M E M O www.aeso.ca

2500, 330 – 5 Ave SW
Calgary, Alberta T2P 0L4
Bus: 403.539.2450
Fax: 403.539.2949
www.aeso.ca
M E M O
DATE:
September 29, 2009
TO:
AESO Board
FROM:
Vice-President, Finance
AESO 2010 and 2011 Business Plan
and Budget Proposal
SUBJECT:
Attached, please find the AESO’s proposed 2010 and 2011 Business Plan and Budget (the Plan).
This document was prepared by AESO Management in consultation with stakeholders and
outlines:
•
•
•
•
•
•
•
The process employed to develop the Plan;
The strategic and operational initiatives that AESO Management believes must be
undertaken in the next two years in accordance with the AESO Board approved Strategic
Plan;
The proposed 2010 and 2011 general and administrative, interest and amortization cost
budgets;
The proposed 2010 and 2011 other industry cost budgets;
The proposed 2010 and 2011 capital budgets;
The forecasted ancillary services and transmission line loss costs for 2010; and
Stakeholder comments on the above information together with AESO Management’s
responses to those comments.
This information will be discussed at the October 28, 2009 Board meeting at which time you will
be asked to approve, or amend and approve, as appropriate, the items outlined in Section 1 of
this document.
Prior to your meeting on October 28, 2009, stakeholders may request the opportunity to meet
with you to discuss their written comments related to the information provided. As you are aware,
these meetings are scheduled for October 15, 2009.
Should you have any questions or additional information requirements please let me know.
Yours truly,
Todd D. Fior
Vice-President, Finance
Cc
David Erickson, President and Chief Executive Officer
Greg Spence, Director, Business Planning
Carol Moline, Director, Accounting and Treasury
Industry Stakeholders
2010 and 2011
Business Plan
and Budget Proposal
September 29, 2009
2010 and 2011 Business Plan and Budget Proposal
Table of Contents
Section 1
Board Decision Items
Section 2
Stakeholder Presentations to the AESO Board
Section 3
Stakeholder Consultation Undertaken
Section 4
Section 5
•
Terms of Reference for Budget Review Process
•
Budget Review Process
•
Budget Review Process Schedule
Business Plan and Budget
•
General & Administrative Costs (2010 and 2011 budget)
•
Interest Costs (2010 and 2011 budget)
•
Amortization (2010 and 2011 budget)
•
Capital (2010 and 2011 budget)
•
Other Industry Costs (2010 and 2011 budget)
•
Transmission Line Losses (2010 forecast)
•
Ancillary Services (2010 forecast)
Stakeholder Comments and AESO Responses
Table of Contents
2010 and 2011 Business Plan and Budget Proposal
Section 1 – AESO Board Decision Items
Executive Summary
The following 2010 and 2011 Business Plan and Budget Proposal (Business Plan) is the
foundation on which AESO Management is intending to operate our business on for the
next two years. To reach this point, we have carried out an in-depth review of our
organization and the environment in which we operate – we have reviewed how we
operate, the demands on our organization and what financial resources are required to
fulfill our mandate and achieve our strategic objectives and business initiatives. The
culmination of this work is our Business Plan which is centered on our four core business
areas: market development, electric system development, customer access services and
electric system operations. At this time, we are presenting this Business Plan to the
AESO Board for endorsement and approval which includes the following:
•
•
•
•
•
•
•
•
Business Initiatives (2010 and 2011)
General and Administrative Costs (2010 and 2011 budget)
Interest Costs (2010 and 2011 budget)
Amortization (2010 and 2011 budget)
Capital (2010 and 2011 budget)
Other Industry Costs (2010 and 2011 budget)
Transmission Line Losses (2010 forecast)
Ancillary Services (2010 forecast)
Over the last several months we have engaged stakeholders interested in reviewing our
initiatives and budgets in more detail and providing us with their comments and feedback
as we were working through this process. This consultation process, referred to as the
Budget Review Process (BRP), allows us to prepare a comprehensive business plan and
budget that has been reviewed, discussed and at times challenged before we’ve reached
this point. As a part of this presentation to the AESO Board, we are providing the
stakeholder written comments that we have received to date. The purpose of providing
these comments is for the AESO Board to gain insight into some of the areas that
created discussion throughout this process. We continue to believe that this open and
transparent process enables us to prepare a thorough and comprehensive Business
Plan, and we believe our stakeholders continue to appreciate this inclusive process. The
end result is a well communicated and understood Business Plan that provides us
direction over the next two years.
Page 1
2010 and 2011 Business Plan and Budget Proposal
As previously mentioned, our budget is based on the funding required for us to achieve
our business initiatives as outlined in the Business Plan. In addition to this, we are also
providing the transmission line loss and ancillary service cost forecasts for 2010 which
are within the AESO Board’s mandate for approval based on the provisions in the
Transmission Regulation. These forecasted costs have been developed by AESO
Management and have been included in the process to engage stakeholders for review
and comment, consistent with the general and administrative costs. The following are the
approvals that AESO Management will be requesting of the AESO Board.
AESO Board Approval Requested
1. Approve the AESO’s proposed 2010 and 2011 business initiatives as discussed in
the strategic plan on pages 3 to 15 in the 2010 and 2011 Business Plan and Budget
Proposal (Section 4).
2. Approve the following proposed budget and forecast amounts:
Revenue Source ($ million)
Budget/Forecast
Category
General and
Administrative 1
Interest 2
Amortization 2
Capital 3
Other Industry 4
Transmission Line
Losses 5
Ancillary Services 5
2010
2011
2010
2011
2010
2011
2010
2011
2010
2011
2010
2011
2010
2011
Transmission
Energy
Market
Load
Settlement
53.5
54.5
1.1
1.4
10.1
13.4
17.3
18.2
0.7
0.9
5.7
7.9
2.3
2.4
0.2
0.3
1.9
1.8
14.7
14.3
173.6
7.2
7.2
-
-
73.1
75.1
2.0
2.6
17.7
23.2
29.4
29.0
21.9
21.5
173.6
144.3
-
-
144.3
Total
Details provided on the total amounts by cost category on the following pages in the
2010 and 2011 Business Plan and Budget Proposal (Section 4):
1
Page 35
2
Page 38
3
Page 39
4
Page 33
5
Page 32
Page 2
2010 and 2011 Business Plan and Budget Proposal
Section 2 – Stakeholder
Presentations
Stakeholder presentations to the AESO Board to be inserted when received.
Page 1
2010 and 2011 Business Plan and Budget Proposal
Section 3 – Stakeholder Consultation
Process
On April 11, 2007, the Alberta government made amendments to the Transmission
Regulation which included provisions addressing the consultation and approval of the
AESO’s own costs, ancillary services costs and transmission line loss costs. The
Transmission Regulation provides that the AESO must consult with participants with
respect to the proposed costs to be approved by our Board. It also provides that these
costs, once approved by the AESO Board, must be considered by the Alberta Utilities
Commission (AUC) as ‘prudent’ unless interested persons satisfy the AUC otherwise.
The practice we have established to carry out this consultation is the budget review
process (BRP). The BRP is a transparent stakeholder process which provides a level of
prudence review with input from stakeholders. At the conclusion of the BRP, we will
make a recommendation with respect to our own costs (general and administrative,
interest, amortization, capital and other industry costs), transmission line loss costs and
ancillary services costs to the AESO Board for approval.
We have posted the detailed budget review process, terms of reference and a calendar
providing the 2009 BRP milestone activities leading up to an AESO Board decision (the
calendar was revised throughout the process to accommodate process changes and
schedules). These documents have been included as Appendices A to C to this section.
The BRP steps, at a high-level, are as follows:
1.
Notice to Stakeholders
2.
AESO Develops 2010 and 2011 Business Initiatives
3. AESO Develops Own Costs Budgets and Forecasted Transmission Line Loss
and Ancillary Services Costs
4.
Technical Meeting to Review Budget/Forecast Costs with Stakeholders
5.
AESO Board Decision
As with prior year’s BRP, the process has been open to all stakeholders and the process
had been transparent as all presentation materials, stakeholder comments and our
responses have been posted on the AESO’s website. Through this process, we have
ensured that all stakeholders have had an opportunity to provide input. Stakeholders
may appeal the AESO Board’s decision using the dispute mechanism outlined in the ISO
Rules. The BRP will be re-evaluated with stakeholders at its conclusion and refinements
made with the process going forward if required.
Page 1
2010 and 2011 Business Plan and Budget Proposal
Appendix A – Terms of Reference
for Budget Review Process
~ last reviewed April 2009
Transparency is the overarching principle in the budget review process (BRP). The
following will ensure transparency to stakeholders during this process:
•
The process should be open to all stakeholders that are interested.
•
The size of the group should not be limited.
•
Stakeholders are encouraged to register as participants at the outset of each year’s
process in order to ensure a consistent understanding and to minimize inefficiencies.
•
Comments will be collected in written form, and be shared with all stakeholders (i.e.
posted to AESO Website). As well stakeholders will have the opportunity to comment
on each others comments.
•
The decision rendered by the AESO Board on these matters, will contain reasons /
rationale.
•
Throughout the process, the AESO will endeavour to provide as much information as
reasonably possible to ensure stakeholders have all information relevant to the
subject matters under review. However, the AESO and stakeholders will need to
agree on the level of detail to discuss (including confidential information), on an issue
by issue basis, in an effort to be most effective and efficient.
•
At the end of each AESO budget process review cycle, the AESO and stakeholders
will evaluate the effectiveness of the process and make appropriate changes if
required for the following year.
In addition:
•
Everyone is able to present their views.
•
Everyone must work within the timeline agreed upon at the start of the process.
•
This process is not a negotiated settlement.
•
The material to be delivered to the AESO Board in order to prepare a decision does
not have to be agreed upon unanimously.
•
Information will be provided to all stakeholders in a timely manner.
•
Stakeholders will have a reasonable time period to review and respond to AESO
material.
•
Nothing will preclude the opportunity for stakeholders to ultimately appeal any
decision using the dispute mechanism outlined in the ISO Rules.
Appendix A
2010 and 2011 Business Plan and Budget Proposal
Appendix B – Budget Review
Process
~ last reviewed April 2009
Refer to the following budget review process flow diagrams.
Appendix B
Process to Approve AESO Own, Ancillary Services & Transmission Line Loss Costs Forecasts (AESO 2010 Budget Review Process – BRP)
1.0
Notice to
Stakeholders
• Notice sent to all
stakeholders that
the process to
develop and
review forecasted
costs will
commence
• Including
developing a
schedule with all
milestone dates
2.0
AESO Develops Draft
Business Priorities
• AESO to solicit
stakeholder input on
draft business priorities.
• Review progress on
existing strategic plan
and business priorities
with stakeholders
• Stakeholders receive
AESO strategic plan
and draft business
priorities prior
3.0
AESO develops Own,
Ancillary Services and
Transmission Line
Loss Costs Forecasts
• AESO prepares Own
Cost forecast based
on business priorities
and strategic plan set
out in step 2.0
• AESO prepares
forecasts of Ancillary
Services and
Transmission Line
Loss Costs
• AESO provides
documents to
stakeholders in
advance of holding a
technical review
meeting
4.0
5.0
6.0
Technical Meeting to
Review Forecasted
Costs
AESO Board Decision
Dispute Process
• AESO holds technical
session(s) with
stakeholders where the
AESO presents forecasted
costs, assumptions and
responds to stakeholder
comments
• AESO posts meeting
overview document to
AESO website and asks
for written comments
• AESO makes revisions as
deemed necessary
• AESO prepares an AESO
Board Decision Document
and provides to
stakeholders for review
prior to submission to the
AESO Board
• AESO submits Board
Decision Document to the
AESO Board for review
and decision
• AESO Board reviews
Board Decision
Document
• Stakeholders make oral
or written presentations
to the AESO Board on
issues of disagreement
or concern (multi-lateral)
• Stakeholders have the
opportunity to provide
comments on each
stakeholder presentation
• AESO Board considers
stakeholder
presentations and reply
comments in its approval
process
• AESO Board issues a
decision for AESO’s
Own, Ancillary Services
and Transmission Line
Loss Cost forecasts with
rationale.
• Dispute resolution
mechanism for
instances where a
stakeholder
disagrees with the
AESO Board
Decision.
• The Dispute
Resolution
process is outlined
in the ISO Rules
Alberta Electric System Operator
April 29, 2009
Page 1 of 6
Process to Approve AESO Own, Ancillary Services & Transmission Line Loss Costs Forecasts (AESO 2010 Budget Review Process – BRP)
1.0 Notice to Stakeholders
AESO holds ongoing
discussions with
stakeholders to gain
industry perspective on
AESO strategy and
business priorities (i.e.
Advisory Committees,
Stakeholder Meetings
and Internal Management
Discussions)
1.1
2.0
AESO posts Notice to
Stakeholders on website
to initiate review process
AESO Develops Draft
Business Priorities
Notice to stakeholders
includes:
• Invitation to participate
• Schedule with milestone
dates
• Contact Person
• Expectations of next steps
Alberta Electric System Operator
April 29, 2009
Page 2 of 6
Process to Approve AESO Own, Ancillary Services & Transmission Line Loss Costs Forecasts (AESO 2010 Budget Review Process – BRP)
2.0 AESO Develops Draft Business Priorities
2.1
AESO prepares
Draft Business
Priorities Based
on Strategic Plan
• AESO updates its
strategic plan and
develops draft
business priorities
• Draft documents
are prepared.
2.2
2.3
2.4
2.5
2.6
3.0
AESO posts draft
documents to
website for BRC
and other
stakeholders to
review
AESO holds review
session with
stakeholders to
discuss the draft
documents
AESO posts
comments
document by
stakeholders to
website
AESO may
make revisions
if necessary
AESO posts
Strategic Plan
and Revised
Draft Business
Priorities to
website
AESO develops
Own, Ancillary
Services and
Transmission
Line Loss Costs
Forecasts
• AESO reviews
written
comments
from
stakeholders
and may make
changes if
deemed
necessary
Website posting
includes:
Website posting
includes:
• Strategic Plan,
Draft Business
Priorities, and Draft
Proposals for
Follow-up items
from prior year’s
BRP Decision
• Invitation to attend
a stakeholder
meeting to review
the documents
• Expectations of
next steps
• AESO reviews
strategic plan with
stakeholders in order
to set the context for
the draft business
priorities
• AESO reviews
follow-up proposals
with stakeholders
• Review session
intended to present
the information that
was provided in
advance and
address stakeholder
comments
• Comments
document posted to
AESO website that
includes: meeting
overview and
responses to
stakeholder
comments from
meeting
• AESO asks
stakeholders for
written submissions
on posted
documents
• AESO consolidates
comments from
stakeholder and
posts to AESO
website
• Strategic Plan
document,
Revised Draft
Business
Priorities and
related
proposals
• Expectations of
next steps
Alberta Electric System Operator
April 29, 2009
Page 3 of 6
Process to Approve AESO Own, Ancillary Services & Transmission Line Loss Costs Forecasts (AESO 2010 Budget Review Process – BRP)
3.0 AESO Develops Own, Ancillary Services and Transmission Line Loss Costs Forecasts
3.1
3.2
4.0
AESO prepares
Own, Ancillary
Services and
Transmission Line
Loss Costs
Forecasts
AESO posts draft
document to the
website for
stakeholder review
Technical Meeting
to Review
Forecasted Costs
• Process starts with
the annual internal
AESO budgeting
process
• Preparation of
these cost
groupings include
both forecast and
prior year’s actual
costs
• Own Cost forecast
preparation is
based on the Final
Business Priorities
developed through
discussions with
stakeholders
Website posting
includes:
• Draft document for
stakeholder review
• Invitation to attend
the technical
session to review
the document
• Expectations of
next steps and an
updated schedule
if required
Alberta Electric System Operator
April 29, 2009
Page 4 of 6
Process to Approve AESO Own, Ancillary Services & Transmission Line Loss Costs Forecasts (AESO 2010 Budget Review Process – BRP)
4.0 Technical Meeting to Review Forecasted Costs
4.1
4.2
4.3
4.4
4.5
4.6
4.7
5.0
AESO holds
technical
session with
stakeholders to
discuss the
draft document
AESO makes
revisions (as
required)
AESO
prepares Draft
AESO Board
Decision
Document
AESO posts
draft
document to
the website for
stakeholder
review
AESO may
make
revisions if
necessary
AESO posts Final
Board Decision
Document, including
responses to
stakeholder
comments to
website
AESO submits
Final Board
Decision
Document for
review and
decision to the
AESO Board
AESO Board
Decision
• Technical
session
intended to
present the
AESO’s
forecast
(assumptions
and inputs),
actual costs
(variance
analysis-prior
year’s actual
over budget),
and address
stakeholder
issues,
questions and
comments
• AESO asks for
• Draft AESO Board
comments and further
Decision Document;
questions
• Includes:
• AESO responds to
(1) Approval request
stakeholder comments
(2) Stakeholder
and posts with
engagement process
stakeholder
(3) Business Plan
consolidated
(4) Stakeholder
comments
Comments
Website posting
includes:
• Draft document
for stakeholders
to review
• Stakeholders
submit written
comments on
draft document
• AESO
consolidates
comments and
posts to website
• Expectations of
next steps and
an updated
schedule if
required
• AESO reviews
written
comments
from
stakeholders
and may make
changes if
deemed
necessary
Website posting
includes:
• Final Board
Decision
Document
• Final responses
to stakeholder
comments
• Expectations of
next steps
Final review
document includes:
• Business Plan
• Forecast costs,
assumptions and
rationale
• Prior year actual
costs and
variance
explanations
against forecast
• Consultation
process
• Areas of
disagreement
with
stakeholders
based on written
comments
Alberta Electric System Operator
April 29, 2009
Page 5 of 6
Process to Approve AESO Own, Ancillary Services & Transmission Line Loss Costs Forecasts (AESO 2010 Budget Review Process – BRP)
5.0 AESO Board Decision
5.1
5.2
5.3
AESO Board receives
and reviews the Final
Board Review
Document
Stakeholders make
presentations to the
AESO Board
AESO Board reviews
the written
information and
prepares a decision
• AESO Board reviews
the Board Review
Document prior to
presentations from
stakeholders
• Stakeholders provide
written presentations in
advance of oral
presentations
• Stakeholders provided
the opportunity to
present their issue to
the AESO Board.
• Stakeholders have the
opportunity to provide
comments to the AESO
Board on each other’s
issues
• The information for the
AESO Board’s review
includes the content of
the Board Review
Document, the
stakeholder
presentations, and the
comments on each
stakeholder
presentation
5.4
AESO Board Provides
Decision on AESO
Own Costs, Ancillary
Services & Line
Losses
6.0
Dispute Process
• The AESO Board Decision
includes: Business Plan,
AESO Own, Ancillary Services
and Transmission Line Loss
Cost forecasts; rationale for
the decision; and comments
regarding process and
stakeholder engagement
• The decision will be written
with sufficient detail to confirm
that the AESO Board
understood the key issues
• The AESO Board Decision is
communicated to AESO
Management and to
stakeholders as well as posted
to the AESO website
Alberta Electric System Operator
April 29, 2009
Page 6 of 6
2010 and 2011 Business Plan and Budget Proposal
Appendix C – Budget Review
Process Schedule
~ last reviewed August 2009
Refer to the following calendar providing the 2009 budget review process milestone
activities.
Appendix C
Schedule for AESO Board Approval Process - 2010 - Revised August 26, 2009
Meeting Material Distributed
Stakeholder Mtgs
Stakeholder Comments Requested
Stakeholder Comments Received
AESO Posts Meeting Summary
AESO Board Meeting
APRIL
Mon
Tues
MAY
Wed
Thurs
Fri
1
2
3
Mon
JUNE
Tues Wed Thurs
Fri
Mon
Tues
Wed
Thurs
Fri
1
1
2
3
4
5
Web posting
for comments
Re: April 29
Mtg.
6
7
8
9
10
4
5
6
7
8
14
15
16
17
12
13
14
15
Tues
AUGUST
Wed Thurs
1
2
SEPTEMBER
Fri
Mon
Tues
Wed
Thurs
Fri
3
3
4
5
6
7
Holiday
Mon
OCTOBER
Tues
Wed
Thurs
Fri
1
2
3
4
8
9
10
15
16
17
Mon
Tues
Wed
NOVEMBER
Thurs Fri
Mon Tues
Wed
DECEMBER
Thurs Fri
1
2
2
3
4
5
6
8
9
9
10
11
12
13
Mon Tues Wed Thurs
Fri
1
2
3
4
7
8
9
10
11
Receive
Stakeholder
comments from
Aug. 19 Mtg.
Holiday
(Step 2.2)
(Step 4.2)
11
Draft
Business
Priorities and
Status Update
1:30-3:30
(Step 2.3)
11
Mon
Distribution of
materials for
June 10 Mtg.
Holiday
13
JULY
12
6
7
8
9
10
Web posting
for
comments
Re:
June 10 Mtg.
(Step 2.4)
18
19
10
11
12
13
14
Distribution of
materials for
Aug.19 & 26
Mtg.
(Step
7
8
14
15
16
17
17
10
11
5
6
7
Receive
Stakeholder
written
submissions for
AESO Board
Distribution of
draft AESO Board
approval
document
Holiday
3.3)
13
9
(Step 4.4)
18
Receive
Stakeholder
comments
from April 29
Mtg.
19
20
21
14
15
16
17
18
Tech. Mtg. Web posting
AS & Line
for comments
Loss Costs
of Aug. 11 mtg.
1:00-5:00
(Step 4.1)
Holiday
(Step 5.2)
12
13
14
15
Holiday
AESO
Board
Meeting
AESO Board
Meeting
AESO
Board
Meeting
(Step 4.2)
16
16
17
18
19
20
14
15
16
17
18
23
23
24
25
26
27
21
22
23
24
25
Oral Presentation to AESO
20
21
22
23
Distribution
of materials
for April 29
Mtg.
24
18
19
20
21
Holiday
(Step 1.1)
27
28
29
1st
Stakeholder
Mtg./
Revised Strat
Plan 1:303:30pm
(Step 1.1)
30
25
26
27
28
22
22
Web posting
on April 29
Mtg.
discussion &
comments
Receive
Stakeholder
comments
from
June 10 Mtg.
(Step 2.4)
29
29
23
24
25
26
20
21
22
23
24
24
25
26
27
Web posting
Tech. Mtg. - for comments
Own Costs on Draft AESO
Board approval
1:00-5:00
(Step 4.1)
document
(Step 4.2)
30
Web posting
on June 10
Mtg.
discussion &
comments
27
28
29
30
31
31
28
21
22
23
24
25
19
20Board or Board
21 Committee 22
(Step 5.2)
Receive
Stakeholder
comments from
Aug. 26 Mtg.and
Draft Decision
Web posting
of AESO
Board
Decision
28
29
Web posting of
comments on
Draft AESO
Board approval
document
Web posting of
final AESO
Board approval
document
(Step 4.4)
Holiday
(Step 5.4)
(Step 4.2 & 4.4)
30
26
27
28
AESO Board
Meeting
29
30
30
28
29
30
31
Holiday
(Step 4.6-4.7)
09-30-2009
2010 and 2011 Business Plan and Budget Proposal
Section 4 – Business Plan and
Budget
Page 1
2010 – 2011
Business Plan
and Budget
Proposal
Version 2
September 29, 2009
2010 – 2011 Business Plan and Budget Proposal
Table of Contents
Message from the Chief Executive Officer.................................................................... iii
Our Mandate ...................................................................................................................... 1
AESO Core Business Areas......................................................................................... 2
Our Strategic Plan............................................................................................................. 3
Objectives ..................................................................................................................... 3
Our Plan to Evolve with Alberta’s Electricity Industry.................................................. 4
Market Development .................................................................................................... 4
Electric System Development (Transmission).............................................................. 6
Customer Access Services........................................................................................... 9
Electric System Operations ........................................................................................ 11
Enabling Our Core Business Areas............................................................................ 13
Financial Overview.......................................................................................................... 16
Section I - 2009 ................................................................................................................ 17
Financial Management ............................................................................................... 17
Total Revenues .......................................................................................................... 18
Total Costs.................................................................................................................. 19
Transmission Operating Costs .......................................................................... 19
Other Industry Costs ......................................................................................... 20
General and Administrative Costs..................................................................... 21
Interest and Amortization Costs ........................................................................ 23
Capital Expenditures ......................................................................................... 23
SECTION II – 2010 and 2011........................................................................................... 26
Financial Outlook........................................................................................................ 26
Key Assumptions over the Planning Period ...................................................... 27
Total Revenues .......................................................................................................... 29
Allocation of Costs for Revenue Requirements ................................................ 30
Revenue ............................................................................................................ 30
PAGE i
2010 – 2011 Business Plan and Budget Proposal
Total Costs.................................................................................................................. 32
Transmission Operating Costs .......................................................................... 32
Other Industry Costs ......................................................................................... 33
General and Administrative Costs..................................................................... 35
Interest Costs and Amortization ........................................................................ 38
Capital Expenditures ......................................................................................... 39
Appendix A: Other Industry Cost Detail ........................................................................... 45
Appendix B: Multi-Year Budget Process.......................................................................... 46
Appendix C: General and Administrative Cost Detail ...................................................... 47
Appendix D: 2010 and 2011 Staff Addition Detail............................................................ 52
Appendix E: Consulting Cost Detail ................................................................................. 57
Appendix F: Audit/Review Cost Detail ............................................................................. 59
Appendix G: Insurance Coverage Detail.......................................................................... 60
Appendix H: Allocation of Costs....................................................................................... 61
Appendix I: Capital Projects............................................................................................ 62
Appendix J: Transmission Operating Cost Definitions..................................................... 66
PAGE ii
2010 – 2011 Business Plan and Budget Proposal
Message from the Chief Executive
Officer
Message from the Chief Executive Officer
This text will be included in the final version of the business plan and budget document.
PAGE iii
2010 – 2011 Business Plan and Budget Proposal
About the AESO
Our Mandate
The Alberta Electric System Operator (AESO) is responsible for the safe, reliable and
economic planning and operation of the Alberta interconnected electric system (AIES)
and the facilitation of a fair, efficient and openly competitive electricity market. Acting in
the public interest, we take a leadership role in planning and operating the province’s
transmission system and wholesale electricity market in a reliable and efficient manner
that benefits all Albertans. To ensure the AESO delivers on this mandate, the
organization is governed by an independent board whose members are appointed by the
Alberta Minister of Energy. We are a not-for-profit entity and are independent of any
industry affiliations and we do not own transmission, distribution, retail or generation
assets.
The AESO’s mandate is outlined in Alberta’s Electric Utilities Act1 and is reflected in our
mission statement:
“The AESO facilitates a fair, efficient and openly competitive market
for electricity and provides for the safe, reliable and economic
operation of the Alberta interconnected electric system.”
The AESO delivers upon its mandate through four core business areas:
(1) Market Development
(2) Electric System Development
(3) Customer Access Services
(4) Electric System Operations
Integral to supporting and developing these four major business areas are the AESO’s
people, technology and processes. These are our core assets. Our commitment to
significant investment in these assets is fundamental to achieving the short- and long-
1
http://www.qp.alberta.ca/
PAGE 1
2010 – 2011 Business Plan and Budget Proposal
term goals established in the AESO’s core business areas. The following describes the
role each of our core business areas plays within the AESO:
AESO Core Business Areas
1. Market Development: The AESO is responsible for facilitating the development
of the competitive wholesale market for electricity, including financial settlement.
