Alberta Electric System Operator 2016 ISO Tariff Update Date:

Alberta Electric System Operator
2016 ISO Tariff Update
Date:
February 2, 2016
Prepared by:
Alberta Electric System Operator
Prepared for: Alberta Utilities Commission
Contents
1
Introduction ........................................................................................................................................... 4
1.1
1.2
1.3
2
AESO 2016 Forecast Revenue Requirement ..................................................................................... 7
2.1
2.2
2.3
2.4
2.5
3
Background ................................................................................................................................................ 4
Organization ............................................................................................................................................... 5
Relief Requested........................................................................................................................................ 6
AESO Board Approval of Costs ................................................................................................................. 7
Wires Costs ................................................................................................................................................ 8
Ancillary Services Costs ........................................................................................................................... 13
Losses Costs............................................................................................................................................ 13
Administrative Costs ................................................................................................................................ 14
2016 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
2016 Forecast Billing Determinants ......................................................................................................... 17
Bill Impacts ............................................................................................................................................... 19
4 2016 Maximum Investment Levels Update ...................................................................................... 22
5 Conclusion .......................................................................................................................................... 24
Appendices ........................................................................................................................ Filed Separately
A
B
C
D
E
F
AESO Board Decision (Dated December 16, 2015)
AESO 2016 Business Plan and Budget Proposal (Dated October 29, 2015)
2016 Rates Calculations
Escalation Factor and Investment Levels
Proposed 2016 ISO Tariff 2016 Rates, Rider J, and Section 8 of the ISO Tariff
Proposed 2016 ISO Tariff 2016 Rates, Rider J, and Section 8 of the ISO Tariff (blackline)
AESO 2016 ISO Tariff Update
Application
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Tables
Table 2-1 – 2016 Forecast, 2015 Updated Forecast, 2014 and 2013 Recorded Cost Components .... 7
Table 2-2 – AESO 2016 Forecast Revenue Requirement ($ 000 000) .................................................. 10
Table 3-1 – Calculation of 2016 Primary Service Credit ........................................................................ 16
Table 3-2 – 2016 Forecast and 2015 Recorded Billing Determinants .................................................. 18
Table 3-3 – 2016 Forecast, 2015, 2014 and 2013 Recorded Billing Determinants .............................. 19
Table 3-4 – Increase (Decrease) for 2016 Rate DTS Components ....................................................... 20
Table 3-5 – Increase (Decrease) for 2016 Rate STS Components ....................................................... 20
Table 4-1 – Escalation Factor for Composite Inflation Index ............................................................... 22
Table 4-2 – Calculation of 2016 Maximum Investment Levels.............................................................. 23
Appendix C: 2016 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 2016 Forecast Revenue Requirement
2016 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
2016 Billing Determinants
Rate Change Impact Compared to 2015 Approved Rates
Fort Nelson Demand Transmission Service Rate Calculation
2016 Fort Nelson Billing Determinants
Bill Impact Estimator
AESO 2016 ISO Tariff Update
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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 2016 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 2016 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 2015 ISO tariff.
3
The AESO notes that since approving the AESO’s most recent major tariff application in Decision 34731
D01-2015, the Commission approved ISO tariff amendments (to rates, rider and definitions) associated
2
with the transmission constraint rebalancing charge in Decision 20623-D01-2015. The AESO has
accordingly included these approved amendments in this tariff update application.
1.1
4
Background
3
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
4
consumer price index (CPI).
5
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.
6
The AESO’s most recent major tariff application was filed on July 17, 2013, by which the AESO sought
5
approval from the Commission for the 2014 ISO tariff. The AESO’s most recent tariff update application
was filed on August 20, 2015, by which the AESO sought approval from the Commission for the 2015 ISO
6
tariff. The Commission approved the current form of the 2015 ISO tariff, effective January 1, 2016, first
7
by way of Decision 20753-D01-2015 on an interim basis and then by way of Decision 20753-D02-2015
1
Decision 3473-D01-2015, Alberta Electric System Operator 2014 ISO Tariff Compliance Filing Pursuant to Decision 2014-242, issued June 2, 2015, errata issued June 17,
2015
2
Decision 20623-D01-2015, Application for AESO 2015 Transmission Constraint Rebalancing Charge and Approval to Amend the ISO Tariff Pursuant to Decisions 2013-135
and 3528-D01-2015, issued November 5, 2015
3
Decision 2010-606, Alberta Electric System Operator 2010 ISO Tariff, issued December 22, 2010.
4
Decision 2010-606 at page 99, paragraph 537.
5
Exhibit 0002.00.AESO-2718.
6
Exhibit 20753-X0002.
7
Decision 20753-D02-2015, Alberta Electric System Operator 2015 ISO Tariff Update, issued December 21, 2015.
AESO 2016 ISO Tariff Update
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on a final basis. The 2015 ISO tariff approved in that decision reflected costs and billing determinants for
the 2015 calendar year. The AESO is now filing this annual tariff update application to reflect costs and
billing determinants for the 2016 calendar year.
