by the AESO made to ensure voltage stability and reliable electrical
service in a region of Alberta. The AESO has developed operating procedures for specific
regions which specify TMR requirements under various operating conditions.
In most cases the AESO acquires TMR services through commercial contracts. Such
contracts may have been the result of a competitive procurement process or the result of a
bi-lateral negotiation with a supplier. In cases where commercial contracts are not in place,
TMR services are acquired under Article 11 (previously Article 24) of the AESO’s terms and
conditions. Acquisition of TMR services under Article 11 is commonly referred to as
“conscription”.
35
40
Acquisition of TMR services under Article 11 is also the subject of a separate proceeding
before the EUB. Article 11 as it appears in the proposed terms and conditions reflects the
AESO’s Article 24 Amendment Application, dated August 16, 2004. The Section 23
requirement of the Transmission Regulation to define the maximum amount to be paid for
TMR service is separate and in addition to the applied-for amendment.
In response to Section 23, this section describes the methodology to determine the
maximum amount to be paid for TMR services, and may limit the compensation specified in
a contract or in Article 11. If the compensation specified in a contract or in Article 11
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 30 of 42
exceeds the maximum, the compensation would be reduced to the maximum as determined
in this methodology. Existing TMR contracts are structured such that the maximum is very
unlikely to be exceeded, and the maximum also would not be exceeded by Article 11 as
proposed in the Amendment Application.
5
The AESO has defined the approach to calculate maximum TMR compensation in
Article 1.1 of the terms and conditions:
10
15
20
25
30
35
40
“Maximum TMR Compensation” means the maximum amount to be paid by the
AESO for Transmission Must-Run (TMR) service that would result in the recovery of
fixed, operating, and maintenance costs, including a reasonable rate of return for the
TMR service provider, based on the following components determined monthly:
(a)
Undepreciated Capital Investment (UCI) reflecting the Customer’s property,
plant, and equipment for the specific generating asset providing the TMR
service less accumulated depreciation for the specific generating asset;
(b)
amortization and depreciation amounts associated with the Customer’s
investment in the generating asset providing TMR service over the economic
life of the asset and consistent with amounts reported in the Customer’s
audited financial statements;
(c)
capital structure reflecting debt, equity, or other financing of the Customer’s
investment in the generating asset at a deemed capital structure of 70% debt
and 30% common equity;
(d)
a 12% rate of return on equity and an interest rate on debt equal to a 10-year
Government of Canada Bond interest rate plus 0.5%;
(e)
income tax costs reflecting the marginal income tax rates for both federal and
provincial portions of income tax;
(f)
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;
(g)
total operation and maintenance costs reflecting direct as well as a prorated
share of indirect or fixed operation and maintenance costs associated with
the generating asset, 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;
(h)
total fuel costs reflecting direct as well as a prorated share of indirect or fixed
fuel costs associated with the generating asset, where the prorated share is
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 31 of 42
(i)
5
(j)
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;
credits for common costs, if applicable, reflecting revenues or benefits
attributable to a service in addition to the TMR service and associated with
the generating asset; and
adjustment for partial use of the generating asset where the asset is only
partially directed for TMR service and the remainder of the unit’s capacity is
available to provide other electric services.
10
The remainder of this section provides additional background on the components included in
the Maximum TMR Compensation definition.
15
20
25
30
35
Undepreciated Capital Investment (UCI) — The appropriate amount of the Customer’s
investment in the generating unit providing TMR service must be determined first. The
AESO refers to the term undepreciated capital investment or UCI to mean the Customer’s
property, plant, and equipment for the specific generating asset providing the TMR service
less accumulated depreciation for the specific generating asset.
The UCI amount forms the basis in determining a return of and on the investment in
subsequent steps.