We develop market rules that ensure a predictable market structure and provide
a reliable price signal for producers, consumers and investors.
2. Electric System Development (Transmission): The AESO is responsible for
assessing the current and future needs of market participants and planning the
transmission system to meet those needs. We utilize a credible and effective
process for system planning that proactively identifies, plans, achieves approvals
for and initiates the timely implementation of system reinforcements.
3. Customer Access Services: The AESO is responsible for ensuring customers
have access to the transmission system and electricity market. The goal is to
deliver high quality interconnection and market access services in an efficient
manner that meets both the customer’s needs and the requirements of the AIES.
4. Electric System Operations: The AESO directs the safe, reliable and economic
operation of the AIES and operates the market in a fair, efficient and openly
competitive manner. This is achieved by ensuring compliance with all market
rules and reliability standards, and maintaining an appropriate set of system
operating limits and procedures.
PAGE 2
2010 – 2011 Business Plan and Budget Proposal
Our Strategic Plan
Electricity plays a critical role in powering our everyday lives. We flip the switch knowing
that the power is there. Albertans count on safe, reliable electricity. It enables Alberta’s
economic progress, our livelihood and our well-being. In 2008, Alberta’s wholesale power
market completed over $9 billion in electricity transactions.
Knowing critical transmission infrastructure is in place ensures power generators can be
confident that Alberta’s grid can accommodate new generation investment. It also
bolsters confidence with customers who rely upon dependable electricity to power their
businesses, industry, homes and farms.
The foundation of the AESO’s commitment to evolve with Alberta’s electricity industry is a
five-year strategic plan that outlines six overarching objectives.
Objectives
1. We will design and operate a competitive, energy-only electricity market where
market evolution is driven by participants and the AESO.
2. We will lead development of a reliable transmission system, including interties to
other jurisdictions, which fully enables operation of the competitive market.
3. We will consistently meet or exceed customer expectations in the delivery of
system and market access services.
4. We will ensure our workforce capacity and skill-sets meet business demand
while making the AESO an exceptional place to work, learn, succeed and make a
difference.
5. We will leverage leading technologies to improve customer service and the
diversity, reliability and efficiency of system and market operations.
6. We will build strong public, industry and government support to ensure effective
execution of our mandate.
These six overarching objectives provide the broad context that shapes the AESO’s dayto-day business activities. We have already embarked on activities to achieve the
objectives and have made significant progress. It will be important to carry this
momentum through 2010 and 2011 as each of our business areas conducts baseline
operations and works towards completing important initiatives needed to improve the
AESO’s efficiency and effectiveness as it moves forward.
PAGE 3
2010 – 2011 Business Plan and Budget Proposal
Evolving with Alberta’s Electricity
Industry
Our Plan to Evolve with Alberta’s Electricity Industry
Market Development
The AESO is responsible for facilitating the development of Alberta’s hourly
wholesale electricity market, which has more than 200 participants and completed
over $9 billion in electricity transactions in 2008.
As Alberta’s wholesale electricity market continues to evolve, the AESO will continue to
engage the Market Advisory Committee (MAC) and stakeholders to provide input on
market policy issues and advance discussions that will guide development of Alberta’s
wholesale electricity market. The MAC is a group of 19 industry participants that
represents a broad range of interests. Their commitment and collaboration provides the
foundation for meaningful consultation on a wide range of market-related matters and
forward-looking issues, as well as a collective vision for the market.
The AESO’s Market Roadmap (initially released for comment in 2007) outlines the highlevel context and sequencing of market design initiatives. It is a directional project plan
that sets the context for market changes the AESO envisions based on consultation with
stakeholders.
We have also been moving forward with an initiative to design and implement a
comprehensive framework that will consistently be applied for all existing AESO
authoritative documents (i.e., those documents such as rules that contain binding
obligations for participants, including the AESO). The objective of this initiative is to
streamline the Independent System Operator (ISO) Rules and Alberta Reliability
Standards approval process and provide clearer definitions of participants’ obligations.
PAGE 4
2010 – 2011 Business Plan and Budget Proposal
2010 - 2011 Planned Evolution of Market Development
In 2010 and 2011, the AESO will execute initiatives to further evolve Alberta’s wholesale
electricity market and contribute to achieving the strategic objective related to the energyonly market (Objective 1: We will design and operate a competitive, energy-only
electricity market where market evolution is driven by participants and the AESO).
As we implement changes to the electricity market, we will continue to consult and work
with stakeholders such as industry, the Alberta Department of Energy (DOE), the Alberta
Utilities Commission (AUC), the Market Surveillance Administrator (MSA), and the MAC
to ensure that as it evolves, Alberta’s wholesale electricity market can be operated in a
fair, efficient and openly competitive manner. Specifically, the initiatives the AESO will
execute over the next two years include:
1. Continue to implement the market roadmap
ƒ
Implement the market policy framework by:
o
Implementing approved market rules for congestion management.
o
Developing operating reserve market rules and implementing market
redesign changes based on the stakeholder consultation in progress.
o
Ongoing development and implementation of market performance
metrics.
o
Implementing requirements arising from Section 6 of the DOE’s Fair,
Efficient and Open Competition (FEOC) Regulation, which came into
effect September 1, 2009.
o
Continuing to clarify market participants’ roles and responsibilities
(e.g., DOE, AUC, MSA and AESO).
ƒ
Complete demand response consultation and develop market rules and new
products accordingly.
ƒ
Implement recommendations from the price cap and floor review.
ƒ
Implement market suspension rules, which have been revised to reflect
market design changes.
2. Facilitate development of interties
ƒ
Develop and implement a revised intertie framework that facilitates possible
development of new intertie capacity and new business practices for intertie
scheduling, dispatching, allocation and curtailment as necessary.
3. Execute the transition of authoritative documents project
ƒ
Implement a standardized process for authoritative documents for the
creation of ISO Rules, operating policies and procedures, standards and
business practices. This includes documents such as ISO Rules that contain
binding obligations for participants, including the AESO.
PAGE 5
2010 – 2011 Business Plan and Budget Proposal
Electric System Development (Transmission)
The AESO is responsible for assessing the current and future needs of market
participants and planning the transmission system to meet those needs. We utilize
a system planning process that proactively identifies, plans, achieves approvals
for and initiates the implementation of system reinforcements. Our objective is to
ensure transmission facilities are in place to maintain reliable and economic
transmission system operation and the facilitation of competitive electricity
markets.
Alberta’s electric transmission system is like a highway. It moves power from where it is
produced to where it is used—just like a highway moves traffic from point to point.
Today’s technologies do not allow us to store electricity in large volumes in any practical
way so transmission lines must be able to deliver the power we need when and where we
need it—instantly. If the transmission highway is too small to handle the needed flow of
electricity, it can become congested, costly and inefficient to run. In addition, knowing
critical transmission infrastructure is in place ensures power generators can be confident
that Alberta’s grid can accommodate new investment in generation.
In the past several years Alberta’s growth has been strong. In electric system terms, this
growth has been equal to adding two cities the size of Red Deer to the power system
every year. However, virtually no major additions to the backbone of the electric system
have been built in over 20 years. Portions of our electricity system are congested and
aging. Alberta’s electric system is stretched and incapable of meeting the province’s
future needs in its current state.
The AESO has approximately $3.2 billion in transmission system reinforcements
currently underway (including projects approved, pending approval and under
construction) throughout the province. However, additional critical transmission
infrastructure is required to support planned generation development. Now is the time to
close the gap between the system in its current strained condition and ensure that critical
transmission infrastructure is ready in advance of the upcoming need.
PAGE 6
2010 – 2011 Business Plan and Budget Proposal
On December 11, 2008 the Alberta government released its Provincial Energy Strategy,
which noted the importance of electricity as a facilitator of economic development in
Alberta. The Strategy states: “Advancing new transmission investment will ensure reliable
service for Albertans, help drive our clean energy agenda by growing new renewable
energy potential, and enhance our ability to serve electricity export markets.”1
In 2009, the AESO released its Long-term Transmission System Plan, which aligns with
the Provincial Energy Strategy and outlines the following five critical transmission
infrastructure (CTI) tier 1 projects.
1. Two 500 kilovolt (kV) high voltage direct current (HVDC) high capacity lines from
the Edmonton area to the Calgary and South regions.
2. One 500 kV double circuit alternating current line from the Edmonton area to the
Industrial Heartland area (parts of Sturgeon, Strathcona and Lamont counties).
3. Two 500 kV lines to Fort McMurray—one from the Wabamun Lake area and one
from the Industrial Heartland area northeast of Edmonton.
4. New transmission development in southern Alberta to integrate wind energy into
the provincial grid.
5. A 240 kV substation in the south Calgary area.
The Provincial Energy Strategy reinforces direction provided by the existing Transmission
Development Policy and Transmission Regulation to increase the capability of the
transmission lines (interties) that connect Alberta with its neighbours. Interties allow us to
import power into Alberta when provincial demand exceeds supply and export surplus
energy to other jurisdictions when supply exceeds demand. Since 2002, Alberta has
been a net importer of power.
In addition to the AESO’s transmission planning efforts, two merchant interties are being
planned:
1. Montana-Alberta Tie Ltd. is proposing to construct an intertie between Alberta
and Montana.
2. The NorthernLights bi-directional merchant transmission project is being
developed by TransCanada Corporation from Alberta to the U.S. Pacific
Northwest.
2010 - 2011 Planned Evolution of Electric System Development
In 2010 and 2011, the AESO will execute initiatives to further evolve the development of
Alberta’s transmission system and contribute to the achievement of the strategic
objective related to the unconstrained transmission system (Objective 2: We will lead
development of a reliable transmission system, including interties to other jurisdictions,
that fully enables operation of the competitive market).
1
Launching Alberta’s Energy Future, Provincial Energy Strategy, page 44.
PAGE 7
2010 – 2011 Business Plan and Budget Proposal
The accelerated pace of change needed to support transmission system planning and
development of the CTI projects means the AESO must reassess and improve certain
working processes. It will be critical to work with our stakeholders to refine these
processes, which will enable us to more efficiently and effectively achieve the initatives
outlined for development of Alberta’s transmission system. These initiatives include:
1. Implement the Provincial Energy Strategy and Transmission Development
Policy
ƒ
ƒ
Review and streamline the end-to-end transmission development process for
CTI projects, regional system developments and customer interconnections to
resolve recurring issues with the existing framework:
o
Clarify roles and accountabilities of the parties.
o
Implement legislative and regulatory amendments.
o
Align incentives among service providers and customers.
Advance the development of CTI projects, including interties, as envisioned
and set out in the Provincial Energy Strategy and the AESO’s Long-term
Transmission System Plan and assist the AUC to advance previously filed
applications.
PAGE 8
2010 – 2011 Business Plan and Budget Proposal
Customer Access Services
We are responsible for providing customers with transmission system access to
the Alberta power grid and access to the wholesale electricity market.
The AESO provides customers (e.g., generators, large commercial or industrial
customers) with access to the AIES. While the number of interconnection applications
slowed in 2009 due to the economic downturn, prior to 2009, system access requests
increased at an unprecedented rate resulting in a backlog of applications. In addition, the
interconnection applications became more complex in nature. We know we must change
how we provide customer service and execute customer system interconnections, and
are focusing efforts on more efficiently and effectively managing the interconnection
process.
During 2008 and 2009, the AESO created a new customer service team and made
improvements to customer service processes. We also launched a thorough review of
business practices to ensure customer needs are met and quality service is being
delivered through process improvements related to transmission interconnections and
energy market business interactions.
2010 - 2011 Planned Evolution of Improving Customer Access
In 2010 and 2011, the AESO will execute initiatives to further improve access to the
transmission system and wholesale electricity market and contribute to the achievement
of the strategic objective related to provision of system and market access services
(Objective 3: We will consistently meet or exceed customer expectations in the delivery of
system and market access services).
Our focus will be primarily based on streamlining the end-to-end process for system and
market access with clearly defined accountabilities and performance measures for the
AESO, customers, distribution facility owners, transmission facility owners and generation
facility owners. This will include developing increased project management capability and
discipline to execute customer projects.
PAGE 9
2010 – 2011 Business Plan and Budget Proposal
Additionally, we will need to simplify rules and complete our transition of authoritative
documents project (e.g. rules, tariffs, standards) related to customer access services.
Specifically, the initiatives the AESO will execute over the next two years include:
1. Customer service access improvements
ƒ
With industry input, develop and implement an improved end-to-end customer
service delivery interconnection process.
ƒ
Implement approved changes to the 2010 general tariffs that contribute to a
more effective and efficient interconnection process.
ƒ
Define and implement a customer relationship model to effectively manage
activities related to the broad range of services the AESO provides.
ƒ
Define and implement best practices and accountabilities to effectively
manage and monitor customer service access agreements.
ƒ
Complete the authoritative documents project, including a customer
interconnection guide and improved web access.
PAGE 10
2010 – 2011 Business Plan and Budget Proposal
Electric System Operations
The AESO is responsible for directing the safe, reliable and economic operation of
the AIES and operation of the wholesale electricity market in a fair, efficient and
openly competitive manner.
The AESO’s system coordination centre (SCC) is the heart of its 24/7 operation and
facilitates our mandate to keep the competitive market functioning and the lights on in
Alberta. Operating a strained, aging and congested transmission system becomes more
challenging every year.
System controllers operate the SCC and have a long and successful track record in
operating power systems that includes more than 200 person-years of combined
experience. They are responsible for the real-time operations of the Alberta electric
system. Our controllers match supply and demand every minute of every day to ensure
power is available when Albertans need it. They also monitor and direct the operation of
the provincial power grid to ensure safe, reliable and economic power for all Albertans.
The system controllers that operate the AIES and the market are a highly specialized
workforce and many senior controllers are nearing retirement. The AESO is focused on
succession planning and finding innovative ways to train and develop future system
controllers. One example of how we are doing this is our successful partnership with
Calgary’s SAIT Polytechnic. This partnership allows students to complete work terms at
the AESO while gaining valuable real-world experience.
The AESO’s system controllers rely on technology to continually get more out of Alberta’s
aging and congested transmission system. We are investing significantly in technology
that will not only provide us with new capabilities to effectively and efficiently operate the
AIES and wholesale electricity market, but will also change how we do business. For
example, replacing our Energy Management System (EMS) will allow us to transition
most of our system controllers’ efforts to the real-time operation of the AIES so they can
focus on real-time operations planning. These investments in technology will allow the
AESO to operate the AIES and wholesale electricity market effectively, safely and reliably
while the CTI tier 1 system reinforcements are brought online.
In addition, the AESO has agreed to operate the AIES and competitive market in a
manner consistent, to the extent possible, with the North American Electric Reliability
Corporation and Western Electricity Coordinating Council Reliability criteria and
standards. These reliability criteria, known as the Alberta Reliability Standards (ARS), are
designed to ensure adequate transmission resources are available to reliably connect
generation and load at all times, taking into account variations in load levels, generation
dispatch, transaction levels, and scheduled and reasonably expected unscheduled
outages of generation and transmission system elements.
2010 - 2011 Planned Evolution of Electric System Operations
In 2010 and 2011, the AESO will execute initiatives to further improve our ability to
operate the AIES and wholesale electricity market. This includes the effective
implementation of ARS and the addition of a fourth system controller desk including the
implementation of the new EMS.
PAGE 11
2010 – 2011 Business Plan and Budget Proposal
Specifically, the initiatives the AESO will execute over the next two years include:
1. Alberta Reliability Standards
ƒ
By mid-2010, the AESO will complete stakeholder consultation and file
with the Alberta Utilities Commission for approval the majority of the ARS.
To support implementation of the ARS, we will establish a monitoring and
compliance program for system and market participants. This monitoring
and compliance program will be supplemented by implementation of an
audit function to perform audits of the AESO’s operations including
compliance requirements and periodic testing of our processes, systems
and internal controls.
2. Fourth system controller desk
ƒ
The changing requirements of operating the AIES and the wholesale
electricity market are driving the AESO to add a fourth system controller
desk. This is being driven by AESO requirements to:
o
Monitor, direct and integrate increased wind power generation
within Alberta.
o
Understand and integrate new technologies on the system (e.g.,
HVDC, phase-shifting transformers, series capacitors, remedial
action schemes, etc.).
o
Integrate the Montana-Alberta intertie and provide dispatchable
intertie capabilities.
o
Utilize the real-time operations planning capabilities (advanced
applications) of the replacement EMS.
PAGE 12
2010 – 2011 Business Plan and Budget Proposal
Enabling Our Core Business Areas
Integral to achieving the objectives related to our core business areas are the AESO’s
people, technology and processes—core assets in which we must invest.
Our People
As an organization, people are the AESO’s most important asset. Without our
employees, we are not capable of executing our operational mandate, strategic
objectives and business priorities outlined in this business plan. Our people allow us to
constantly improve the way we do business and identify innovative ways to operate our
aging and congested transmission system until critical transmission infrastructure system
reinforcements are put in service.
Our Technology
Technology is an enabler of everything we do from operating the market to operating the
system. The AESO must ensure that we are a knowledge leader and fast follower of
proven technologies. This includes implementing technologies based on the future
requirements of stakeholders and customers. We must also ensure we are capable of
proactively implementing new supply and demand technologies to support market and
grid operations and providing effective access to data and information for the industry.
Finally, in support of every aspect of the AESO’s business we must utilize scalable,
robust and secure information technology (IT) systems to achieve operational excellence.
The AESO understands that to support Alberta’s evolving electricity industry, we must
appreciate that technology extends beyond information systems to various forms of
technology such as integrating wind power, HVDC, Smart Grid, and advanced metering
infrastructure. Given the role we play as the independent system operator, we must
support and enable technologies that our stakeholders and customers use.
PAGE 13
2010 – 2011 Business Plan and Budget Proposal
Our Stakeholder Engagement and Public Outreach Process
All organizations must be cognizant of external stakeholders and customers. Given the
role the AESO plays within the province’s electricity industry (being independent and not
having an ownership stake in transmission lines or generation assets), we rely on others
to successfully execute our mandate. We do this by engaging and collaborating with our
stakeholders, customers and the public. Stakeholder consultation with the general public,
including elected officials, special interest groups and others provides us with a broad
perspective as well as input into the plans we develop.
In addition to our extensive stakeholder consultation processes, the AESO has
developed a comprehensive public outreach program. Through this program, we try to
give Albertans factual and unbiased information about the electric industry including how
it works and who the players are. Our goal is to help Albertans better understand how
important electricity is to our quality of life, the competitiveness of our provincial business
and industry climate, and our overall economic future.
2010 - 2011 Planned Evolution and Focus on Our People, Technology, Stakeholder
Engagement and Public Outreach Processes
AESO staff and technology drive a significant portion our business activities and related
expenditures. As such, we are focused on efficiency improvements across our core
assets (people, technology and processes) that will improve our overall effectiveness.
Specifically, the initiatives the AESO will execute over the next two years include:
1. Develop and implement a comprehensive resource strategy to attract and
retain quality staff
ƒ
Develop and implement a workforce sourcing strategy for key roles,
define how identified gaps will be addressed and monitor the
effectiveness of the sourcing strategy.
ƒ
Implement the AESO’s succession plan for key roles.
ƒ
Implement a recruitment module for human resources systems.
ƒ
Implement a workforce-training program through internal and external
means.
2. Become a technology knowledge leader by creating internal capability to
evaluate, deploy and transfer emerging technology
ƒ
Establish an executive technology steering committee to provide
leadership, oversight and coordination of possible investments in new
technologies within the AESO.
ƒ
Assess and analyze HVDC features and integration issues and identify
necessary changes to procedures, tools, study techniques, resources and
training.
ƒ
Implement the market and operational framework for wind integration
including rules, technical requirements and practices/procedures.
PAGE 14
2010 – 2011 Business Plan and Budget Proposal
ƒ
Establish high performing integrated business systems that adapt to
business process and needs.
ƒ
Define life cycle models for all IT systems based on future business and
customer requirements.
ƒ
Expand the existing Market Roadmap to reflect the priorities of market
design, market operations, grid operations and the capabilities of
current/future IT systems (i.e., a market system vision that includes the
dispatch tool and Energy Trading System).
ƒ
Continue to implement and advance the new Energy Management
System.
ƒ
Provide customers with timely access to relevant data and information.
ƒ
Implement an information management platform that provides
stakeholders with simplified access to AESO data. This will be achieved
through a series of information management pilot projects.
3. Continue to refine and implement the AESO’s public outreach plan
ƒ
Enhance the public awareness program through ongoing definition of
target audience requirements.
ƒ
Support community-based education initiatives by seeking public
engagement opportunities (e.g., high schools, college, university and
community interest electricity courses).
ƒ
Utilize regional advisors and continue joint management-regional advisor
sessions.
ƒ
Develop E-communications plan and public information section as
website revisions.
4. Enhance relationships with stakeholders
ƒ
Enhance working relationships with stakeholders, government and related
agencies to improve communications, gain procedural efficiencies and
improve effectiveness.
ƒ
Engage stakeholders in consultation initiatives such as the Market
Advisory Committee, Alberta Reliability Standards Committee and Wind
Steering Committee.
PAGE 15
2010 – 2011 Business Plan and Budget Proposal
Financial Overview
Financial Overview
The AESO’s five-year strategic plan and related business initiatives, in addition to our
day-to-day operations, are the foundation on which annual funding requirements are
determined. Once the business initiatives are confirmed, we complete a detailed
assessment of what resources are required to deliver on our commitments, reviewing
human resource needs and information technology (IT) system requirements in addition
to other ongoing administrative costs.
At the AESO, financial management which includes the assurance that expenditures are
made in a prudent and value-added manner, is a key business philosophy. Through
responsible and effective use of the funding provided to the AESO, our goal is to ensure
every dollar is maximized in delivering on our initiatives.
As part of this business plan, we are presenting our 2010 and 2011 budgets. The process
for developing the budgets included detailed discussions and reviews with all levels of
management to establish business initiatives, which may be the extension of current
work, and to begin to assess the impact of these initiatives on existing resources and
system infrastructure. Based on these discussions and analysis, we then compile the
budget. This process ensures a consistent approach and removes gaps and overlaps in
work efforts while aligning with the overall corporate direction. This process ensures that
sufficient resources (human and financial) are available to deliver on business initiatives.
Financial information is presented in two sections: Section I reviews the 2009 financial
results and Section II provides budget information that is part of the 2010 and 2011
business plan. Additional information is included in Appendices A to J.
PAGE 16
2010 – 2011 Business Plan and Budget Proposal
Section I - 2009
Financial Management
When the Alberta government released its Provincial Energy Strategy in December 2008,
it was clear that remaining within the AESO’s 2009 budget would require a renewed
focus on resources. A key point in the Provincial Energy Strategy is strengthening the
provincial transmission system, which in turn had an impact on the AESO’s plans for
2009 in the planning and engineering areas, in addition to the communication strategies
to support these changes. In response to the Provincial Energy Strategy, the AESO
reprioritized its resources and we anticipate our 2009 financial results for general and
administrative costs will be at or very near the 2009 budget.
With respect to other cost categories, mainly transmission operating costs, we anticipate
costs significantly less than budgeted due to the lower than anticipated pool price in 2009
(a year-to-date July average pool price of $47 per megawatt hour (MWh) compared to a
forecast of $84 per MWh used for the 2009 transmission operating cost forecast).
Year-to-Date July 2009 Operating Results ($ million)
Transmission
Energy
Market
Revenue
Other Revenue
487.6
1.0
15.6
0.1
0.2
-
503.4
1.1
Total Revenue
488.6
15.7
0.2
504.5
Transmission Operating Costs
Other Industry Costs
General & Administrative Costs
Interest Costs
Amortization
Major Project Operating Costs
453.5
8.1
29.2
0.7
2.7
0.2
4.1
8.8
0.1
1.7
0.1
1.3
0.9
-
453.5
12.3
39.3
0.8
5.2
0.2
Total Costs
494.4
14.7
2.2
511.3
(5.8)
1.0
(2.0)
(6.8)
Operating (Deficit)/Surplus
Load
Settlement
YTD
Total
Any differences are due to rounding.
Allocation and Cost Classifications
Cost Categories
Wire
Line Losses
Operating Reserves
Transmission Must-Run
Other Ancillary Services
General
Classification
Operating
Operating
Operating
Operating
Operating
Other Industry Costs
Non-operating
General and Administration
Interest
Amortization / Capital
Non-operating
Non-operating
Non-operating
PAGE 17
Transmission
AESO Services (%)
Energy
Load
Settlement
Market
100
100
100
100
100
All other
costs
-
-
AUC-related
admin fee
-
Costs allocated based on an
established methodology
2010 – 2011 Business Plan and Budget Proposal
Total Revenues
The AESO recovers its operating and capital costs through three separate revenue
sources. Each is designed to recover the costs directly related to a specific service as
well as a portion of the shared corporate services costs. The AESO’s operations integrate
the functions of transmission, energy market and load settlement to maximize benefits
under the Electric Utilities Act (EUA). This integration results in cost allocations in many
parts of the organization for the purpose of cost recovery. In determining the revenue
requirement on a function-by-function basis, all AESO costs are assigned or allocated to
one of the three functions.
Transmission
The AESO is responsible for paying all the costs of managing the provincial transmission
system and recovering the costs through a tariff approved by the Alberta Utilities
Commission (AUC). The tariff is designed to allocate the costs to all users of the
transmission system based on level of usage.
As of July 2009, the operating deficit related to the transmission function is $5.8 million,
which represents a one per cent variance between revenue collections and costs. The
transmission tariff allows for the use of Rate Riders C “Deferral Account Adjustment
Rider” and E “Losses Calibration Factor Rider” to help match revenue collections with
actual costs incurred during the year.
Energy Market
The AESO recovers the costs of operating the real-time energy market through an
energy market trading charge on all MWhs traded. The energy market trading charge is
set to recover the operating costs and the amortization of capital assets during the
period. For 2009, the AESO’s component of the energy market trading charge is 23.2¢
per MWh to cover operating and capital costs (13.1¢ per MWh) and the AUC
administrative fee (10.1¢ per MWh). There is also a component in the energy market
trading charge that relates to the operations of the Market Surveillance Administrator
(MSA), which is independent of AESO operations.
As of July 2009, energy market revenue collections are greater than costs incurred by
$1.0 million or six per cent. This variance is primarily due to lower than anticipated costs
related to interest and amortization of capital assets in the first seven months of 2009.
Load Settlement
The expenses the AESO incurs to provide services related to administering provincial
load settlement are charged to the owners of electric distribution systems and wire
service providers conducting load settlement. The costs associated with load settlement
include operating costs and the amortization of capital assets.
As of July 2009, revenue collections are $2.0 million less than costs incurred. While the
2009 revenue collections are $2.3 million, they are offset by a refund payment of $1.9
million made in April of this year to settle an over-collection from 2008. By the end of
2009, it is anticipated that cumulative revenue collections and costs will be at or close to
zero.
PAGE 18
2010 – 2011 Business Plan and Budget Proposal
Total Costs
Transmission Operating Costs
The following chart provides the transmission operating costs as of July 2009 compared
to the forecast.