7
In accordance with the approach referred to above, this tariff update application consists of formulaic
updates to: (i) the AESO’s annual revenue requirement, based on the AESO’s updated forecast costs for
2016; (ii) rate, rider, and maximum investment level amounts using the rate calculation methodology
8
already approved by the Commission in Decision 3473-D01-2015, and (iii) the investment amounts first
9
10
approved in Decision 3473-D01-2015 and then updated in Decision 20753-D02-2015, in accordance
with the escalation factor described below. In the AESO’s view, the updates 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
8
Organization
Similar to previous ISO tariff update applications, this application is organized into the following sections:
1 Introduction — Provides background on the application and specifies the relief requested.
2 2016 Forecast Revenue Requirement — Summarizes the AESO’s forecast revenue requirement for
2016, including costs that 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 2016 Tariff Update — Discusses the calculation of rate levels based on the 2016 forecast revenue
requirement, 2016 wires costs functionalization and classification approved in Commission Decision
11
2013-421, and 2016 forecast billing determinants.
4 2016 Maximum Investment Levels Update — Discusses the calculation of 2016 maximum
investment levels using the 2016 escalation factor.
5 Conclusion — Reiterates the relief requested.
9
This application also includes the following appendices:
A AESO Board Decision — AESO Board decision issued on December 16, 2015, approving forecasted
ancillary services costs, forecasted losses costs, and the AESO’s business plan and budget for 2016.
B AESO 2016 Business Plan and Budget Proposal — Document prepared by AESO management in
consultation with stakeholders, as submitted to the AESO Board on October 29, 2015, containing the
AESO’s proposed 2016 business initiatives and proposed 2016 budgets and forecasts for ancillary
services costs, transmission line losses costs, and administrative costs.
C 2016 Rate Calculations — Microsoft Excel workbook which calculates the updated dollar and
percentage of pool price amounts for the 2016 rates, based on the same methodology used for the
AESO’s currently approved rates.
D 2016 Escalation Factor and Investment Levels — Microsoft Excel workbook which calculates the
composite inflation index and escalation factor used to update maximum investment levels.
8
See footnote 1.
See footnote 1.
See footnote 7.
11
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.
9
10
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E 2016 Rates, Riders, and Section 8 of the ISO Tariff — The proposed 2016 rates, riders, and section
8 that incorporate the 2016 updated amounts included as Appendices C and D to this application.
F 2016 Rates, Riders, and Section 8 of the ISO Tariff (blackline) — The blackline version of the
proposed 2016 rates, riders, and section 8 that incorporate the 2016 updated amounts included as
Appendix C to this application.
1.3
Relief Requested
10
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 included as Appendix C to this application, and (ii) the
proposed 2016 ISO tariff Rate DTS, Rate FTS, Rate DOS, Rate XOS, Rate XOM, Rate PSC and Rate
STS, Rider J and Section 8 included as Appendix E to this application, which incorporates the updated
amounts.
11
The AESO respectfully requests that this application be approved effective April 1, 2016. If the timing of
this application does not permit the granting of final approval prior to April 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 March 31, 2016 as this is the last approval date that will allow the AESO to implement
the proposed tariff updates effective April 1, 2016 on a prospective basis. For additional clarity, the
AESO requests that the updated rates, riders and investment levels proposed in this application apply on
a go-forward basis only, commencing from the effective date approved by the Commission. Consistent
12
with the Commission’s statements in Decision 2014-242, the AESO submits that currently-approved
deferral account rider and reconciliation mechanisms should continue to be used to address any
variances between costs and revenues occurring prior to the approval of the applied-for rates. The AESO
is not seeking any retroactivity with respect to the rates proposed for approval in this application.
12
The AESO requires a minimum of one month to program and test approved rates. As such, the AESO will
begin programming and testing with the applied-for updated rates in March or April and will therefore be
ready to perform calculations based on the applied-for updated rates when statements of account for April
are issued in early May, consistent with an April 1, 2016 effective date.
12
Decision 2014-242, Alberta Electric System Operator 2014 ISO Tariff Application and 2013 ISO Tariff Update, issued August 21, 2014, paragraph 617.
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2
13
AESO 2016 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 2016 are detailed in column A of Table 2-1. For
comparison, Table 2-1 includes costs approved in the AESO Board Decision for 2016 (included as
13
Appendix A to this application), updated forecast costs for 2015, and the recorded costs for 2014 and
2013, in columns B, C, D, and E, respectively.
Table 2-1 – 2016 Forecast, 2015 Updated Forecast, 2014 and 2013 Recorded Cost Components
2016 Forecast
Cost Component
Wires
Ancillary services
Losses
Administrative
Revenue Requirement
Updated
($ 000 000)
Budget Proposal
($ 000 000)
A
1,684.5
182.6
111.9
98.4
2,077.6
B
1,684.8
182.6
111.9
98.4
2,077.8
2015
2014
2013
Updated
Forecast
($ 000 000)
C
1,523.1
162.9
76.4
101.0
1,863.6
Recorded
($ 000 000)
Recorded
($ 000 000)
D
1,387.6
213.6
118.2
101.3
1,820.6
E
1,123.8
398.2
181.7
100.1
1,803.9
Note: Numbers may not add due to rounding
14
The 2016 updated forecast costs represent an increase of $214.0 million (or 11.5%) over the 2015
updated forecast costs. The increase primarily results from a forecast increase of $161.4 million (or
10.6%) in wires costs reflecting recent applications for TFO tariffs by transmission facility owners.
