Alberta Electric System Operator 2015 ISO Tariff Update Date:

Alberta Electric System Operator
2015 ISO Tariff Update
Date:
August 18, 2015
Prepared by:
Alberta Electric System Operator
Prepared for: Alberta Utilities Commission
Contents
1
Introduction ........................................................................................................................................... 4
1.1
1.2
1.3
2
AESO 2015 Forecast Revenue Requirement ..................................................................................... 7
2.1
2.2
2.3
2.4
2.5
3
Background ................................................................................................................................................ 4
Organization ............................................................................................................................................... 5
Relief Requested........................................................................................................................................ 5
AESO Board Approval of Costs ................................................................................................................. 7
Wires Costs ................................................................................................................................................ 8
Ancillary Services Costs ........................................................................................................................... 13
Losses Costs............................................................................................................................................ 13
Administrative Costs ................................................................................................................................ 14
2015 Tariff Update .............................................................................................................................. 15
3.1
3.2
3.3
Specific Rate Changes ............................................................................................................................. 15
3.1.1 Rate PSC, Primary Service Credit ................................................................................................ 15
3.1.2 Regulated Generating Unit Connection Costs in Rate STS, Supply Transmission Service .......... 16
3.1.4 Rider J, Wind Forecasting Service Cost Recovery Rider .............................................................. 16
2015 Forecast Billing Determinants ......................................................................................................... 17
Bill Impacts ............................................................................................................................................... 19
4 2015 Maximum Investment Levels Update ...................................................................................... 21
5 Conclusion .......................................................................................................................................... 23
Appendices ........................................................................................................................ Filed Separately
A
B
C
D
E
AESO Board Decision (Dated December 18, 2014)
AESO 2015 Business Plan and Budget Proposal (Dated October 29, 2014)
2015 Rates Calculations
Escalation Factor and Investment Levels
Proposed 2015 ISO Tariff
AESO 2015 ISO Tariff Update
Application
Page 2 of 23
Confidentiality: Public
August 18, 2015
Tables
Table 2-1 – 2015 Forecast, 2014 Recorded and 2013 Recorded Cost Components ............................ 7
Table 2-2 – AESO 2015 Forecast Revenue Requirement ($ 000 000) .................................................. 10
Table 3-1 – Calculation of 2015 Primary Service Credit ........................................................................ 16
Table 3-2 – 2015 and 2014 Forecast Billing Determinants .................................................................... 18
Table 3-3 – 2015 Forecast, 2014 Recorded, and 2013 Recorded Billing Determinants ..................... 18
Table 3-4 – Increase (Decrease) for 2015 Rate DTS Components ....................................................... 19
Table 3-5 – Increase (Decrease) for 2015 Rate STS Components ....................................................... 20
Table 4-1 – Escalation Factor for Composite Inflation Index ............................................................... 21
Table 4-2 – Calculation of 2015 Maximum Investment Levels.............................................................. 22
Appendix C: 2015 Rate Calculations ................................. Microsoft Excel Workbook Filed Separately
C-1
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
C-10
C-11
C-12
C-13
C-14
C-15
C-16
AESO 2015 Forecast Revenue Requirement
2015 Forecast Transmission Facility Owner Wires Costs
Revenue Requirement Allocation to Demand and Supply Transmission Service
Tariff Revenue Offsets
Demand Transmission Service Costs Classified to Demand, Usage, and Customers
POD Cost Function and POD Cost Classification
Demand Transmission Service Cost Recovery
Demand Transmission Service Rate Calculation
Supply Transmission Service Costs Classified to Demand and Usage
Supply Transmission Service Rate Calculation
Opportunity Service Rate Calculations
2015 Billing Determinants
Rate Change Impact Compared to 2014 Approved Rates
Fort Nelson Demand Transmission Service Rate Calculation
2015 Fort Nelson Billing Determinants
Bill Impact Estimator
AESO 2015 ISO Tariff Update
Application
Page 3 of 23
Confidentiality: Public
August 18, 2015
1
Introduction
1
Pursuant to sections 30 and 119 of the Electric Utilities Act, S.A. 2003, c. E-5.1 (“Act”), the Alberta Electric
System Operator (“AESO”) applies to the Alberta Utilities Commission (“Commission”) for approval of its 2015
update to the Independent System Operator (“ISO”) tariff. As outlined in further detail below, this annual tariff
update application seeks approval of changes to the rates to be charged by the AESO for system access
service and to the maximum investment levels provided under section 8 of the ISO tariff.
2
The updates proposed in this application change only the levels (that is, the dollar-based and percentage of
pool price amounts) included in the rates and section 8 of the ISO tariff, based on costs and billing
determinants forecast by the AESO for the 2015 calendar year. This application does not include any
changes to the structure of the rates or to the provisions of the terms and conditions (other than maximum
investment levels) currently approved in the 2014 ISO tariff.
1.1
3
Background
1
On December 22, 2010, the Commission issued Decision 2010-606 , in which the AESO’s proposed annual
tariff update was summarized as follows:
In conjunction with its proposal for major updates, the AESO proposed to make annual
tariff update filings involving the following three principal components:

an annual revenue requirement update using the approach to the wires cost forecast as
described in section 2.2 of the Application, plus forecasts for ancillary services costs, losses
costs and administration costs approved by the AESO Board for the forecast year;

revised rate levels for each AESO rate calculated from the forecast revenue requirement and
forecast billing determinants using rate calculations and rate design approved in the most
recent comprehensive tariff application; and