Year-to-Date July 2009 Transmission Operating Costs
($ million)
YTD July
Actual
YTD July
Forecast
YTD July
Variance
2009
Forecast
Wire Costs
Transmission Line Losses
Operating Reserves
Transmission Must-Run
Other Ancillary Service Costs
307.2
68.2
55.1
14.2
3.5
288.2
144.6
136.4
22.0
5.6
19.0
(76.4)
(81.3)
(7.8)
(2.1)
493.8
238.0
235.5
37.2
9.5
Transmission Operating Costs
448.2
596.8
(148.6)
1,014.0
Differences are due to rounding.
Transmission operating costs represent wire, transmission line loss and ancillary services
costs. As of July 2009, costs are lower than forecast by $148.6 million or 25 per cent.
This variance is attributed to significant variances in ancillary services and transmission
line loss costs due primarily to lower than anticipated pool and gas prices thus far in
2009.
Wire Costs
Wire costs as of July 2009 are $307.2 million compared to the AESO forecast of $288.2
million, an increase of $19.0 million or seven per cent based on the amounts paid
primarily to the owners of transmission facilities in accordance with their AUC-approved
tariffs.
Transmission Line Losses
The cost of transmission line losses is $76.4 million or 53 per cent lower than forecast in
the first seven months of 2009 primarily as a result of lower than forecasted pool prices.
The average hourly pool price has been $47 per MWh compared to a forecast of $84 per
MWh used for the line loss forecast. During this period, the volume of transmission line
losses has been 112 gigawatt hours or seven per cent less than the forecast (actual
volumes of 1,452 gigawatt hours compared to the forecast of 1,564 gigawatt hours).
Operating Reserves
Operating reserve costs in 2009 have been $81.3 million or 60 per cent lower than
forecast. As operating reserve costs are indexed to the hourly pool price, the difference is
primarily attributed to the significant decrease in the actual hourly pool price in 2009
compared to the forecast pool price. Operating reserve volumes are 134 gigawatt hours
or three per cent lower than forecast at the end of July.
PAGE 19
2010 – 2011 Business Plan and Budget Proposal
Transmission Must-Run
Transmission must-run costs in 2009 are $7.8 million or 35 per cent lower than forecast.
This decrease is attributable to the combination of lower TMR requirements in North
West Alberta due to lower load in this area and higher market heat rates so far in 2009
compared to forecast (pool price divided by gas price).
Other Ancillary Service Costs
Other ancillary services include the remaining services that the AESO procures for the
secure and reliable operation of the AIES. These services are procured through bilateral
contracts with suppliers. Over the first seven months of 2009, these costs are lower than
forecast due to the withdrawal of one load shed service participant and a contract delay
with a service provider.
Other Industry Costs
The following chart provides other industry costs as of July 2009 compared to the
AESO’s approved budget.
Year-to-Date July 2009 Other Industry Costs ($ million)
AUC Fees – Transmission
AUC Fees – Energy Market
External Regulatory Costs
WECC/NWPP* Costs
Balancing Pool
Other Industry Costs
YTD July
Actual
YTD July
Budget
YTD July
Variance
2009
Budget
6.0
4.1
0.0
2.1
-
5.8
4.2
3.4
1.6
-
0.2
(0.1)
(3.4)
0.4
-
9.9
7.2
5.9
2.8
-
12.3
15.0
(2.8)
25.8
*Western Electricity Coordinating Council/Northwest Power Pool
Differences are due to rounding.
Other industry costs are costs that are not within the control of the AESO; rather, these
costs are determined by third parties such as the AUC or the board of directors for the
Western Electricity Coordinating Council/Northwest Power Pool (WECC/NWPP). For
2009, it is anticipated that other industry costs will be significantly lower than budget due
primarily to external regulatory costs. As part of the Provincial Energy Strategy, the
Government of Alberta introduced new legislation in June (Bill 50) for the government to
assume responsibility for approving the need for critical transmission infrastructure (CTI)
projects, which is currently in the AUC’s approval mandate. While the 2009 budget for
external regulatory costs includes intervener and AESO costs related to need
applications for transmission projects that the AESO would file with the AUC, these costs
would not be incurred should Bill 50 receive legislative approval. Appendix A provides
additional information on other industry costs.
PAGE 20
2010 – 2011 Business Plan and Budget Proposal
General and Administrative Costs
The following chart provides the general and administrative costs as of July 2009
compared to the AESO’s approved budget.
50
$ Millions
40
30
20
10
0
Actual
Budget
Staff Costs
Contract Services & Consultants
Administration
Facilities
Computer Services and Maintenance
Telecommunications
Year-to-Date July 2009 General and Administrative Costs ($ million)
YTD July
Actual
YTD July
Budget
YTD July
Variance
2009
Budget
Staff Costs
Contract Services & Consultants
Administration
Facilities
Computer Services and Maintenance
Telecommunications
23.0
8.0
3.4
2.1
2.0
0.8
24.8
7.6
3.8
1.9
1.5
0.8
(1.8)
0.4
(0.4)
0.1
0.5
(0.0)
43.0
13.0
6.5
3.3
2.6
1.3
General and Administrative Costs
39.3
40.4
(1.1)
69.7
Differences are due to rounding.
Additional information on general and administrative costs is provided in Appendices C
through G.
PAGE 21
2010 – 2011 Business Plan and Budget Proposal
Staff Costs and Contract Services & Consultants
Operations at the AESO are labour intensive and work is completed through the efforts of
our staff or with the assistance of contractors or consultants. Thus far in 2009, staff costs
have been less than budgeted as we manage staff vacancies that have occurred for both
new staff additions and through general attrition. We maintain a focused recruitment
strategy to do everything we can to fill this gap on a timely basis. During this recruitment
period, we will use contractors and consultants to supplement our internal staff
resources. We project that by the end of 2009, actual costs for staff, contract services
and consultants combined will be marginally higher than budgeted.
Administration
Administration costs include corporate communications, recruiting, travel and training,
AESO Board fees and office costs that present the general operating costs of the
company. While costs are currently lower than budgeted, we expect that by the end of
the year, actual costs will be close to budget.
Facilities
While the staff complement may be growing, the AESO has focused on maximizing our
utilization of existing office space. There have been no new unanticipated office leases in
2009. However, operating costs were understated by $0.3 million in the 2009 budget,
which will result in operating costs being higher than budgeted in 2009.
Computer Services and Maintenance
As a result of the IT focus of AESO operations, acquiring and storing computer hardware
is a challenge we face. When the system coordination centre was designed, the server
rooms were built to accommodate future growth. However, for our back-up facility this
growth means we need to acquire additional server space, which means higher costs.
Additional space was required for our back-up site in 2009 and these costs had not been
incorporated into the 2009 budget. Higher costs in 2009 are also related to operating
licences and maintenance agreements. With delays in commissioning new systems or
applications, we have incurred unanticipated costs for software support on current
systems that have continued to operate past their planned retirement dates. It is
projected that actual costs in 2009 will be approximately $0.7 million higher than budget.
Telecommunications
Current and projected year-end costs for telecommunications are anticipated to be close
to budget.
PAGE 22
2010 – 2011 Business Plan and Budget Proposal
Interest and Amortization Costs
The following chart provides the interest and amortization costs as of July 2009
compared to the AESO’s approved budget.
Year-to-Date July 2009 Costs ($ million)
YTD July
Actual
YTD July
Budget
YTD July
Variance
2009
Budget
Interest
0.8
1.7
(0.8)
2.9
Amortization of Capital Assets
5.2
7.7
(2.5)
13.0
Interest
This past year has seen considerable changes in the economic landscape with significant
reductions to market interest rates. This has translated to lower borrowing rates for the
AESO. Interest costs in 2009 will continue to be significantly lower than budgeted.
Amortization of Capital Assets
Two major IT systems were to be commissioned in 2009—the Dispatch Tool Rearchitecture and Energy Management System (EMS) projects, which have a significant
impact on the current year amortization. As a result of changes in the actual
commissioning dates for these systems, there will be a misalignment of the
commissioning dates that will actually occur and those that were considered in the 2009
budget. Amortization costs will be less than budgeted for 2009.
Capital Expenditures
The AESO has three main asset categories: people, technology and processes. While we
invest in all three, only the technology assets (computer systems and system
coordination centre) are our focus for capital expenditures. The development and
acquisition of capital assets is a major budget component given the AESO’s significant
reliance on IT infrastructure to carry out our operations. As with all IT intensive
organizations, our challenge is to find the right balance between implementing technology
advancements, determining the level of IT development that can be supported by
business operations and then establishing the funding requirements to make it all
happen.
To address these challenges, we have implemented and continue to enhance a vetting
and prioritization process to ensure capital expenditures achieve the most beneficial and
cost-effective results to continue to meet operating requirements. We call this the capital
portfolio management process. As we progress through a planning year, capital projects
are reviewed on an ongoing basis to assess progress and budget spending and identify
unanticipated issues. We also review and prioritize any new requirements that are
identified and determine how they align with existing work. This is a continual process to
ensure alignment of priorities and business needs.
PAGE 23
2010 – 2011 Business Plan and Budget Proposal
For 2009, we are anticipating capital expenditures of $22.4 million, which is consistent
with the 2009 amended budget. The following table provides a summary of current capital
projects.
Capital Expenditures ($ million)
YTD July
2009
Key Capital Initiatives
1. Energy Management System
2. Dispatch Tool – Upgrade & Enhancements
3. Information Management Platform
4. Wind Integration
Total Key Capital Initiatives
Other Capital Initiatives
Life Cycle Initiatives
Total Capital Spending
Rest-of-Year Projected
Projection
2009
4.6
2.9
0.3
0.8
8.5
1.0
1.0
5.1
1.5
0.5
0.8
8.0
3.6
0.3
9.7
4.4
0.8
1.6
16.5
4.6
1.3
10.5
11.9
22.4
Differences are due to rounding.
Key capital initiatives represent the most critical capital projects over the planning
period that the AESO believes must be completed within the identified timeframe.
Other capital initiatives are also necessary projects; however, they have more flexibility
in planning or delivery so timing is not as critical or they are lower priority than the key
capital initiatives.
Life cycle initiatives are typically replacement of end-of-life hardware and recurring
software upgrades.
KEY CAPITAL INITIATIVES
1. Energy Management System (EMS)
In 2007, the AESO initiated a major capital project to replace the EMS with a new
solution provided by AREVA. The EMS receives and reports real-time telemetry from
participants to the system controller and manages regulating reserve signals for the grid.
This phase of the project implemented the base capabilities of the EMS and is targeted to
be commissioned in the last quarter of 2009.
2. Dispatch Tool – Upgrade and Enhancements
Following an assessment of our dispatch system’s technical architecture in 2008, we
initiated the first phase of our dispatch improvement program to improve the reliability
and responsiveness of this mission critical system. Additionally, a number of end-user
enhancements were included within the 2009 scope of work.
PAGE 24
2010 – 2011 Business Plan and Budget Proposal
3. Information Management Platform
With over 60 terabytes of data to manage, the AESO required a strategy to deal with data
growth and the increasing demand for information by staff and stakeholders. In 2009, we
undertook a project to build the foundational components of a data warehouse and highspeed data transfer technology to expedite the transfer of data from our production
systems to the data warehouse.
4. Wind Integration
This program is intended to facilitate the large-scale integration of wind power into the
AIES. The wind integration program includes capabilities for producing and maintaining
wind power forecasts, tools to manage surplus supply conditions and tools for developing
daily operating plans, as well the development of potential wind following services to
manage wind variability.
The initial phase of this program will be completed in the last quarter of 2009 and
includes the development of a dispatch decision support tool. This system controller tool
will integrate with future forecast providers and wind power management tools to allow
the system controller to better predict and react to the impact of wind on system and
market operations.
2009 OTHER CAPITAL INITIATIVES
Compliance Data Management
The AESO is responsible for establishing and carrying out compliance to settlement rules
as established in AUC Rule 21. This project is part of a program to enable our
compliance system to reconcile the 1.5 million metering sites across Alberta.
Oracle Database Re-architecture
The current version of our database software has reached the end of its useful life and
will no longer be supported by the vendor. An upgrade is required and strategic decisions
must be made to ensure the platform is configured to meet future business needs. While
the majority of the project will be done in 2010, work will begin in 2009 to ensure the
target delivery date is met.
Project Management/Reporting System
The ability to manage a large portfolio of projects, whether interconnections, market
initiatives or IT system changes, is critical to the AESO’s success. A project management
and reporting system is a foundational tool to improve project execution through better
management and visibility of our project’s complex timelines, resources and
interdependencies.
PAGE 25
2010 – 2011 Business Plan and Budget Proposal
SECTION II – 2010 and 2011
Financial Outlook
Similar to when we presented the 2008 and 2009 budgets to our Board in the fall of 2007,
a two-year budget has been prepared this year for 2010 and 2011. When the multi-year
budget process was first established with stakeholders and our Board, the principles for
an annual review process were set (Appendix B provides additional information). As part
of this process, prior to the start of each fiscal year we would prepare a forecast to
assess any budget changes required to deliver on current business initiatives. This
process ensures that any material change to our budget is considered as we reassess
our business initiatives in year-two of the business plan. This process will occur for the
2011 budget year in mid-2010.
As part of this 2010 and 2011 budget plan, we have reviewed and determined the twoyear funding requirements to address other industry, general and administrative, and
interest costs and amortization. For the following five transmission operating cost
categories, only the 2010 budget plan has been prepared:
•
Wire Costs
•
Transmission Line Loss Costs
•
Operating Reserve Costs
•
Transmission Must-Run Costs
•
Other Ancillary Service Costs
There were two main focuses in determining the general and administrative funding
requirements for 2010 and 2011. First, we focused on what the AESO must deliver to
fulfil its mandate and meet stakeholder needs. In addition, we were watchful of the
economy, including the impact on stakeholders and how this should influence operations.
The result of our assessment was that a general and administrative budget of $73.1
million would be required in 2010 and $75.1 million in 2011. This represents a $3.4
million or five per cent increase from the 2009 budget and a $2.0 million or three per cent
increase from 2010 to 2011.
We are committed to finding efficiencies in our organization, which includes reviewing the
AESO’s organizational structure to extract the highest level of productivity from current
resources. While the following sections will provide additional detail on the 2010 and
2011 general and administrative costs, the increase stems mainly from three areas. We
required additional resources to deliver on our strategic plan and business initiatives. We
have noted the AESO’s reliance on IT infrastructure to provide the necessary tools to
ensure reliable processes that meet our business needs. And, as our IT infrastructure
grows, so do the costs to maintain and support this infrastructure. Lastly, facility costs will
increase as we expand our back-up facility to accommodate additional hardware and
incur higher facility operating costs.
As for capital expenditures, we are currently projecting expenditures of $22.4 million in
2009. For 2010 and 2011, the level of capital expenditures will increase to $29.4 million
and $29.0 million respectively. We have compiled a preliminary list of pending projects to
provide new or enhanced business applications, to facilitate the replacement of end-of-
PAGE 26
2010 – 2011 Business Plan and Budget Proposal
life IT hardware, or to upgrade software. Based on our current assessment, this level of
investment will be required for the following two years. One of the main reasons for the
increase is the need to develop or modify systems to incorporate changes to the energy
market rules. Further details on capital expenditures are provided further in this document
and in Appendix I.
Key Assumptions over the Planning Period
To determine the 2010 and 2011 funding requirements, it is necessary to analyze and
conclude on various assumptions that play an integral role in the budget development.
Two main categories of assumptions are reviewed. First, human resource assumptions,
which have a significant impact on the overall budget as staff costs represent
approximately 60 per cent of the 2009 general and administrative cost budget. The
second assumption category includes general business assumptions on how the AESO
will approach its mandate, level and quality of work and the impact these factors have on
budget requirements.
Key Human Resource Assumptions
The following discussion presents the key human resource assumptions with additional
information provided in Appendix C.
Each year, the current labour market is reviewed to determine what, if any, salary
adjustment should occur for existing staff to keep the pay structure in line with
organizations that compete with the AESO for technical staff and the general labour
market as a whole. In addition to salary research, economic indicators such as the
Consumer Price Index are reviewed. Based on this analysis, the 2010 and 2011 salary
adjustment for existing staff is two per cent in each year.
The other notable human resource assumption is the staff complement. In each of the six
years since the AESO’s inception in 2003, the staff complement has increased in
response to new initiatives or functions and to an increase in workload as functions were
fully developed over time. In 2009, management has made a focused effort to review and
enhance key business processes (such as the customer interconnection process and
transmission planning) with an objective to find improvements in both the quality of work
and resource efficiency. These initiatives, in conjunction with the overall philosophy to reevaluate and, where appropriate, realign the efforts of existing staff positions will identify
staff positions that can be reallocated to offset the requirement for additional resources in
2010 and 2011. In keeping with this, management has identified new staff positions
required to address the implementation of new functions, new technology, grid and
market operations and succession planning in 2010 and 2011. Several of these new
position requirements have been offset through realignment of existing positions.
After this comprehensive review of both existing and future staff requirements, the 2010
budget includes 15 new permanent staff positions with an additional 10 positions planned
for 2011. Information on the new 2010 and 2011 staff positions is provided in Appendix
D.
PAGE 27
2010 – 2011 Business Plan and Budget Proposal
General Business Assumptions
In developing the budget requirements for 2010 and 2011, the focus is always on
resource efficiency and ensuring the funding we receive is used in the most cost-effective
manner. With the critical nature of the AESO’s operations, this does not always mean the
most inexpensive alternative available; rather, it considers how to get the most from
every dollar. The AESO’s focus is on quality, reliability and timeliness and these
principles underlie the determination of the annual budget requirements.
For the budget assumptions made each planning year, there may be several possible
alternatives. We select the most probable based on available information. We know
things can change. It is the scope of that change that determines if the budget plan can
absorb these changes (such as the timeline and level of economic recovery, changes in
legislation such as Bill 50).
PAGE 28
2010 – 2011 Business Plan and Budget Proposal
Total Revenues
1,200
$ Millions
1,000
800
600
400
200
0
2010 Budget
2009 Budget
Transmission - Op Costs
Energy Market
2008 Actual
2007 Actual
Transmission - G&A/Other Industry
Load Settlement
Total Revenue ($ million)
Transmission – Operating Costs
Transmission – Non-operating Costs
Energy Market
Load Settlement
Total Revenue
2011
Plan
2010
Plan
2009
Budget
2008
Actual
2007
Actual
83.5
34.3
4.6
855.4
79.2
31.0
4.4
1,014.1
80.0
26.5
4.9
1,031.5
62.6
22.7
3.6
860.8
49.2
14.0
5.2
-
970.1
1,125.5
1,120.4
929.2
Differences are due to rounding.
Given the AESO’s status as a not-for-profit statutory corporation, the annual revenue
amounts represent the cost recovery of the operating and capital costs. The majority of
revenues the AESO collects are the recovery of transmission operating costs (wires, line
loss and ancillary services costs). The remaining costs (other industry, general and
administrative, and interest and amortization costs) are recovered through a methodology
intended to relate the cost to the specific service that it supports (transmission, energy
market or load settlement).
As part of our 2010 and 2011 business planning process, only the 2010 transmission
operating costs are included with the 2011 transmission cost review to occur in mid-2010
as part of the 2011 business plan update.
PAGE 29
2010 – 2011 Business Plan and Budget Proposal
Allocation of Costs for Revenue Requirements
The allocation of costs to one of the AESO’s three services is based on the direct or
indirect relationship the cost has to one of the services. If an operating cost is directly
associated with a service, the cost will be assigned directly to that service (i.e., a
consultant cost in the transmission planning group would be assigned 100 per cent to
transmission and recovered through the transmission tariff). Alternatively, if the operating
cost is not directly associated with any one service (typical for corporate service areas),
the cost will be allocated to all services based on the directly assigned costs. This
methodology assumes that the service with the higher direct costs would contribute to a
higher demand for general costs (such as corporate services) and therefore be assigned
a higher percentage allocation.
There are a few exceptions to this general methodology for: IT, rent and capital costs. IT
costs are allocated based on an activity-based analysis to better reflect the nature of the
underlying costs. Rent costs are allocated based on the staff associated with the three
services. Capital expenditures made to support one service are recovered from that
service or alternatively from multiple services based on management judgment, taking
into consideration the business/operating activities that will be supported on the systems
(hardware and software).
Appendix H provides additional information on the cost allocation methodology.
Revenue
Transmission
The AESO is responsible for paying the costs of managing the provincial transmission
system and recovering the costs through a tariff approved by the AUC. The tariff is
designed to allocate the costs to all users of the transmission system based on level of
usage. The 2010 budget costs related to the transmission service will be incorporated
into the AESO’s 2010 General Tariff Application.
Energy Market
The AESO recovers the costs of operating the real-time energy market through an
energy market trading charge on all MWhs traded. Based on the proposed 2010 and
2011 budgets and the forecast trading volumes, an energy market trading charge of
27.2¢ per MWh traded is required for 2010 and 28.0¢ per MWh traded 2011.
Proposed Trading Charge Components (¢ per MWh)
2011
2010
2009
AESO Costs
Energy Market Deficit / (Surplus)
22.1¢
-
20.1¢
1.0
15.7¢
(2.6)
AESO Component
AUC Energy Market Administration Fee
22.1¢
5.9
21.1¢
6.1
13.1¢
10.1
Total
28.0¢
27.2¢
23.2¢
Differences are due to rounding.
PAGE 30
2010 – 2011 Business Plan and Budget Proposal
Proposed Trading Charge Components ($ million)
2011
2010
2009
AESO Costs
Energy Market Deficit / (Surplus)
27.0
-
23.7
1.2
19.3
(3.2)
AESO Component
AUC Energy Market Administration Fee
27.0
7.2
24.9
7.2
16.1
12.4
Total
34.2
32.1
28.5
Differences are due to rounding.
To collect for the general and administrative, interest and amortization costs associated
with the energy market function in 2010, an additional $4.4 million will be incorporated
into the energy market trading charge in comparison to the 2009 budget. The increase
results from the combination of higher cost allocations to the energy market function for
corporate service and IT costs and overall increases in general and administrative costs
and amortization in both 2010 and 2011. When the 2009 trading charge was established,
the AESO costs were offset by the cumulative prior-year collection surplus which reduced
the overall collection requirements in 2009 by $3.2 million. For 2010, we anticipate
starting the year with a $1.2 million collection deficit due to the combination of lower than
budgeted costs in 2009, the benefit of which is more than offset by lower revenue
collections.
For the AUC energy market administration fee in 2009, the 10.1 cents per MWh traded
incorporated the fees for two years (2008 and 2009) which in aggregate were $12.4
million. For 2010, only the estimated current year administration fee of $7.2 million will be
incorporated into the energy market trading charge representing 6.1 cents per MWh.
These trading charge amounts are independent of the Market Surveillance Administrator
(MSA) charge. The 2010 MSA cost recovery amount will be communicated to the AESO
in the latter part of 2009. The MSA cost recovery amount is approved by the Chair of the
AUC in an independent budget process.
Load Settlement
Expenses that we incur to provide services related to administering provincial load
settlement are charged to the owners of electric distribution systems and wire service
providers conducting load settlement under AUC Rule 21.
PAGE 31
2010 – 2011 Business Plan and Budget Proposal
Total Costs
Transmission Operating Costs
The following chart provides the summary of transmission operating costs. Additional
information on the 2010 forecast methodology and descriptions of the cost categories is
provided in Appendix J.
$ Millions
1,200
900
600
300
0
2010 Budget
2009 Budget
2008 Actual
Wire Costs
Transmission Line Losses
Transmission Must Run
Other Ancillary Service Costs
2007 Actual
Operating Reserves
Transmission Operating Costs ($ million)
2010
Plan
2009
Forecast
2008
Actual
2007
Actual
Wire Costs
Transmission Line Losses
Operating Reserves
Transmission Must-Run
Other Ancillary Service Costs
537.5
173.6
112.5
22.3
9.5
493.8
238.0
235.5
37.2
9.5
504.1
236.0
262.2
43.3
8.0
458.2
188.6
180.7
47.0
9.6
Transmission Operating Costs
855.4
1,014.0
1,053.6
884.1
Differences are due to rounding.
Wires
Wires costs represent the amounts paid primarily to owners of transmission facilities
(TFOs) in accordance with their AUC-approved tariffs and are not controllable costs of
the AESO. For 2010, we are forecasting wires costs of $537.5 million based on the
current AUC-approved TFO costs (totaling $532.8 million) and the AESO’s forecast for
other included costs (netting to $4.7 million). This forecast represents an increase of
$43.7 million or nine per cent compared to the 2009 forecast of $493.8 million. Prior to
the AESO filing the 2010 GTA later this year, we will update the wires costs forecast to
include any additional amounts approved in AUC decisions.
Transmission Line Losses
Transmission line loss costs are the cost of energy that is ‘lost’ as a result of electrical
resistance on the transmission lines. Our forecast for the 2010 transmission line loss
PAGE 32
2010 – 2011 Business Plan and Budget Proposal
costs is $173.6 million based on 2.64 terawatt hours of energy and the July 28, 2008
EDC hourly pool price forecast (annual 2010 average pool price of $64 per MWh). This
forecast represents a $64.4 million or 27 per cent decrease from the 2009 forecast of
$238.0 million which was based on 2.76 terawatt hours of energy with the annual 2009
average pool price of $84 per MWh. While the forecasted volumes have decreased by
approximately four per cent in 2010 (2.76 to 2.64 terawatt hours), the reduction to costs is
primarily attributed to the lower pool price forecast.
Operating Reserves
The AESO purchases operating reserves from the ancillary services exchange and
through over-the-counter contracts with suppliers. Operating reserves are generating
capacity or load that is held in reserve and made available to the system controller to
manage the transmission system supply-demand balance in real-time. Operating reserve
prices are indexed to the hourly pool price and the AESO’s forecast for operating reserve
costs is based on the 2010 forecasted pool prices.
In 2010, we are forecasting that operating reserve costs will decrease to $112.5 million
which is a $123.0 million or 52% decrease from the 2009 forecast. While the forecast
operating reserve volumes for 2010 are similar to the 2009 forecast, the significant
decrease in the forecast hourly pool price for 2010 is the primary reason for the forecast
cost decrease over 2009.
Transmission Must-Run
Transmission must-run (TMR) is generation required to be on-line and operating to
ensure reliability in specific areas of the AIES with insufficient transmission capacity.
In 2010, we are forecasting TMR costs to be $22.3 million which is a $14.9 million or a 40
per cent decrease from the 2009 forecast. Forecast TMR costs for 2010 are lower than
those for 2009 due to a significant decrease in the natural gas price forecast relative to
the 2009 forecast and lower anticipated TMR volume requirements in 2010.
Other Ancillary Services
Other ancillary services include the remaining services that the AESO procures for the
secure and reliable operation of the AIES such as load shed services and black start
services. Forecast costs for these services are $9.5 million which is consistent with the
2009 forecast. These services are largely procured on a fixed cost basis through bilateral
contracts and do not vary significantly from year to year.
Other Industry Costs
Other industry costs represent fees or costs paid based on regulatory requirements or
membership fees for industry organizations; the amounts of which are not under the
control of the AESO. These costs relate to the annual administration fee for the AUC,
external regulatory costs for the cost recovery related to the AESO’s regulatory
proceedings and the AESO’s share of Western Electricity Coordinating Council (WECC)
and Northwest Power Pool (NWPP) membership fees.