Ancillary services costs are forecast to increase by $19.6 million (or 12.1%) and losses costs are forecast
to increase by $35.5 million (or 46.5%), while administrative costs are forecast to decrease by $2.6 million
(or 2.6%).
2.1
AESO Board Approval of Costs
15
The AESO is not seeking approval in this application of its 2016 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 2016 Business Plan and
Budget Proposal dated October 29, 2015, included as 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
2016 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 2015, as discussed in more detail
below.)
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.
13
2015 Updated Forecast includes actual recorded costs to November 30, 2015 and 1 month forecast costs for December 2015
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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 2016 budget, AESO management consulted with
stakeholders in a planning process that had been first established with stakeholders in 2009. In mid-2015,
the AESO reviewed the business initiatives established for 2016 and prepared a forecast budget required
to deliver those business initiatives. Following consultation with stakeholders and incorporating
appropriate amendments arising from it, AESO management submitted the 2016 Business Plan and
Budget Proposal to the AESO Board on October 29, 2015. This document (included as 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 2016. The 2016 Business Plan and Budget Proposal was also
provided to stakeholders and posted on the AESO website.
24
The AESO’s 2016 forecast costs were approved by the AESO Board on December 16, 2015. A Board
Decision Document was posted on the AESO website and is included as Appendix A to this application.
25
Additional information on the AESO’s business priorities and budget for 2016 is available on the AESO
website at www.aeso.ca by following the path About AESO  Our Business  Business Plan and Budget
 2016 Budget.
2.2
Wires Costs
26
The 2016 updated forecast costs for wires are $1,684.5 million and represent approximately 81.1% 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 2016 Business Plan and Budget Proposal discussed in section 2.1 above included wires-related
costs based on the TFO tariff approved by the Commission or applied for by TFOs at the time the AESO
budget was prepared in late 2015. Those costs are included in column B, lines 1 through 10, of Table 2-2
below. For most of the TFOs, costs in column B reflect their tariff applications for 2016. For TFOs that
have not filed a tariff application for 2016, costs in column B reflect their most recent tariff application or
their most recent TFO tariff approval on a final basis.
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28
The AESO has determined the 2016 wires costs for TFOs using the following approach, which was
14
described in section 2.2.1 of the AESO’s 2014 ISO tariff application and 2013 ISO tariff update and
15
referred to in 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
16
Commission on either a final or interim basis.
17,18
29
As discussed in greater detail below, the Commission has issued decisions
approving certain 2016
TFO tariffs, and applications have been filed for several 2016 TFO tariffs. Therefore, in accordance with
the foregoing approach, the AESO has forecasted the 2016 wires costs in Table 2-1 to reflect these
approval 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
19
AESO support for any specific components of a transmission facility owner tariff application”.
31
The TFO tariff costs included in this application are included as Table C-2 of Appendix C to this
application. These costs are also included in column A of Table 2-2 below.
14
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 5357.
15
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.
16
Exhibit 0026.00.AESO-2718, at page 13, paragraphs 54-57.
17
Decision 20802-D01-2015, The City of Red Deer Compliance Filing to Decision 3599-D01-2015, issued October 23, 2015.
18
20818-D01-2015 FortisAlberta Inc. 2016 Annual Performance-Based Regulation Rate Adjustment Filing, issued December 17, 2015
19
Exhibit 0026.00.AESO-2718, at page 13, paragraph 58.
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Table 2-2 – AESO 2016 Forecast Revenue Requirement ($ 000 000)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
2016
2016
2015
2014
2013
Updated Forecast Updated
Recorded Recorded
Forecast Budget Forecast
A
B
C
D
E
Description
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
Non-Wires Costs
Invitation to Bid on Credits (IBOC)
Location Based Credit Standing Offer (LBC SO)
Subtotal IBOC/LBC SO Costs
TOTAL WIRES COSTS
691.6
796.9
(2.9)
794.0
73.9
99.8
6.2
4.9
3.9
4.8
1,679.1
718.7
770.7
(2.9)
767.9
74.1
98.9
6.1
4.9
3.9
4.8
1,679.3
666.8
662.0
(2.9)
659.1
74.9
97.8
6.1
4.9
3.6
4.7
1,518.0
631.7
578.1
(3.7)
574.4
66.1
90.1
6.1
5.0
3.9
4.7
1,381.9
492.7
483.5
(5.8)
477.7
54.4
75.3
5.9
4.5
3.4
4.6
1,118.5
1.5
4.0
5.5
1,684.5
1.5
4.0
5.5
1,684.8
1.4
3.7
5.1
1,523.1
1.5
4.1
5.6
1,387.6
1.3
4.0
5.3
1,123.8
27.2
57.7
40.7
125.7
27.2
57.7
40.7
125.7
33.0
42.0
30.2
105.2
41.8
72.0
54.0
167.8
72.1
137.6
131.3
340.9
6.9
12.4
3.5
22.7
(1.3)
147.1
6.9
12.4
3.5
22.7
(1.3)
147.1
5.0
19.8
8.3
33.1
(1.0)
137.3
5.2
8.8
2.7
16.8
(3.7)
180.9
9.4
14.9
4.3
28.6
(7.3)
362.2
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
26
27
28
29
30
31
32
33
34
35
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
Transmission Constraint Rebalancing (TCR)
Subtotal Other Ancillary Services
TOTAL ANCILLARY SERVICES
2.1
4.0
2.5
20.0
2.9
4.0
35.5
182.6
2.1
4.0
2.5
20.0
2.9
4.0
35.5
182.6
2.1
1.3
2.6
17.4
2.1
25.6
162.9
1.0
4.4
2.8
24.4
32.7
213.6
1.0
11.2
2.5
21.2
36.0
398.2
36
37
LOSSES
Pool Payment
TOTAL LOSSES COSTS
111.9
111.9
111.9
111.9
76.4
76.4
118.2
118.2
181.7
181.7
16
17
18
19
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Table 2-2 – AESO 2016 Forecast Revenue Requirement ($ 000 000) (continued)
Line
2016
No.