annual updates to investment amounts approved in the most recent comprehensive tariff
reflecting an escalation factor based on the most recent Conference Board of Canada Alberta
2
consumer price index (CPI).
4
The Commission approved the AESO’s proposal in Decision 2010-606, and the AESO has subsequently
applied for tariff updates between its major tariff applications in accordance with this approach.
5
The AESO’s most recent major tariff application was filed on July 17, 2013, by which the AESO sought
3
approval from the Commission for the 2014 ISO tariff. Following a compliance filing process, the Commission
4
approved the current form of 2014 ISO tariff, effective July 1, 2015, by way of Decision 3473-D01-2015. The
2014 ISO tariff approved in that decision reflected costs and billing determinants for the 2014 calendar year.
The AESO is now filing this annual tariff update application to reflect costs and billing determinants for the
2015 calendar year.
6
In accordance with the approach referred to above, this tariff application consists of formulaic updates to: (i)
the AESO’s annual revenue requirement, based on the AESO’s updated forecast costs for 2015; (ii) rate,
rider, and maximum investment level amounts using the rate calculation methodology already approved by
the Commission in Decision 3473-D01-2015, and (iii) the investment amounts approved in Decision 3473D01-2015, in accordance with the escalation factor described below. In the AESO’s view, the updates
1
Decision 2010-606, Alberta Electric System Operator 2010 ISO Tariff, issued December 22, 2010.
Decision 2010-606 at page 99, paragraph 537.
Exhibit 0002.00.AESO-2718.
4
Decision 3473-D01-2015, Alberta Electric System Operator 2014 ISO Tariff Compliance Filing Pursuant to Decision 2014-242 –
Module 1, issued June 2, 2015 (followed by errata issued June 17, 2015).
2
3
AESO 2015 ISO Tariff Update
Application
Page 4 of 23
Confidentiality: Public
August 18, 2015
proposed in this application will limit potential misallocations that might occur if the AESO continued to rely on
Rider C, Deferral Account Adjustment Rider, to allocate revenue and cost imbalances to market participants.
1.2
7
Organization
This application is organized into the following sections:
1 Introduction — Provides background on the application and specifies the relief requested.
2 2015 Forecast Revenue Requirement — Summarizes the AESO’s forecast revenue requirement for
2015, including costs which have been approved either by the Commission (for transmission facility
owner (“TFO”) tariffs) or by the AESO Board (for ancillary services, transmission line losses, and the
AESO’s own administration).
3 2015 Tariff Update — Discusses the calculation of rate levels based on the 2015 forecast revenue
requirement, 2015 wires costs functionalization and classification approved in Commission Decision
5
2013-421 , and 2015 forecast billing determinants.
4 2015 Maximum Investment Levels Update — Discusses the calculation of 2015 maximum
investment levels using the 2015 escalation factor.
5 Conclusion — Reiterates the relief requested.
8
This application also includes the following appendices:
A AESO Board Decision — AESO Board decision issued on December 19, 2014, approving forecasted
ancillary services costs, forecasted losses costs, and the AESO’s business plan and budget for 2015.
B AESO 2015 Business Plan and Budget Proposal — Document prepared by AESO management in
consultation with stakeholders, as submitted to the AESO Board on October 29, 2014, containing the
AESO’s proposed 2015 business initiatives and proposed 2015 budgets and forecasts for ancillary
services costs, transmission line losses costs, and administrative costs.
C 2015 Rate Calculations — Microsoft Excel workbook which calculates the updated dollar and
percentage of pool price amounts for the 2015 rates, based on the same methodology used for the
AESO’s currently approved rates.
D 2015 Escalation Factor and Investment Levels — Microsoft Excel workbook which calculates the
composite inflation index and escalation factor used to update maximum investment levels.
E 2015 ISO Tariff, Including Updated 2015 Rates, Riders, and Section 8 of ISO Tariff — The
proposed 2015 ISO tariff, including rates, rider, and section 8 that incorporate the 2015 updated
amounts set out in Appendix C to this application.
1.3
9
Relief Requested
For the reasons outlined below, the AESO submits that the tariff updates proposed in this application are just
and reasonable, and respectfully requests that the Commission approve this annual tariff update application,
including (i) the updated amounts set out in Appendix C to this application, and (ii) the proposed 2015 ISO
tariff set out in Appendix E to this application, which incorporates the updated amounts.
5
Decision 2013-421, Alberta Electric System Operator 2014 ISO Tariff Application and 2013 ISO Tariff Update Negotiated
Settlement – Cost Causation Study, issued November 27, 2013.
AESO 2015 ISO Tariff Update
Application
Page 5 of 23
Confidentiality: Public
August 18, 2015
10
The AESO respectfully requests that this application be approved effective January 1, 2016. If the timing of
this application does not permit the granting of final approval prior to January 1, 2016, the AESO also
requests that the Commission approve this application on an interim refundable basis effective as of that date.
The AESO further requests that the Commission issue its approval (whether on an interim or final basis) on or
before November 1, 2015, to provide the AESO with adequate time to program and test the rates in the
AESO’s billing system in advance of the January 1, 2016 effective date.
11
For additional clarity, the AESO requests that the updated rates proposed in this application apply on a goforward basis only, commencing from the effective date approved by the Commission. In the AESO’s view, it
is appropriate that currently-approved deferral account rider and reconciliation mechanisms be used to
address any variances between costs and revenues occurring prior to the approval of the applied-for rates.
The AESO is therefore not seeking any retroactivity with respect to the rates proposed for approval in this
application.
AESO 2015 ISO Tariff Update
Application
Page 6 of 23
Confidentiality: Public
August 18, 2015
2
12
AESO 2015 Forecast Revenue Requirement
The AESO’s revenue requirement consists of costs related to wires, ancillary services, transmission line
losses, and the AESO’s own administration (which includes other industry costs and general and
administrative costs). The AESO’s forecast costs for 2015 are detailed in column A of Table 2-1. For
comparison, Table 2-1 includes costs approved in the AESO Board Decision for 2015 (set out in Appendix A
to this application) and the recorded costs for 2014 and 2013, in columns B, C and D, respectively.
Table 2-1 – 2015 Forecast, 2014 Recorded and 2013 Recorded Cost Components
2015 Forecast
Cost Component
Wires
Ancillary services
Losses
Administrative
Revenue Requirement
2014
2013
Updated
($ 000 000)
A
Budget Proposal
($ 000 000)
B
Recorded
($ 000 000)
C
Recorded
($ 000 000)
D
1,524.0
165.1
105.3
101.1
1,895.5
1,373.7
163.0
105.3
101.1
1,743.1
1,387.6
213.6
118.2
101.3
1,820.6
1,123.8
398.2
181.7
100.1
1,803.9
Note: Numbers may not add due to rounding
13
The 2015 updated forecast costs represent an increase of $74.9 million (or 4.1%) over the 2014 recorded
costs. The increase primarily results from a forecast increase of $136.5 million (or 9.8%) in wires costs
reflecting recent applications for TFO tariffs. The wires costs increase is offset by decreases in other forecast
cost components, with the decreases in ancillary services and losses reflecting a forecast decrease in pool
price.
14
Although deferral account riders and later reconciliations allow the AESO to recover variances between base