PAGE 33
2010 – 2011 Business Plan and Budget Proposal
Other Industry Costs ($ million)
2011
Plan
2010
Plan
2009
Budget
2008
Actual
2007
Actual
AUC Fees – Transmission
AUC Fees – Energy Market
External Regulatory Costs
WECC/NWPP Costs
Balancing Pool
10.8
7.2
0.1
3.4
0.0
10.8
7.2
0.5
3.4
0.0
9.9
7.2
5.9
2.8
0.0
8.6
5.2
0.7
2.2
0.0
2.3
0.0
0.8
1.7
0.0
Other Industry Costs
21.5
21.9
25.8
16.7
4.8
Differences are due to rounding.
The AUC levies two separate administration fees to the AESO: a transmission fee that is
recovered through the transmission tariff and an energy market fee that is recovered from
energy market participants through the AESO’s trading charge on a per MWh traded
basis. Annualizing the April to December 2009 AUC fees, the transmission fees for a 12month period would be $10.8 million and the energy market fees would be $7.2 million.
As the AUC administration fees have not been set for the period beyond December 2009,
2010 and 2011 AUC fees are budgeted using the 2009 fee amounts.
The budget for external regulatory costs, the recoverable costs for the AESO and
stakeholder participation in the AESO’s regulatory proceedings, is significantly lower in
2010 and 2011 compared to 2009 due to the anticipated changes to the regulatory
proceedings should the legislative approval of Bill 50 occur, whereby critical transmission
infrastructure would no longer be the subject of a regulatory need application.
The AESO’s share of the WECC membership fees is budgeted to increase as the result
of an increase in the WECC 2010 budget, which was approved by the WECC board of
directors and allocated to the AESO on a percentage share basis.
Appendix A provides additional information on other industry costs.
PAGE 34
2010 – 2011 Business Plan and Budget Proposal
General and Administrative Costs
80
$ Millions
60
40
20
0
2011 Budget
2010 Budget
2009 Budget
2008 Actual
2007 Actual
Staff Counts
Contract Services & Consultants
Administration
Facilities
Computer Services and Maintenance
Telecommunications
General and Administrative Costs ($ million)
2011
Plan
2010
Plan
2009
Budget
2008
Actual
2007
Actual
Staff Costs
Contract Services & Consultants
Administration
Facilities
Computer Services and Maintenance
Telecommunications
46.4
11.7
7.1
4.7
3.8
1.4
44.4
12.4
7.0
4.7
3.3
1.3
43.0
13.0
6.5
3.3
2.6
1.3
37.4
11.8
6.5
3.1
2.6
1.3
32.3
8.2
4.4
2.5
2.2
1.4
General and Administrative Costs
75.1
73.1
69.7
62.7
51.0
Differences are due to rounding.
Additional information on general and administrative costs is provided in Appendices C
through G.
Staff Costs
People continue to be the AESO’s most valuable asset. We must ensure that we
continue to have the right people with the right skill sets working to achieve our corporate
objectives. This requires the organization to focus on attracting and retaining qualified
staff. Two factors key to achieving this are maintaining a competitive compensation
package and ensuring sufficient resources are available (permanent staff and
contractors) to support employee work/life balance.
PAGE 35
2010 – 2011 Business Plan and Budget Proposal
In 2010 and 2011, the budgets reflect additional staff and compensation increases for
current staff. Staff additions will focus on the following:
•
New functions to address Alberta Reliability Standards, the creation of an audit
service function and managing the AESO’s authoritative documents.
•
New technology initiatives related to the Provincial Energy Strategy
(incorporating new, major interconnections onto the system including wind
integration), establishing a fourth system controller desk to study and manage
these new technologies (such as wind power integration, high voltage direct
current (HDVC) impact, new interties etc.) and establishing IT and information
security guidelines and practices in response to the North American Electric
Reliability Corporation (NERC), Alberta (Critical Infrastructure Protection (CIP))
and ISO standards.
•
Maximizing the functionality and information available to the system controllers
and planners with the implementation of the EMS in 2010 and ongoing
maintenance of the system.
•
Initial succession planning for identified positions. This is the initial stage of a
larger corporate initiative.
The following chart outlines the AESO’s permanent staff complement:
334
Number of Staff
350
292
300
250
344
319
266
227
243
200
150
2005
2006
2007
2008
PAGE 36
2009
2010
2011
2010 – 2011 Business Plan and Budget Proposal
Contract Services & Consultants
With the focus on more efficient utilization of resources within the AESO, management is
committed to reduce the use of external consultants and contractors. This results in a
reduction to the contract services and consultants costs in 2010 by $0.6 million or five per
cent and a further $0.7 million or six per cent in 2011. Appendix E provides summary
information on 2010 and 2011 consulting initiatives.
Administration
The remaining administrative cost categories include corporate communications,
recruiting, travel and training, AESO Board fees, office costs, etc. that present the
organization’s general operating costs.
These costs will increase by $0.5 million or eight per cent in 2010 and then remain
relatively stable. The increase is mainly attributable to publishing an additional version of
Powering Alberta (two publications each year from the single edition included in the 2009
budget) and stakeholder consultation/meeting costs for open house events on
transmission projects. A second publication of Powering Alberta each year will allow
additional topics to be addressed in our effort to enhance public understanding of the
Alberta electricity industry. It also avoids over-communication by using one publication to
cover multiple topics.
Facilities
Under a long-term lease, we lease approximately 60,000 square feet in downtown
Calgary. In addition, approximately 15,000 square feet is leased on an annual basis to
accommodate current requirements for IT project staff. The AESO is owns and operates
the system coordination centre (approximately 30,000 square feet). The 2010 and 2011
budgets also include rent and operating costs associated with the AESO’s back-up
facility, which were included in the computer services and maintenance cost category
prior to 2010 ($0.4 million in the 2009 budget).
In 2010, the facility costs budget will increase by $1.4 million or 42 per cent compared to
the 2009 budget. This increase is the result of re-classifying the back-up facility’s
associated lease costs ($0.4 million), increasing space at the back-up facility to
accommodate an increase in the amount of IT hardware due primarily to the new EMS
($0.4 million), inclusion in the budget of the operating costs for the office space for IT
project staff that was not included in the 2009 budget ($0.4 million) and an increase to the
business taxes at the system control centre facility as assessed by the City of Calgary
($0.2 million). Facility costs are not anticipated to increase further in 2011.
Computer Services and Maintenance
As the AESO invests in IT infrastructure to support the organization’s business
operations, ongoing costs are incurred to purchase annual software operating licences
and maintenance agreements for these systems with high availability requirements that
are supported by premium class maintenance and support agreements. As previously
mentioned, prior to 2010, this cost category also included the lease and operating costs
for the AESO’s back-up facility, which are now incorporated into the facility costs.
PAGE 37
2010 – 2011 Business Plan and Budget Proposal
The 2010 budget shows an increase in the computer services and maintenance costs of
$1.1 million or 50 per cent (after removing the back-up facility costs of $0.4 million from
the 2009 budget as previously described). The 2011 budget shows a further increase of
$0.5 million or 15 per cent. These cost increases are a combination of: i) operating
licences and maintenance agreements that occurred in 2009 but had not been
incorporated into the 2009 budget and ii) new operating licences and maintenance
agreements for changes that will occur in 2010 and 2011. The new EMS and its
peripheral applications are the main system changes in 2010.
Telecommunications
The AESO incurs costs for network systems and telecommunications to support general
business operations and, to a much larger extent, to support real-time operations. The
strategy for developing and maintaining the telecommunication infrastructure is based on
the requirement for high availability, which necessitates redundancies of services and
equipment.
The telecommunication costs in 2010 and 2011 will remain consistent with 2009 with an
annual budget of $1.3 million.
Interest Costs and Amortization
Interest Costs and Amortization ($ million)
Interest
Amortization of Capital Assets
2011
Plan
2010
Plan
2.6
23.2
2.0
17.7
2009 2008 2007
Budget Actual Actual
2.9
13.0
1.4
7.8
2.2
9.2
Interest
Interest expense is incurred as a result of bank debt held throughout the year and the
associated borrowing rate. Bank debt is issued to fund capital purchases and working
capital deficiencies due to timing differences in the collection of revenues and payment of
expenses. Capital assets are financed through the AESO’s credit facilities and recovered
over the useful life of the asset (included in the amortization amounts).
With the increase in the AESO’s capital expenditures in 2010 and 2011, in addition to the
full year of amortization on the EMS that will be commissioned in the latter part of 2009 (a
$20 million capital project), debt borrowings will increase in 2010 and 2011 in relation to
2009 as the recovery of capital assets is over their useful lives.
This past year has seen considerable changes in our economic landscape with significant
reductions to market interest rates. This has translated to lower borrowing rates for the
AESO in 2009. The interest cost budget has been based on an interest rate of 2.5 per
cent in 2010 and 3.0 per cent in 2011 to reflect our cost of borrowing.
PAGE 38
2010 – 2011 Business Plan and Budget Proposal
Amortization of Capital Assets
Capital assets are amortized over their estimated useful lives in accordance with
generally accepted accounting principles and reviewed on an annual basis. Amortization
of capital assets in 2010 includes the full year of amortization for the 2009 additions, most
notably the full year of amortization of the EMS, which will be commissioned in the latter
part of 2009. Additional, detailed information on capital projects is provided in the capital
expenditures section.
Capital Expenditures
Over the planning period, the AESO intends to incur capital expenditures estimated to
total:
• $29.4 million in 2010
• $29.0 million in 2011
2010 and 2011 Capital Plan Summary by Year ($ million)
2011
Plan
2010
Plan
2009
Budget
2008
Actual
Key Projects
Other Projects
Life Cycle Funding
18.6
5.0
5.4
16.0
8.0
5.4
15.7
5.4
1.3
12.1
4.5
3.8
Total Capital Costs
29.0
29.4
22.4
20.4
Differences are due to rounding.
Key capital initiatives represent the most critical capital projects over the planning
period that the AESO believes must be completed within the identified timeframe.
Other capital initiatives are also necessary projects; however, they have more flexibility
in planning or delivery so timing is not as critical or they are lower priority than the key
capital initiatives.
Life cycle initiatives are typically replacement of end-of-life hardware and recurring
software upgrades.
As the AESO operates in a dynamic environment, our business practices need to adapt
to change. This includes adapting to changing priorities. As previously described with
respect to the 2009 capital expenditures, the AESO has implemented a capital portfolio
management process to regularly review and prioritize capital projects to ensure we meet
business requirements and, at the same time, achieve the most beneficial and costeffective results. With this capital portfolio management process in place and our need for
flexibility to re-evaluate capital plans throughout the year, we consider this business
planning process an opportunity to establish a level of capital expenditures for use in the
capital portfolio management process (the capital ‘envelope’) and not the review and
approval of specific capital projects for 2010 and 2011.
PAGE 39
2010 – 2011 Business Plan and Budget Proposal
To arrive at the 2010 and 2011 capital expenditure budget or capital envelope, the AESO
undertook an assessment of the anticipated projects for these years. This is the
preliminary list of projects based on current knowledge, including initiatives to support our
plan. Based on these projects, we have established anticipated funding requirements for
each year. We know things will change—both priorities and projects—and we will use the
capital portfolio management process throughout the year to manage these changes. All
projects identified during the year, which may include those described in the following
paragraphs or those not yet identified, will be subject to a detailed review as part of the
capital portfolio management process prior to approval of any project funding. This review
includes further consideration for project need, a cost-benefit analysis and a business
case.
With this approach for approval of a capital expenditure budget or capital envelope as
opposed to individual capital projects, we recognize the need for ongoing communication
with our Board and stakeholders about capital projects that receive approval through the
capital portfolio management process. This reporting will include details on a project’s
progress and budget and will identify unanticipated issues.
The following information provides details on our current capital plan for 2010 and 2011.
The actual projects to be completed in 2010 and 2011 will vary, and include the addition
of projects yet to be determined, deferral of projects in this plan or the elimination of
projects deemed no longer necessary. It is anticipated that the key capital initiatives will
be delivered as scheduled.
Capital Expenditures ($ million)
2011
Plan
2010
Plan
2009
Projected
Key Capital Initiatives
1. Energy Management System
2. Wind Integration
3. FEOC* Regulation Implementation
4. Congestion Management
5. Intertie Framework
6. Dispatch Tool - Upgrade/Enhancements
7. Transmission and Market Modelling
8. Information Management Platform
9. 2010 General Tariff Application
10. Alberta Reliability Standards
11. System Coordination Centre Expansion
Total Key Capital Initiatives
Other Capital Initiatives
Life Cycle Funding
3.2
3.0
3.0
0.3
1.9
1.0
0.5
1.8
0.6
3.3
18.6
5.0
5.4
3.8
3.2
3.0
2.0
1.6
0.7
0.7
0.6
0.4
16.0
8.0
5.4
9.7
1.6
4.4
0.8
16.5
4.6
1.3
Total Capital Spending
29.0
29.4
22.4
*Fair Efficient Open Competition
Differences are due to rounding.
PAGE 40
2010 – 2011 Business Plan and Budget Proposal
KEY CAPITAL INITIATIVES
The following is a brief description of each initiative. Note that a number of key capital
initiatives are multi-year.
1. Energy Management System (EMS)
In 2007, the AESO initiated a major capital project to replace the EMS with a new
solution provided by AREVA. The EMS receives and reports real-time telemetry from
participants to the system controller and manages regulating reserve signals for the grid.
This phase of the project implemented the base capabilities of the EMS and is targeted to
be commissioned in the last quarter of 2009.
In 2010, the AESO will initiate the next phase of the EMS implementation, which includes
improved situational awareness, look-ahead functionality, load-shed services and a
system controller training environment.
Implementation of these features is projected to cost $7.0 million over two years.
2. Wind Integration
This program is intended to facilitate the large-scale integration of wind power into the
AIES. The wind integration program includes capabilities for producing and maintaining
wind power forecasts, tools to manage surplus supply conditions and tools for developing
daily operating plans, as well the development of potential wind following services to
manage wind variability.
The initial phase of this program will be completed in the last quarter of 2009 and
includes development of a dispatch decision support tool. This system controller tool will
integrate with future forecast providers and wind power management tools to allow the
system controller to better predict and react to the impact of wind on system and market
operations.
These future capabilities will be developed over multiple years with the bulk of
development occurring in 2010 and 2011. The forecast two-year cost is $6.2 million.
3. Fair Efficient Open Competition (FEOC) Regulation Implementation
In July 2009, the Alberta Department of Energy issued a new regulation to the EUA that
sets the framework to monitor and report on the market share offer control of market
participants. To fulfil the requirements of the regulation, the AESO must provide outage
reporting and historical merit orders and develop IT systems capable of identifying and
tracking the market participant that holds the offer control associated with each submitted
offer block.
The AESO will implement the regulation requirements over the next four years as some
elements will require further stakeholder consultation before the full scope of
implementation is understood.
This business plan incorporates costs of $6.0 million in 2010 and 2011 on this project.
PAGE 41
2010 – 2011 Business Plan and Budget Proposal
4. Congestion Management
The AESO is responsible for ensuring open and non-discriminatory access to the
transmission system, and must establish rules and practices to manage transmission
constraints that may occur in an equally open and non-discriminatory way.
New rules for managing transmission constraints are in the final stages of development.
Implementation will require significant changes to the bid submission and dispatch
processes currently built into our energy market dispatch, trading and settlement
systems.
New transmission constraint management rules are expected to be finalized in 2009 and
should be fully implemented within our IT systems in 2011 at an estimated cost of $2.3
million over two years.
5. Intertie Framework
Current electricity policy requires the AESO to develop a comprehensive intertie
framework (ISO Rules, operating policies and procedures (OPPs) and system capability)
that facilitates development of new intertie capacity and implements dispatchable interties
so that imports/exports can fully participate in the Alberta electricity market. The
framework includes new business practices for intertie scheduling, dispatching, allocation
and curtailment.
The program will require a new tariff design, rule and OPP changes, and IT
enhancements to systems involved in infrastructure planning, cost allocation, market
pricing, operations and compliance.
It is anticipated that $3.5 million will be spent on this initiative in 2010 and 2011.
6. Dispatch Tool – Upgrade and Enhancements
In 2009, the AESO undertook a project to improve the performance and reliability of the
dispatch tool by migrating the system to a new event-driven architecture. Product
upgrades and enhancements not related to performance and reliability improvements
were deferred to later phases of the tool’s evolution.
In 2010 and 2011, the AESO plans to implement the deferred functional enhancements
as a series of product releases. These enhancements include improved reporting,
usability, administration and functional (market) features.
These improvements will be implemented over a two-year period at an estimated cost of
$1.7 million.
7. Transmission and Market Modelling
The AESO maintains an object-model of the transmission system that supports asset
management and power flow, short-circuit and transient analysis. Additionally, the AESO
maintains models for market analysis, generation planning, adequacy assessments, state
estimation and training simulation. Each model is currently managed in its own
independent system, each requiring its own operational expertise of essentially duplicate
information.
PAGE 42
2010 – 2011 Business Plan and Budget Proposal
This project will implement an electricity industry standard planning model to better
coordinate the AESO’s planning, development and operation activities, reduce the
number of errors and eliminate redundancies, allowing us to communicate more
efficiently with external parties.
This two-year program is forecast to cost $1.2 million to complete.
8. Information Management Platform
With over 60 terabytes of data to manage, the AESO required a strategy to deal with the
data growth and the increasing demand for information by staff and stakeholders.
In 2009, we initiated a multi-year information management program by creating the data
warehouse and high-speed data transfer technology to expedite data transfer from our
production systems to the warehouse. Further foundational components are required to
deliver a solution that ensures the quality, consistency and security of the data required
by staff and stakeholders for analysis, reporting, and investigation purposes. The plan is
to implement these foundational components in 2010 and 2011, and include master data
management, data transformation (ETL), and business intelligence tool sets as well as
further integration of the AESO’s production systems data into the data warehouse.
We have budgeted $2.4 million to complete this project over the next two years.
9. 2010 General Tariff Application
This includes development and implementation of changes to the transmission billing
system for any system modifications required from the AESO’s 2010 General Tariff
Application rate structure.
We have budgeted $0.4 million to complete this project in 2010.
10. Alberta Reliability Standards
The AESO is leading an initiative to adopt North American Electric Reliability Council
(NERC) reliability standards as Alberta Reliability Standards. Development of a more
consistent set of standards is essential to the reliable operation of the Alberta electric
system, as well as maintaining and improving the reliability of the interconnected North
American electric grid.
The AESO is responsible for compliance tracking, NERC standards conversion,
notification/audit/reporting and documentation management of the Alberta Reliability
Standards. This project will provide tools to manage and report on the hundreds of
requirements and measures contained within these standards.
Alberta Reliability Standards management and compliance tracking tools are projected to
cost $0.6 million and should be implemented in 2011.
11. System Coordination Centre Expansion
The system control centre (SCC) facility was constructed in 2006 and was designed to
accommodate the AESO’s primary data centre, the system controllers’ operating theatre
and support staff for operations, operations planning and IT EMS.
During the design stage, several options were considered regarding the facility’s physical
size and the number of staff that would be located there. While it was foreseen that there
PAGE 43
2010 – 2011 Business Plan and Budget Proposal
was potential to outgrow the facility within a short time, high construction costs and
budget limitations dictated we build only what was needed in the two- to five-year range.
The building was designed to be expanded if needed and the mechanical, electrical,
heating ventilation and air conditioning systems were installed to accommodate the
expansion of the second floor.
The facility was designed to provide approximately 36 staff with office space in addition to
the main operating theatre. Currently 37 permanent staff are assigned to the facility. In
addition, 17 EMS project team members occupy space designed for future computer
room expansion in the basement.
The SCC floor expansion is expected to cost $3.3 million to complete.
OTHER CAPITAL INITIATIVES
Information on capital projects identified as other capital initiatives is provided in
Appendix I.
PAGE 44
2010 – 2011 Business Plan and Budget Proposal
Appendix A: Other Industry Cost Detail
Other industry costs represent certain costs the AESO funds on behalf of industry
participants, including an allocation for AUC-related costs, the cost of membership in the
Western Electricity Coordinating Council (WECC) and Northwest Power Pool (NWPP),
the costs of stakeholder participation in the AESO’s regulatory proceedings and
Balancing Pool operating cost shortfalls, if any.
WECC/NWPP Membership Fees
The WECC is a cross-border regional entity responsible for implementing NERC
standards, monitoring and enforcing reliability standards in the United States, and
working with Alberta and British Columbia as they maintain provincial jurisdictional
authority but coordinate operations for a reliable interconnection.
NWPP is the body that serves as a forum in the electric industry for reliability and
operational adequacy issues in the Northwest.
Balancing Pool
In the Balancing Pool’s role to manage the financial accounts on behalf of electricity
consumers arising from the transition to a competitive generation market, Section 82 of
the EUA directs it to provide the AESO with an annualized amount in respect of its
forecast revenue and expenses. No forecast has been made for any payments to or
collections from the Balancing Pool for 2010 and 2011 (nor have any occurred in prior
years).
External Regulatory Costs
The AESO’s general and administrative costs for staff, legal and consulting services do
not include recoverable regulatory costs. External legal costs and the costs of expert
consultants that exceed the AUC recoverable rates and any disallowed hearing costs by
the AUC are recorded in the AESO’s general and administrative costs in the appropriate
category.
External regulatory costs are expensed at the time of payment. For AESO costs, legal
and expert consulting costs that are incurred in the application process (and are therefore
anticipated to be recoverable) are recorded as receivables on the Balance Sheet. When
the cost order is issued by the AUC, the receivable is drawn down for the amount that is
approved and the external regulatory costs are recorded. For any balance that is
disallowed by the AUC, the costs will be recorded in the AESO’s general and
administrative costs at that time. Based on the AUC cost order, the AESO also pays
intervener costs as directed.
The 2010 and 2011 budget amounts are based upon the estimated cost recovery for the
AESO and stakeholders for the AESO’s 2010 General Tariff Application (in 2010) and
other smaller proceedings occurring in each year.
PAGE 45
2010 – 2011 Business Plan and Budget Proposal
Appendix B: Multi-Year Budget Process
Results of Forecast
Related Budget Process
If the forecast is below or in line with
the previously approved budget
amount.
At management’s discretion, any under-budget
amounts will be used to advance future year
business priorities or will be accumulated in the
deferral accounts.
If the forecast is above the
previously approved budgeted
amount and the amount is
determined to be a ‘manageable
variance’.
If the forecast is above the
previously approved budgeted
amount and the amount is in excess
of a ‘manageable variance’.
Management would request approval from the
AESO Board and subsequently issue a
stakeholder communication.
Management will review the new funding
requirements with stakeholders, followed by a
request for approval from the AESO Board.
A manageable variance is a forecast to actual variance that would be:
•
•
less than 10 per cent of budgeted general and administrative expenditures
less than 20 per cent of budgeted capital
PAGE 46
2010 – 2011 Business Plan and Budget Proposal
Appendix C: General and Administrative Cost Detail
Staff Costs
Staff Costs are determined through the analysis and conclusions reached for several key
budget variables or factors:
• Base pay adjustments for existing staff or an overall change in the AESO’s
compensation philosophy - While the compensation philosophy has remained
unchanged in 2010 and 2011, we have incorporated a two per cent base pay
adjustment in each year for general salaries. This adjustment percentage is the
result of current economic indicators (such as the Consumer Price Index and
salaries surveys). At the end of each year during the company’s annual
performance review process, the AESO Board’s Human Resources, Compensation
and Governance Committee reviews all relevant market information to determine
the final corporate base pay adjustment.
• New staff additions - Through a focused approach to re-evaluate and, where
appropriate, realign the efforts of current staff, we will be able to limit the
requirement for new staff positions in 2010 and 2011 to 15 and 10 respectively.
The start dates for new staff additions are staggered throughout the year in the
budget. Appendix D provides the work focus and job descriptions for the new staff
positions.
• Incentive compensation - Our philosophy is to expect the best and for our people
to find new, innovative and efficient ways to fulfil our mandate with a focus on
customer service. When this occurs, our incentive compensation will be adjusted to
reflect this. In preparing this budget, we have confidence in our approach to deliver
on our goals and have reflected this in our incentive compensation. While we have
traditionally budgeted incentive compensation at 50 per cent of an employee’s
eligible pay out amount and paid an amount closer to 60 per cent, we are now
budgeting our incentive compensation at 60 per cent.
• Vacancy rate - Due to normal staff attrition and the time it takes to find and hire
new staff, there are always staff positions that remain vacant for part of the year.
We are anticipating the vacancy rate to be eight per cent in 2010 and 2011, which
is consistent with the 2009 budget and also what we believe our actual annual
vacancy rate will be close to for 2009.
• Benefit costs - In addition to their salary, each employee participates in the
company’s comprehensive benefit plan. For the company, this represents costs
such as health and dental coverage, defined contributions for retirement savings
and government payroll costs. We present these costs as a percentage of salary
costs to determine the ‘benefits load factor’, which is typically budgeted at 23 per
cent of salary costs. To better reflect the true cost of these benefits, the 2010 and
2011 budgets have incorporated a 22 per cent benefits load factor.
PAGE 47
2010 – 2011 Business Plan and Budget Proposal
• Refinement of budget model - In 2009, our job progression compensation
structure was revised from a six pay level structure to 12 pay levels. This change
was incorporated into the budget model to increase the precision of the
calculations (each pay level now has narrower parameters). By analyzing the
impact of the change to the budget model, it was identified that a reduction to the
salaries budget in 2010 would occur, all else remaining unchanged.
Contract Services & Consultants
Contract Services & Consultants ($ million)
2011
Plan
2010
Plan
2009
Budget
2008 2007
Actual Actual
Consulting
Legal
Audit/Reviews
10.3
0.8
0.6
10.8
0.9
0.6
11.3
0.9
0.7
10.6
0.9
0.3
6.6
1.0
0.6
Contract Services & Consultants
11.7
12.4
13.0
11.8
8.2
Differences are due to rounding.
Consulting - We use consultants to supplement the AESO’s staff for three general
purposes. It is not practical for the AESO to retain staff that have all the skill sets that
may be required from time to time. In these circumstances, we utilize consultants to
either complete the work or assist in training AESO staff. Consultants are also used to
address workload peaks to maintain seamless operations and continual progression on
key initiatives. And finally, we have started to implement a strategic plan in IT to
consolidate or co-source support services for our IT infrastructure to facilitate more
coordinated and reliable service for the critical systems. Appendix E provides summary
information on the consulting initiatives.
Legal – Legal counsel is retained to support general business operations by
supplementing in-house legal resource and to provide expertise on legal matters such as
regulatory filings.
Audit/Review – To conduct audits or reviews on AESO or industry stakeholder
processes, systems or reporting, we will use the professional services of others to assist
in these initiatives. Several examples are the financial statement audit, transmission
facility owner compliance on the competitive procurement for transmission facility projects
assigned by the AESO, meter point audits and internal operation audit on key AESO
processes. Appendix F provides additional information on planned audits and reviews.
PAGE 48
2010 – 2011 Business Plan and Budget Proposal
Administration
Administration Costs ($ million)
2011
Plan
2010
Plan
2009
Budget
2008
Actual
2007
Actual
AESO Board Fees
Travel and Training
Insurance
Other Administrative
0.6
2.4
0.6
3.5
0.6
2.3
0.5
3.5
0.7
2.2
0.6
3.0
0.5
2.1
0.5
3.4
0.3
1.6
0.6
2.0
Administration
7.1
7.0
6.5
6.5
4.4
Differences are due to rounding.