2016
2015
2014
2013
Forecast Updated
Updated
Recorded Recorded
Budget Forecast
A
B
C
D
E
Description
38
39
40
41
OTHER INDUSTRY COSTS
Regulatory Process Costs
Western Electricity Coordination Council (WECC)
Share of AUC Overhead
TOTAL OTHER INDUSTRY COSTS
1.4
2.2
12.0
15.5
1.4
2.2
12.0
15.5
1.5
1.2
14.0
16.7
0.9
1.1
13.4
15.3
1.0
2.8
13.2
17.0
42
43
44
45
46
47
48
49
GENERAL AND ADMINISTRATIVE COSTS
Administrative Costs
Staff and Benefits
Contract Services and Consultants
Administration
Facilities
Computer and Telecom Services and Maintenance
IT Wind Forecasting
Interconnection Fees (offset)
Subtotal Administrative Costs
47.2
4.2
3.5
5.7
6.6
0.2
67.4
47.2
4.2
3.5
5.7
6.6
0.2
67.4
44.6
7.6
3.6
5.8
5.8
0.2
67.5
45.0
10.3
3.7
4.6
6.1
0.3
70.0
43.7
11.5
3.7
4.9
6.1
0.3
70.2
50
51
52
53
54
General Costs
Market System Replacement
Interest
Amortization and Depreciation
Subtotal General Costs
TOTAL G&A COSTS
(0.2)
15.7
15.5
82.9
(0.2)
15.7
15.5
82.9
(0.2)
17.0
16.8
84.3
0.9
(0.7)
15.8
16.0
86.0
(0.5)
13.4
12.9
83.1
55
TOTAL G&A AND OTHER INDUSTRY COSTS
98.4
98.4
101.0
101.3
100.1
56
TOTAL REVENUE REQUIREMENT
2,077.6
2,077.8
1,863.6
1,820.6
1,803.9
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 2016 TFO tariff costs of $703.5 million (amended
from an initial application for costs of $1,001.6 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 201420
258 plus 72% of an applied-for 2014 amount of $14.3 million included in AltaLink’s 2012-2013 deferral
21
account reconciliation application. The AESO has included forecast 2016 wires costs of $691.6 million
for AltaLink that have been calculated in two steps. First 2015 wires costs of $660.8 million have been
forecasted as: (a) $631.6 million for 2014 tariff costs plus (b) 72% of AltaLink’s applied-for increase of
$40.6 million (from $631.6 million for 2014 to $672.2 million for 2015). Then 2016 wires costs of $691.6
20
21
Decision 2014-258, AltaLink Management Ltd. Refiling Pursuant to Decision 2013-407 and Decision 2013-459, issued September 8, 2014.
Exhibit 3585-X0655, AltaLink 2012 and 2013 Deferral Account Reconciliation Application, Proceeding 3585, dated July 31, 2015
AESO 2016 ISO Tariff Update
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million have been forecasted as: (a) $660.8 million for 2015 tariff costs plus (b) 72% of AltaLink’s appliedfor increase of $42.7 million (from $660.8 million for 2015 to $703.5 million for 2016).
Lines 2-4 ATCO Electric Ltd.
34
ATCO Electric Ltd. (“ATCO Electric”) has applied for 2016 TFO tariff costs of $843.2 million (amended
from an initial application for costs of $810.8 million). ATCO Electric’s 2014 tariff costs are $569.3 million,
comprised of 2014 TFO tariff costs of $579.0 million as approved on a final basis in Commission Decision
22
2014-348 plus 72% of an applied-for 2014 amount of ($13.4) million included in ATCO Electric’s 201323
2014 deferral account reconciliation application. The AESO has included forecast 2016 wires costs of
$796.9 million for ATCO Electric that have been calculated in two steps. First 2015 wires costs of $677.8
million have been forecasted as: (a) $569.3 million for 2014 tariff costs plus (b) 72% of ATCO Electric’s
applied-for increase of $150.7 million (from $569.3 million for 2014 to $720.0 million for 2015). Then 2016
wires costs of $796.9 million have been forecasted as: (a) $677.8 million for 2015 tariff costs plus (b) 72%
of ATCO Electric’s applied-for increase of $165.4 million (from $677.8 million for 2015 to $843.2 million for
2016).