rate revenue and actual costs, use of deferral accounts generally provides imprecise and delayed allocation
of costs. It is therefore preferable to update rates to reflect significant changes in costs, as included in this
tariff update.
2.1
AESO Board Approval of Costs
15
The AESO is not seeking approval in this application of its 2015 forecast revenue requirement. The AESO’s
forecast costs are approved through other processes provided for in relevant legislation. These costs, as
provided in column B of Table 2-1, were addressed in the AESO 2015 Business Plan and Budget Proposal
dated October 29, 2014, set out in Appendix B to this application.
16
With respect to the AESO’s costs, including their approval processes:
17
(a)
Wires-related costs reflect the amounts paid by the AESO to TFOs in the TFO tariffs approved by
the Commission under section 37 of the Act. (The wires costs forecast included in the AESO
2015 Business Plan and Budget Proposal reflected TFO tariffs applied for or approved by the
Commission at the time the AESO budget was prepared in late 2014, as discussed in more detail
below.)
AESO 2015 ISO Tariff Update
Application
Page 7 of 23
Confidentiality: Public
August 18, 2015
18
(b)
Ancillary services costs reflect recovery of the prudent costs incurred by the AESO related to the
provision of ancillary services acquired from market participants under subsection 30(4) of the
Act.
19
(c)
Losses costs reflect recovery of the prudent costs of transmission line losses under subsection
30(4) of the Act.
20
(d)
Administrative costs reflect the transmission-related costs and expenses incurred by the AESO
and described under subsection 1(1)(g) of the Transmission Regulation.
21
The ancillary services costs, losses costs, and administrative costs described above are approved by the
AESO Board (consisting of the “ISO members” appointed under section 8 of the Act) in accordance with the
Transmission Regulation. Section 3 of the Transmission Regulation addresses consultation and approval of
those costs and requires that the AESO consult with market participants with respect to proposed costs to be
approved by the AESO Board. Subsection 48(1) of the Transmission Regulation provides that a reference to
“prudent” or “appropriate” in the Act in relation to the costs of ancillary services and losses means the
amounts of those costs that have been approved by the AESO Board. In addition, subsection 46(1) of the
Transmission Regulation provides that the AESO’s administrative costs, once approved by the AESO Board,
must be considered as “prudent” by the Commission unless an interested person satisfies the Commission
otherwise.
22
The practice established by the AESO to carry out consultation on ancillary services, losses, and
administrative costs is the Budget Review Process. The Budget Review Process is a transparent stakeholder
process which provides a prudence review with input from stakeholders. At the conclusion of the Budget
Review Process, AESO management proposes a business plan and budget to the AESO Board, including a
request for approval of ancillary services costs, losses costs, and administrative costs.
23
As part of the AESO Budget Review Process for its 2015 budget, AESO management consulted with
stakeholders in a planning process that had been first established with stakeholders in 2009. Prior to the start
of the 2015 fiscal year, the AESO accordingly reviewed the business initiatives that had been established the
prior year and prepared a forecast to assess any budget changes required to deliver those business
initiatives. Following the consultation with stakeholders and incorporating appropriate amendments arising
from it, AESO management submitted the 2015 Business Plan and Budget Proposal to the AESO Board on
October 29, 2014. The document (set out in Appendix B to this application) includes details on the
consultation process and on the proposal for the AESO’s business plan and budget as it relates to forecasted
ancillary services costs, forecasted losses costs, and the AESO’s business priorities and budget for 2015.
The 2015 Business Plan and Budget Proposal was also provided to stakeholders and posted on the AESO
website.
24
The AESO’s 2015 forecast costs were approved by the AESO Board on December 18, 2014. A Board
Decision Document was posted on the AESO website and is set out in Appendix A to this application.
25
Additional information on the AESO’s business priorities and budget for 2015 is available on the AESO
website at www.aeso.ca by following the path About AESO  Our Business  Business Plan and Budget 
2015 Budget.
2.2
Wires Costs
26
The 2015 forecast costs for wires are $1,524.0 million and represent approximately 80.4% of the AESO’s
transmission revenue requirement. Wires costs include primarily wires-related costs of TFOs as well as two
small non-wires costs.
27
The 2015 Business Plan and Budget Proposal discussed in section 2.1 above included wires-related costs
based on the TFO tariffs approved by the Commission or applied for by the transmission facility owners at the
AESO 2015 ISO Tariff Update
Application
Page 8 of 23
Confidentiality: Public
August 18, 2015
time the AESO budget was prepared in late 2014. Those costs are included in column B, lines 1 through 10,
of Table 2-2 below. Most of the TFO costs in column B reflect Commission approvals for 2014, as that was
the most recent year for which several tariff approvals had been issued or tariff applications had been filed at
the time.
28
The AESO has determined the 2015 wires costs for TFOs using the following approach, which was described
6
in section 2.2.1 of the AESO’s 2014 ISO tariff application and 2013 ISO tariff update and referred to in
7
Decision 2014-242 :
(a)
If a transmission facility owner has received final Commission approval for its
applicable tariff, the AESO includes the approved cost for that transmission
facility owner tariff.
(b)
If a transmission facility owner has applied for its tariff, the Commission has
issued an initial decision on the application, and the transmission facility owner
has submitted a refiling in compliance with the decision, the AESO includes the
transmission facility owner tariff costs included in the refiling.
(c)
If a transmission facility owner has applied for its tariff but the Commission has
not yet issued an initial decision on the application or an initial decision has been
issued but the transmission facility owner has not yet submitted its compliance
refiling, the AESO includes the tariff costs most recently approved by the
Commission on a final basis for the transmission facility owner plus 72% of any
increase or decrease included in the transmission facility owner’s tariff
application above or below the prior approved costs.
(d)
If a transmission facility owner has not yet applied for its tariff, the AESO includes
the transmission facility owner tariff costs most recently approved by the
8
Commission on either a final or interim basis.
29
As discussed in greater detail below, the Commission has issued decisions on, and applications have been
filed for, several 2015 TFO tariffs. Therefore, in accordance with the foregoing approach, the AESO has
updated the 2015 wires costs in Table 2-1 to reflect these more recent approvals and applications.
30
As noted in the AESO’s 2014 ISO tariff application, “the inclusion of 72% of an applied-for increase or
decrease in (c) above was determined from the percentages of applied-for changes which had received final
approval in recent transmission facility owner tariff applications, and is not meant to indicate any
predetermination of the result of a transmission facility owner tariff proceeding, nor be interpreted as AESO
9
support for any specific components of a transmission facility owner tariff application”.
