Transmission Cost Causation Study for the Alberta Electric System Operator (AESO)

London Economics International LLC
Transmission Cost Causation Study for the
Alberta Electric System Operator (AESO)
August 19th, 2013
Calgary, Alberta
LEI and project team
www.londoneconomics.com ■
LEI has worked with Alberta clients across the electricity sector
value chain on a range of issues associated with both regulated and
competitive assets
LEI gathered a team of dedicated professionals with required qualifications to perform the transmission cost
causation study. The team possesses considerable energy markets expertise and technical, evaluation,
strategy, and expert testimony expertise in transmission-related projects internationally, in North America,
and specifically, in Alberta
Team Member
Relevant Experience
A. J. Goulding
Team lead
Considerable energy industry, Albertaspecific, cost allocation and transmissionrelated project experience. Previously led
teams advising the AESO, the Balancing
Pool, and the Alberta Department of
Energy, and has worked with generators,
transmission companies, distributors, and
industry associations in Alberta
Gary Tarplee
Senior Engineering
Professional
30 years of energy transmission-related
work experience, including an engagement
directing the planning and engineering of
Edison International’s largest T&D capital
expansion in its history
Amit Pinjani
Project Manager
Worked on multiple Alberta-specific and
other cost allocation-related projects,
including a review and analysis of
historical and going-forward costs
associated with PPAs of a large
independent power producer
Ian Chow
Project Analyst
Worked on multiple Alberta engagements,
including analysis of risk management
practices of a large organization.
Significant experience with transmission
development in New York State
2
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Agenda
1
Scope and approach for current study
2
Functionalization of capital costs
3
Functionalization of O&M costs
4
Classification of bulk and regional costs
5
Implementation considerations
6
Appendix
Additional reference slides
Case studies – review of international jurisdictions
Previous cost causation studies and Board decisions
3
www.londoneconomics.com ■
Scope
LEI was asked to prepare a transmission cost causation study
for AESO covering both capital and O&M costs
►
►
Functionalization of Capital Costs

Research, recommend an approach to, and provide results for the functionalization of transmission facility
owner capital-related costs into bulk system, regional system, and point of delivery functions

Recommended approach must address both existing and planned transmission facilities that will give rise to
capital-related costs during the 2014-2016 period which will be covered by the AESO’s tariff application
Functionalization of Operating and Maintenance Costs

►
Classification of Bulk System and Regional System Costs

►
Functionalization of transmission facility owner operating and maintenance costs (including non-capitalrelated costs such as general and administrative costs, if appropriate)
Classification of bulk system and regional system costs into appropriate billing determinants (demand and
energy)
Implementation Considerations

Discuss considerations that may be relevant to the implementation of the functionalization and classification
results, in as much as implementation may be affected by the recommended approach and results