In a relatively simple case, the UCI would be the entire remaining undepreciated cost of the
generating unit providing TMR service if the generating unit was a stand-alone facility and
the TMR direction was for the full capacity of the generating unit. In more complicated
cases, the facility may produce other products such as steam or hot water, or make other
electricity sales in addition to the TMR service. Also, the level of the TMR service will likely
be for only a portion of the generating unit’s capacity. Another complexity arises where the
Customer may have investments in administration or head office facilities and the Customer
may consider that the TMR compensation mechanism should provide for a return of and on
these types of facilities.
A final complexity concerns whether contributions made in respect of the capital costs of the
facilities providing the TMR service made by the AESO or its predecessor in prior periods
should be treated as a deduction to the UCI calculation.
The following principles will be applied in determining the relevant UCI.
•
40
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.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 32 of 42
•
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.
5
10
15
20
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.
25
30
35
40
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.
Amortization and depreciation — This step determines the appropriate amortization or
depreciation amount associated with the Customer’s investment in the generating unit
providing TMR service. The appropriate amortization period and the applicable depreciation
rates for calculating the depreciation amount included in TMR compensation need to be
determined.
The AESO considered whether the amortization period and depreciation calculation should
be adjusted to take into account the period when TMR service was provided. The AESO
concluded that TMR service does not reduce the economic life of the asset. As a result, the
asset’s total amortization period should be equal to the economic life of the asset.
The applicable amortization period, depreciation rates, and resulting depreciation amount for
the asset should be consistent with how these amounts have been reported in the
Customer’s audited financial statements. Upon request by the AESO, documentation
necessary to independently verify and affirm that the asset specific amortization period,
depreciation rates, and resulting depreciation amount should be provided by the Customer
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 33 of 42
to ensure these amounts are consistent with the methods and amounts reported in the
Customer’s audited financial statements.
5
10
15
Capital structure — 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.
Rate of return on equity and interest rate on debt — This step determines the
appropriate equity rate of return and debt rate for return on investment. Generating units
providing TMR services are typically independent power producers. The AESO is not aware
of any generic reference to a market-based rate of return for an entity in the IPP business.
Some stakeholders have indicated that the short-term services, such as TMR, should
receive a rate of return greater than a typical IPP.
20
The equity rate of return on the equity portion of financing should reflect a general marketbased 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.
25
The debt rate on the portion financed by debt should reflect a general market-based 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%.
30
35
40
The rate of return has not been adjusted for the specific service or the specific duration of
the service provided. The provision of TMR service for a period of time does not affect the
capability of the unit in future periods, or expose the service provider to incremental risk.
TMR compensation provides financial upside compared to the energy market and therefore
no adjustment is required.
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.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 34 of 42
5
In selecting the debt rate, the AESO considered other potential references. In the evidence
of the Ancillary Services Group dated February 21, 2002, a debt rate equal to a 10-year
Canada Bond interest rate plus 0.5% was proposed. An average debt rate for each
Customer could be calculated from the Customer’s audited financial statements.
Income tax costs — 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.
10
15
20
25
Total return costs — The total monthly return costs would be calculated as the sum of:
• the amortization and depreciation monthly amount, determined as 1/12th of the annual
amount;
• monthly debt costs, determined as 1/12th of the product of the UCI times the debt
percentage of the capital structure times the annual debt rate;
• monthly equity return costs, determined as 1/12th of the product of the UCI times the
equity percentage of the capital structure times the annual equity rate of return; and
• monthly income tax costs, determined as the product of the tax rates and the monthly
equity return amounts.
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.
On a monthly basis, the TMR share of total monthly return costs will be a pro-rated 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 non-TMR, 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.
30
Operation and maintenance costs — Direct operation and maintenance costs or those
incurred only and entirely for the provision of the TMR service should be included. If indirect
or fixed O&M costs are also associated with the provision of TMR service, a reasonable
estimate of the indirect or fixed O&M costs will also be included.
35
40
On a monthly basis, the TMR share of indirect or fixed O&M costs will be a pro-rated 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 non-TMR, 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 indirect or
fixed O&M costs should also be pro-rated if the unit was only partially used for TMR service
as described in step 10.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 35 of 42
Fuel costs — Direct fuel costs or those incurred only and entirely for the provision of the
TMR service should be included. If indirect or fixed fuel costs are also associated with the
provision of TMR service, a reasonable estimate of the indirect or fixed fuel costs will also be
included.