31
The TFO tariff costs included in this application are set out in Table C-2 of Appendix C to this application.
These costs are also included in column A of Table 2-2 below.
6
Exhibit 0026.00.AESO-2718, Alberta Electric System Operator 2014 ISO Tariff Application and 2013 ISO Tariff Update, dated July
19, 2013, at pages 12-13, paragraphs 53-57.
7
Decision 2014-242, Alberta Electric System Operator 2014 ISO Tariff Application and 2013 ISO Tariff Update, issued August 21,
2014, at page 9, paragraph 43.
8
Exhibit 0026.00.AESO-2718, at page 13, paragraphs 54-57.
9
Exhibit 0026.00.AESO-2718, at page 13, paragraph 58.
AESO 2015 ISO Tariff Update
Application
Page 9 of 23
Confidentiality: Public
August 18, 2015
Table 2-2 – AESO 2015 Forecast Revenue Requirement ($ 000 000)
Line
No.
2015
Forecast
2014
2013
2012
Updated Budget Recorded Recorded Recorded
A
B
C
D
E
Description
1
2
3
4
5
6
7
8
9
10
11
WIRES
TFO Wires-Related Costs
AltaLink
ATCO Electric
Isolated Generation
Subtotal ATCO Costs
ENMAX Power Corporation
EPCOR Distribution & Transmission
City of Lethbridge
TransAlta Utilities Corporation
City of Red Deer
FortisAlberta (Farm Transmission)
Subtotal TFO Wires-Related Costs
666.8
662.0
(2.9)
659.1
74.9
97.8
6.1
4.9
3.6
4.7
1,518.0
621.4
579.0
(2.9)
576.1
66.7
84.4
4.7
6.1
3.9
4.5
1,367.7
631.7
578.1
(3.7)
574.4
74.9
97.8
6.1
4.9
3.6
4.7
1,381.9
492.7
483.5
(5.8)
477.7
66.7
84.4
4.7
6.1
3.9
4.5
1,118.5
388.2
400.0
(4.8)
395.2
66.1
90.1
6.1
5.0
3.9
4.7
915.0
12
13
14
15
Non-Wires Costs
Invitation to Bid on Credits (IBOC)
Location Based Credit Standing Offer (LBC SO)
Subtotal IBOC/LBC SO Costs
TOTAL WIRES COSTS
1.5
4.5
6.0
1,524.0
1.5
4.5
6.0
1,373.7
1.5
4.1
5.6
1,387.6
1.3
4.0
5.3
1,123.8
1.6
4.2
5.8
920.8
15.7
49.4
23.9
88.9
15.7
49.4
23.9
88.9
41.8
72.0
54.0
167.8
72.1
137.6
131.3
340.9
70.7
116.6
108.4
295.7
20
21
22
23
24
25
ANCILLARY SERVICES
Operating Reserves
Active
Regulating
Spinning
Supplemental
Subtotal Active Reserves
Standby
Regulating
Spinning
Supplemental
Subtotal Standby Reserves
Trading Fees and Other Related Charges
Subtotal Operating Reserves
11.2
19.7
10.8
41.6
130.5
11.2
19.7
10.8
41.6
130.5
5.2
8.8
2.7
16.8
(3.7)
180.9
9.4
14.9
4.3
28.6
(7.3)
362.2
10.6
15.3
4.7
30.6
(5.7)
320.6
26
27
28
29
30
31
32
33
34
Other Ancillary Services
Black Start
Transmission Must Run (TMR)
Under Frequency Mitigation
Poplar Hill
Interruptible Load Remedial Action Scheme (ILRAS)
LSSi
Reliability Services from BC
Subtotal Other Ancillary Services
TOTAL ANCILLARY SERVICES
5.0
2.5
25.0
2.1
34.6
165.1
5.0
2.5
25.0
32.5
163.0
1.0
4.4
2.8
24.4
32.7
213.6
1.0
11.2
2.5
21.2
36.0
398.2
1.4
27.7
2.5
0.0
22.7
54.3
374.9
35
36
LOSSES
Pool Payment
TOTAL LOSSES COSTS
105.3
105.3
105.3
105.3
118.2
118.2
181.7
181.7
150.5
150.5
16
17
18
19
AESO 2015 ISO Tariff Update
Application
Page 10 of 23
Confidentiality: Public
August 18, 2015
Table 2-2 – AESO 2015 Forecast Revenue Requirement ($ 000 000) (continued)
Line
No.
2015
Forecast
2014
2013
2012
Updated Budget Recorded Recorded Recorded
A
B
C
D
E
Description
37
38
39
40
41
OTHER INDUSTRY COSTS
External Regulatory Costs
Regulatory Process Costs
Western Electricity Coordination Council (WECC)
Share of AUC/EUB Overhead
TOTAL OTHER INDUSTRY COSTS
0.1
1.4
1.2
14.0
16.7
0.1
1.4
1.2
14.0
16.7
0.2
0.7
1.1
13.4
15.3
0.0
1.0
2.8
13.2
17.0
0.3
1.4
3.0
14.0
18.6
42
43
44
45
46
47
48
49
GENERAL AND ADMINISTRATIVE COSTS
Administrative Costs
Staff and Benefits
Contract Services and Consultants
Rent
Administration
Computer and Telecom Services and Maintenance
IT Wind Forecasting
Interconnection Fees (offset)
Subtotal Administrative Costs
44.6
7.6
5.8
3.6
5.8
0.2
67.6
44.6
7.6
5.8
3.6
5.8
0.2
67.6
45.0
10.3
4.6
3.7
5.8
0.3
70.9
43.7
11.5
4.9
3.7
6.1
0.3
70.2
42.2
12.1
4.8
4.2
6.1
0.3
69.0
50
51
52
53
54
General Costs
Market System Replacement
Interest
Amortization and Depreciation
Subtotal General Costs
TOTAL G&A COSTS
(0.2)
17.0
16.8
84.4
(0.2)
17.0
16.8
84.4
0.9
(0.7)
15.8
16.0
86.0
(0.5)
13.4
12.9
83.1
(0.5)
13.3
12.8
81.8
55
TOTAL G&A AND OTHER INDUSTRY COSTS
101.1
101.1
101.3
100.1
100.4
56
TOTAL REVENUE REQUIREMENT
1,895.5
1,743.1
1,820.6
1,803.9
1,546.6
Totals may not add due to rounding
32
The wires costs included in this application and set out in Table 2-2 above are based on the following
Commission decisions and TFO tariff applications.
Line 1 AltaLink Management Ltd.
33
AltaLink Management Ltd. (“AltaLink”) has applied for 2015 TFO tariff costs of $680.5 million (amended from
an initial application for costs of $813.0 million). AltaLink’s 2014 tariff costs are $631.6 million, comprised of
2014 TFO tariff costs of $621.4 approved on a final basis in Commission Decision 2014-258, issued
10
September 7, 2014 plus 72% of an applied-for 2014 amount of $14.3 million included in AltaLink’s 20122013 deferral account reconciliation application. The AESO has included forecast 2015 wires costs of $666.8
million for AltaLink, comprised of $631.6 million for 2014 tariff costs plus 72% of AltaLink’s applied-for
increase of $48.9 million for 2015.
10
Decision 2014-258, AltaLink Management Ltd. Refiling Pursuant to Decision 2013-407 and Decision 2013-459, issued September
8, 2014.
AESO 2015 ISO Tariff Update
Application
Page 11 of 23
Confidentiality: Public
August 18, 2015
Lines 2-4 ATCO Electric Ltd.
34
ATCO Electric Ltd. (“ATCO Electric”) has applied for 2015 TFO tariff costs of $694.3 million. ATCO Electric’s
2014 tariff costs are $579.0 million, being the 2014 TFO tariff costs approved on a final basis in Commission
11
Decision 2014-348, issued December 15, 2014. The AESO has included forecast 2015 wires costs of
$662.0 million for 2015, comprised of $579.0 million for 2014 tariff costs plus 72% of ATCO Electric’s appliedfor increase of $115.3 million.
35
ATCO Electric’s TFO tariff costs are offset by payments to the AESO in respect of pool price for electric
energy provided to isolated communities in accordance with the Isolated Generating Units and Customer
Choice Regulation. The isolated generation cost offset was estimated at $2.9 million based on 2014 recorded
volumes for isolated communities and the 2015 forecast pool price.
36
The 2015 net forecast cost for ATCO Electric is $659.1 million.
Line 5 ENMAX Power Corporation
37
12
ENMAX Power Corporation has refiled for approval of 2015 TFO tariff costs of $74.9 million . The AESO has
accordingly included this amount in this application.
Line 6 EPCOR Distribution & Transmission Inc.
38
EPCOR Distribution & Transmission Inc. (“EPCOR”) has applied for 2015 TFO tariff costs of $100.8 million.
EPCOR’s 2014 tariff costs are $90.1 million, being the 2014 TFO tariff costs approved on a final basis in
13
Commission Decision 3474-D01-2015, issued February 12, 2015. The AESO has included forecast 2015
wires costs of $97.8 million for 2015, comprised of $90.1 million for 2014 tariff costs plus 72% of EPCOR’s
applied-for increase of $10.7 million.
Line 7 City of Lethbridge
39
The City of Lethbridge has not yet applied for its 2015 final TFO tariff costs. The 2015 interim costs for the
City of Lethbridge are $6.1 million as approved on an interim basis in Commission Decision 2014-309, issued
14
on November 13, 2014. The AESO has accordingly included this amount in this application.
Line 8 TransAlta Corporation
40
TransAlta Corporation (“TransAlta”) has not yet applied for its 2015 final TFO tariff costs. The 2015 interim
costs for TransAlta are $4.5 million as approved on an interim refundable basis in Commission Decision
15
2014-369, issued December 22, 2014. The 2015 interim approved cost is same as 2012 final approved cost.
41
TransAlta has refiled for the approval of 2013 and 2014 tariff costs of $4.4 million and $4.9 million
16
respectively . The AESO considers the 2014 refiled costs to be a more reasonable forecast of 2015 costs