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 2014-2015
recorded volumes for isolated communities and the 2016 forecast pool price.
36
The 2016 net forecast cost for ATCO Electric is $794.0 million.
Line 5 ENMAX Power Corporation
37
ENMAX Power Corporation (“ENMAX”) has received approval for 2015 TFO tariff costs of $73.9 million in
24
Commission Decision 20819-D01-2015. ENMAX has not yet applied for 2016 TFO tariff costs. The
AESO has accordingly included $73.9 million as forecast ENMAX 2016 TFO tariff costs in this application.
Line 6 EPCOR Distribution & Transmission Inc.
38
EPCOR Distribution & Transmission Inc. (“EPCOR”) has refilled for 2016 TFO tariff costs of $99.8
25
million. The AESO has accordingly included $99.8 million as forecast EPCOR 2016 TFO tariff costs in
this application.
Line 7 City of Lethbridge
39
26
The City of Lethbridge has applied for 2016 TFO tariff costs of $6.3 million. City of Lethbridge’s 2014
27
tariff costs are $6.1 million as approved on a final basis in Commission Decision 2013-364. The AESO
has included forecast 2016 wires costs of $6.2 million for City of Lethbridge that have been calculated in
two steps. First 2015 wires costs of $5.7 million have been forecasted as: (a) $6.1 million for 2014 tariff
costs plus (b) 72% of City of Lethbridge’s applied-for decrease of $0.5 million (from $6.1 million for 2014
to $5.6 million for 2015). Then 2016 wires costs of $6.2 million have been forecasted as: (a) $5.7 million
for 2015 tariff costs plus (b) 72% of City of Lethbridge’s applied-for increase of $0.6 million (from $5.7
million for 2015 to $6.3 million for 2016).
22
Decision 2014-348, ATCO Electric Ltd. 2013-2014 Transmission General Tariff Application Second Compliance Filing, issued December 15, 2014.
Exhibit 21206-X0010, ATCO Electric Application for Disposal of 2013 and 2014 Transmission Deferral Account and Annual Filing for Adjustment Balances, Proceeding
21206, dated January 8, 2016
24
Decision 20819-D01-2015, ENMAX Power Corporation Decision on Request for Review and Variance of Decision 20124-D01-2015: 2014 Phase I Distribution Tariff and
2015-2015 Transmission General Tariff Compliance Filing, issued November 27, 2015
25
EPCOR Distribution & Transmission Inc. 2015-2017 Transmission Facility Owner Tariff and 2013 Generic Cost of Capital Compliance Refiling Application, Proceeding 21229,
filed January 4, 2016.
26
City of Lethbridge 2015-17 TFO General Tariff Application, Proceeding 21213, filed December 24, 2015.
27
Decision 2013-364, City of Lethbridge 2012-1014 Transmission Facility Owner General Tariff Application, issued September 30, 2013.
23
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Line 8 TransAlta Corporation
40
TransAlta Corporation (“TransAlta”) has not yet applied for its 2016 final TFO tariff costs. TransAlta’s
28
2014 TFO tariff costs are $4.9 million as approved in Commission Decision 20524-D01-2015. The
AESO has accordingly included $4.9 million as forecast TransAlta 2016 TFO tariff costs in this
application. For additional clarity, TransAlta’s 2014 TFO tariff was most recently approved by the
29
Commission; Decision 2014-369 which approved TransAlta’s 2015-2016 interim TFO tariff was issued
before Decision 20524-D01-2015 and continued TransAlta’s 2012 TFO tariff amounts into 2016.
Line 9 City of Red Deer
41
The City of Red Deer’s 2016 tariff costs are $3.9 million as approved on a final basis in Commission
30
Decision 20802-D01-2015. The AESO has accordingly included $3.9 million as forecast City of Red
Deer 2016 TFO tariff costs in this application.
Line 10 FortisAlberta Inc. (Farm Transmission)
42
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. (“FortisAlberta”) has received approval for
31
2016 farm transmission costs of $4.8 million in Commission Decision 20818-D01-2015. The AESO has
accordingly included $4.8 million as forecast FortisAlberta 2016 farm transmission costs in this
application.
Lines 12-14 Non-Wires Costs
43
The AESO includes as wires costs two cost components that 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 $5.5 million cost for the two programs was forecast
by the AESO in conjunction with ancillary services costs and, as evidenced by the AESO Board Decision
included as Appendix A to this application, has been approved by the AESO Board.
2.3
Ancillary Services Costs
44
The forecast 2016 costs for ancillary services are $182.6 million and represent approximately 8.8% 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
32
above system demand required to provide for regulation, forced outages and unplanned outages.
45
Ancillary services costs are primarily a function of volume forecasts and market-based commodity pricing
forecasts. The 2016 forecast costs for ancillary services were based on a forecast average pool price of
$40.99/MWh.
2.4
46
Losses Costs
The 2016 forecast costs for transmission line losses are $111.9 million and represent approximately 5.4%
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.