5
10
15
On a monthly basis the TMR share of indirect or fixed fuel costs will be the pro-rated 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 non-TMR, 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 indirect or
fixed fuel costs may also be reduced if the unit was only partially used for TMR service.
Credits for common costs — Some generation facilities may provide additional services to
industrial or other processes. For example, a cogeneration plant may provide steam or hot
water from the generation facilities to an industrial plant. Common costs are fuel, operating,
and maintenance expenses or costs associated with property, plant, and equipment where
such costs or facilities are used for a service in addition to the TMR service. Administration
and head office costs will not be considered as common costs.
20
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.
25
30
35
40
The credit for common costs is the revenue and other benefits received from the provision of
other services. For example, if steam is sold from a cogeneration facility, the revenue from
the sale of the steam would be a credit. If instead of sale of the steam, a benefit was derived
for provision of the steam, the effect of the benefit would be considered as a credit. For
example, natural gas may be provided to a cogeneration complex in exchange for the
steam. In such a case, the reduction in the requirement to purchase fuel would be reflected
as a credit.
The monthly revenue and other benefits received from the provision of other services would
be deducted from the TMR cost amounts in order to determine the net cost.
On a monthly basis, the TMR share of the credit will be the pro-rated 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 non-TMR, 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 the credit may also be
reduced if the unit was only partially used for TMR service.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 36 of 42
5
Adjustment for partial use of the unit for TMR service — In cases where the unit is only
partially directed for TMR service and the remainder of the unit’s capacity is available to
provide other electric services, an adjustment will be made to recognize the partial TMR use.
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.
Maximum amount of TMR compensation — The maximum amount would be the sum of
the TMR portions of total return costs, the O&M costs, and fuel costs.
10
15
20
Other matters — The AESO may wish to verify that the information provided by the
Customer was accurate. The AESO would normally expect the full cooperation of the
Customer in its review of the information provided to ensure accordance with the principles
above. However, in certain circumstances, information and calculations provided in respect
of the TMR compensation by the Customer may require review and verification through an
independent audit.
In order to determine if compensation for TMR service has exceeded the maximum, AESO
will monitor compensation of TMR service providers. If AESO judges that compensation paid
to a customer for TMR services associated with a generating unit may be approaching or
exceed the maximum defined in the terms and conditions, the AESO will determine the
maximum for the Customer’s unit based on costs of the unit in accordance with the above
methodology. The AESO will the adjust compensation, as needed, to comply with the terms
and conditions.
25
30
Finally, to ensure that the maximum TMR compensation limit applies to both contracted and
conscripted TMR services, the AESO has added one sentence to the Article as included in
the Amendment Application. The AESO acknowledges that its December 3, 2004, letter to
the EUB in the Amendment Application process stated, “As a result, the AESO has no
intention of applying for any further amendment to Article 24 [proposed Article 11].” On
further review, the AESO believes explicit recognition of the maximum TMR compensation
limit required by the Transmission Regulation should be included in Article 11.
The AESO therefore proposes the following addition to the end of Article 11.1:
35
Notwithstanding the foregoing, the compensation shall not exceed the Maximum
TMR Compensation.
40
The AESO apologizes if this creates any concerns for parties involved in the Amendment
Application proceeding, but believes it simply recognizes the existence of legislation which
would have precedence in any case.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 37 of 42
6.5
5
10
15
20
25
Other Changes to Terms and Conditions of Service
In addition to the specific changes already discussed and those discussed below, the AESO
has generally amended its terms and conditions of service by simplifying language,
reorganizing articles, and removing the bulk of the appendices which will instead be
available from the AESO on request. As a general guideline, process related articles and
appendices were removed so that the AESO can make non-material changes without
triggering a formal regulatory submission.