than the 2015 interim approved costs, which are a continuation of 2012 final approved costs. The AESO has
accordingly included the $4.9 million amount from TransAlta’s 2013-2014 refiling in this application.
11
Decision 2014-348, ATCO Electric Ltd. 2013-2014 Transmission General Tariff Application Second Compliance Filing, issued
December 15, 2014.
12
ENMAX Power Corporation 2014 Phase I Distribution Tariff Application (“DTA”) and 2014-2015 transmission General Tariff
Application (“GTA”) Refiling Application, Proceeding ID 20124, filed on February 10, 2015
13
Decision 3474-D01-2015, EPCOR Distribution & Transmission Inc. 2013-2014 Transmission Facility Owner Tariff Compliance
Filing, issued February 12, 2015.
14
Decision 2014-309, City of Lethbridge 2015 Interim Transmission Facility Owner Tariff, issued November 13, 2014.
15
Decision 2014-369, TransAlta Corporation, as Manager of the TransAlta Generation Partnership 2015-2016 Interim Tariff
Application, issued December 22, 2014.
16
TransAlta Corporation 2013-2014 GTA Refiling in respect of Decision 3466-D01-2015, Proceeding ID 20524, filed on June 5,
2015
AESO 2015 ISO Tariff Update
Application
Page 12 of 23
Confidentiality: Public
August 18, 2015
Line 9 City of Red Deer
42
The City of Red Deer has applied for 2015 TFO tariff costs of $3.5 million. The City of Red Deer’s 2014 tariff
costs are $3.9 million, being the TFO tariff costs approved on a final basis in Commission Decision 2013-214,
17
issued June 5, 2013. The AESO has included forecast 2015 wires costs of $3.6 million for 2015, comprised
of $3.9 million for 2014 tariff costs less 72% of the City of Red Deer’s applied-for decrease of $0.4 million.
43
Section 32 of the Act requires the AESO to pay owners of electric distribution systems for “farm transmission
costs” as defined in the Act. FortisAlberta Inc. has received approval for 2015 farm transmission costs of $4.7
18
million in Commission Decision 2014-351. The AESO has accordingly included this amount in this
application.
Line 10 FortisAlberta Inc. (Farm Transmission)
Lines 12-14 Non-Wires Costs
44
The AESO includes as wires costs two cost components which are not related to TFOs: Invitation to Bid on
Credit (“IBOC”) costs and Location Based Credit Standing Offer (“LBC SO”) costs. These two programs were
initiated to provide non-wires solutions to transmission wires issues in Alberta and their costs are included as
wires costs for rate-setting purposes. The $6.0 million cost for the two programs was forecast by the AESO in
conjunction with ancillary services costs and, as evidenced by the approval set out in Appendix A to this
application, has been approved by the AESO Board.
2.3
Ancillary Services Costs
45
The forecast 2015 costs for ancillary services are $165.1 million and represent approximately 8.7% of the
AESO’s transmission revenue requirement. Ancillary services, as defined in subsection 1(1)(b) of the Act, are
services required to ensure that the interconnected electric system is operated in a manner that provides a
satisfactory level of service with acceptable levels of voltage and frequency. The largest component of
ancillary services costs is operating reserves, which represent the real power capability above system
19
demand required to provide for regulation, forced outages and unplanned outages.
46
The forecast 2015 ancillary services costs have been updated from amounts included in the AESO 2015
Business Plan and Budget Proposal to incorporate $2.1 million in respect of a reliability services agreement
with British Columbia as approved by the AESO Board. The reliability services comprise grid restoration
balancing support in the event of an Alberta blackout and emergency energy in the event of supply shortfall.
47
Ancillary services costs are primarily a function of volume forecasts and market-based commodity pricing
forecasts. The 2015 forecast costs for ancillary services were based on a forecast average pool price of
$41.49/MWh.
2.4
48
Losses Costs
The 2015 forecast costs for transmission line losses are $105.3 million and represent approximately 5.6% of
the AESO’s transmission revenue requirement as provided in Table 2-1. Losses are the energy lost on the
transmission system when power is transmitted from suppliers to loads. Losses are the residual of the
metered generation plus scheduled imports less metered loads and less scheduled exports.
17
Decision 2013-214, City of Red Deer 2012-2014 Transmission Facility Owner General Tariff Application Compliance Filing, issued
June 5, 2013.
18
Decision 2014-351, FortisAlberta Inc. 2015 Annual PBR Rate Adjustment Filing, issued December 16, 2014 (Errata issued
February 5, 2015).
19
AESO Consolidated Authoritative Document Glossary
AESO 2015 ISO Tariff Update
Application
Page 13 of 23
Confidentiality: Public
August 18, 2015
49
Losses costs are a function of volume forecasts and market-based commodity pricing forecasts. The 2015
forecast costs for losses were based on a forecast average pool price of $41.49/MWh.
2.5
Administrative Costs
50
The 2015 forecast cost for administration is $101.1 million and represents approximately 5.3% of the AESO’s
transmission revenue requirement.
51
Administrative costs are defined in paragraph 1(1)(g) of the Transmission Regulation:
1(1)(g) “ISO’s own administrative costs” means
52
(i)
the transmission-related costs and expenses of the ISO respecting the
administration, operation and management of the ISO,
(ii)
the transmission-related costs and expenses of the ISO respecting
reliability standards and reliability management systems, and
(iii)
the transmission-related costs and expenses required to be paid, or
otherwise appropriately paid, by the ISO, except for the following:
(A)
costs for the provision of ancillary services;
(B)
costs of transmission line losses;
(C)
amounts payable under TFO transmission tariffs;
The AESO Board approves the AESO’s administrative costs in their entirety. However, only the transmissionrelated portions of those costs (as defined in subsection 1(1)(g) of the Transmission Regulation) are
20
recovered through the ISO tariff. Further, the AESO Board approval set out in Appendix A to this application
allocates administrative costs among the three functions of the AESO described above; namely, transmission,
energy market, and load settlement. The transmission-related portions of the AESO’s administrative costs are
included in the AESO’s transmission revenue requirement detailed in Table 2-1 above.
20
Appendix A, AESO Board Decision 2015-BRP-001 at page 7.
AESO 2015 ISO Tariff Update
Application
Page 14 of 23
Confidentiality: Public
August 18, 2015
3
2015 Tariff Update
53
In accordance with the approach referred to in section 1.1 above, this 2015 tariff update uses the rate
calculation methodology approved by the Commission in Decision 3473-D01-2015 in connection with the
AESO’s 2014 ISO tariff application.. Specifically, the AESO has used the 2014 rate calculations provided in
21
Appendix B of the AESO 2014 ISO tariff compliance filing as the template for the 2015 rate calculations. The
2015 rate calculations are set out in Appendix C to this application, in Tables C-1 through C-16.
54
The rate calculations use the following inputs:
(a)
the 2015 forecast revenue requirement discussed in section 2.1 of this application;
(b)
the functionalization of wires costs approved for 2015 in Decision 2013-421 ; and
(c)
the 2015 forecast billing determinants prepared by the AESO.
3.1
Specific Rate Changes
22
55
Where applicable, rates in the ISO tariff have been updated to reflect the 2015 forecast revenue requirement,
2015 wires costs functionalization, and 2015 forecast billing determinants. Specifically, levels of dollar-based
and percentage of pool price amounts have been updated in the following rates:

Rate DTS, Demand Transmission Service;

Rate FTS, Fort Nelson Demand Transmission Service;

Rate DOS, Demand Opportunity Service;

Rate XOS, Export Opportunity Service; and

Rate XOM, Export Opportunity Merchant Service.
56
The levels for each of the above rates have been calculated in accordance with Appendix C to this
application. The updated rate sheets themselves are provided in the proposed 2015 ISO tariff set out in
Appendix E to this application.
57
Additional incidental changes to Rate PSC, Primary Service Credit; Rate STS, Supply Transmission Service,
and Rider J, Wind Forecasting Service Cost Recovery Rider, are discussed below.
3.1.1
Rate PSC, Primary Service Credit
58
Consistent with the calculation of the 2014 primary service credit, the 2015 primary service credit is calculated
as:

79% of the substation fraction ($/month) tier of the Rate DTS point of delivery charge;

79% of the first three capacity (7.5 MW, 9.5 MW, and 23 MW) tiers of the Rate DTS point of delivery
charge; and

100% of the fourth capacity (remaining capacity above 40 MW) tier of the Rate DTS point of delivery
charge.
59
As the Rate DTS point of delivery charge has been updated in this application, the AESO has correspondingly
updated the primary service credit as provided in Table 3-1 below. The primary service credit amounts
21
Proceeding 3473, Exhibit 0004.00.AESO-3473, Alberta Electric System Operator 2014 ISO Tariff Compliance Filing Pursuant to
Decision 2014-242, revised as discussed in Exhibit 0044.01.AESO-3473, response to information request UCA-AESO-002.
22
Proceeding 2718, Exhibit 0265.02.AESO-2718, Alberta Transmission System Cost Causation Study Update dated January 17,
2014, at page 7, Figure 6.
AESO 2015 ISO Tariff Update
Application
Page 15 of 23
Confidentiality: Public
August 18, 2015
determined in Table 3-1 are reflected in Rate PSC of the proposed 2015 ISO tariff set out in Appendix E to
this application.
Table 3-1 – Calculation of 2015 Primary Service Credit
Rate DTS
Charge
PSC
Factor
Rate PSC
Credit
$7,865.00/month
79%
$6,213.00/month
First (7.5 × substation fraction) MW
of billing capacity
$3,184.00/MW
79%
$2,515.00/MW
Next (9.5 × substation fraction) MW
of billing capacity
$1,994.00/MW
79%
$1,575.00/MW
Next (23 × substation fraction) MW
of billing capacity
$1,391.00/MW
79%
$1,099.00/MW
All remaining MW of billing capacity
$901.00/MW
100%
$901.00/MW
Rate Component
Substation fraction
3.1.2
Regulated Generating Unit Connection Costs in Rate STS, Supply Transmission Service
60
The AESO most recently provided the derivation of the regulated generating unit connection costs (“RGUCC”)
charge in an attachment to the AESO’s response to information request AUC-AESO-009 in its 2014 ISO tariff
23
application proceeding. That attachment included a calculation of the RGUCC charge for each calendar
year to 2020, based on the original determinations of the Alberta Energy and Utilities Board (referred to
below) which established the RGUCC. In general, RGUCC charges decrease every year reflecting the
on-going amortization of connection costs over the lives of the previously-regulated generating units.
61
The RGUCC charge calculation was reviewed in Decision 2007-106 in connection with the AESO’s 2007
general tariff application, where the Alberta Energy and Utilities Board stated that “The Board has reviewed
24
this calculation and considers the AESO RGUCC appears to be reasonable.” The 2015 RGUCC value
included in the attachment to the response to information request AUC-AESO-009 is $148.57/MW.
62
The regulated generating unit connection cost charge has accordingly been updated to $149.00/MW in Rate
STS in the proposed 2015 ISO tariff set out in Appendix E to this application, being the 2015 value rounded to
the nearest dollar.
3.1.4
Rider J, Wind Forecasting Service Cost Recovery Rider
63
As the AESO explained in its 2014 ISO tariff application, Rider J charges recover both costs associated with
the AESO’s contracted wind forecasting service as well as variances from forecasts of costs and energy
25
initially used to determine the values of the rider . Since first being implemented in 2011, Rider J is expected
to recover in 2015 all costs of the contracted wind forecasting service incurred to date. With no outstanding
variances to be recovered, the Rider J charge may be set based on the annual cost of the wind forecasting
service.
64
The wind forecasting service annual cost is currently $304,560 and annual metered energy from wind
generating facilities is approximately 4.8 million MWh based on 2014 actuals. The AESO proposes to set the
23
Exhibit 0109.03.AESO-2718, Attachment AUC-AESO-009.
Decision 2007-106, Alberta Electric System Operator 2007 General Tariff Application, issued December 21, 2007, at page 76.
25
Exhibit 0026.00.AESO-2718, at page 13, paragraphs 124-126.
24
AESO 2015 ISO Tariff Update
Application
Page 16 of 23
Confidentiality: Public
August 18, 2015
Rider J charge at $0.06/MWh. The AESO will continue to monitor and report this amount in future tariff
applications and updates.
65
The Rider J charge has accordingly been updated to $0.06/MWh in the proposed 2015 ISO tariff set out in
Appendix E to this application.
3.2
2015 Forecast Billing Determinants
66
The rate calculations for the 2015 rates update are based on the AESO’s forecast of billing determinants for
2015. Those billing determinants were in turn based on the 2015 load forecast in the AESO 2014 Long-term
Outlook, which is the AESO’s long-term load forecast prepared in accordance with the Act and the
Transmission Regulation.
67
The AESO 2014 Long-term Outlook includes a 20-year peak load and electricity consumption forecast for
Alberta. The load forecast is generated from economic growth (gross domestic product or GDP) information,
oilsands production forecasts, and population projections by select consumer sectors, with regional
adjustments based on historical results and participant-driven growth expectations. The AESO 2014 Longterm Outlook, including its data file, is available on the AESO website at www.aeso.ca by following the path
Transmission  Forecasting.
68
To develop the AESO 2014 Long-term Outlook, the AESO produces hourly load forecasts by metering point,
including adjustments for load supplied through on-site generation. Metering points are then correlated to
system access service accounts to develop annual profiles for forecast hourly load at each point of delivery.
Billing determinants are calculated directly from the per-point-of-delivery forecast hourly load profiles. In
addition, the billing determinant for billing capacity also incorporates:

current contract capacity and known contract capacity changes during the forecast year for each
service account; and

ratchets based on historical peak demand information in the AESO’s billing system as well as new
forecast peak demands during the forecast year for each service account.
69
Substation fractions are applied to billing capacities to develop billing determinants for each of the point of
delivery charge capacity tiers. Substation fractions are also applied to develop the billing determinant for
“equivalent” market participants, used in the calculation of the fixed ($/month) tier of the Rate DTS point of
delivery charge.
70
The AESO notes that the per-point-of-delivery annual profiles for forecast hourly load as well as the per-pointof-delivery billing determinants are considered confidential information which should not be made publicly
available. Forecast hourly load data for individual points of delivery and future contract capacity changes are
clearly of a commercial and financial nature that is consistently treated as confidential by the AESO. The
AESO further considers that the provision of such detailed information could result in harm to a market
participant’s competitive position by disclosing patterns and trends that could be used to advantage by a
competitor.
71
As has been the traditional practice in AESO rate calculations, the billing determinants used in the 2015 rate
calculations are provided in aggregate, in Table C-12 of Appendix C to this application.
72
Additionally, Table 3-2 below provides a comparison of the forecast billing determinants in this tariff update to
those for 2014 in the AESO’s 2014 ISO tariff compliance filing. Coincident metered demand and energy billing
determinants have increased by 1.5% and 2.4% respectively compared to the 2014 forecast, while number of
DTS market participants has increased by approximately 5.6%. Billing capacity (which incorporates noncoincident metered demand, demand ratchets, and contract minimums) has increased by approximately
AESO 2015 ISO Tariff Update
Application
Page 17 of 23
Confidentiality: Public
August 18, 2015
1.6%, with an increase of approximately 5.7% in the first demand tier, an increase of approximately 4.2% in
the second demand tier, almost no change in the third demand tier and a decrease of approximately 2.7% in
the last demand tier.
Table 3-2 – 2015 and 2014 Forecast Billing Determinants
Rate DTS
Billing Determinant
Units
Increase (Decrease)
2015
Forecast
2014
Forecast
94,946.8
93,499.5
1,447.2
1.5%
Amount
Coincident Metered Demand
MW-months
Billing Capacity

Total Billing Capacity

First (7.5×SF) MW

Next (9.5×SF) MW

Next (23×SF) MW

All Remaining MW
MW-months
MW-months
MW-months
MW-months
MW-months
147,147.6 144,857.7
37,499.9
35,479.3
33,233.2
31,895.7
38,564.8
38,601.5
37,849.7
38,881.2
2,289.9
2,020.6
1,337.5
(36.7)
(1,031.5)
1.6%
5.7%
4.2%
(0.1%)
(2.7%)
Highest Metered Demand
MW-months
114,583.1 115,788.5
(1,205.4)
(1.0%)
Metered Energy (All Hours)
DTS Market Participants
Pool Price (Weighted by Volume)
GWh
60,328.0
58,920.9
1,407.0
2.4%
customer-months
5,599.5
5,300.5
299.1
5.6%
$/MWh
41.49
48.68
(7.19)
Average Increase (Decrease) (Weighted by Revenue)
73
%
(14.8%)
2.0%
To further examine the reasonableness of the 2015 forecast billing determinants, Table 3-3 below provides a
comparison of the forecast billing determinants in this rates update application to the actual billing
determinants recorded by the AESO in 2013 and 2014. The AESO considers that the increase in billing
determinants forecast for 2015 is reasonable when compared to recorded billing determinants for the two
prior years.
Table 3-3 – 2015 Forecast, 2014 Recorded, and 2013 Recorded Billing Determinants
Rate DTS
Billing Determinants
Coincident Metered Demand
Billing Capacity (Total)
Highest Metered Demand
Metered Energy (All Hours)
Market Participants (Total)
74
Units
MW-months
MW-months
MW-months
GWh
customer-months
2015
Forecast
94,946.8
147,147.6
114,583.1
60,328.0
5,599.5
2014
Recorded
2013
Recorded
94,058.7
145,958.0
116,814.7
59,043.3
5,244.4
91,160.3
140,073.3
112,713.2
56,959.3
5,137.7
Overall, the AESO considers that the 2015 forecast provides an accurate estimation of billing determinants for
the rate calculations in this application.
AESO 2015 ISO Tariff Update
Application
Page 18 of 23
Confidentiality: Public
August 18, 2015
3.3
Bill Impacts
75
As noted in section 2 of this application, the AESO’s 2015 forecast revenue requirement represent an
increase of 4.1% over the total recorded costs for 2014.
76
At the same time, billing determinants have also changed from the 2014 forecast on which currently-approved
rates are based. As a result, the AESO’s 2015 updated rates represents an overall increase of 4.5% over the
2014 rates currently in place, including an increase of 5.1% to Rate DTS, Demand Transmission Service, and
a decrease of 4.2% to Rate STS, Supply Transmission Service.
77
Deferral accounts provide certainty that the AESO’s costs will be exactly recovered by revenue, either through
base rates or through deferral accounts. Increases in costs paid by the AESO will therefore flow to and impact
market participants through deferral accounts if rates are not increased. The changes in rates summarized
above simply improve the timeliness and accompanying accuracy of the recovery of costs from market
participants.
78
The increases to the different components of Rate DTS are provided in Table 3-4 below. The Rate DTS
increase of 5.1% represents a revenue-weighted average increase over all components of Rate DTS. Of note
is the approximately 19% increase to bulk system charges and the approximately 9% decrease to point of
delivery charges, resulting from the functionalization of wires costs approved for 2015 in Decision 2013-421
as discussed earlier in section 2 of this application. The 2015 functionalization has a greater proportion of
wires costs functionalized as bulk system, and a lower proportion functionalized as point of delivery,
compared to the 2014 functionalization used for currently-approved rates.
79
Individual increases experienced by market participants will vary, depending on the specific characteristics of
a market participant’s service including peak demand coincidence, billing capacity, load factor, and hourly
pool price at the time of usage.
80
To allow individual market participants to estimate the impact of the 2015 rates on their own Rate DTS bills,
the AESO has included a bill impact estimator as Table C-16 in the rate calculations set out in Appendix C to
this application. The bill impact estimator calculates bills for a given set of billing inputs under both the current
2014 Rate DTS and the updated 2015 Rate DTS, to allow the impact of the rates update on an individual
service to be estimated.
Table 3-4 – Increase (Decrease) for 2015 Rate DTS Components
Rate DTS Charge
Bulk System