AESO Board Member Fees – The AESO is governed by the AESO Board whose
members are appointed by the Alberta Minister of Energy. While the number of Board
members can vary from time to time, there can be no more than nine members with their
compensation based on a retainer fee and additional fees based on their Board
committee involvement and time spent on corporate matters.
Travel and Training - The travel and training category covers costs incurred for general
business travel, staff training and associated travel, corporate meetings and related
meals. In addition, costs related to stakeholder open houses for proposed transmission
projects and enhanced public outreach/education are included in this category.
Insurance - The EUA provides limited statutory protection for the business risks of the
AESO organization, directors, officers and staff. To ensure business risks are properly
insured, we carry insurance for exposures not covered by the EUA, specifically for direct
damages resulting from the AESO’s negligence. The AESO has statutory protection for
indirect damages, which would typically be the most costly damages that would occur for
business interruption and lost revenue. Appendix G provides additional information on
insurance coverages and premiums.
Other Administrative Costs – This includes corporate relations, general office costs,
printing, recruiting, corporate subscriptions/memberships and professional membership
fees. The notable increase in 2010 and 2011 is mainly attributable to publishing an
additional version of Powering Alberta (two publications each year from the single edition
included in the 2009 budget) and stakeholder consultation/meeting costs for open house
events on transmission projects.
PAGE 49
2010 – 2011 Business Plan and Budget Proposal
Facilities
Facilities Costs ($ million)
2011
Plan
2010
Plan
2009
Budget
2008
Actual
2007
Actual
4.7
4.7
3.3
3.1
2.5
Rent
Under a long-term lease ending in 2014, we lease approximately 60,000 square feet of
office space in Calgary Place in downtown Calgary. We also lease approximately 15,000
square feet on an annual basis to accommodate current requirements for IT project staff.
The AESO owns and operates the system coordination centre and has approximately
30,000 square feet of office and building management space.
To accommodate our redundant computer systems to support seamless operating
performance in the event of a disruption to the operations at the system coordination
centre, we also lease additional office space for our back-up facility. Prior to 2010, both
the lease and operating costs for the back-up facility were included in the computer
services and maintenance cost category. Going forward from 2010, these costs will be
included with other facility costs. The 2009 budget included $0.4 million for these costs.
As a result of the lease arrangement at Calgary Place, the 10-month rent-free period we
received in 2004 must be related to the occupancy of the office space over the lease term
and should be recognized over the 10-year lease period. We determined an average
annual rent cost for the 10-year lease and when the actual base rent and operating costs
are less than this average, a ‘build-up’ of the rent-free amortization amount occurs (and
converse is a ‘draw-down’). Starting in 2008 and continuing until the end of the lease
term, the amortization of the rent-free amount is a draw-down as the actual cash rent is
greater than the average annual lease rent costs.
Computer Services and Maintenance
Computer Services and Maintenance ($ million)
2011
Plan
2010
Plan
2009
Budget
2008
Actual
2007
Actual
3.8
3.3
2.6
2.6
2.2
IT Maintenance and Services
As we continue to invest in IT infrastructure to support our business operations, ongoing
costs are incurred to purchase annual software operating licences and maintenance
agreements for these systems with high availability requirements that are supported by
premium class maintenance and support agreements.
In 2009 and prior years, this cost category also included the lease and operating costs for
our back-up facility, which accommodates the redundant computer systems to support
seamless operating performance in the event of a disruption to operations at the system
coordination centre.
PAGE 50
2010 – 2011 Business Plan and Budget Proposal
The notable increase in 2010 and 2011 is mainly attributable to a combination of: i)
operating licences and maintenance agreements that occurred in 2009 but had not been
incorporated into the 2009 budget and ii) new operating licences and maintenance
agreements for changes that will occur in 2010 and 2011. The new EMS and its
peripheral applications are the main system changes in 2010.
Telecommunications
Telecommunications ($ million)
Telecommunications
2011
Plan
2010
Plan
2009
Budget
2008
Actual
2007
Actual
1.4
1.3
1.3
1.3
1.4
The AESO incurs costs for network systems and telecommunications to support general
business operations and, to a much larger extent, to support real-time operations. The
strategy for developing and maintaining the telecommunication infrastructure is based
upon the requirement for high availability, which necessitates redundancies of services
and equipment.
PAGE 51
2010 – 2011 Business Plan and Budget Proposal
Appendix D: 2010 and 2011 Staff Addition Detail
Staff Additions
NEW FUNCTIONS
ALBERTA RELIABILITY STANDARDS
Senior Technical Specialist
Alberta Reliability Standards Compliance Specialist
Senior Compliance Analyst/Auditor
Senior Engineer
Engineer, 500kV Planning
AUDIT SERVICES
# of Additions
2010
2011
√
√
√
√
√
√
Director, Audit Services
√
Staff Auditor
AUTHORITATIVE DOCUMENTS
Legal/Drafting Manager
√
Authoritative Documents Manager
√
√
NEW TECHNOLOGY INTEGRATION
PROVINCIAL ENERGY STRATEGY
Operations Planning Engineers
√√
Senior Engineer, 500kV Planning
√
Director, Wind Integration
FOURTH SYSTEM CONTROLLER DESK
√√
√
System Controllers 4th Desk
√√√
Security Standards Specialist
√
√√√
SECURITY
GRID AND MARKET OPERATIONS
Manager, EMS Design and Change
√
Applications Business Analyst
√
√
√
System Controller Trainer
Manager, EMS Advanced Applications Engineering
√
Engineer, Outage Coordination
√
√
EMS Engineer/Technical Support
√
√
SUCCESSION PLANNING
√
System Controller
Senior Technical Specialist
√
Senior Engineering Analyst
Total
√
22
13
Workforce Adjustments (efficiencies and reassignments)
(7)
(3)
Net New Positions
15
10
PAGE 52
2010 – 2011 Business Plan and Budget Proposal
NEW FUNCTIONS
•
ALBERTA RELIABILITY STANDARDS (5 positions)
Senior Technical Specialist (2010) - This resource will provide business
expertise for ongoing review and implementation of the Alberta Reliability
Standards and assessment of both the AESO’s and market participants’
compliance to the Alberta Reliability Standards. In addition, this business
resource will provide input into the review of authoritative documents.
Alberta Reliability Standards Compliance Specialist (2010) - As part of the
implementation of the Alberta Reliability Standards, the AESO must document
and maintain compliance records. This resource will assume the lead role to
assign ownership responsibilities within the AESO for the Alberta Reliability
Standards and establish the compliance process (determining compliance
criteria, gathering evidence of compliance and developing and implementing
mitigation plans where necessary). This resource will also represent the AESO
on audits of Alberta participants.
Senior Compliance Analyst/Auditor (2010) - This resource will coordinate and
conduct industry audits, certifications and reporting related to the new
compliance monitoring program established for implementation of the Alberta
Reliability Standards. This resource will also be used to conduct audits on
transmission facility owner project costs and reporting rules due to increased
workload in this area.
Senior Engineer (2010) - This resource will provide research, development and
administration support to ensure compliance with the Alberta Reliability
Standards in the AESO’s engineering function. In addition, this resource will
provide corporate expertise on the advancement and introduction of new
technologies into the Alberta grid including Smart Grid type technologies and
direct current transmission.
Engineer, 500kV Planning (2011) - This resource will provide research,
development and administration support to ensure AESO compliance with the
Alberta Reliability Standards in the transmission planning area. This resource will
also facilitate necessary backup and succession planning for this function.
•
AUDIT SERVICES (3 positions)
Director, Audit Services (2010) and Staff Auditor (2010 and 2011) - These
resources are required to establish an audit function within the AESO to perform
various operational audits in keeping with the mandate of the Audit Committee.
Operational audits will include compliance with the new Alberta Reliability
Standards, cyclical testing of key AESO processes and systems and internal
controls over financial reporting. Consultants currently perform this work.
PAGE 53
2010 – 2011 Business Plan and Budget Proposal
•
AUTHORITATIVE DOCUMENTS (2 positions)
Legal/Drafting Manager (2010) - As part of the AESO’s reforms regarding
management, governance and quality control over its authoritative documents
(rules, tariffs, and standards), this resource will be responsible for drafting
documents. Consultants currently perform this work.
Authoritative Documents Manager (2010) - As part of the AESO’s reforms
regarding management, governance and quality control over its authoritative
documents (rules, tariffs, standards), this resource will be responsible for overall
management of the new authoritative documents process to ensure full
integration across the organization. This position will also be responsible for
management of the drafting and other legal and administrative resources.
Consultants currently perform this work.
NEW TECHNOLOGY INTEGRATION
•
PROVINCIAL ENERGY STRATEGY (6 positions)
Operations Planning Engineers (x2) (2010) and Operations Planning
Engineers (x2) (2011) - In response to new facilities planned in Alberta related
to the government’s Provincial Energy Strategy for critical infrastructure, these
additional resources will focus on the following areas to support the reliable
transition to real-time operations:
•
Conduct operational planning studies to refine operating transfer limits.
•
Modify reliability-based OPPs.
•
Create outage schedules to integrate new facilities.
•
Additional real-time requirements regarding operation of facilities such as
HVDC, wind power management and interties.
As part of the Alberta Reliability Standards implementation, these resources will
also ensure AESO compliance to the reliability standards and provide operational
expertise to internal compliance monitoring resources during compliance
monitoring of market participants.
Senior Engineer, 500kV Planning (2010) - To assist in the planning of large
interconnection projects and merchant interties, this resource will provide senior
level technical support to customers and other AESO staff.
Director, Wind Integration (2010) - With the efforts to integrate wind power onto
the electric system, this resource will be responsible for developing the strategic
direction for the AESO’s wind integration efforts as well as being responsible for
leading the development and ongoing refinement of related ISO Rules, operating
procedures, standards and operating tools.
PAGE 54
2010 – 2011 Business Plan and Budget Proposal
•
FOURTH SYSTEM CONTROLLER DESK (6 new positions)
System Controllers 4th Desk (x3 - 2010) and (x3 - 2011) - As the Alberta
electric system changes in response to various market and system requirements,
additional responsibilities and complexities will occur in the real-time
management of the system. In response to this, a fourth desk for the system
controller function will be established in 2010. This additional real-time desk is in
response to changes such as the following:
•
•
Monitoring and direction for the integration of increased wind power
volumes.
•
Understanding and integrating the impact of new technologies on the
system (such as HDVC, phase-shifting transformers, series capacitors,
etc.).
•
Managing the complexity of the ISO Rules due to the increasingly
complicated market structure.
•
Integrating the Montana-Alberta intertie and developing the AESO’s
OASIS and dispatchable interties capabilities.
•
Utilizing the real time study capabilities in the new EMS.
SECURITY (1 new position)
Security Standards Specialist (2010) - This resource will provide assistance
with the timely development of policies, guidelines and practices for IT and
information security for the implementation of NERC, Alberta (CIP) and ISO
standards. Additional focus and resources will also be made available to support
safety and facility initiatives, compliance to Alberta Reliability Standards for
internal and industry clients and implementation of procedures required by
Alberta Reliability Standards.
GRID AND MARKET OPERATIONS (9 new positions)
Manager, EMS Design and Change (2010) - This resource will manage the
direction, vision and ongoing application changes to ensure the reliability and
accuracy of the grid and market systems. This formal change management role
has been identified for an individual that possesses both real-time system and
market operating expertise and grid and market functionality/system knowledge.
This role will assist in gathering the necessary business requirements for system
modifications and enhancements, and provide oversight for the business
analysts.
Applications Business Analysts (2010 and 2011) - To support the
development and maintenance of various applications that support the system
controller function, a resource is required to define the business requirements for
new applications, identify and document interdependencies between applications
and provide support to develop business rules for the more complex operation
processes.
PAGE 55
2010 – 2011 Business Plan and Budget Proposal
System Controller Trainer (2011) - To support the system controller training
program, including system controller certification requirements, a dedicated
training resource is required to plan, design, develop and deliver the training
program. This resource will be an individual who has professional experience in
this field. Once this position is filled, the various operations staff currently in this
role will be able to refocus on their primary responsibilities.
Manager, EMS Advanced Applications Engineering (2010) - This resource
will manage the engineering and dataset function for the EMS to ensure system
models and applications are current, accurate and well maintained. This position
will ensure the new AREVA application is well understood within the company to
enable maximum utilization of the available functionality.
Engineer, Outage Coordination (2010 and 2011) - With implementation of the
new EMS application, additional resources are required to manage and engineer
the AREVA EMS model and associated applications for the analysis of system
conditions to meet reliability criteria. In addition, these resources will address the
increased workload in the outage coordination area as a result of the significant
increase in the number of customer interconnections and system improvements
associated with the government’s Provincial Energy Strategy for critical
infrastructure.
EMS Engineer/Technical Support (2010 and 2011) - The new EMS application
is a more complex technology than the previous application. This role requires
additional resources for ongoing support and to ensure the appropriate level of
backup and succession planning is in place for this critical system.
SUCCESSION PLANNING (3 new positions)
System Controller (2010) - Through standard operations, system controllers are
required to provide coverage for the 24 by 7 system operations in addition to
meeting extensive continuing education requirements (four to six weeks on an
annual basis). Further to this, system controller resources are an essential
resource for developing and testing EMS applications. This additional system
controller resource will alleviate the over-time hours system controllers currently
incur.
Senior Technical Specialist (2011) - This resource will support the
development of the AESO’s OPPs to implement ISO Rule changes, reliability
operating limits and system changes due to the addition of generator, load and
transmission connections as well as changes to market rules.
Senior Engineering Analyst (2011) - This resource will support project
management activities recognizing the increased number of large-scale
transmission projects, as identified in the AESO’s Long-term Transmission
System Plan, that need to be advanced to meet system and customer
interconnection requirements. The analyst will assist with project tracking and
reporting and resource and financial forecasting, as well as enhancing overall
efforts in coordinating activities with transmission facility owners.
PAGE 56
2010 – 2011 Business Plan and Budget Proposal
Appendix E: Consulting Cost Detail
2010
2011
Technical Standards/Studies – execution of studies and/or assistance with
standards development for Alberta Reliability Standards, critical transmission
infrastructure development, interties, wind integration, new technologies, load
forecasting and system restoration
1.9
1.4
Interconnection Projects – complete studies and interconnection proposals
for wind generation, industrial projects, etc.
0.9
0.6
Corporate Strategy – develop and implement a strategy for organization
changes including development of an operating model to deliver business
results that are aligned to the strategic plan; development and implementation
of human resource strategies and government relations
0.9
0.9
Provincial Energy Strategy Communications – support for media and
communications for transmission initiatives
0.4
0.4
Energy Trading System (ETS) Project Initiation – research and preparation
of request for information and request for proposal documents and vendor
analysis for replacement of the ETS and related market systems
0.3
0.4
Communications – analysis of the effectiveness of Powering Alberta;
communications and topic research; communication tools for transmission
open houses
0.3
0.3
Market Development and Design – technical support on market initiatives
including expertise from other jurisdictions
0.2
0.3
10-Year Plan Development – complete technical studies and document
writing/communication
0.2
0.2
System Coordination Centre Expansion Drawings and Specifications –
preparation of the architectural drawings to initiate construction tendering for
development of the complete second floor at the SCC to accommodate
additional resources
0.2
-
Regional Advisors – retain six provincial representatives to provide feedback
and suggestions on electricity industry matters and share their expertise and
local knowledge for inclusion in AESO outreach programs, consultation
processes and communication initiatives
0.1
0.1
Record/Document Management Project – develop and implement a
strategy on record and document retention and filing
0.1
0.1
Miscellaneous Projects Less Than $0.1 Million
1.1
1.2
Total Technical Resources
6.6
5.9
Technical Resources ($ millions)
PAGE 57
2010 – 2011 Business Plan and Budget Proposal
Workload Peaks – Supplement Staff Resources ($ millions)
2010
2011
Transition of Authoritative Documents – project management and
supplementary resources to implement a standardized process for
authoritative documents (creation of market rules, OPPs, standards and
business practices)
0.9
0.7
Miscellaneous Projects Less Than $0.1 Million
1.1
1.3
Total Workload Peaks
2.0
2.0
2010
2011
Co-sourcing arrangements are in place to provide resources with specialized
skill sets to support and maintain specific IT systems in a cost-effective
manner. This co-source strategy is being used on the following: EMS, EMS
historian database (PI), enterprise service bus (TIBCO), wide area network,
data storage technologies, help desk support, Windows and database
administration and various corporate systems (billing, HR, accounting).
2.2
2.5
Total Co-source IT Support
2.2
2.5
10.8
10.4
Co-source IT Support ($ millions)
Total Consulting
PAGE 58
2010 – 2011 Business Plan and Budget Proposal
Appendix F: Audit/Review Cost Detail
Financial statement audit - Standard business practice, reporting requirement to the
Alberta Minister of Energy under the EUA and to meet bank requirements. (2010 and
2011)
Controls audit on specific AESO business processes - Review internal controls
related to the AESO’s financial and operating processes to ensure internal controls are
adequate and operating effectively. (2010 and 2011)
Auditor’s Report on Controls at a Service Organization (CICA Handbook Section
5970) - Assessment of the internal controls of service organizations for specific
requirements for managing customer data with a focus on compliance, security and
access. (2010)
Direct assign rules audit - AESO Rule 9.1.5 deals with the requirement for transmission
facility owners to competitively procure materials and construction labour for transmission
facility projects assigned by the AESO. The AESO has a requirement to confirm
compliance by the transmission facility owner to this Rule. (2010 and 2011)
Meter point audits - As stipulated by the Measurement System Standard, up to two
metering point audits will be conducted each year. (2010 and 2011)
IT architecture audit/review - Perform an audit of the AESO’s enterprise architecture
processes and artifacts. (2011)
IT security/penetration audit - An independent review of IT system security will be
performed to determine the ability of third parties to penetrate AESO IT systems. (2010
and 2011)
PAGE 59
2010 – 2011 Business Plan and Budget Proposal
Appendix G: Insurance Coverage Detail
Insurance Summary ($ thousands)
Insured
Values
2008/2009
Renewal1
2009/2010
Renewal1
2010/2011
Renewal1
Commercial General Liability &
Professional Liability
$50 million
367.0
340.0
357.0
Crime
$20 million
22.0
22.0
23.1
Directors & Officers
$25 million
52.9
52.9
55.5
$50 million
90.9
98.5
103.4
532.8
513.4
539.0
Policy
Office Contents &
General Liability
Total Premium
1
The annual renewal period is from July 1 to June 30.
PAGE 60
2010 – 2011 Business Plan and Budget Proposal
Appendix H: Allocation of Costs
Management reviews allocation percentages twice a year. They are first reviewed when
the annual budget is prepared and again at year-end when the allocations are finalized
based upon actual activities and costs. This methodology has not changed from that
used in prior years, although the allocation percentages change to reflect the
business/operational activities each year.
Transmission
(%)
AESO Department
Energy
Market (%)
Load
Settlement (%)
0
0
0
0
0
0
0
25
33
33
50
30
100
0
0
0
0
0
0
0
0
0
0
0
50
0
DIRECT OPERATING
500 kV System Planning
Regional Planning
Engineering
Customer Interconnections
Technical Services
Commercial Services
Regulatory
Operations Planning
Operations Integration
Grid and Market Operations
Resource Adequacy
Compliance
Market Operations & Services
100
100
100
100
100
100
100
75
67
67
50
20
0
SHARED SERVICES
1
Corporate Services
Information Technology2
Office Lease
Based on Direct Operating Group Costs (%)
65
30
5
Based on AESO Staff Count
CAPITAL
Assigned on a Project Basis
1
2
Includes departments such as: Accounting, Settlement & Risk, Human Resources, Corporate
Communications, etc.
Based on 2008 actual allocations.
PAGE 61
2010 – 2011 Business Plan and Budget Proposal
Appendix I: Capital Projects
The following tables provide information on the AESO’s current capital plan for 2010 and
2011. Actual projects to be completed in 2010 and 2011 will vary, and include the
addition of projects yet to be determined, deferral of projects in this plan or elimination of
projects deemed no longer necessary. Where applicable, references have been provided
to the related strategic objective.
Key Capital Initiatives ($ millions)
ƒ
These are the most critical capital projects over the planning period that the AESO
believes must be completed within the identified timeframe.
Key Capital
Initiatives
(strategic
objective
reference)
Description
20102011
Capital
Plan
Totals
2011
Capital
Plan
2010
Capital
Plan
2009
Projected
Capital
Spending
EMS (strategic
objective 5)
The next phase of the EMS implementation,
which includes improved situational awareness,
look-ahead functionality, load-shed services
and a system controller training environment.
7.0
3.2
3.8
9.7
Wind integration
(strategic
objective 5)
Develop and deploy tools that assist with
implementation of the market and operational
framework for wind.
6.2
3.0
3.2
1.6
Fair Efficient
Openly
Competitive
(FEOC) regulation
(strategic
objective 1)
Develop and deploy tools to assist with
implementation of protocols to ensure
participants act in accordance with FEOC
mandate - section 6.
6.0
3.0
3.0
-
Congestion
management
(strategic
objective 1)
Develop and deploy automation tools that
facilitate management of transmission
constraints in specific AIES operating areas.
2.3
0.3
2.0
-
Intertie framework
(strategic
objective 1)
Develop and implement tools that support
increased transfer capacity with neighbouring
jurisdictions. This includes but is not limited to
support for import/export transmission tariffs
and automated scheduling solutions.
3.5
1.9
1.6
-
Dispatch tool upgrade/enhance
ment (strategic
objective 5)
Dispatch tool stabilization and enhancements
supporting energy market changes. Ensure
dispatch down service and dispatch variance
notification.
1.7
1.0
0.7
4.4
PAGE 62
2010 – 2011 Business Plan and Budget Proposal
Key Capital
Initiatives
(strategic
objective
reference)
Description
20102011
Capital
Plan
Totals
2011
Capital
Plan
2010
Capital
Plan
2009
Projected
Capital
Spending
Transmission and
market modelling
(strategic
objective 2)
Implement an Alberta industry standard
planning model of the AIES.
1.2
0.5
0.7
-
Information
management
platform (strategic
objective 5)
Develop and implement a data analysis and
reporting platform supporting stakeholder
(authorized) access and reporting
requirements.
2.4
1.8
0.6
0.8
2010 General
Tariff Application
(GTA) 2010
Develop and implement changes to the
transmission billing system that support the
2010 GTA rate and calculation structure.
0.4
-
0.4
-
Alberta Reliability
Standards
Implement compliance management and
reporting tools that support business practices
and processes and ensure internal and external
adherence to Alberta Reliability Standards.
0.6
0.6
-
-
SCC expansion
(strategic
objective 4)
Implement SCC expansions to accommodate
an increase in staffing requirements.
3.3
3.3
-
-
34.6
18.6
16.0
16.5
Key Capital
Initiatives
PAGE 63
2010 – 2011 Business Plan and Budget Proposal
Other Capital Initiatives ($ millions)
ƒ
These are necessary projects that have more flexibility in planning or delivery so
timing is not as critical or they are lower priority than the key capital initiatives.
Other Capital Initiatives
Description
2010-2011
Capital Plan
Totals
Load settlement program
Implement a settlement verification model and integrate with other AESO
systems.
1.9
Interconnection project
support and reporting
(strategic objective 3)
Identify and implement a project management and reporting tool to manage
the queue of system interconnection projects the AESO oversees.
1.8
IT test & production
environment (strategic
objective 5)
Procure and implement a testing environment that facilitates application
cloning (set up and removal) and simulates the AESO’s production
environments (pre-production testing).
1.2
Identify access
management (strategic
objective 5)
Identify and implement a common user (internal/external) identification
authorization process for all information technology (IT) systems/services.
1.2
IT ESB integrations
(strategic objective 5)
Replace fragile point-to-point integrations between legacy systems with
publish and subscribe data links using an enterprise service bus.
1.1
Enterprise content
management (strategic
objective 1)
Retire and replace the existing enterprise content management and
workflow product.
1.0
AESO website (strategic
objective 6)
Define and identify areas for AESO website improvement. Based on
findings, modify internal and external websites to enhance stakeholder
navigation and functionality.
0.7
IT security program
Implement security improvements to IT systems to reduce security risks to
critical IT services and infrastructure.
0.7
SCC voice and order-wire
enhancements
Install new hardware and software to support new operator order-wire
functionality at the SCC.
0.5
Price cap and floor
(strategic objective 1)
Modify AESO marketing systems that remove existing price cap/floor limits.
0.4
Loss factor determination
Modify system HVDC logic into the forecasting algorithms.
0.3
Operating reserve market
redesign (strategic
objective 1)
Design, develop and implement AESO systems that allow for ancillary
services market changes to accommodate harmonization and convergence
with the energy market.
0.3
Miscellaneous
Other projects not exceeding $0.25 million.
1.9
Other Capital Initiatives
13.0
PAGE 64
2010 – 2011 Business Plan and Budget Proposal
Life Cycle Initiatives ($ millions)
ƒ
These are typically replacement of end-of-life hardware and recurring software
upgrades.
Life Cycle
Initiatives
Description
2010-2011
Capital Plan
Totals
Oracle database
upgrade
Upgrade the AESO’s database environments (development, test and production
to a current version) as mainstream support for the installed version ends April
2010.
3.1
Server upgrades
Retire and replace corporate server hardware/software based on pre-determined
corporate retirement plan.
2.0
Network upgrades
Upgrade AESO voice and data networks to ensure vendor support, meet
reliability requirements and address increased capacity needs. This includes data
switches, telephone system, remote access capabilities, and redundancy of SCC
critical network services.
1.3
Storage upgrade
Implement a new storage infrastructure designed to address existing end-of-life
cycle considerations and support the high-performance storage requirements of
online stakeholder systems (e.g., Energy Trading System).
1.2
Information archiving
upgrade
Upgrade backup and restore platform, as the AESO’s current archiving platform
cannot keep pace with the explosive data growth.
1.0
Personal system
refresh
Ongoing investment in desktop systems and mobile devices to replace aging
software and equipment and accommodate resource growth.
1.0
Desktop Microsoft
upgrade
Upgrade the AESO’s computing workstations to an appropriate version of
Windows and Office as mainstream support (i.e., XP and Office 2003) ends April
2009.
0.7
Application server
upgrade
Migrate AESO applications still running dated (end-of-life) application server
technology to the new application server environment.
0.5
Life Cycle
Initiatives
10.8
PAGE 65
2010 – 2011 Business Plan and Budget Proposal
Appendix J: Transmission Operating Cost Definitions
Transmission Line Losses
The annual volume forecast for transmission line losses is based on the following:
•
The latest forecast of Alberta Internal Load (includes ‘behind-the-fence’ loads
and new Demand Transmission Service (DTS) contracts)
•
The grid facility profiles of transmission and generation (existing, new,
decommissioned)
•
Transmission must-run (TMR) forecasts based on the latest Operational Policies
and Procedures (OPPs) and updated generation stacking order based on the
latest 12 months of actual dispatch behaviour (generators, import and export)
•
Current export Availability Transfer Capability (ATC) limits
•
A loss forecast based on the Alberta Interconnected Electric System (AIES)
hourly net to grid levels from the settlement system
The annual forecast for transmission line losses is the accumulation of the hourly
forecasted loss volumes priced at the most current hourly pool price forecasted for that
period. The AESO has used the June 8, 2009 EDC Associates Ltd. commodity price
forecast (ESP Volume 9 Issue 23).