A full blackline comparison of the current and proposed terms and conditions is included as
Appendix E to this Application.
Definitions and Interpretation (Article 1, Previously 1) — Definitions have been updated
and revised to reflect current legislation and revisions to other articles of the terms and
conditions of service. Several new definitions have been added, including the maximum
compensation to be paid for transmission must-run generation as required by Section 23(1)
of the Transmission Regulation.
Application of Tariff (Article 2, Previously 2) — Other than restructuring for clarity, the
intent and content of this article remains unchanged.
Provision of System Access Service (Article 3, Previously 3) — The list of specific Articles
under which the AESO reserves the right to withhold, limit, or discontinue service has been
amended to provide such right where the Customer does not abide by the Tariff in its
entirety. This change has been made to accord with the AESO’s provision of service in
Article 3.1, which relies on a similar level of compliance.
Customer Interconnection Requirements (Article 4, Previously 5) — Amendments include
the condition that the AESO compliance waiver is subject to system reliability concerns.
30
System Access Application (Article 5, Previously 7) — Material revisions are discussed in
Section 6.3.
35
Security and Customer Agreements (Article 6, Previously 8) — Article 6 has been
amended to recognize the revised interconnection process discussed in Section 6.2.
40
In Decision 2001-6 on the EAL 2001 General Rate Application Customer Contribution
Policy, the EUB summarized intervenors’ concerns with respect to EAL’s ability, through
terms and conditions, to mitigate the risk associated with serving new demand customers. In
response to these concerns, the EUB provided the following directions:
20.
Accordingly, the Board directs EAL, in its refiling, to amend the
contribution policy to clarify that EAL has the discretion to limit the
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 38 of 42
contractual term in order to mitigate the risk associated with serving
new demand customers.
21.
5
10
15
20
The discretion over commitment term required by Direction 20 is no longer needed with the
elimination of the commitment term amount in the AESO’s proposed calculation of maximum
local investment (as discussed in Section 6.1) and the contract termination provisions of
Article 14.
The discretion over forms of security required by Direction 21 is provided by proposed
Article 6 (previously 8) on Security and Customer Agreements and proposed Article 15
(previously 10) on Financial Security, Billing, and Payment Terms. These articles provide the
AESO with the tools to mitigate the risk of stranded costs. Changes from the previous
articles are consistent with the security requirements set out in the current ISO Rules for the
Energy Market and permit the AESO to stipulate the form, timing, and realization of security,
summarized as follows:
•
•
25
•
30
35
Accordingly, the Board directs EAL, at the next GTA, to address the
proposal to amend Article 10 to provide the TA with discretion over
what forms of security it will accept to mitigate the risk that a customer
might abandon service and create the potential for stranded costs.
Form of security — guarantee, cash deposit, or irrevocable letter of credit (Clauses
6.2(a) and 15.1(b));
Timing of security – when the customer commits to construction (Article 6.1) or before
granting service to the customer (Article 15.1(b)), with additional or replacement security
(as determined by the AESO) able to be requested at any time after the customer
commits to construction (Clauses 6.2(b) and 15.1(c)); and
Realization of security — the AESO may recover costs by realization of security or by
offsetting such costs against other amounts owed by the AESO to the customer or its
affiliates (Article 15.8).
Metering (Article 7, Previously 12) — Detailed requirements regarding meter data
submission have been removed, and reliance placed instead on the Electricity and Gas
Inspection Act, the AESO Measurement System Standard, and the Settlement System Code
where such requirements are established.
Provision of Information by Customers (Article 8, Previously 11) — The detailed rationale
for information required from customers has been replaced with a blanket term that
customers must provide any information required by the AESO in the discharge of its duties.
40
Customer and System Contribution Policy (Article 9, Previously 9) — Material revisions
are discussed in Sections 6.1 and 6.2.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 39 of 42
5
Demand Opportunity Service (Article 10, Previously 6) — Process details have been
replaced with the condition that customers interested in taking Demand Opportunity Service
must meet the requirements and submit the applications as detailed in the AESO’s Demand
Opportunity Business Practices. This amendment permits non-material procedure changes
without the time and expense of a regulatory application.