Coincident Demand

Energy
Local System

Billing Capacity

Energy
Point of Delivery

Participant × SF

First (7.5 × SF) MW BC

Next (9.5 × SF) MW BC

Next (23 × SF) MW BC

Remaining MW BC
AESO 2015 ISO Tariff Update
Application
Unit
Proposed
(1 Oct 2015)
Current
(1 Jul 2015)
Increase
(Decrease)
$/MW
$/MWh
$9,305.00
$1.09
$7,790.00
$0.92
19.4%
18.5%
$/MW billing
$/MWh
$2,162.00
$0.76
$2,181.00
$0.77
(0.9%)
(1.3%)
$/month
$/MW
$/MW
$/MW
$/MW
$7,865.00
$3,184.00
$1,994.00
$1,391.00
$901.00
$8,653.00
$3,503.00
$2,194.00
$1,530.00
$991.00
(9.1%)
(9.1%)
(9.1%)
(9.1%)
(9.1%)
Page 19 of 23
Confidentiality: Public
August 18, 2015
Operating Reserve
Voltage Control
Other System Support
Net Change (revenue weighted)
% of Pool Price
$/MWh
$/MW
6.41%
$0.00
$41.00
7.74%
$0.00
$22.00
(17.2%)
NA
86.4%
5.1%
81
The decreases to the different components of Rate STS are provided in Table 3-5 below. The Rate STS
decrease of 4.2% represents a revenue-weighted average decrease over all components of the rate.
82
Individual decreases or increases experienced by market participants will vary, depending on the specific
characteristics of a market participant’s system access service including whether it includes a previouslyregulated generating unit subject to the regulated generating unit (“RGU”) connection costs charge.
Table 3-5 – Increase (Decrease) for 2015 Rate STS Components
Rate STS Charge
Losses
RGU Connection Costs
Net Change (revenue weighted)
83
Unit
% of Pool Price
$/MW
Proposed
(1 Oct 2015)
Current
(1 Jul 2015)
3.92%
$149.00
4.04%
$176.00
Increase
(Decrease)
(3.2%)
(15.3%)
(4.2%)
In particular, the AESO notes that the loss factors provided in Table 3-5 are representative average loss
factors only. The actual losses charge applicable to an individual market participant will be based on a
location-specific loss factor determined in accordance with section 501.10 of the ISO rules, Transmission
Loss Factor Methodology and Requirements, as specified in Rate STS.
AESO 2015 ISO Tariff Update
Application
Page 20 of 23
Confidentiality: Public
August 18, 2015
4
2015 Maximum Investment Levels Update
84
The tariff update approach described in section 1.1 of this application includes updating investment amounts
approved in the most recent comprehensive tariff application reflecting an escalation factor.
85
The AESO has accordingly updated the composite inflation index used for developing the point of delivery
cost function to 2015, using additional Statistics Canada cost index values and the most recent Conference
Board of Canada forecast of the Alberta consumer price index. Table 4-1 below provides the composite
inflation index values for 2013, 2014, and 2015 as included in the 2014 ISO tariff compliance filing and as
updated in this application. Values prior to 2013 have not changed and are excluded from Table 4-1 as they
do not affect the escalation factor.
Table 4-1 – Escalation Factor for Composite Inflation Index
Year
2014 Compliance Filing
Basis
2013
Actual
2014
Forecast
2015
—
Escalation Factor
Annual
2.78%
3.00%
—
Cumulative
2015 Tariff Update
Basis
Annual
2.78%
Actual
2.78%
5.86%
Actual
3.32%
—
Forecast
0.38%
106.59% 2015 ÷ 105.86% 2014 =
Cumulative
2.78%
6.19%
6.59%
1.0069
86
The resulting escalation factor for updating the 2015 maximum investment levels in section 8 of the ISO tariff
is 1.0069, which represents a small increase to the 2014 maximum investment levels. The increase reflects
increases in the latest underlying indices used for the composite index. The detailed calculation of the
composite inflation index is included in Appendix D of this application.
87
The AESO has applied the resulting 1.0069 escalation factor to the 2014 Rate DTS maximum investment
levels to determine the 2015 Rate DTS maximum investment levels, as summarized in Table 4-2 below.
Table 4-2 also includes the calculation of the corresponding Rate PSC maximum investment levels for each
year.
AESO 2015 ISO Tariff Update
Application
Page 21 of 23
Confidentiality: Public
August 18, 2015
Table 4-2 – Calculation of 2015 Maximum Investment Levels
Rate DTS
Investment
PSC
Factor
Rate PSC
Investment
$76 050/year
21%
$15 970/year
First (7.5 × substation fraction) MW
of contract capacity
$30 800/MW/year
21%
$6 470/MW/year
Next (9.5 × substation fraction) MW
of contract capacity
$19 300/MW/year
21%
$4 050/MW/year
Next (23 × substation fraction) MW
of contract capacity
$13 450/MW/year
21%
$2 820/MW/year
All remaining MW of contract capacity
$8 700/MW/year
0%
$0/MW/year
Tier
2014 Maximum Investment Levels
Substation fraction (for new points of
delivery only)
2015 Escalation Factor
1.0069
2015 Maximum Investment Levels
Substation fraction (for new points of
delivery only)
$76 550/year
21%
$16 080/year
First (7.5 × substation fraction) MW of
contract capacity
$31 000/MW/year
21%
$6 510/MW/year
Next (9.5 × substation fraction) MW of
contract capacity
$19 450/MW/year
21%
$4 080/MW/year
Next (23 × substation fraction) MW of
contract capacity
$13 550/MW/year
21%
$2 850/MW/year
All remaining MW of contract capacity
$8 750/MW/year
0%
$0/MW/year
AESO 2015 ISO Tariff Update
Application
Page 22 of 23
Confidentiality: Public
August 18, 2015
5
Conclusion
88
Based on all of the foregoing, the AESO submits that the tariff updates proposed in this application are just
and reasonable, and respectfully requests that the Commission approve this tariff update application,
including (i) the updated amounts set out in Appendix C to this application, and (ii) the proposed 2015 ISO
tariff set out in Appendix E to this application, effective January 1, 2016. If the timing of this application does
not permit the granting of final approval prior to January 1, 2016, the AESO also requests that the
Commission approve this application on an interim refundable basis effective as of that date. The AESO
further requests that the Commission issue its approval (whether on an interim or final basis) on or before
November 1, 2015, to provide the AESO with adequate time to program and test the rates in the AESO’s
billing system in advance of the January 1,2016 effective date.
89
All of which is respectfully submitted this 18 day of August, 2015.
Alberta Electric System Operator
Per: “Heidi Kirrmaier”
Heidi Kirrmaier
Vice-President, Regulatory
AESO 2015 ISO Tariff Update
Application
Page 23 of 23
Confidentiality: Public
August 18, 2015