Ancillary Services
Ancillary services are procured by the AESO to ensure ongoing reliability of the
transmission system through contracts, which include exchange-traded or over-thecounter contracts, generation capacity and load reduction capabilities, as well as
contracts that are entered by way of competitive processes. The AESO has entered into
various contracts for ancillary services that include operating reserves, transmission
must-run (TMR), load shed and system restoration.
Operating Reserves
Operating reserves are procured in two ways: through an online exchange and through
over-the-counter contracts. All providers of operating reserves traded on the exchange
are paid the market clearing price whereas all providers who sell volumes over-thecounter are paid their offer price. In exchange for this payment, the AESO obtains the
right to utilize the provider’s energy and/or capacity as reserves. The majority of
operating reserve offer prices are indexed to the pool price.
Operating reserves are comprised of three types of active reserves, with the minimum
levels of operating reserves based on standards established by the Western Electricity
Coordinating Council (WECC):
•
Regulating reserves – The provision of generation and load response capability,
including capacity, energy and maneuverability, which respond to the AESO’s
automatic generation control (AGC) system. In Alberta, regulating reserves track
variations in the load that cannot be met with energy dispatches. The volumes of
PAGE 66
2010 – 2011 Business Plan and Budget Proposal
regulating reserve are specified as a range in MW over which a level of control is
required by the AGC system.
•
Spinning reserves – Unloaded generation that is synchronized to the system,
automatically responsive to frequency deviation and ready to serve additional
demand following an AESO system controller directive. A customer offering
spinning reserves must be able to ramp up their generator within 10 minutes in
response to a system controller directive due to a system contingency.
Spinning and supplemental reserves are required in order to restore frequency
following the loss of generation in Alberta or in the WECC region. Alberta must
comply with WECC policies for maintaining specific volumes of spinning and
supplemental reserves in order to maintain reliability.
•
Supplemental reserves – Similar to spinning reserves except supplemental
reserves are not required to respond to frequency deviations; therefore, they
include unloaded generation, off-line generation or system load that is ready to
serve additional demand (generator), or reduce demand (load), within 10 minutes
of a directive from the system controller.
Active Operating Reserves
Active operating reserves are the operating reserves that are forecast by the AESO as
necessary to operate the AIES securely and meet the AESO’s reliability obligations to the
WECC.
Standby Reserves
Standby Reserves provide additional reserves for use when the resources available
under the active portfolio are insufficient. Payments for standby reserves include a
premium for the option to activate the standby reserves and a price that is paid if the
reserves are activated.
Transmission Must-Run (TMR)
TMR is generation required to be on-line and operating to ensure reliability in specific
areas of the AIES with insufficient transmission capacity. This service is typically
procured through long-term commercial contracts.
The costs of TMR are dependent upon numerous variables including, but not limited to,
market heat rates and gas prices. The market heat rate is the pool price divided by the
gas price. As the market heat rate increases, representing a divergence of pool price and
gas price, the cost of TMR contracts will decrease, though not proportionately.
Invitation to Bid on Credits (IBOC)
The IBOC program is a long-term contractual arrangement that provides a financial credit
to a specific generator in the Calgary area based on the volume of megawatt-hours
generated each month.
Location Based Credit Standing Offer (LBC SO)
The LBC SO program is a long-term contractual arrangement that provides increased
system security, whereby the AESO retains dispatch rights to location-specific generation
PAGE 67
2010 – 2011 Business Plan and Budget Proposal
in return for location-based credits. The credits are made up of fixed and variable
payments.
Other Ancillary Services
Black Start
Black start service is provided by suppliers that have the ability to self-start, energize
transmission lines and provide start up power to other generators. This service is integral
to the AESO’s system restoration plan and enables timely restoration of electrical supply
on the AIES in the unlikely event of a blackout. This service is procured via long-term
contracts.
Load Shed Service
Load shed service is configured to automatically trip a specified amount of load if the
system frequency drops below 59.5 Hz following a system disturbance. The service
mitigates the need to trip firm load following an under-frequency event and works
together with ILRAS to increase the capacity of the Alberta-BC interconnection. The
AESO conducted a competitive procurement process and now procures these services
by way of long-term contracts with service providers.
Import Load Remedial Action Scheme (ILRAS)
ILRAS supports the import capability of the Alberta–BC interconnection. If the Alberta-BC
interconnection trips concurrent with high levels of import, the system will become
generation deficient, system frequency will decline and the AESO will be required to shed
load quickly in Alberta to arrest the frequency decline and maintain system reliability. The
AESO contracts for loads to automatically trip in these situations to limit the frequency
decline and attempt to prevent shedding of additional system load.
PAGE 68
2010 and 2011 Business Plan and Budget Proposal
Section 5 – Stakeholder Comments
and Our Responses
The attached stakeholder comments and the AESO’s responses were compiled through
the budget review process (BRP) that has occurred since April 2009.
Throughout this process we’ve held several meetings with stakeholders to discuss our
business plan and budget materials and provided stakeholders with the opportunity to
provide comments on this information. The following table lists the stakeholders that
participated in the current-year BRP.
Stakeholder Participants in the Budget
Review Process
Alberta Direct Connects
ATCO Power
Capital Power Corporation
City of Calgary
TransCanada Energy
Attendance
2009 Stakeholder Meetings
April
June
August August
29
10
19
26
√
Comments
Attendance
√
√
√
√
√
√
√
Comments
√
√
Attendance
Comments
Attendance
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
Comments
Attendance
Comments
Cities of Red Deer and
Lethbridge
Attendance
Industrial Power Consumers
Association of Alberta (IPCAA)
Attendance
Office of the Utilities Consumer
Advocate (UCA)
Attendance
√
√
Comments
Comments
Comments
Page 1
2010 and 2011 Business Plan and Budget Proposal
Following a stakeholder meeting or the posting of BRP information on our website, we
asked stakeholders for their questions or comments. This occurred on four occasions and
we’ve provided responses to stakeholders on these questions or comments. For the
AESO Board’s review purposes, we’ve compiled these questions or comments and our
responses in the following material (our responses are highlighted in blue text). We’ve
organized the material in two ways. First by main discussion or approval category (e.g.
consultation process, strategic plan and business initiatives, general and administration,
etc.) and then by the stakeholder who submitted the question or comment.
The following table identifies the key BRP dates in 2009 and the associated deliverables.
Key BRP
Dates in 2009
Purpose
April 29
Overview of AESO Board approval process, BRP (i.e. stakeholder
consultation process), terms of reference, proposed process
schedule and revised strategic plan
June 10
Overview of our draft 2010 and 2011 business initiatives
August 19
Technical meeting to review the forecast 2010 Ancillary Services and
Transmission Line Loss Costs
August 26
Technical meeting to review the 2010 and 2011 Own Costs Budget
(General & Administrative, Interest, Amortization, Capital and Other
Industry Costs)
September 13
Distribution of first draft of our 2010 and 2011 business plan and
budget proposal
September 29
Distribution of second draft of our 2010 and 2011 business plan and
budget proposal
October 13-15
Stakeholder and AESO Board meetings (if required)
Page 2
2010 and 2011 Business Plan and Budget Proposal
Consultation Process
OFFICE OF THE UTILITIES CONSUMER ADVOCATE (UCA)
April 29, 2009
Stakeholder Comment
AESO Response
Technical Meetings to Review Forecasted Costs The Agreed. The AESO will work with
UCA submits that one meeting may not be sufficient to
stakeholders to revise the BRP schedule to
adequately address all the material presented. The
accommodate multiple meetings on the
UCA suggests that a series of meetings be scheduled. If costs forecasts.
some later meetings are not required, they can be
cancelled.
Stakeholder Comment
Comments on proposed BRP timeline The proposed
August 11 meeting conflicts with planned vacations.
The UCA requests that the meeting be rescheduled to
August 19. Alternatively, the UCA requests that the
deadline for comments be delayed by one week and
requests the AESO allow a separate meeting with the
UCA on August 19.
AESO Response
Noted. The AESO revise and review with
stakeholders a revised timeline to
accommodate the request.
Stakeholder Comment
Stakeholder comments on proposed terms of
reference The UCA supports the draft terms of
reference.
AESO Response
Noted. There are no changes in the terms
of reference from those established in the
prior year.
Stakeholder Comment
Do you support the AESO proposing a two (2) year
general and administrative budget? Yes. The multiyear process seemed to work well in the past, and the
UCA expects that it should achieve efficiencies again
this time.
AESO Response
Noted
June 10, 2009
Stakeholder Comment
AESO Response
Comments on proposed BRP timeline The UCA is
Noted.
pleased that the August meeting has been separated in
to two portions. This will allow a better discussion of the
issues related to each section. The proposed timelines
are acceptable to the UCA at this time. As well, see
additional comments related to a second review of
strategic initiatives in light of budgets.
August 19, 2009
August 26, 2009
Page 1
2010 and 2011 Business Plan and Budget Proposal
TRANSCANADA
April 29, 2009
Stakeholder Comment
AESO Response
Noted. This is a step in the proposed Budget
Comments on proposed BRP timeline
TransCanada would see value in the AESO
Review Process provided to stakeholders and
presenting the Draft Board Approval Document to
has been a historical practice.
stakeholders in early September, after it has been
posted and prior to comments being submitted on it.
This would give stakeholders a chance to ask
questions on it and improve the quality of
submissions.
Stakeholder comments on proposed terms of
reference These appear to be consistent with those
established in 2007.
Noted. There are no changes in the terms of
reference from those established in the prior
year.
Do you support the AESO proposing a two (2)
year general and administrative budget? Yes.
The two year budget and one year forecasts seem
to have worked well over the past two years.
Similar to last year, TransCanada suggests the
AESO update stakeholders on the second year
budget before it is provided to the AESO Board.
Noted
June 10, 2009
August 19, 2009
August 26, 2009
Page 2
2010 and 2011 Business Plan and Budget Proposal
Strategic Plan & Business Initiatives
ALBERTA DIRECT CONNECT CONSUMERS ASSOCIATION (ADC):
April 29, 2009
Stakeholder Comment
AESO Response
AESO Develop Draft Business Priorities The draft
Yes. As in prior years we are open to
business priorities are a good starting point. As the
comments from stakeholders on the
Budget Review process unfolds, the UCA expects that
AESO’s business priorities and the AESO
the priorities may have to be modified based on
will consider amending the proposed
consultation and input from customers. As such, the
business priorities based on feedback
UCA trusts that the AESO will be open to revisiting the
received from stakeholders.
priorities in light of feedback from the review process.
June 10, 2009
Stakeholder Comment
AESO Response
Noted. The AESO has identified Demand
Strategic Objective #1: Market Road Map and
Interties The ADC wishes to emphasize the importance Response as one of its Draft Initiatives.
of advancing the demand response initiative in a timely
Continued ADC support will facilitate
manner. Specifically program advancement in areas
associated 2010/11 planning and BRP
where load can compete for the same A/S products as
budgeting activities.
generators such as spinning reserves, long lead time
generation, congestion management, “uplift “ for price
responsive loads, and Under-frequency support
services.
Stakeholder Comment
Strategic Objective #2: Provincial Energy Strategy
(PES) and the Transmission Development Policy
The ADC is concerned that the current processes in
place will not adequately control the costs for the CTI
projects. These projects should not necessarily be
direct assigned, but rather advanced in a competitive
fashion with clear budget expectations and cost
accountability.
AESO Response
Noted: The AESO’s normal practice,
consistent with the legislative framework
and the Transmission Development Policy,
is to direct assign transmission facilities to
the incumbent TFOs based on franchise
area (service territory). It should be noted
that government policy is outside the scope
of the BRP process.
The ADC requests that the AESO provide a clear
expectation of the annual cost implications of these
projects to a typical industrial load of various sizes (i.e. 5
MW, 10 MW, 50 MW, 100 MW), the timing that the costs
would enter rate base as well as a projection thereafter
of costs to 2017 as the projects are completed.
Noted: Initial project cost estimates are
available in the Long-term Transmission
System Plan - 2009 published on the AESO
website. Our plan is to respond to the
additional cost estimate requests and report
back to stakeholders at a later date.
The ADC also requests that the AESO report on the
suitability of the technology of the HVDC lines between
Noted: Use of HVDC is mandated under the
Provincial Energy Policy where possible
Page 1
2010 and 2011 Business Plan and Budget Proposal
Edmonton and Calgary. It is our understanding, that the
line loss savings by using DC technology may be
forgone by the incremental losses in the converter
stations if the distance of lines isn’t long enough.
Please report the conversion losses in the AB – SK
connection.
Stakeholder Comment
Strategic Objective #5: Technology Knowledge
Leadership See comments in Strategic Objective #2
regarding HVDC technology.
and is planned for the Edmonton Calgary
reinforcements.
AESO Response
Noted. See AESO response to Strategic
Objective #2 above.
Stakeholder Comment
AESO Response
Noted. The AESO is open to evaluate any
Strategic Objective #6: Enhance Stakeholder
recommendation that improves stakeholder
Relationships The ADC expresses some concern over
efficiency/effectiveness in the consultative
the efficiency of the stakeholder process. The load
processes.
groups are sparsely represented and there are a
number of consultation activities underway that require
load participation. Suggest the AESO upgrade the
stakeholder calendar such that all activities and relevant
materials are readily accessible. It would be helpful to
also include any key dates for AUC proceedings such as
rates, facilities applications and rule changes. The cost
to participate for Edmonton based stakeholders such as
the ADC is excessive as the majority of activity occurs in
Calgary. The conference call facilities at the AESO
main boardroom make participation difficult. Consider
any merit in a videoconference solution.
August 19, 2009
August 26, 2009
OFFICE OF THE UTILITIES CONSUMER ADVOCATE (UCA)
April 29, 2009
Stakeholder Comment
AESO Response
AESO Develop Draft Business Priorities The draft
Yes. As in prior years we are open to
business priorities are a good starting point. As the
comments from stakeholders on the
Budget Review process unfolds, the UCA expects that
AESO’s business priorities and the AESO
the priorities may have to be modified based on
will consider amending the proposed
consultation and input from customers. As such, the
business priorities based on feedback
UCA trusts that the AESO will be open to revisiting the
received from stakeholders.
priorities in light of feedback from the review process.
Stakeholder Comment
Comments on the AESO’s strategic objectives: See
Stakeholder Comment Above
AESO Response
See AESO Response Above
June 10, 2009
Stakeholder Comment
AESO Response
Noted. The AESO would like to highlight it
Strategic Objective #1: Market Road Map and
Interties The UCA does not have comments on each
performs a minimum of two cost/benefit
strategic initiative individually. The main concern is that reviews on every Information Technology
there is limited Cost/Benefit analysis at this time. Many
capital initiative. The first is during the BRP
of the initiatives can only be accurately assessed in light budget development process, which
of the cost of implementation. As such, the UCA
provides high-level cost benefit information
Page 2
2010 and 2011 Business Plan and Budget Proposal
submits that the process should include a second look
at the initiatives when the costs and budgets have been
presented and analysed. Support for some initiatives
will be contingent on the cost of implementation
compared to the benefits.
(This comment is also posted in the “Other Comments”
section of this report.)
Stakeholder Comment
Strategic Objective #2: Provincial Energy Strategy
(PES) and the Transmission Development Policy
See comment under Strategic Objective #1.
to stakeholders. The second occurs prior to
project approval/initiation, when the cost of
options is available and compared against
identified benefits.
Stakeholder Comment
Strategic Objective #3: Customer Services
Improvements See comment under Strategic Objective
#1.
AESO Response
Noted. See AESO response to Strategic
Objective #1
Stakeholder Comment
Strategic Objective #4: Attract and Retain Quality
Staff See comment under Strategic Objective #1.
AESO Response
Noted. See AESO response to Strategic
Objective #1
Stakeholder Comment
Strategic Objective #5: Technology Knowledge
Leadership See comment under Strategic Objective #1.
AESO Response
Noted. See AESO response to Strategic
Objective #1
AESO Response
Noted. See AESO response to Strategic
Objective #1
August 19, 2009
August 26, 2009
TRANSCANADA
April 29, 2009
Stakeholder Comment
AESO Response
In prior years the AESO’s strategic objectives
Comments on the AESO’s strategic objectives:
The BRP Strategic Objectives have been different in were review by the AESO and minor
each of the past three years. TransCanada
modifications were undertaken. During 2008,
understands that over that time period there have
the AESO undertook a significant strategic
been changes within the AESO, in the marketplace
planning process to develop a new strategic
and in government policy. However, TransCanada
plan, including new strategic objectives. As a
considers Strategic Objectives to be longer range
result, the new strategic objectives will not link
and not as dynamic as Business Priorities, which
to those from the prior year and should be
may fluctuate yearly. Please explain why the
review on a standalone basis. The new
Strategic Objectives have changed and also show
strategic objectives were reviewed with the
the progression or linkage between those in place
senior executives of various stakeholders for
for the past two years and 2010.
feedback.
In the future, the AESO will be better able to
provide stakeholders with feedback on the
AESO’s progress as it relates to the new
strategic objectives. At the June 10 stakeholder
meeting the AESO will further expand upon the
AESO’s strategic planning process.
August 19, 2009
August 26, 2009
Page 3
2010 and 2011 Business Plan and Budget Proposal
General & Administrative
CITIES OF RED DEER AND LETHBRIDGE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
The information on page 15 is consistent
AESO’s draft General & Administrative Budget
All of the comments presented in this form reference the with the final approved budget for 2009.
AESO’s Draft 2010-2011 Business Plan and Budget
Please refer to the following link on the
document dated September 11, 2009.
AESO’s website that provides the 2009
budget detail for comparison. The document
1. Please reconcile the 2009 Budget figures as
is located under About AESO > Our
presented on Page 15 with the final approved 2009
Business > Business Plan and Budget >
budget.
2009 Budget Review > 2008 and 2009
Approved Budget Summary Updated.
http://www.aeso.ca/downloads/2008_and_2009_Appro
ved_Budget_Summary_-_updated.pdf
INDUSTRIAL POWER CONSUMERS ASSOCIATION OF ALBERTA (IPCAA)
COMBINED COMMENTS FROM IPPCA, ALBERTA DIRECT CONNECT CONSUMERS ASSOCIATION (ADC),
OFFICE OF THE UTILITIES CONSUMER ADVOCATE, (UCA)
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
AESO’s draft General & Administrative Budget The
AESO responsibilities include matters that
overall focus and emphasis of the AESO priorities is to
provide both load and generators access to
enhance generator participation in the market. The Load a fair, efficient and openly competitive
Coalition’s key priority is cost mitigation. To address
wholesale electricity market.
this, the AESO needs to focus on the ways to reduce
costs expected to be incurred in implementing the
AESO responsibilities also include the safe,
Transmission plan and Provincial Energy Strategy –
Page 1
2010 and 2011 Business Plan and Budget Proposal
load cannot afford for CTI projects to be rushed through
without appropriate consideration for technology choice,
cost controls, and cost causation. To have the
transmission costs in Alberta double in the next 5 years
without any public process on need and/or who pays is
simply unacceptable to load.
reliable and economic planning and
operation of Alberta’s interconnected power
system for both load and generators.
The AESO also needs to ensure adequate resource are
available to advance demand response opportunities
(LSSI, Wind following, Operating Reserves), As
currently proposed, new AESO staff additions are to be
working on these key focus areas. The Load Coalition
would like to be sure that there are sufficient staff
allocated to these areas that development will not be
restricted due to AESO resource constraints.
The AESO has identified Demand
Response as a key initiative in its Market
Roadmap. The AESO recognizes its
importance as an integrated solution which
enhances load participation in the market.
As well, no explanation is given for the decision to
include an extra edition of “Powering Alberta”. The Load
Coalition is concerned that this publication will be used
to promote government policy (i.e. Bill 50), using
ratepayer dollars, when majority of ratepayers do not
support elements of Bill 50.
As reported during the meeting, research
has indicated that respondents have
recommended more frequent publications of
Powering Alberta. The purpose of Powering
Alberta is to build public awareness about
the AESO and its role in the province,
ensuring electricity in the public interest of
Albertans. The publication is focused on
educating Albertans about the electricity
industry, not to discuss government policy.
Cost controls are primarily a matter between
the incumbent Transmission Facility
Operators and the Alberta Utilities
Commission.
Existing staff resources will
facilitate 2010/11 planning,
consultation and eventual implementation of
demand response opportunities. It is
essential that these resources also
participate in the entire Market Roadmap
program. This helps to ensure awareness of
the broader impact of the market changes
being discussed.
OFFICE OF THE UTILITIES CONSUMER ADVOCATE (UCA)
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
TRANSCANADA
April 29, 2009
August 19, 2009
August 26, 2009
Page 2
2010 and 2011 Business Plan and Budget Proposal
Capital
CAPITAL POWER CORPORATION (CPC)
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
AESO Capital Budget
Noted
Capital Power would like to thank the AESO for the
opportunity to provide comments on the AESO’s Capital
Budget. Capital Power recognizes that the AESO has a
large number of initiatives currently in progress. We also
appreciate that the AESO may face resource limitations
that require the prioritization of initiatives to achieve its
business objectives. We offer the following comments
with respect to the prioritization of 2010 and 2011 capital
initiatives.
The establishment of rules and processes aimed at
managing the increasingly constrained transmission
system is the single most important element required for
the continued development of Alberta’s Energy-Only
market. In addition to the AESO’s mandate, to
proactively plan for a “congestion-free” transmission
system, the AESO has received clear direction from the
Department of Energy (DOE) to ensure that the impacts
of transmission constraints do not interfere with the
energy market price signal. For these reasons the
AESO should budget sufficient resources dedicated to
the development of, and consultation on, a
comprehensive constraint management rule(s) that
supports the fair, efficient and openly competitive
(FEOC) operation of Alberta’s electricity market.
The AESO has dedicated resources in the
process of developing a comprehensive
congestion management rule. This process
includes, interpretation of the AUC Decision
2009-007, a discussion paper and ultimately
a revised rule that complies with the
Decision, including “minimize the disruption
of market prices as much as possible”.
We are pleased to see that the AESO’s key capital
initiatives include a number of IT initiatives including the
replacement of the Energy Management System (EMS)
and upgrades to the dispatch tool (DT). A well
functioning and robust IT system is essential to the
reliable operation of the electric grid and a competitive
market. The AESO should make every effort required to
Noted. The AESO is in agreement that a
stable system foundation is required in
order to facilitate overall market
advancement. The AESO has budget
amounts in 2010 and 2011 to address
system concerns and implement a number
of new market advancements.
Page 1
Central to the success of the revised rule
development is consultation with
stakeholders. The AESO intends to follow
our normal consultation process to develop
a rule that promotes a fair, efficient, openly
competitive market.
2010 and 2011 Business Plan and Budget Proposal
update the current IT infrastructure such that inferior
solutions to market issues are not developed at the
expense of market participants and the FEOC operation
of the market. Once a robust IT system is developed the
AESO will have the ability to focus on implementing
market efficiencies. Until such time, Capital Power sees
little value in tackling large projects, such as the Intertie
Framework, until the required IT infrastructure is in place
to address these types of initiatives appropriately.
The AESO’s current market systems have
reached end of life and were not designed
to incorporate some of the additional
complexities, or provide the desired
flexibility market participants are demanding
without impacting the performance or
reliability of these systems.
A Market Systems Visioning project was
undertaken earlier this year. It solicited
industry input into system specifications for
current, expected and possible future
system capability. A replacement market
system is anticipated later in the 2011-2012
timeframe.
In addition, changes to legislation have placed an
increased importance on the reliability and robustness of
several AESO administered reports. As mentioned
above, Alberta’s electricity market is extremely IT
dependent. Therefore, it is prudent and necessary that
the AESO ensure there are back up systems in place to
mitigate the impact of the loss of critical IT infrastructure,
and that normal operation can be resumed in a timely
fashion.
Reliability of the AESO's IT services is, and
will continue to be, a critical consideration in
our support strategies and system design.
All AESO "critical" systems are designed to
be highly available and disaster
recoverable. As IT solutions approach near
100% reliability the costs to implement them
increase exponentially. As part of our
solution design we evaluate the appropriate
level of investment required to give a
desired level of reliability.
Finally, in the past, sufficient market performance
metrics had not been developed and as a result there
are no clear thresholds for determining the success of
many AESO or market initiatives. As a result, there is a
need to allocate resources to address a number of
issues that are currently having a negative impact on
price fidelity. Perhaps most significant of these is the
Dispatch Down Service market which continues to have
a negative impact on price fidelity and creates perverse
market behaviour incentives. The AESO should ensure
that the market design initiatives already implemented
are operating efficiently before spending additional
capital resources on implementing more complicated
design elements.
As part of the Market Roadmap, Market
Services has highlighted that a selection of
appropriate market metrics may be shared
with industry to improve the fair, efficient
and openly competitive operation of the
market. Additional data
reporting requirements have
been mandated upon the AESO under the
FEOC regulation. The AESO has drafted a
discussion paper for publishing a
standardized version of monthly market
performance metrics. This paper is
scheduled for stakeholder review and
comment 4Q09.
The AESO agrees that it is important to
ensure that market design initiatives are
efficient and effective. For that reason it is
not uncommon to conduct reviews
subsequent to market design change
implementation as we have done with the
Quick Hits. In particular, our review of Quick
Hits has concluded that while the DDS has
Page 2
2010 and 2011 Business Plan and Budget Proposal
had some undesirable effects, some
foreseen and some not, overall the product
has not had a negative impact on price
fidelity and is generally doing what it was
designed to do which is to remove the
impact of TMR on the pool price.
INDUSTRIAL POWER CONSUMERS ASSOCIATION OF ALBERTA (IPCAA)
COMBINED COMMENTS FROM IPPCA, ALBERTA DIRECT CONNECT CONSUMERS ASSOCIATION (ADC),
OFFICE OF THE UTILITIES CONSUMER ADVOCATE, (UCA)
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
AESO Capital Budget Demand Response/Import
The AESO is committed to facilitating
Support/Wind Following product infrastructure and IT
demand response, restoring intertie
support should be included as it is a major load priority
capacity and integrating wind generation
and loads will be paying for these items.
into the Alberta electric system without
compromising system reliability or the fair,
efficient and openly competitive operation of
the market. The AESO's business priorities
and budget assign significant future
investment in the AESO's IT systems. Each
product is being addressed in the Market
Advisory Committee, in workgroups or as
part of the Market Roadmap and staff are
both focused on these key areas as well as
understanding the broader impact of
proposed market and system changes.
Page 3
2010 and 2011 Business Plan and Budget Proposal
Other Industry
CITIES OF RED DEER AND LETHBRIDGE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
AESO Response
The AESO is not provided with this level of
detail from the AUC. The AESO receives an
AUC Administration Fee Order from the
1. The Cities request that the AESO breakout the
AUC to pay the transmission and energy
following Other Industry Cost line items:
market administration fees.
Stakeholder Comment
AESO Other Industry Costs Budget
•
•
AUC Fees for Load Settlement, and;
Costs recovered for the Market Surveillance
Administrator
2. Please provide a more accurate forecast of AUC
fees for 2010 and 2011, including a breakout of
Load Settlement costs if applicable.