28
Decision 20524-D01-2015 TransAlta Corporation 2013-2014 General Tariff Application Refiling in Respect of Decision 3466-D01-2015, issued September 21, 2015
Decision 2014-369, TransAlta Corporation, as Manager of the TransAlta General Partnership 2015-2016 Interim Tariff Application, issued December 22, 2014
Decision 2013-214, City of Red Deer 2012-2014 Transmission Facility Owner General Tariff Application Compliance Filing, issued June 5, 2013.
31
Decision 20818-D01-2015, FortisAlberta Inc. 2016 Annual Performance-Based Regulation Rate Adjustment Filing, issued December 17, 2015.
32
AESO Consolidated Authoritative Document Glossary
29
30
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47
Losses costs are a function of volume forecasts and market-based commodity pricing forecasts. The
2016 forecast costs for losses were based on a forecast average pool price of $40.99/MWh.
2.5
Administrative Costs
48
The 2016 forecast cost for administration is $98.4 million and represents approximately 4.7% of the
AESO’s transmission revenue requirement.
49
Administrative costs are defined in paragraph 1(1)(g) of the Transmission Regulation as follows:
1(1)(g) “ISO’s own administrative costs” means
50
(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
transmission-related portions of those costs (as defined in subsection 1(1)(g) of the Transmission
Regulation) are recovered through the ISO tariff. Further, the AESO Board Decision provided as
33
Appendix A to this application allocates administrative costs among the three functions of the AESO;
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.
33
Appendix A, AESO Board Decision, page 7 of 11.
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3
2016 Tariff Update
51
In accordance with the approach referred to in section 1.1 above, this application uses the rate calculation
34
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 included as
35
Appendix B of the AESO 2014 ISO tariff compliance filing as the template for the 2016 rate calculations,
updated to reflect the transmission constraint rebalancing charge approved in Decision 20623-D0136
2015 . The 2016 rate calculations are included as Appendix C to this application, in Tables C-1 through
C-16.
52
The rate calculations use the following inputs:
(a)
the 2016 forecast revenue requirement discussed in section 2.1 of this application;
(b)
the functionalization of wires costs approved for 2016 in Decision 2013-421;
(c)
the 2016 forecast billing determinants prepared by the AESO.
3.1
Specific Rate Changes
37
and
53
Where applicable, rates in the ISO tariff have been updated to reflect the 2016 forecast revenue
requirement, 2016 wires costs functionalization, and 2016 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.
54
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 2016 ISO tariff included as
Appendix E to this application.
55
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
56
Consistent with the calculation of the 2014 primary service credit, the 2016 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.
57
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
34
See footnote 1.
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.
36
See footnote 2.
37
Proceeding 2718, Exhibit 0265.02.AESO-2718, Alberta Transmission System Cost Causation Study Update dated January 17, 2014, at page 7, Figure 6.
35
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credit amounts determined in Table 3-1 are reflected in Rate PSC of the proposed 2016 ISO tariff
included in Appendix E to this application.
Table 3-1 – Calculation of 2016 Primary Service Credit
Rate DTS
Charge
PSC
Factor
Rate PSC
Credit
Substation fraction
$8,604/month
79%
$6,797.00/month
First (7.5 × substation fraction) MW
of billing capacity
$3,484.00/MW
79%
$2,752.00/MW
Next (9.5 × substation fraction) MW
of billing capacity
$2,182.00/MW
79%
$1,724.00/MW
Next (23 × substation fraction) MW
of billing capacity
$1,522.00/MW
79%
$1,202.00/MW
All remaining MW of billing capacity
$986.00/MW
100%
$986.00/MW
Rate Component
3.1.2
Regulated Generating Unit Connection Costs in Rate STS, Supply Transmission Service
58
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
38
2014 ISO tariff 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.
59
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
39
reviewed this calculation and considers the AESO RGUCC appears to be reasonable.” A value of
$121.55/MW was included for the 2016 RGUCC in the attachment to the response to information request
AUC-AESO-009 in the AESO’s 2014 ISO tariff application proceeding.
60
The regulated generating unit connection cost charge has accordingly been updated to $122.00/MW in
Rate STS in the proposed 2016 ISO tariff included as Appendix E to this application, being the 2016
value rounded to the nearest dollar.
3.1.4
Rider J, Wind Forecasting Service Cost Recovery Rider
61
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
40
energy initially used to determine the values of the rider. Since first being implemented in 2011, Rider J
is expected to recover in 2016 all costs of the contracted wind forecasting service incurred to date.
62
On a cumulative basis, the AESO overcollected $115,692 by the end of 2015, changing from a
cumulative undercollection in all prior years to a cumulative overcollection for the first time by the end of
2015. The wind forecasting service annual cost forecast for 2016 is $304,560. Annual wind powered
38
39
40
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.
Exhibit 0026.00.AESO-2718, at page 13, paragraphs 124-126.
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generation metered energy forecast for 2016 is about 4.3 million MWh, up slightly from metered energy
for 2015 of about 4.1 million MWh. The AESO proposes to set the Rider J charge at $0.05/MWh. The
AESO will continue to monitor and report this amount in future tariff applications and updates.
63
The Rider J charge has accordingly been updated to $0.05/MWh in the proposed 2016 ISO tariff included
in Appendix E to this application.