Ancillary Services (Article 11, Previously 24) — Article 11 has been revised to accord with
the AESO’s Article 24 Amendment Application, dated August 16, 2004, as discussed in
Section 6.4.
10
Under-Frequency Load Shedding (Article 12, Previously 4) — No material changes are
proposed for this article.
15
20
25
30
Contract Capacity Allocation (Article 13, Previously (In Part) 15) — Article 13.1 and 13.2
are new in the proposed terms and conditions, and set out the AESO’s terms for and
definition of contract capacity allocation for new or expanding points of connection. Article
13.1 states that the AESO will allocate contract capacity at the time the customer commits to
construction. Article 13.2 allows the AESO to re-allocate contract capacity if the customer
fails to act in a timely manner to meet the agreed-upon in-service date. These clauses
address circumstances where the delay of one customer could block system access for
another.
Reductions or Termination of Contract Capacity (Article 14, Previously (In Part) 15) —
Article 14 has been expanded to include the provision that in reducing contract capacity the
customer will be required to sign a revised System Access Service Agreement and may be
required to pay a customer contribution. The potential for additional contribution recognizes
that the proposed local investment is based on contract capacity over a contract term. The
maximum local investment would therefore be reduced in proportion to a reduction in
contract capacity, to a level potentially below the customer-related costs and therefore
requiring a customer contribution.
Article 14.3 has been added to provide customers that request early contract termination the
option of making a lump sum payment to the AESO, as an alternative to ongoing monthly
billing.
35
40
Financial Security, Billing, and Payment Terms (Article 15, Previously 10 and (In Part)
15) — Security requirements have been amended to accord with Article 6 on security and
customer agreements, as discussed above. The process for issuing statements of account
has been revised to reflect the three steps consisting of initial, interim, and final statements
to accord with the energy settlement schedule. Article 15.3(c) provides that, in the case of
interim and final statements of account for charges or refunds of less than $1,000, the
AESO has discretion to not issue such statements.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 40 of 42
Peak Metered Demand Waiver (Article 16, Previously 21) — Article 16.1(b) has been
expanded and made distinct to distribution facility owners, to clearly set out the information
required by the AESO in respect of pre-scheduled distribution maintenance and the related
peak demand waiver.
5
10
Service Interruptions and Force Majeure (Article 17, Previously 13) — To add clarity, the
wording in Article 17.1 on service interruptions has been changed to “The AESO specifically
does not guarantee uninterrupted…” service in respect of listed activities, from “The AESO
will not be responsible for interruptions…” as a result of listed activities. Article 17.2 has
been added to explicitly permit the AESO, on six months’ notice, to temporarily suspend
System Access Service to accommodate the construction, commissioning, or testing of new
facilities. The AESO recognizes the disincentive for an existing customer to agree to such
suspension where the new facilities are required for a competitor, and intends to rely on this
provision only in circumstances where such agreement is not obtained.
15
20
25
Limitation of Liability (Article 18, Previously 14) — As a response to certain liability
protection issues that arose during the AESO’s 2003 General Tariff Application, the EUB
directed the AESO by letter dated June 25, 2003 to initiate a process through which the
EUB could make a determination in respect of the issues raised. As part of that process, the
AESO proposed an interim amendment to the liability provisions of its tariff enabling the
AESO to expressly indemnify ancillary service providers. The EUB approved the
amendment in Decision 2003-059 on the AESO’s 2003 General Tariff Application Liability
Protection, on an interim basis until the matter could be heard in full.
In its final determinations in Decision 2003-109 on the AESO’s 2003 GTA Liability
Protection, the EUB provided the following directions:
1.
The Board directs the AESO forthwith to initiate discussions with
appropriate members of the Government of Alberta in furtherance of
the Board’s recommendation. The Board also directs the AESO to
advise the Board and all parties to this proceeding that discussions
have commenced.