The AESO does not include budgeted costs
for the MSA in the AESO’s budget. The
MSA prepares its own budget which is
approved by the Chair of the AUC and the
AESO collects the costs on behalf of the
MSA as a component of the energy
marketing trading charge.
The forecast for AUC costs in 2010 and
2011 that was included in the draft budget
on August 26, 2009 is the most accurate
forecast we can provide. As described in
our response to the first question, the AESO
does not receive information that details the
AUC fees.
Load settlement costs are AESO costs that
the AESO has incurred related to the load
settlement function, not other industry costs.
Page 1
2010 and 2011 Business Plan and Budget Proposal
INDUSTRIAL POWER CONSUMERS ASSOCIATION OF ALBERTA (IPCAA)
COMBINED COMMENTS FROM IPPCA, ALBERTA DIRECT CONNECT CONSUMERS ASSOCIATION (ADC),
OFFICE OF THE UTILITIES CONSUMER ADVOCATE, (UCA)
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
AESO Other Industry Costs Budget Explanation for
The increase in the WECC fees is primarily
WECC/NWPP fee increase would be appreciated.
related to an increase in their staff costs for
additional resources focused on compliance
and reliability coordination activities, in
addition to higher audit costs related to the
NERC CIP (critical infrastructure protection)
implementation plan.
Page 2
2010 and 2011 Business Plan and Budget Proposal
Transmission Line Losses
CITIES OF RED DEER AND LETHBRIDGE
April 29, 2009
June 10, 2009
August 19, 2009
Stakeholder Comment
AESO Response
AESO Line Loss Costs Presentation for 2010 The
The 2010 Line Loss Costs and Ancillary
Service Costs Forecasts used the same
Cities of Red Deer and Lethbridge request that the
EDC forecast data set to develop pool price
AESO reconcile the differing pool price forecast figures
(EDC volume 9, issue 23 price forecast for
as stated in the Line Loss Costs and Ancillary Services
2010). Reasonability tests were performed
Costs presentations.
on this data
2010
Line Loss Costs
Ancillary Services Costs
The difference in the figures stated are due
to the fact that:
$64.40
$50.68
i) the Line Loss Costs figure identifies the
pool price forecast based on a full year (i.e.
January – December, 2010) of data and
ii) the Ancillary Services Costs figure
identifies the pool price forecast based on
the first six months (i.e. January – June,
2010) of data.
The six month perspective was provided to
facilitate historical analysis (e.g. a year-todate comparison between 2009 & 2010).
This was not clearly noted in the Ancillary
Services Costs presentation.
The Cities also wish to understand why the forecasted
pool price as per the 2009 Rates Update Application is
not presented as the 2009 updated pool price in the Line
Loss Costs presentation.
Page 1
Both the 2009 Rates Update Application
and the Transmission Line Loss Costs
presentation were based on the best
available data at the time the information
was prepared for each.
2010 and 2011 Business Plan and Budget Proposal
2009 Update
Line Loss Costs
2009 Rates Update Application
$59.60
$86.88
The Cities believe there should only be one pool price
forecast presented for the 2009 Update and 2010
scenarios. In addition to presenting only one forecast
figure for each scenario, will the AESO revise the pool
price forecast to be more reflective of current forward
curves?
The 2009 Transmission Line Loss Costs
given to stakeholders was provided for
informational purposes only. By using the
same pool price for providing an update on
2009 Transmission Line Loss Costs as the
pool price used for the 2009 Rates Update
Application, the information provided to
stakeholders for Transmission Line Loss
Costs would not have reflected the most
recent forward price curves.
The AESO does not intend on revising the
pool price to reflect the current forward
curves as ancillary service costs and
transmission line loss costs are forecasts
prepared at a point in time. The forecasts
for these costs would continue to be subject
to forecasted pool price volatility even if the
forecasts were updated to current
information as a result of changing market
conditions.
Page 2
2010 and 2011 Business Plan and Budget Proposal
Ancillary Services
CITIES OF RED DEER AND LETHBRIDGE
April 29, 2009
June 10, 2009
August 19, 2009
Stakeholder Comment
AESO Response
AESO Ancillary Service Costs Presentation for 2010 The 2010 Line Loss Costs and Ancillary
Service Costs Forecasts used the same
The Cities of Red Deer and Lethbridge request that the
EDC forecast data set to develop pool price
AESO reconcile the differing pool price forecast figures
(EDC volume 9, issue 23 price forecast for
as stated in the Line Loss Costs and Ancillary Services
2010). Reasonability tests were performed
Costs presentations.
on this data
2010
Line Loss Costs
Ancillary Services Costs
The difference in the figures stated are due
to the fact that:
$64.40
$50.68
i) the Line Loss Costs figure identifies the
pool price forecast based on a full year (i.e.
January – December, 2010) of data and
ii) the Ancillary Services Costs figure
identifies the pool price forecast based on
the first six months (i.e. January – June,
2010) of data.
The six month perspective was provided to
facilitate historical analysis (e.g. a year-todate comparison between 2009 & 2010).
This was not clearly noted in the Ancillary
Services Costs presentation.
The Cities also wish to understand why the forecasted
pool price as per the 2009 Rates Update Application is
not presented as the 2009 updated pool price in the Line
Loss Costs presentation.
Page 1
Both the 2009 Rates Update Application
and the Transmission Line Loss Costs
presentation were based on the best
available data at the time the information
was prepared for each.
2010 and 2011 Business Plan and Budget Proposal
2009 Update
Line Loss Costs
2009 Rates Update Application
$59.60
$86.88
The Cities believe there should only be one pool price
forecast presented for the 2009 Update and 2010
scenarios. In addition to presenting only one forecast
figure for each scenario, will the AESO revise the pool
price forecast to be more reflective of current forward
curves?
The 2009 Transmission Line Loss Costs
given to stakeholders was provided for
informational purposes only. By using the
same pool price for providing an update on
2009 Transmission Line Loss Costs as the
pool price used for the 2009 Rates Update
Application, the information provided to
stakeholders for Transmission Line Loss
Costs would not have reflected the most
recent forward price curves.
The AESO does not intend on revising the
pool price to reflect the current forward
curves as ancillary service costs and
transmission line loss costs are forecasts
prepared at a point in time. The forecasts
for these costs would continue to be subject
to forecasted pool price volatility even if the
forecasts were updated to current
information as a result of changing market
conditions.
August 26, 2009
OFFICE OF THE UTILITIES CONSUMER ADVOCATE (UCA)/ INDUSTRIAL POWER CONSUMERS
ASSOCIATION OF ALBERTA (IPCAA)
April 29, 2009
June 10, 2009
August 19, 2009
Stakeholder Comment
AESO Response
AESO Ancillary Service Costs Presentation for 2010 Noted. The AESO intends to continue
The UCA & IPCAA understands that Ancillary Services
pursuing improving the deferral account
are proposed to become a flow through cost effective
process, and specifically Rider C.
2010. This is to reduce the lags resulting from deferral
Distribution Facility Owner (DFO) changes
accounts. The UCA supports any move to bring billing
are subject to DFO Regulatory proceedings.
and payment closer to the delivery of service. The
proposed AESO change must accompany changes to
DFO deferral accounts which have not been revised to
include the proposed methodology. Without changes to Over/under collections are adjusted
the DFO deferral accounts, end use customers will not
quarterly through the Rider C process. The
experience the full benefit of the AESO change to make AESO expects to file its 2009 deferral
Ancillary Services a flow through cost.
account reconciliation in April 2010.
Historically, the application process end-toIn the presentations, the AESO made reference to 2009 end takes several months.
variances in costs as a result of the decrease in
commodity and power pool prices. These reductions
could result in material over collection of the deferral
accounts this year. The UCA encourages the AESO to
complete its 2009 deferral account applications as soon
as possible. The AESO may also consider making an
interim filing to rectify any material over collections in
deferral accounts sooner than the end of the year.
The AESO has sufficient firm blackstart
Page 2
2010 and 2011 Business Plan and Budget Proposal
There was also discussion of Black Start services. The
AESO has spent significantly less on Black Start
services than plan in 2009. The explanation centered on
not having firm Black Start contracts in place and that
the current arrangements were on a “best efforts” basis.
The UCA is concerned that the lack of firm Black Start
contracts may be increasing the risk to Alberta
customers. As such, the UCA would encourage the
AESO to ensure that the appropriate level of Black Start
contracts are budgeted and then actually secured.
contracts in place to restart the system in
the event of a system-wide blackout. The
AESO procures blackstart services on a firm
basis to ensure the availability of resources
when required.
In order to enhance system restart
capability, the AESO is pursuing additional
firm contracts with providers. The actual
cost for blackstart services in 2009 are
lower than the forecast because the AESO
has not contracted for the additional
blackstart resources anticipated in the 2009
cost forecast.
August 26, 2009
Page 3
2010 and 2011 Business Plan and Budget Proposal
Other Comments
ALBERTA DIRECT CONNECT CONSUMERS ASSOCIATION (ADC):
April 29, 2009
Stakeholder Comment
AESO Response
June 10, 2009
Stakeholder Comment
AESO Response
The ADC appreciates the opportunity to provide
Noted
feedback.
August 19, 2009
August 26, 2009
CITIES OF RED DEER AND LETHBRIDGE
April 29, 2009
Stakeholder Comment
The Cities of Red Deer and
Lethbridge have no comment
on the material presented at
the 2009 BRP meeting on
June 10th.
June 10, 2009
AESO Response
Noted
August 19, 2009
Page 1
2010 and 2011 Business Plan and Budget Proposal
Stakeholder Comment
1. Please refer to the
attached Excel
spreadsheet. The Cities
request that the AESO
provide a breakout of its
2010 and 2011 budget
along with its 2009
budget and YTD figures
(for comparative
purposes) for each cost
item by AESO
Department (where
applicable) and please
provide the allocators
for each line item.
Under the Transmission
allocator, please
breakout further
between operating and
non-operating costs.
Please note: The attached
spreadsheet includes the
requested Other Industry
Cost line items from Section
2 above along with Operating
Reserves.
August 26, 2009
AESO Response
The presentation of transmission costs as operating or non-operating
on page 26 of the draft document has been used to differentiate costs
such as G&A, interest and amortization (the AESO’s Own Costs) from
the transmission operating costs (e.g. wire, losses, reserves, etc.).
100%
100%
Energy
Market
-
Load
Settlement
-
Operating
100%
-
-
Operating
100%
-
-
Operating
100%
-
-
Other Industry
Costs
Nonoperating
All other
costs
AUCrelated
admin
fee
-
General and
Administration
Nonoperating
Nonoperating
Nonoperating
Costs allocated based on
established methodology
AESO
Function
Wire
Line Losses
Operating
Reserves
TMR
Other
Ancillary
Services
General
Classification
Operating
Operating
Interest
Amortization /
Capital
Transmission
The AESO does not provide external financial reporting on a
department basis but on the basis of cost category. For internal
purposes, the annual budget is managed and reviewed on a
department basis which facilitates budget ownership and
accountability, and the allocation of costs to one of the three services
provided by the AESO (transmission, energy market and load
settlement). For external reporting purposes, only cost category
information is made available.
2. For the AESO’s Key
Capital Initiatives, please
provide a breakout of the
costs using the same
methodology as
requested above. Key
Capital Initiatives have
been included on the
attached Excel
spreadsheet.
The determination of allocators for capital initiatives occurs once a
year, at the end of a year, for the systems or hardware that was
commissioned during the year. At that time, each asset addition or
project is reviewed to determine the business functions that will be
supported by that asset. Throughout our project management process,
the delivery of the project is of primary importance with a focus on
scope, budget and timing. The allocation of costs is determined
through an accounting initiated process at year end. The allocators
used for a capital initiative typically remain constant for the life of the
asset though there have been instances when it has changed as a
result of a change in the function being supported by the asset.
Page 2
2010 and 2011 Business Plan and Budget Proposal
3. From Appendix H:
Allocation of Costs on
Page 55 along with the
line items in the attached
Excel spreadsheet,
please:
-
Provide the basis
upon which the
allocators are
determined and the
metrics used,
-
Confirm if there other
allocators used which
are not stated in
Appendix H,
-
Indicate when the
allocation
methodology was last
reviewed, and;
-
Update/confirm the
methodology of the
planned operational
changes for
2010/2011 e.g. staff
additions,
reallocations, recently
approved and
proposed regulations.
4. Please indicate the
capital items included
under Amortization costs
e.g. Buildings, IT systems
for 2009, 2010 and 2011.
The complete cost allocation methodology is described in Appendix H
and on page 27 of the document.
In general, department costs are allocated to one of the three functions
based on the business activities of that department using the
judgement of management (through direct inquiries for this purpose to
the appropriate senior management). There are specific allocation
methods used for IT, rent, capital and service groups/departments to
accommodate the uniqueness of those departments or cost categories
(as described in the business plan and budget document).
The methodology used to allocate costs is reviewed at least twice a
year; when the budget is prepared as a basis for the preliminary
allocations of costs and at the end of the year to go back and allocate
the costs based on the activities that actually occurred (focus of work,
staff count, etc.). From time to time the AESO will restructure areas
within the company and when this occurs, new departments may be
set up or cost allocation percentages revised based on management’s
judgment. When this occurs, the allocators will be revised mid-year to
incorporate these changes. The methodology and allocators were
reviewed at part of this 2010 and 2011 budget and are based on the
best information available at the time the budget is being prepared.
($ million)
Capital Categories
2009
4.6
Software
2.6
Hardware
1.5
Energy Management System
Compliance and Data Monitoring System 2.4
0.0
Dispatch Tool Re-architecture Project
1.3
System Coordination Centre
0.7
Leasehold Improvements / Furniture
13.0
Total
Page 3
Budgets
2010
6.3
3.1
3.0
2.0
1.5
1.3
0.5
17.7
2011
9.7
4.6
3.6
1.8
1.6
1.3
0.5
23.2
2010 and 2011 Business Plan and Budget Proposal
INDUSTRIAL POWER CONSUMERS ASSOCIATION OF ALBERTA (IPCAA)
COMBINED COMMENTS FROM IPPCA, ALBERTA DIRECT CONNECT CONSUMERS ASSOCIATION (ADC),
OFFICE OF THE UTILITIES CONSUMER ADVOCATE, (UCA)
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
There are currently two
More specific goals with respect to Strategic Objectives
major strategic initiatives underway at the
should be developed. “Facilitating Interties” has been a
AESO with respect to interties:
goal for quite a while with no demonstrable results.
implementation of the Provincial Energy
Strategy (PES) and establishing a
strategic program for interties under the
Market Roadmap.
The PES is a policy direction from the
province outlining goals and has a section
specifically directed at increasing the
number of interconnections between Alberta
and external markets.
An Intertie Workgroup has been established
and is focused on AESO rules, policies and
procedures to operate current interties and
support future development. Several
workstreams have been identified by the
workgroup that will impact the intertie
development strategy. The goal is to
develop a comprehensive intertie
framework program (e.g. ISO rules, OPPs
and develop system capability) that
facilitates development of new intertie
capacity, restores ATC and implements
dispatchable interties.
No forecast of the Trading charge was provided; please
notify stakeholders when this becomes available.
Page 4
This information will be provided in the final
version of the Business Plan and Budget
which is to be posted September 29th.
2010 and 2011 Business Plan and Budget Proposal
OFFICE OF THE UTILITIES CONSUMER ADVOCATE (UCA)
April 29, 2009
June 10, 2009
Stakeholder Comment
AESO Response
The UCA does not have comments on each
strategic initiative individually. The main concern is
that there is limited Cost/Benefit analysis at this
time. Many of the initiatives can only be accurately
assessed in light of the cost of implementation. As
such, the UCA submits that the process should
include a second look at the initiatives when the
costs and budgets have been presented and
analysed. Support for some initiatives will be
contingent on the cost of implementation compared
to the benefits.
(This comment is also posted in the “Strategic Plan
& Business Initiatives” section of this report.)
Noted. The AESO would like to highlight it
performs a minimum of two cost/benefit reviews
on every Information Technology capital
initiative. The first is during the BRP budget
development process, which provides high-level
cost benefit information to stakeholders. The
second occurs prior to project approval/initiation,
when the cost of options is available and
compared against identified benefits.
The UCA would request that all tables/schedules to
be presented in future sessions be produced in
Microsoft Excel format to allow easier analysis.
Noted. MS file formats will be considered when
releasing future BRP documents.
August 19, 2009
August 26, 2009
Page 5
2010 and 2011 Business Plan and Budget Proposal
ALBERTA DIRECT CONNECT
CONSUMERS ASSOCIATION (ADC)
CONSULTATION PROCESS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
STRATEGIC PLAN & BUSINESS INITIATIVES
April 29, 2009
Stakeholder Comment
AESO Response
AESO Develop Draft Business Priorities The draft
Yes. As in prior years we are open to
business priorities are a good starting point. As the
comments from stakeholders on the
Budget Review process unfolds, the UCA expects that
AESO’s business priorities and the AESO
the priorities may have to be modified based on
will consider amending the proposed
consultation and input from customers. As such, the
business priorities based on feedback
UCA trusts that the AESO will be open to revisiting the
received from stakeholders.
priorities in light of feedback from the review process.
Stakeholder Comment
Comments on the AESO’s strategic objectives: As
with the draft business priorities, the UCA sees the
strategic objectives as a good starting point. As the
Budget Review process unfolds, the UCA expects that
the objectives may have to be modified based on
consultation and input from customers. As such, the
UCA trusts that the AESO will be open to revisiting the
objectives in light of feedback from the review process.
AESO Response
Yes. Similar to the AESO’s business
priorities, the AESO is open to comments
from stakeholders on the AESO’s strategic
objectives and the AESO will consider
amending the strategic objectives based on
the feedback received.
June 10, 2009
Stakeholder Comment
AESO Response
Noted. The AESO has identified Demand
Strategic Objective #1: Market Road Map and
Interties The ADC wishes to emphasize the importance Response as one of its Draft Initiatives.
of advancing the demand response initiative in a timely
Continued ADC support will facilitate
manner. Specifically program advancement in areas
associated 2010/11 planning and BRP
where load can compete for the same A/S products as
budgeting activities.
generators such as spinning reserves, long lead time
generation, congestion management, “uplift “ for price
responsive loads, and Under-frequency support
services.
Page 1
2010 and 2011 Business Plan and Budget Proposal
Stakeholder Comment
Strategic Objective #2: Provincial Energy Strategy
(PES) and the Transmission Development Policy
The ADC is concerned that the current processes in
place will not adequately control the costs for the CTI
projects. These projects should not necessarily be
direct assigned, but rather advanced in a competitive
fashion with clear budget expectations and cost
accountability.
AESO Response
Noted: The AESO’s normal practice,
consistent with the legislative framework
and the Transmission Development Policy,
is to direct assign transmission facilities to
the incumbent TFOs based on franchise
area (service territory). It should be noted
that government policy is outside the scope
of the BRP process.
The ADC requests that the AESO provide a clear
expectation of the annual cost implications of these
projects to a typical industrial load of various sizes (i.e. 5
MW, 10 MW, 50 MW, 100 MW), the timing that the costs
would enter rate base as well as a projection thereafter
of costs to 2017 as the projects are completed.
Noted: Initial project cost estimates are
available in the Long-term Transmission
System Plan - 2009 published on the AESO
website. Our plan is to respond to the
additional cost estimate requests and report
back to stakeholders at a later date.
The ADC also requests that the AESO report on the
suitability of the technology of the HVDC lines between
Edmonton and Calgary. It is our understanding, that the
line loss savings by using DC technology may be
forgone by the incremental losses in the converter
stations if the distance of lines isn’t long enough.
Please report the conversion losses in the AB – SK
connection.
Stakeholder Comment
Strategic Objective #5: Technology Knowledge
Leadership See comments in Strategic Objective #2
regarding HVDC technology.
Noted: Use of HVDC is mandated under the
Provincial Energy Policy where possible
and is planned for the Edmonton Calgary
reinforcements.
Stakeholder Comment
Strategic Objective #6: Enhance Stakeholder
Relationships The ADC expresses some concern over
the efficiency of the stakeholder process. The load
groups are sparsely represented and there are a
number of consultation activities underway that require
load participation. Suggest the AESO upgrade the
stakeholder calendar such that all activities and relevant
materials are readily accessible. It would be helpful to
also include any key dates for AUC proceedings such as
rates, facilities applications and rule changes. The cost
to participate for Edmonton based stakeholders such as
the ADC is excessive as the majority of activity occurs in
Calgary. The conference call facilities at the AESO
main boardroom make participation difficult. Consider
any merit in a videoconference solution.
AESO Response
Noted. The AESO is open to evaluate any
recommendation that improves stakeholder
efficiency/effectiveness in the consultative
processes.
AESO Response
Noted. See AESO response to Strategic
Objective #2 above.
August 19, 2009
August 26, 2009
Page 2
2010 and 2011 Business Plan and Budget Proposal
GENERAL & ADMINISTRATIVE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
CAPITAL
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
OTHER INDUSTRY
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
TRANSMISSION LINE LOSSES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
ANCILLIARY SERVICES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 3
2010 and 2011 Business Plan and Budget Proposal
OTHER COMMENTS
April 29, 2009
June 10, 2009
Stakeholder Comment
AESO Response
The ADC appreciates the opportunity to provide
Noted
feedback.
August 19, 2009
August 26, 2009
Page 4
2010 and 2011 Business Plan and Budget Proposal
ATCO Power
CONSULTATION PROCESS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
STRATEGIC PLAN & BUSINESS INITIATIVES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
GENERAL & ADMINISTRATIVE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
CAPITAL
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 1
2010 and 2011 Business Plan and Budget Proposal
OTHER INDUSTRY
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
TRANSMISSION LINE LOSSES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
ANCILLIARY SERVICES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
OTHER COMMENTS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 2
2010 and 2011 Business Plan and Budget Proposal
Capital Power Corporation (CPC)
CONSULTATION PROCESS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
STRATEGIC PLAN & BUSINESS INITIATIVES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
GENERAL & ADMINISTRATIVE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 1
2010 and 2011 Business Plan and Budget Proposal
CAPITAL
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
AESO Capital Budget
Noted
Capital Power would like to thank the AESO for the
opportunity to provide comments on the AESO’s Capital
Budget. Capital Power recognizes that the AESO has a
large number of initiatives currently in progress. We also
appreciate that the AESO may face resource limitations
that require the prioritization of initiatives to achieve its
business objectives. We offer the following comments
with respect to the prioritization of 2010 and 2011 capital
initiatives.
The establishment of rules and processes aimed at
managing the increasingly constrained transmission
system is the single most important element required for
the continued development of Alberta’s Energy-Only
market. In addition to the AESO’s mandate, to
proactively plan for a “congestion-free” transmission
system, the AESO has received clear direction from the
Department of Energy (DOE) to ensure that the impacts
of transmission constraints do not interfere with the
energy market price signal. For these reasons the
AESO should budget sufficient resources dedicated to
the development of, and consultation on, a
comprehensive constraint management rule(s) that
supports the fair, efficient and openly competitive
(FEOC) operation of Alberta’s electricity market.
The AESO has dedicated resources in the
process of developing a comprehensive
congestion management rule. This process
includes, interpretation of the AUC Decision
2009-007, a discussion paper and ultimately
a revised rule that complies with the
Decision, including “minimize the disruption
of market prices as much as possible”.
We are pleased to see that the AESO’s key capital
initiatives include a number of IT initiatives including the
replacement of the Energy Management System (EMS)
and upgrades to the dispatch tool (DT). A well
functioning and robust IT system is essential to the
reliable operation of the electric grid and a competitive
market. The AESO should make every effort required to
update the current IT infrastructure such that inferior
solutions to market issues are not developed at the
expense of market participants and the FEOC operation
of the market. Once a robust IT system is developed the
AESO will have the ability to focus on implementing
market efficiencies. Until such time, Capital Power sees
little value in tackling large projects, such as the Intertie
Framework, until the required IT infrastructure is in place
to address these types of initiatives appropriately.
Noted. The AESO is in agreement that a
stable system foundation is required in
order to facilitate overall market
advancement. The AESO has budget
amounts in 2010 and 2011 to address
system concerns and implement a number
of new market advancements.
In addition, changes to legislation have placed an
increased importance on the reliability and robustness of
several AESO administered reports. As mentioned
Page 2
Central to the success of the revised rule
development is consultation with
stakeholders. The AESO intends to follow
our normal consultation process to develop
a rule that promotes a fair, efficient, openly
competitive market.
The AESO’s current market systems have
reached end of life and were not designed
to incorporate some of the additional
complexities, or provide the desired
flexibility market participants are demanding
without impacting the performance or
reliability of these systems.
A Market Systems Visioning project was
undertaken earlier this year. It solicited
industry input into system specifications for
current, expected and possible future
2010 and 2011 Business Plan and Budget Proposal
above, Alberta’s electricity market is extremely IT
dependent. Therefore, it is prudent and necessary that
the AESO ensure there are back up systems in place to
mitigate the impact of the loss of critical IT infrastructure,
and that normal operation can be resumed in a timely
fashion.
system capability. A replacement market
system is anticipated later in the 2011-2012
timeframe.
Finally, in the past, sufficient market performance
metrics had not been developed and as a result there
are no clear thresholds for determining the success of
many AESO or market initiatives. As a result, there is a
need to allocate resources to address a number of
issues that are currently having a negative impact on
price fidelity. Perhaps most significant of these is the
Dispatch Down Service market which continues to have
a negative impact on price fidelity and creates perverse
market behaviour incentives. The AESO should ensure
that the market design initiatives already implemented
are operating efficiently before spending additional
capital resources on implementing more complicated
design elements.
As part of the Market Roadmap, Market
Services has highlighted that a selection of
appropriate market metrics may be shared
with industry to improve the fair, efficient
and openly competitive operation of the
market. Additional data
reporting requirements have
been mandated upon the AESO under the
FEOC regulation. The AESO has drafted a
discussion paper for publishing a
standardized version of monthly market
performance metrics. This paper is
scheduled for stakeholder review and
comment 4Q09.
The AESO agrees that it is important to
ensure that market design initiatives are
efficient and effective. For that reason it is
not uncommon to conduct reviews
subsequent to market design change
implementation as we have done with the
Quick Hits. In particular, our review of Quick
Hits has concluded that while the DDS has
had some undesirable effects, some
foreseen and some not, overall the product
has not had a negative impact on price
fidelity and is generally doing what it was
designed to do which is to remove the
impact of TMR on the pool price.
Reliability of the AESO's IT services is, and
will continue to be, a critical consideration in
our support strategies and system design.
All AESO "critical" systems are designed to
be highly available and disaster
recoverable. As IT solutions approach near
100% reliability the costs to implement them
increase exponentially. As part of our
solution design we evaluate the appropriate
level of investment required to give a
desired level of reliability.
OTHER INDUSTRY
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 3
2010 and 2011 Business Plan and Budget Proposal
TRANSMISSION LINE LOSSES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
ANCILLIARY SERVICES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
OTHER COMMENTS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 4
2010 and 2011 Business Plan and Budget Proposal
CITIES OF RED DEER &
LETHBRIDGE
CONSULTATION PROCESS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
STRATEGIC PLAN & BUSINESS INITIATIVES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
GENERAL & ADMINISTRATIVE
April 29, 2009
June 10, 2009
August 19, 2009
All of the comments presented in
this form reference the AESO’s Draft
2010-2011 Business Plan and
Budget document dated September
11, 2009.