3.2
2016 Forecast Billing Determinants
64
The rate calculations for the 2016 rates update are based on the AESO’s forecast of billing determinants
for 2016. The AESO prepares a long-term load forecast in accordance with the Act and the Transmission
Regulation. The load forecast most recently prepared by the AESO is set out in the AESO 2014 Longterm Outlook, which contains a 2016 load forecast. This 2016 load forecast was adjusted to reflect
expected changes in electricity consumption in 2016 due to a decline in economic growth rate compared
to that included in the AESO 2014 Long-term Outlook. The forecast 2016 billing determinants are based
on this adjusted 2016 load forecast.
65
The AESO expects to publish its next long-term outlook in the second quarter of 2016. The 2016 longterm outlook will more thoroughly incorporate the changes in economic growth as well as the impacts of
the new climate change policy being implemented in Alberta. However, to facilitate a tariff update as early
as possible in 2016, the AESO is proceeding with this 2016 tariff update application in advance of
finalizing the 2016 long-term outlook.
66
To recognize the decline in expected economic growth rate, the AESO has reduced the forecast 2016
billing determinants, based on the AESO 2014 Long-term Outlook, by 1.5%. This reduction reflects the
AESO’s current estimate as it continues to work on the next long-term outlook. The AESO considers that
timely tariff updates reduce Rider C charges and the associated issue of inter-customer transfers in
deferral account reconciliations, and is therefore applying for its 2016 tariff update as soon as possible.
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 Long-term 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 perpoint-of-delivery billing determinants are considered confidential information that should not be made
AESO 2016 ISO Tariff Update
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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 2016
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 recorded for 2015. Coincident metered demand and energy billing determinants have
increased by 1.8% and 5.2% respectively compared to the 2015 recorded billing determinants, while
number of DTS market participants has increased by approximately 1.5%. Billing capacity (which
incorporates non-coincident metered demand, demand ratchets, and contract minimums) has not
changed appreciably, with an increase of approximately 5.1% in the first demand tier, an increase of
approximately 2.8% in the second demand tier, a decrease of approximately 0.5% in the third demand tier
and a decrease of approximately 6.2% in the last demand tier.
Table 3-2 – 2016 Forecast and 2015 Recorded Billing Determinants
Rate DTS
Billing Determinant
Units
2015
Recorded
95,650.2
93,932.1
1,718.1
1.8%
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
150,245.3 150,192.2
37,549.4
35,719.7
33,643.9
32,722.6
40,708.1
40,893.2
38,343.9
40,856.7
53.0
1,829.6
921.3
(185.1)
(2,512.8)
0.0%
5.1%
2.8%
(0.5%)
(6.2%)
Highest Metered Demand
MW-months
115,223.0 117,088.4
(1,865.5)
(1.6%)
Metered Energy (All Hours)
DTS Market Participants
Pool Price (Weighted by Volume)
GWh
62,004.8
58,942.2
3,062.6
5.2%
customer-months
5,317.8
5,237.1
80.6
1.5%
$/MWh
Average Increase (Decrease) (Weighted by Revenue)
73
Increase (Decrease)
Amount
%
2016
Forecast
40.99
33.34
7.65
22.9%
2.0%
To further examine the reasonableness of the 2016 forecast billing determinants, Table 3-3 below
provides a comparison of the forecast billing determinants in this rates update application to the 2013,
2014 and 2015 recorded billing determinants. The AESO considers that the increase in billing
determinants forecast for 2016 is reasonable when compared to recorded billing determinants for the two
prior years and expectations for 2016 as discussed at the beginning of this section.
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Table 3-3 – 2016 Forecast, 2015, 2014 and 2013 Recorded Billing Determinants
Rate DTS
Billing Determinants
74
2016
Forecast
Units
2015
Recorded
2013
2014
Recorded Recorded
Coincident Metered
Demand
MW-months
95,650.2
93,932.1
94,058.7
91,160.3
Billing Capacity (Total)
MW-months
150,245.3
150,192.2
145,958.0
140,073.3
Highest Metered Demand
MW-months
115,223.0
117,088.4
116,814.7
112,713.2
Metered Energy (All Hours)
GWh
62,004.8
58,942.2
59,043.3
56,959.3
Market Participants (Total)
customer-months
5,317.8
5,237.1
5,244.4
5,137.7
Overall, the AESO considers that the 2016 forecast provides an accurate estimate of billing determinants
for the rate calculations in this application.
3.3
Bill Impacts
75
As noted in section 2 of this application, the AESO’s 2016 forecast revenue requirement represents an
increase of 11.5% over the total recorded costs for 2015.
76
At the same time, billing determinants have also changed from the 2015 forecast on which currentlyapproved rates are based. As a result, the AESO’s 2016 updated rates represents an overall increase of
8.3% over the 2015 rates currently in place, including an increase of 8.7% to Rate DTS, Demand
Transmission Service, and an increase of 1.7% 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 the deferral account rider and reconciliations. 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 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 8.7% represents a revenue-weighted average increase over all components of Rate DTS.
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 and transmission constraint rebalancing charge at the time of usage.