2.
Furthermore, the Board directs the AESO to advise the Board of the
progress of these discussions no later than April 1, 2004 and to
provide the AESO’s views on the likelihood of the Board’s
recommendation being implemented, in whole or in part.
3.
The Board also encourages the AESO, in the context of these
discussions, to explore with the Government the reasons for the
exclusion of directors from individual protection under the EUA with a
view to determining whether they should be protected either under
section 90 or in relation to those entities for whom the Board has
recommended protection in this Decision, or both.
30
35
40
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 41 of 42
4.
In that regard, if matters cannot be concluded with the Government of
Alberta as recommended in this Decision by July 1, 2004, then the
Board directs the AESO to advise the Board to that effect no later
than July 1, 2004. At the same time, if those matters cannot be
concluded, the Board directs the AESO to recommend a process that
will lead to Board approval of a tariff based solution, no later than
December 1, 2004, by proposing the necessary amendments to the
T&Cs of the AESO, TFOs and DISCOs in order for them to be
effective January 1, 2005.
5.
The Board directs the AESO to further amend Article 14 by providing
that the amendments to Article 14 approved on an interim basis in
Decision 2003-059 and confirmed in this Decision will terminate
effective December 31, 2004.
5
10
15
The AESO responded to Directions 1 and 2 by way of letters to the EUB dated January 23,
2004 and April 1, 2004, respectively.
20
25
In respect of the remaining directions, the AESO notes that the Liability Protection
Regulation (A.R. 66/2004) was enacted on March 31, 2004. The Regulation specifically
extended the liability protection of the AESO, as provided in Section 90 of the Electric
Utilities Act, to include, without limitation:
(a)
(b)
(c)
(d)
(e)
30
(f)
(g)
an ancillary services provider,
a power purchase arrangement owner,
an owner of a transmission facility,
an owner of an electric distribution system,
a person who is a member of a joint venture with or is a partner of a
person referred to in clauses (a) to (d), including a general partner of
a limited partnership,
an affiliate of a person referred to in clauses (a) to (e), and
each director, officer and employee of a person referred to in clauses
(a) to (f).
35
Additionally, the Liability Protection Regulation specifically requires that the ISO must
indemnify black start service providers in the same manner and in the same circumstances
as other Independent System Operator persons under Section 90(5) of the Electric Utilities
Act.
40
In accordance with the above, the AESO proposes to amend the limitation of liability article
by deleting the indemnity provisions for ancillary service providers and instead broadening
the liability protection for an AESO Person as defined in the Electric Utilities Act and the
Liability Protection Regulation.
Alberta Electric System Operator
AESO 2006 General Tariff Application
January 31, 2005
Section 6 — Terms and Conditions of Service
Page 42 of 42
Dispute Resolution (Article 19, Previously 16) — Article 19.1 has been added to ensure all
disputes are documented appropriately.
5
Confidentiality (Article 20, Previously 25) — No material changes are proposed for this
article.
Miscellaneous (Article 21, Previously 19, 20, and 23) — Other than restructuring for clarity,
the intent and content of this article remains unchanged.
10
Metering Equipment Information (Appendix A, Previously D) — No changes are proposed
for this appendix.
15
Regulated Generating Units (Appendix B, Previously E) — No changes are proposed for
this appendix.
Deleted Articles (Previously 22) — The AESO proposes to delete the previous Article 22 on
transmission system expansion as terms of transmission expansion procurement and direct
assignment are no longer required under the Transmission Regulation.
20
Deleted Appendices (Previously A, B, and C) — The AESO proposes to delete:
• Appendix A — Intentionally left Blank;
• Appendix B — System Access Service Agreement Proformas; and
• Appendix C — Construction Commitment Agreement Proforma.
25
The deletion of the agreement proformas will enable on-going, non-material changes to
these agreements without the time and expense of gaining regulatory approval. The AESO
will make such agreement proformas available to customers upon request.
30