August 26, 2009
The information on page 15 is consistent with the final
approved budget for 2009. Please refer to the following link on
the AESO’s website that provides the 2009 budget detail for
comparison. The document is located under About AESO > Our
Business > Business Plan and Budget > 2009 Budget Review >
2008 and 2009 Approved Budget Summary Updated.
1. Please reconcile the 2009 Budget
figures as presented on Page 15
with the final approved 2009 budget.
http://www.aeso.ca/downloads/2008_and_2009_Approved_Budget_Summary__updated.pdf
Page 1
2010 and 2011 Business Plan and Budget Proposal
CAPITAL
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
OTHER INDUSTRY
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
1. The Cities request that the AESO breakout the
The AESO is not provided with this level of
following Other Industry Cost line items:
detail from the AUC. The AESO receives an
AUC Administration Fee Order from the
AUC to pay the transmission and energy
• AUC Fees for Load Settlement, and;
market administration fees.
•
Costs recovered for the Market Surveillance
Administrator
2. Please provide a more accurate forecast of AUC
fees for 2010 and 2011, including a breakout of
Load Settlement costs if applicable.
The AESO does not include budgeted costs
for the MSA in the AESO’s budget. The
MSA prepares its own budget which is
approved by the Chair of the AUC and the
AESO collects the costs on behalf of the
MSA as a component of the energy
marketing trading charge.
The forecast for AUC costs in 2010 and
2011 that was included in the draft budget
on August 26, 2009 is the most accurate
forecast we can provide. As described in
our response to the first question, the AESO
does not receive information that details the
AUC fees.
Load settlement costs are AESO costs that
the AESO has incurred related to the load
settlement function, not other industry costs.
TRANSMISSION LINE LOSSES
April 29, 2009
June 10, 2009
August 19, 2009
Stakeholder Comment
AESO Response
1. The Cities of Red Deer and Lethbridge request that The 2010 Line Loss Costs and Ancillary
the AESO reconcile the differing pool price forecast Service Costs Forecasts used the same
figures as stated in the Line Loss Costs and
EDC forecast data set to develop pool price
Page 2
2010 and 2011 Business Plan and Budget Proposal
(EDC volume 9, issue 23 price forecast for
2010). Reasonability tests were performed
on this data
Ancillary Services Costs presentations.
2010
Line Loss Costs
Ancillary Services Costs
The difference in the figures stated is due to
the fact that:
$64.40
$50.68
i) the Line Loss Costs figure identifies the
pool price forecast based on a full year (i.e.
January – December, 2010) of data and
ii) the Ancillary Services Costs figure
identifies the pool price forecast based on
the first six months (i.e. January – June,
2010) of data.
The six month perspective was provided to
facilitate historical analysis (e.g. a year-todate comparison between 2009 & 2010).
This was not clearly noted in the Ancillary
Services Costs presentation.
2. The Cities also wish to understand why the
forecasted pool price as per the 2009 Rates
Update Application is not presented as the 2009
updated pool price in the Line Loss Costs
presentation.
2009 Update
Line Loss Costs
2009 Rates Update Application
$59.60
$86.88
The Cities believe there should only be one pool price
forecast presented for the 2009 Update and 2010
scenarios. In addition to presenting only one forecast
figure for each scenario, will the AESO revise the pool
price forecast to be more reflective of current forward
curves?
Both the 2009 Rates Update Application
and the Transmission Line Loss Costs
presentation were based on the best
available data at the time the information
was prepared for each.
The 2009 Transmission Line Loss Costs
given to stakeholders was provided for
informational purposes only. By using the
same pool price for providing an update on
2009 Transmission Line Loss Costs as the
pool price used for the 2009 Rates Update
Application, the information provided to
stakeholders for Transmission Line Loss
Costs would not have reflected the most
recent forward price curves.
The AESO does not intend on revising the
pool price to reflect the current forward
curves as ancillary service costs and
transmission line loss costs are forecasts
prepared at a point in time. The forecasts
for these costs would continue to be subject
to forecasted pool price volatility even if the
forecasts were updated to current
information as a result of changing market
conditions.
August 26, 2009
Page 3
2010 and 2011 Business Plan and Budget Proposal
ANCILLIARY SERVICES
April 29, 2009
June 10, 2009
August 19, 2009
Stakeholder Comment
AESO Response
Please refer to the Cities’ first comment in the
Noted. See response to item 1) in the
Transmission Line Losses section above.
Transmission Line Losses section.
August 26, 2009
OTHER COMMENTS
April 29, 2009
Stakeholder Comment
AESO Response
The Cities of Red Deer and Lethbridge have no
Noted
comment on the material presented at the 2009 BRP
meeting on June 10th.
June 10, 2009
August 19, 2009
1. Please refer to the
attached Excel
spreadsheet. The Cities
request that the AESO
provide a breakout of its
2010 and 2011 budget
along with its 2009
budget and YTD figures
(for comparative
purposes) for each cost
item by AESO
Department (where
applicable) and please
provide the allocators
for each line item.
Under the Transmission
allocator, please
breakout further
between operating and
non-operating costs.
Please note: The attached
spreadsheet includes the
requested Other Industry
Cost line items from Section
2 above along with Operating
Reserves.
August 26, 2009
The presentation of transmission costs as operating or non-operating
on page 26 of the draft document has been used to differentiate costs
such as G&A, interest and amortization (the AESO’s Own Costs) from
the transmission operating costs (e.g. wire, losses, reserves, etc.).
100%
100%
Energy
Market
-
Load
Settlement
-
Operating
100%
-
-
Operating
100%
-
-
Operating
100%
-
-
Other Industry
Costs
Nonoperating
All other
costs
AUCrelated
admin
fee
-
General and
Administration
Nonoperating
Nonoperating
Nonoperating
Costs allocated based on
established methodology
AESO
Function
Wire
Line Losses
Operating
Reserves
TMR
Other
Ancillary
Services
General
Classification
Operating
Operating
Interest
Amortization /
Capital
Transmission
The AESO does not provide external financial reporting on a
department basis but on the basis of cost category. For internal
purposes, the annual budget is managed and reviewed on a
Page 4
2010 and 2011 Business Plan and Budget Proposal
department basis which facilitates budget ownership and
accountability, and the allocation of costs to one of the three services
provided by the AESO (transmission, energy market and load
settlement). For external reporting purposes, only cost category
information is made available.
2. For the AESO’s Key
Capital Initiatives, please
provide a breakout of the
costs using the same
methodology as
requested above. Key
Capital Initiatives have
been included on the
attached Excel
spreadsheet.
The determination of allocators for capital initiatives occurs once a
year, at the end of a year, for the systems or hardware that was
commissioned during the year. At that time, each asset addition or
project is reviewed to determine the business functions that will be
supported by that asset. Throughout our project management process,
the delivery of the project is of primary importance with a focus on
scope, budget and timing. The allocation of costs is determined
through an accounting initiated process at year end. The allocators
used for a capital initiative typically remain constant for the life of the
asset though there have been instances when it has changed as a
result of a change in the function being supported by the asset.
3. From Appendix H:
Allocation of Costs on
Page 55 along with the
line items in the attached
Excel spreadsheet,
please:
The complete cost allocation methodology is described in Appendix H
and on page 27 of the document.
-
Provide the basis
upon which the
allocators are
determined and the
metrics used,
-
Confirm if there other
allocators used which
are not stated in
Appendix H,
-
Indicate when the
allocation
methodology was last
reviewed, and;
-
Update/confirm the
methodology of the
planned operational
changes for
2010/2011 e.g. staff
additions,
reallocations, recently
approved and
proposed regulations.
In general, department costs are allocated to one of the three functions
based on the business activities of that department using the
judgement of management (through direct inquiries for this purpose to
the appropriate senior management). There are specific allocation
methods used for IT, rent, capital and service groups/departments to
accommodate the uniqueness of those departments or cost categories
(as described in the business plan and budget document).
The methodology used to allocate costs is reviewed at least twice a
year; when the budget is prepared as a basis for the preliminary
allocations of costs and at the end of the year to go back and allocate
the costs based on the activities that actually occurred (focus of work,
staff count, etc.). From time to time the AESO will restructure areas
within the company and when this occurs, new departments may be
set up or cost allocation percentages revised based on management’s
judgment. When this occurs, the allocators will be revised mid-year to
incorporate these changes. The methodology and allocators were
reviewed at part of this 2010 and 2011 budget and are based on the
best information available at the time the budget is being prepared.
Page 5
2010 and 2011 Business Plan and Budget Proposal
4. Please indicate the
capital items included
under Amortization
costs e.g. Buildings, IT
systems for 2009, 2010
and 2011.
($ million)
Capital Categories
2009
4.6
Software
2.6
Hardware
1.5
Energy Management System
Compliance and Data Monitoring System 2.4
0.0
Dispatch Tool Re-architecture Project
1.3
System Coordination Centre
0.7
Leasehold Improvements / Furniture
13.0
Total
Page 6
Budgets
2010
6.3
3.1
3.0
2.0
1.5
1.3
0.5
17.7
2011
9.7
4.6
3.6
1.8
1.6
1.3
0.5
23.2
2010 and 2011 Business Plan and Budget Proposal
City of Calgary
CONSULTATION PROCESS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
STRATEGIC PLAN & BUSINESS INITIATIVES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
GENERAL & ADMINISTRATIVE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
CAPITAL
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 1
2010 and 2011 Business Plan and Budget Proposal
OTHER INDUSTRY
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
TRANSMISSION LINE LOSSES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
ANCILLIARY SERVICES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
OTHER COMMENTS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 2
2010 and 2011 Business Plan and Budget Proposal
Industrial Power Consumers Association
of Alberta (IPCAA)
Combined comments from IPPCA, Alberta Direct Connect Consumers Association (ADC),
OFFICE OF THE UTILITIES CONSUMER ADVOCATE, (UCA)
CONSULTATION PROCESS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
STRATEGIC PLAN & BUSINESS INITIATIVES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
GENERAL & ADMINISTRATIVE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
AESO responsibilities include matters that
AESO’s draft General & Administrative Budget The
provide both load and generators access to
overall focus and emphasis of the AESO priorities is to
enhance generator participation in the market. The Load a fair, efficient and openly competitive
wholesale electricity market.
Coalition’s (IPCAA, ADC and UCA) key priority is cost
mitigation. To address this, the AESO needs to focus on
the ways to reduce costs expected to be incurred in
AESO responsibilities also include the safe,
implementing the Transmission plan and Provincial
reliable and economic planning and
Energy Strategy – load cannot afford for CTI projects to
operation of Alberta’s interconnected power
be rushed through without appropriate consideration for
system for both load and generators.
technology choice, cost controls, and cost causation. To
have the transmission costs in Alberta double in the next Cost controls are primarily a matter between
5 years without any public process on need and/or who
the incumbent Transmission Facility
Page 1
2010 and 2011 Business Plan and Budget Proposal
pays is simply unacceptable to load.
Operators and the Alberta Utilities
Commission.
The AESO also needs to ensure adequate resource are
available to advance demand response opportunities
(LSSI, Wind following, Operating Reserves), As
currently proposed, new AESO staff additions are to be
working on these key focus areas. The Load Coalition
would like to be sure that there are sufficient staff
allocated to these areas that development will not be
restricted due to AESO resource constraints.
The AESO has identified Demand
Response as a key initiative in its Market
Roadmap. The AESO recognizes its
importance as an integrated solution which
enhances load participation in the market.
As well, no explanation is given for the decision to
include an extra edition of “Powering Alberta”. The Load
Coalition is concerned that this publication will be used
to promote government policy (i.e. Bill 50), using
ratepayer dollars, when majority of ratepayers do not
support elements of Bill 50.
As reported during the meeting, research
has indicated that respondents have
recommended more frequent publications of
Powering Alberta. The purpose of Powering
Alberta is to build public awareness about
the AESO and its role in the province,
ensuring electricity in the public interest of
Albertans. The publication is focused on
educating Albertans about the electricity
industry, not to discuss government policy.
Existing staff resources will
facilitate 2010/11 planning,
consultation and eventual implementation of
demand response opportunities. It is
essential that these resources also
participate in the entire Market Roadmap
program. This helps to ensure awareness of
the broader impact of the market changes
being discussed.
CAPITAL
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
AESO Capital Budget Demand Response/Import
The AESO is committed to facilitating
Support/Wind Following product infrastructure and IT
demand response, restoring intertie
support should be included as it is a major load priority
capacity and integrating wind generation
and loads will be paying for these items.
into the Alberta electric system without
compromising system reliability or the fair,
efficient and openly competitive operation of
the market. The AESO's business priorities
and budget assign significant future
investment in the AESO's IT systems. Each
product is being addressed in the Market
Advisory Committee, in workgroups or as
part of the Market Roadmap and staff are
both focused on these key areas as well as
understanding the broader impact of
proposed market and system changes.
Page 2
2010 and 2011 Business Plan and Budget Proposal
OTHER INDUSTRY
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
AESO Other Industry Costs Budget Explanation for
The increase in the WECC fees is primarily
WECC/NWPP fee increase would be appreciated.
related to an increase in their staff costs for
additional resources focused on compliance
and reliability coordination activities, in
addition to higher audit costs related to the
NERC CIP (critical infrastructure protection)
implementation plan.
TRANSMISSION LINE LOSSES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
ANCILLIARY SERVICES
April 29, 2009
June 10, 2009
August 19, 2009
Stakeholder Comment
AESO Response
AESO Ancillary Service Costs Presentation for 2010 Noted. See response to item 1) above.
The UCA & IPCAA understand that Ancillary Services
Noted. The AESO intends to continue
are proposed to become a flow through cost effective
pursuing improving the deferral account
2010. This is to reduce the lags resulting from deferral
process, and specifically Rider C.
accounts. The UCA supports any move to bring billing
Distribution Facility Owner (DFO) changes
and payment closer to the delivery of service. The
are subject to DFO Regulatory proceedings.
proposed AESO change must accompany changes to
DFO deferral accounts which have not been revised to
include the proposed methodology. Without changes to
the DFO deferral accounts, end use customers will not
experience the full benefit of the AESO change to make Over/under collections are adjusted
quarterly through the Rider C process. The
Ancillary Services a flow through cost.
AESO expects to file its 2009 deferral
In the presentations, the AESO made reference to 2009 account reconciliation in April 2010.
variances in costs as a result of the decrease in
Historically, the application process end-tocommodity and power pool prices. These reductions
end takes several months.
could result in material over collection of the deferral
accounts this year. The UCA encourages the AESO to
complete its 2009 deferral account applications as soon
as possible. The AESO may also consider making an
Page 3
2010 and 2011 Business Plan and Budget Proposal
interim filing to rectify any material over collections in
deferral accounts sooner than the end of the year.
There was also discussion of Black Start services. The
AESO has spent significantly less on Black Start
services than plan in 2009. The explanation centered
on not having firm Black Start contracts in place and that
the current arrangements were on a “best efforts” basis.
The UCA is concerned that the lack of firm Black Start
contracts may be increasing the risk to Alberta
customers. As such, the UCA would encourage the
AESO to ensure that the appropriate level of Black Start
contracts are budgeted and then actually secured.
The AESO has sufficient firm blackstart
contracts in place to restart the system in
the event of a system-wide blackout. The
AESO procures blackstart services on a firm
basis to ensure the availability of resources
when required.
In order to enhance system restart
capability, the AESO is pursuing additional
firm contracts with providers. The actual
cost for blackstart services in 2009 are
lower than the forecast because the AESO
has not contracted for the additional
blackstart resources anticipated in the 2009
cost forecast.
August 26, 2009
OTHER COMMENTS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Stakeholder Comment
AESO Response
There are currently two
More specific goals with respect to Strategic Objectives
major strategic initiatives underway at the
should be developed. “Facilitating Interties” has been a
AESO with respect to interties:
goal for quite a while with no demonstrable results.
implementation of the Provincial Energy
Strategy (PES) and establishing a
strategic program for interties under the
Market Roadmap.
The PES is a policy direction from the
province outlining goals and has a section
specifically directed at increasing the
number of interconnections between Alberta
and external markets.
An Intertie Workgroup has been established
and is focused on AESO rules, policies and
procedures to operate current interties and
support future development. Several
workstreams have been identified by the
workgroup that will impact the intertie
development strategy. The goal is to
develop a comprehensive intertie
framework program (e.g. ISO rules, OPPs
and develop system capability) that
facilitates development of new intertie
capacity, restores ATC and implements
Page 4
2010 and 2011 Business Plan and Budget Proposal
dispatchable interties.
No forecast of the Trading charge was provided; please
notify stakeholders when this becomes available.
Page 5
This information will be provided in the final
version of the Business Plan and Budget
which is to be posted September 29th.
2010 and 2011 Business Plan and Budget Proposal
OFFICE OF THE UTILITIES
CONSUMER ADVOCATE (UCA)
CONSULTATION PROCESS
April 29, 2009
Stakeholder Comment
AESO Response
Technical Meetings to Review Forecasted Costs The Agreed. The AESO will work with
UCA submits that one meeting may not be sufficient to
stakeholders to revise the BRP schedule to
adequately address all the material presented. The
accommodate multiple meetings on the
UCA suggests that a series of meetings be scheduled. If costs forecasts.
some later meetings are not required, they can be
cancelled.
Comments on proposed BRP timeline The proposed
August 11 meeting conflicts with planned vacations.
The UCA requests that the meeting be rescheduled to
August 19. Alternatively, the UCA requests that the
deadline for comments be delayed by one week and
requests the AESO allow a separate meeting with the
UCA on August 19.
Noted. The AESO revise and review with
stakeholders a revised timeline to
accommodate the request.
Stakeholder comments on proposed terms of
reference The UCA supports the draft terms of
reference.
Noted. There are no changes in the terms
of reference from those established in the
prior year.
Do you support the AESO proposing a two (2) year
general and administrative budget? Yes. The multiyear process seemed to work well in the past, and the
UCA expects that it should achieve efficiencies again
this time.
Noted
June 10, 2009
Stakeholder Comment
AESO Response
Comments on proposed BRP timeline The UCA is
Noted.
pleased that the August meeting has been separated in
to two portions. This will allow a better discussion of the
issues related to each section. The proposed timelines
are acceptable to the UCA at this time. As well, see
additional comments related to a second review of
strategic initiatives in light of budgets.
August 19, 2009
August 26, 2009
Page 1
2010 and 2011 Business Plan and Budget Proposal
STRATEGIC PLAN & BUSINESS INITIATIVES
April 29, 2009
Stakeholder Comment
AESO Response
AESO Develop Draft Business Priorities The draft
Yes. As in prior years we are open to
business priorities are a good starting point. As the
comments from stakeholders on the
Budget Review process unfolds, the UCA expects that
AESO’s business priorities and the AESO
the priorities may have to be modified based on
will consider amending the proposed
consultation and input from customers. As such, the
business priorities based on feedback
UCA trusts that the AESO will be open to revisiting the
received from stakeholders.
priorities in light of feedback from the review process.
Stakeholder Comment
Comments on the AESO’s strategic objectives: As
with the draft business priorities, the UCA sees the
strategic objectives as a good starting point. As the
Budget Review process unfolds, the UCA expects that
the objectives may have to be modified based on
consultation and input from customers. As such, the
UCA trusts that the AESO will be open to revisiting the
objectives in light of feedback from the review process.
AESO Response
Yes. Similar to the AESO’s business
priorities, the AESO is open to comments
from stakeholders on the AESO’s strategic
objectives and the AESO will consider
amending the strategic objectives based on
the feedback received.
June 10, 2009
Stakeholder Comment
AESO Response
Strategic Objective #1: The UCA does not have
Noted. The AESO would like to highlight it
comments on each strategic initiative individually. The
performs a minimum of two cost/benefit
main concern is that there is limited Cost/Benefit
reviews on every Information Technology
analysis at this time. Many of the initiatives can only be
capital initiative. The first is during the BRP
accurately assessed in light of the cost of
budget development process, which
implementation. As such, the UCA submits that the
provides high-level cost benefit information
process should include a second look at the initiatives
to stakeholders. The second occurs prior to
when the costs and budgets have been presented and
project approval/initiation, when the cost of
analysed. Support for some initiatives will be contingent options is available and compared against
on the cost of implementation compared to the benefits. identified benefits.
(This comment is also posted in the “Other Comments”
section of this report.)
Stakeholder Comment
AESO Response
Noted. See AESO response to Strategic
Strategic Objective #2: Provincial Energy Strategy
Objective #1
(PES) and the Transmission Development Policy
See comment under Strategic Objective #1.
Stakeholder Comment
Strategic Objective #3: Customer Services
Improvements See comment under Strategic Objective
#1.
AESO Response
Noted. See AESO response to Strategic
Objective #1
Stakeholder Comment
Strategic Objective #4: Attract and Retain Quality
Staff See comment under Strategic Objective #1.
AESO Response
Noted. See AESO response to Strategic
Objective #1
Stakeholder Comment
Strategic Objective #5: Technology Knowledge
Leadership See comment under Strategic Objective #1.
AESO Response
Noted. See AESO response to Strategic
Objective #1
August 19, 2009
August 26, 2009
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2010 and 2011 Business Plan and Budget Proposal
GENERAL & ADMINISTRATIVE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
CAPITAL
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
OTHER INDUSTRY
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
TRANSMISSION LINE LOSSES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
ANCILLIARY SERVICES
April 29, 2009
June 10, 2009
August 19, 2009
Stakeholder Comment
AESO Response
AESO Ancillary Service Costs Presentation for 2010 Noted. See response to item 1) above.
The UCA & IPCAA understands that Ancillary Services
Noted. The AESO intends to continue
are proposed to become a flow through cost effective
pursuing improving the deferral account
2010. This is to reduce the lags resulting from deferral
process, and specifically Rider C.
accounts. The UCA supports any move to bring billing
Distribution Facility Owner (DFO) changes
and payment closer to the delivery of service. The
are subject to DFO Regulatory proceedings.
proposed AESO change must accompany changes to
DFO deferral accounts which have not been revised to
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2010 and 2011 Business Plan and Budget Proposal
include the proposed methodology. Without changes to
the DFO deferral accounts, end use customers will not
experience the full benefit of the AESO change to make
Ancillary Services a flow through cost.
In the presentations, the AESO made reference to 2009
variances in costs as a result of the decrease in
commodity and power pool prices. These reductions
could result in material over collection of the deferral
accounts this year. The UCA encourages the AESO to
complete its 2009 deferral account applications as soon
as possible. The AESO may also consider making an
interim filing to rectify any material over collections in
deferral accounts sooner than the end of the year.
There was also discussion of Black Start services. The
AESO has spent significantly less on Black Start
services than plan in 2009. The explanation centered
on not having firm Black Start contracts in place and that
the current arrangements were on a “best efforts” basis.
The UCA is concerned that the lack of firm Black Start
contracts may be increasing the risk to Alberta
customers. As such, the UCA would encourage the
AESO to ensure that the appropriate level of Black Start
contracts are budgeted and then actually secured.
Over/under collections are adjusted
quarterly through the Rider C process. The
AESO expects to file its 2009 deferral
account reconciliation in April 2010.
Historically, the application process end-toend takes several months.
The AESO has sufficient firm blackstart
contracts in place to restart the system in
the event of a system-wide blackout. The
AESO procures blackstart services on a firm
basis to ensure the availability of resources
when required.
In order to enhance system restart
capability, the AESO is pursuing additional
firm contracts with providers. The actual
cost for blackstart services in 2009 are
lower than the forecast because the AESO
has not contracted for the additional
blackstart resources anticipated in the 2009
cost forecast.
August 26, 2009
OTHER COMMENTS
April 29, 2009
June 10, 2009
Stakeholder Comment
AESO Response
Noted. The AESO would like to highlight it
The UCA does not have comments on each
performs a minimum of two cost/benefit reviews
strategic initiative individually. The main concern is
on every Information Technology capital
that there is limited Cost/Benefit analysis at this
initiative. The first is during the BRP budget
time. Many of the initiatives can only be accurately
development process, which provides high-level
assessed in light of the cost of implementation. As
cost benefit information to stakeholders. The
such, the UCA submits that the process should
second occurs prior to project approval/initiation,
include a second look at the initiatives when the
when the cost of options is available and
costs and budgets have been presented and
compared against identified benefits.
analysed. Support for some initiatives will be
contingent on the cost of implementation compared
to the benefits.
The UCA would request that all tables/schedules to
be presented in future sessions be produced in
Microsoft Excel format to allow easier analysis.
Noted. MS file formats will be considered when
releasing future BRP documents.
August 19, 2009
August 26, 2009
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2010 and 2011 Business Plan and Budget Proposal
TRANSCANADA
CONSULTATION PROCESS
April 29, 2009
Stakeholder Comment
AESO Response
Noted. This is a step in the proposed Budget
Comments on proposed BRP timeline
TransCanada would see value in the AESO
Review Process provided to stakeholders and
presenting the Draft Board Approval Document to
has been a historical practice.
stakeholders in early September, after it has been
posted and prior to comments being submitted on it.
This would give stakeholders a chance to ask
questions on it and improve the quality of
submissions.
Stakeholder comments on proposed terms of
reference These appear to be consistent with those
established in 2007.
Noted. There are no changes in the terms of
reference from those established in the prior
year.
Do you support the AESO proposing a two (2)
year general and administrative budget? Yes.
The two year budget and one year forecasts seem
to have worked well over the past two years.
Similar to last year, TransCanada suggests the
AESO update stakeholders on the second year
budget before it is provided to the AESO Board.
Noted
June 10, 2009
August 19, 2009
August 26, 2009
STRATEGIC PLAN & BUSINESS INITIATIVES
April 29, 2009
Stakeholder Comment
AESO Response
In prior years the AESO’s strategic objectives
Comments on the AESO’s strategic objectives:
The BRP Strategic Objectives have been different in were review by the AESO and minor
each of the past three years. TransCanada
modifications were undertaken. During 2008,
understands that over that time period there have
the AESO undertook a significant strategic
been changes within the AESO, in the marketplace
planning process to develop a new strategic
and in government policy. However, TransCanada
plan, including new strategic objectives. As a
considers Strategic Objectives to be longer range
result, the new strategic objectives will not link
and not as dynamic as Business Priorities, which
to those from the prior year and should be
may fluctuate yearly. Please explain why the
review on a standalone basis. The new
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2010 and 2011 Business Plan and Budget Proposal
Strategic Objectives have changed and also show
the progression or linkage between those in place
for the past two years and 2010.
strategic objectives were reviewed with the
senior executives of various stakeholders for
feedback.
In the future, the AESO will be better able to
provide stakeholders with feedback on the
AESO’s progress as it relates to the new
strategic objectives. At the June 10 stakeholder
meeting the AESO will further expand upon the
AESO’s strategic planning process.
June 10, 2009
August 19, 2009
August 26, 2009
GENERAL & ADMINISTRATIVE
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
CAPITAL
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
OTHER INDUSTRY
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
TRANSMISSION LINE LOSSES
April 29, 2009
June 10, 2009
August 19, 2009
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2010 and 2011 Business Plan and Budget Proposal
August 26, 2009
ANCILLIARY SERVICES
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
OTHER COMMENTS
April 29, 2009
June 10, 2009
August 19, 2009
August 26, 2009
Page 3