80
To allow individual market participants to estimate the impact of the 2016 rates on their own Rate DTS
bills, the AESO has included a bill impact estimator as Table C-16 in the rate calculations included as
Appendix C to this application. The bill impact estimator calculates bills for a given set of billing inputs
under both the current 2015 Rate DTS and the updated 2016 Rate DTS, to allow the impact of the rates
update on an individual service to be estimated.
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Table 3-4 – Increase (Decrease) for 2016 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
Operating Reserve
Transmission Constraint
Rebalancing Charge
Voltage Control
Other System Support
Net Change (revenue weighted)
Unit
Proposed
(1 Apr 2016)
Current
(1 Jan 2016)
Increase
(Decrease)
$/MW
$/MWh
$10,175.00
$1.17
$9,305.00
$1.09
9.3%
7.3%
$/MW billing
$/MWh
$2,333.00
$0.81
$2,162.00
$0.76
7.9%
6.6%
$/month
$/MW
$/MW
$/MW
$/MW
$8,604.00
$3,484.00
$2,182.00
$1,522.00
$986.00
$7,865.00
$3,184.00
$1,994.00
$1,391.00
$901.00
9.4%
9.4%
9.4%
9.4%
9.4%
% of Pool Price
6.66%
6.41%
$/MWh
$0.06
$0.00
$/MWh
$/MW
$0.06
$46.00
$0.05
$41.00
3.9%
NA
20.0%
12.2%
8.7%
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The changes to the different components of Rate STS are provided in Table 3-5 below. The Rate STS
increase of 1.7% represents a revenue-weighted average increase over all components of the rate.
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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 2016 Rate STS Components
Rate STS Charge
Losses
RGU Connection Costs
Net Change (revenue weighted)
83
Unit
% of Pool Price
$/MW
Proposed
(1 Apr 2016)
4.06%
$122.00
Current
(1 Jan 2016)
3.92%
$149.00
Increase
(Decrease)
3.6%
(18.1%)
1.7%
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. The AESO notes that the losses
AESO 2016 ISO Tariff Update
Application
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February 2, 2016
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charge remains as approved on an interim basis in Commission Decision 2014-242, and that locationspecific loss factors will be established using a methodology determined in Commission Proceeding
42
790.
41
42
Decision 2014-242, Alberta Electric System Operator 2014 ISO Tariff Application and 2013 ISO Tariff Update, issued August 21, 2014, paragraph 730.
Proceeding 790, Milner Power Inc. Complaint Against the ISO Line Loss Rule, Registered August 25, 2015.
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4
2016 Maximum Investment Levels Update
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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
based on a composite of specified recent inflation indices.
85
The AESO has accordingly updated the composite inflation index used for developing the point of delivery
cost function to 2016, 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 2014 and 2015, as included in the 2014 ISO tariff filing and the 2015
ISO tariff update, and for 2016 as updated in this application. Values prior to 2014 are excluded from
Table 4-1 as they do not affect the escalation factor.
Table 4-1 – Escalation Factor for Composite Inflation Index
Year
Basis
Present Value
Factor
2014 Tariff Application
2014
Forecast
1.5727
2015 Tariff Update
2015
Forecast
1.5834
2016 Tariff Update
2016
Forecast
1.6201
1.62012016 / 1.57272014 =
1.0302
2016 Escalation Factor (over 2014)
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The resulting escalation factor for updating the 2016 maximum investment levels in section 8 of the ISO
tariff is 1.0302, which represents a small increase to the 2016 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 1.0302 escalation factor to the 2014 Rate DTS maximum investment
levels to determine the 2016 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.
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Table 4-2 – Calculation of 2016 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
2016 Escalation Factor (over 2014)
1.0302
Tier
2014 Maximum Investment Levels
Substation fraction (for new points of
delivery only)
2016 Maximum Investment Levels
Substation fraction (for new points of
delivery only)
$78 350/year
21%
$16 450/year
First (7.5 × substation fraction) MW of
contract capacity
$31 750/MW/year
21%
$6 670/MW/year
Next (9.5 × substation fraction) MW of
contract capacity
$19 900/MW/year
21%
$4 180/MW/year
Next (23 × substation fraction) MW of
contract capacity
$13 850/MW/year
21%
$2 910/MW/year
All remaining MW of contract capacity
$8 950/MW/year
0%
$0/MW/year
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5
Conclusion
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Based on all of the foregoing, the AESO submits that the tariff updates proposed in this application are
just and reasonable, and comply with the update methodology approved by the Commission for the
AESO’s tariff. The AESO respectfully requests that the Commission approve this tariff update application,
including (i) the updated amounts included as Appendix C to this application, and (ii) the proposed 2016
ISO tariff Rate DTS, Rate FTS, Rate DOS, Rate XOS, Rate XOM, Rate PSC, Rate STS, Rider J and
Section 8 included as Appendix E to this application, effective April 1, 2016. If the timing of this
application does not permit the granting of final approval prior to April 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 March 31, 2016, as this is the last approval date that will allow the proposed tariff updates to be
implemented by the AESO effective April 1, 2016 on a prospective basis. .
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All of which is respectfully submitted this 2nd day of February, 2016.
Alberta Electric System Operator
Per: “Heidi Kirrmaier”
Heidi Kirrmaier
Vice-President, Regulatory
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