Considerations may include averaging the results to achieve rate stability, implementing results annually to
reflect cost causation, phasing in the results gradually, and other appropriate options
Classification of POD costs and rate design was outside the scope of this study
Relevant historical timeline (with respect to previous transmission cost causation studies)
2005
2005
Transmission
(Capital) Cost
Causation Study
2005
Board Decision
2005-096
2006
2007
2009
2010
2006
Transmission
(Capital) Cost
Causation Update
Board Decision
2007-106
2009 Operating
and Maintenance
Cost Study
Board Decision
2010-606
4
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Documents reviewed
LEI reviewed over two hundred documents, totaling over 500
megabytes, which aided in the development of this analysis
Sample of documents reviewed
AESO. AESO 2010 ISO Tariff Application (1605961 - ID 530)
AEUB. Decision 2007-106: 2007 GTA.
AESO. 2011 Unit Cost Estimates
AEUB. Decision 2010-606: 2007 GTA.
AESO. 2013 Planning Base Case Suite. January 24, 2013.
Alberta Energy. Transmission Development: The Right Path for Alberta.
December 22, 2003.
PS Technologies Inc. Electric Transmission Operating and Maintenance Cost
Study. December 10, 2009
Bonbright, James, Albert L. Danielsen and David R. Kamerschen. Principles of
Public Utility Rates,
AESO Point of Delivery database
California Independent System Operator Corporation. Fifth Replacement CAISO
Tariff. Mar 20, 2013.
AESO Draft Transmission Rate Impact Projection Model
Hydro One. EB-2012-0031 Exhibit G1. Tab 2. Schedule 1. Filed May 28, 2012.
National Association of Regulatory Utility Commissioners. Electricity Utility Cost
Allocation Manual. January 1992.
OEB. EB-2012-0031. Decision in the matter of an application by Hydro One
Networks Inc. for an approving of new transmission revenue requirements and
rates for the transmission of electricity in 2013 and 2014. Decision issued on
December 20, 2012.
Ontario Energy Board. Filing Requirements: Transmission Project Development
Plans; August 26, 2010.
ATCO quotes for transformer
Alberta Interconnected Electric System Map
Interveners’ submissions on Transmission O&M study
Need Identification Documents for Planned Projects
Ontario Energy Board. Board Policy: Framework for Transmission project
Development Plans; August 26, 2010.
Planning Base Case - 2015 data files
PS Technologies Inc. Alberta Transmission System Wires Only – Cost Causation
Study. January 25, 2005.
Project Progress reports – cost and schedule information (approx. 62 files)
PS Technologies Inc. Alberta Transmission System 2006 Transmission Cost
Causation Update. September 15, 2006
AESO. 2013-01-17 AESO 2014 Cost Causation Working Group
Presentation.
AEUB. Decision 2005-096: 2007 GTA
Meeting #1
AESO. AESO Long-term Transmission Plan. Filed June 2012.
TCWG meeting notes and underlying AESO analysis
AESO. Reasonableness Assessment of Transmission Cost Using Benchmarking
Methodology
TFO depreciation studies
AESO. TCE.AESO-004 (a-d) Revised. February 14, 2007
TFO Asset Data for Capital Cost Study
Rule 005 Annual Reports
TFO Data for O&M Study
TFOs tariff applications and underlying Excel files
5
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Approach
LEI functionalized and classified costs drawing upon
methods previously tested in Alberta
Project Categories
Existing and
future/planned
projects
Functionalization
Classification
Bulk
Demand
Energy
Regional
Demand
Energy
Point of Delivery
Methods:
 Voltage (recommended)
 Economics (considered)
 MW-km (considered)

Methods used:
Minimum System Approach
►
LEI utilized methods of cost allocation similar to prior studies, while enhancing the process by taking into
account planned/future projects
►
After reviewing the strengths and weaknesses of the different functionalization approaches and
considering the rate design principles, we recommend functionalization by voltage as the method going
forward
►
O&M costs were functionalized by first deriving non-capital costs from revenue requirement information
provided by the TFOs, and using allocators such as actual line and substation costs for related expenses,
proportion of full time equivalents in cost centers for salaries and wages etc.
►
For classification, we adapted the minimum system approach for the transmission system
►
After arriving at functionalization and classification results, we commented on implementation
considerations, providing recommendations consistent with cost causation
6
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Recommendatons
LEI’s recommendations focus on consistency with cost causation;
each will be discussed in greater detail in the presentation
Area
Recommendation
Functionalization by voltage approach going
forward
Functionalization
of Capital Costs
Functionalization
of O&M costs
Classification of
bulk and regional
costs
Implementation
considerations
Relative to 2007 GTA, significantly higher
proportion of costs functionalized as bulk, and
significantly lower as POD
Rationale / comments
 Least subjective and consistent with cost causation principles
 Has been acceptable to the Commission in the past and is
transparent for all stakeholders
 Consistent with expectations, given the amount of bulk projects in
the 2012 LTP
 Between 2007 GTA and end of 2016, bulk system costs are
projected to increase by approximately $9.5 billion, while POD
costs increased by around $1.8 billion
Use 2014 results for the period 2014-2016 (2015
and 2016 cost projections not available from
TFOs)
 Given that there is no material change in future capital cost
functionalization ratios between 2014 (bulk 84%) and 2016 (bulk
86%), a material change in O&M functionalization ratios is not
anticipated
Relative to previous O&M study, functionalization
of bulk O&M has increased from 16.5% to 29.1%
 Sensible given significant planned investment, however relative to
regional and POD functions, bulk has less O&M costs in proportion
to capital costs
Classify using the minimum system approach
 Results reflect cost causation
 Previously approved in Alberta
Higher proportions for demand-related costs as
compared to energy-related costs
 Expected because transmission primarily serves peak load
Apply combined capital and O&M
functionalization results
 Do not pose an issue of declining bulk charges in the face of
extensive bulk investment planned
Apply 2014, 2015 and 2016 results separately for
each of the three years
 Consistent with cost causation
7
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Agenda
1
Scope and approach for current study
2
Functionalization of capital costs
3
Functionalization of O&M costs
4
Classification of bulk and regional costs
5
Implementation considerations
6
Appendix
Additional reference slides
Case studies – review of international jurisdictions
Previous cost causation studies and Board decisions
8
Functionalization of capital costs > Definitions of transmission functions
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The process of functionalization allocates costs into three
functional groups: bulk, regional and POD
These three functions do not have universally accepted definitions, however, LEI has
defined them here generally, based on understanding of the Alberta transmission system,
the results of prior cost causation studies, and experience in other jurisdictions
Transmission
functions
Definition
► Defined as high voltage, and typically carries large amounts of electricity over
long distances

Provide high capacity interconnections between adjacent utilities or concentrated load
centers geographically separated

Typically operate at 500 kV and 240 kV AC or as High Voltage Direct Current (“HVDC”)

Point-of-supply (“POS”) substations which are used to connect generation are also
considered bulk
Bulk system
► Transmits electricity from the bulk system to load centers with numerous PODs
Regional system

The lines are typically lower in capacity and shorter in length than bulk power lines and
typically operate at 138 kV and 69 kV
► The point of delivery system serves distribution utilities or industrial customers
POD system
that connect directly to the transmission system

Most obvious to identify: point of delivery substations, radial transmission lines which serve
these substations, or radial transmission lines directly serving a customer can be
considered POD
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Functionalization of capital costs > Existing asset data
LEI received asset data from the four major TFOs with
varying levels of detail
► Line and substation-level
details data required for
functionalization
methods

Net book values

Voltages

Line lengths
TFO
Data Received
AltaLink
•
•
ATCO
•
•
•
Existing asset NBV ($ millions,
depreciated to 2016)
ENMAX
•
•
EPCOR
•
Missing Data
Line and substation-level details on
net book values, voltages and line
lengths
Substation secondary voltages
Original costs for lines and
substations
Line and substation-level details on
voltages and line lengths
Accumulated depreciation
aggregated to line and substation
totals
•
Line and
substation-level
details on net
book values
Net book values aggregated to
substation and transmission totals
Line and substation-level details on
voltages and line lengths
•
Line and
substation-level
details on net
book values
Net book values and accumulated
depreciation up to 2011,
aggregated to Genesee Switchyard,
transmission, and substation totals
•
Line and
substation-level
details on net
book values,
voltages and line
lengths
Net book values
and accumulated
depreciation for
2012
•
Functionalization of capital costs > Future asset data sources
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Sources for future asset data included 2012 LTP, AESO
benchmarking file and project progress reports
►
AUC instructed AESO to consider a forecast of capital build for the entire expected
effective tariff term, using the LTP as a starting point (Decision 2010-606)
►
The 2012 LTP (filed in June 2012) projected total cost estimate of $13.5 billion for
projects in service by 2020, with significant bulk investment
 Projects coming online until 2016 ($11.7 billion) were considered for the purpose of this analysis
►
AESO provided LEI with additional data sources beyond the data contained in the LTP
 AESO cost benchmarking data file: Provided significant future line data, mostly extracted from
Proposal to Provide Services documents, which are usually included with Needs Identification
Documents (“NID”s) and/or Facility Applications (“FA”s)
–
More up to date than the LTP data, though LEI understands that NID level documents have a cost estimate
which is of a +30%/-30% quality, while FAs are of a +20%/-10% or better quality
 Individual project progress report files (as of November 2012): Referred to as “progress reports”,
which are reports submitted to the Transmission Facility Cost Monitoring Committee (“TFCMC”)
►
LEI identified missing data to the AESO, and voltage information was provided for
specific projects and taken into account
 $2 billion of projects are still in the planning stage and have not progressed to the point where further
details are available
 $1 billion of the $2 billion is from the South Area Transmission Reinforcement (“SATR”), which is a
staged project meaning some stages are contingent on reaching particular milestones – therefore,
detailed cost data is not available
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Functionalization of capital costs > Recommendations for data tracking
LEI recommends initiation of specific requirements for data
tracking
►
Challenges were encountered in obtaining adequate data for
the analysis

►
►
One of the TFO’s line and substation-level asset information, net
book values, voltages, and line lengths were not received
Significant manual data matching was undertaken by LEI for
future/planned projects, as data was provided from multiple
sources which were not fully cross-referenced

AESO provided over two hundred documents for this analysis

Documents such as the project progress reports provided varying
levels of detail
LEI recommends making the TFOs aware of the specific data
requirements (line and substation level details on net book
values, voltages and line length), so accounting systems are
configured to take these requirements into account

Due to changes with systems and personnel at one of the TFOs, it
was not possible to confirm that the categories provided contain
the exact same accounts as the accounts used in the 2005
Transmission Cost Causation Study
►
Initiation of appropriate data tracking would reduce the effort
required for future cost causation studies or regulatory
proceedings by the TFOs and the AESO
►
Although LEI completed the analysis on a best effort basis, it
was not possible to guarantee 100% completeness of the data
Data requirements for lines
Line
#
Voltage
(kV)
Length
(km)
Radial
(Y/N)
Net Book
Value ($
million)
A
138
15
Y
4
B
240
20
N
10
Data requirements for substations
Sub#
Primary
Voltage (kV)
Secondary
Voltage
(kV)
Net Book
Value ($
million)
C
240
138
4
D
69
25
2
Functionalization of capital costs > Utilization of future data
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LEI followed a structured process to refine the information
received
• Any projects with in-service dates post-2016 were excluded
• LTP projects were matched with project reference codes
Data Matching
and Exclusion
• Using project reference codes and LTP descriptions, progress reports were matched to their
respective LTP projects
• Using project reference codes, the data in the AESO cost benchmarking data file was matched to LTP
projects
• Any AESO cost benchmarking data which did not match LTP projects was excluded (e.g. existing
projects)
• Any AESO cost benchmarking data with missing lengths or voltages was excluded
• AESO cost benchmarking data file was used as the starting point, as it provided line lengths and
voltages on a line by line basis, which was necessary for certain functionalization methods
Determining Final
Line Data
• Progress reports were assumed to be the most up-to-date source of information. Many line list
projects costs were similar to the progress report costs, and LEI multiplied the AESO cost
benchmarking data file costs by a scaling factor in order to update them for the latest information
• When progress reports were not available or insufficient, and AESO cost benchmarking data file costs
were similar to LTP costs, AESO cost benchmarking data file costs were used as they are deemed
to be more up to date than LTP costs
• Certain projects which were still in planning stages, and had not progressed to the NID stage were
lacking details. AESO provided voltage data for planning stage projects
• The June 2013 Draft Transmission Rate Impact Model ("TRIP") was used to update in service dates
of certain projects
Determining Final
Substation Data
• Progress reports were used as a starting point, as they were the most up to date data source, and
provided a breakdown of substation costs and voltages. The LTP did not break costs down at the
substation level
• Certain projects which were still in planning stages had not progressed to the NID stage, and were
lacking details. AESO provided voltage data for planning stage projects
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Functionalization of capital costs > Utilization of future data
Following the process presented on previous slide,
information was matched and organized into usable data
Data details
► Information without cost data cannot be
quantified and has not been included
► Lines with voltage information, but no
length information were functionalized by
voltage (~$100 million)
► Large projects with a construction
duration of more than 1 year (Hanna,
Foothills, SATR, East/West HVDC),
allowance for funds used during
construction (“AFUDC”) is accounted for

Applied assumptions in the AESO Draft
Transmission Rate Impact Projection Model
► For projects that come into service after
2016 as per the 2012 LTP (~$1.8 billion),
no construction work in progress (“CWIP”)
costs are in the revenue requirement in
and before 2016
► “Other costs” and data with missing
details do not have enough information to
be functionalized by the various methods,
but are taken into account when
calculating the weighted final
functionalization results
Total data used: $10.6B
Excluded: $2.8B

“Other Costs” are comprised of distributed
costs, owners’ costs, AFUDC, salvage and
engineering & supervision costs
Functionalization of capital costs > Functionalization methods
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LEI explored functionalization using three methods before
settling upon the voltage approach
Functionalization by:
Voltage
MW-km
Economics
www.londoneconomics.com ■ 16
Functionalization of capital costs > Voltage approach
Voltage levels of lines and substations are utilized to
functionalize capital costs by voltage approach
Functionalization by voltage (line voltage,
substation secondary voltage)
Existing and future assets: functionalization by voltage
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
86.0%
Regional
Existing assets
Future assets
69 kV
►
43.0%
29.7%
27.3%
12.6%
Regional
POD
Overall functionalization by voltage (weighted by NBV)
►
80%
70%
66.7%

All radial lines serving a single point of delivery
are considered POD

Radial lines serving a generator are POS, and
considered bulk
►
50%
40%
30%
17.6%
20%
15.7%
10%
0%
Bulk
LEI functionalized substations based
on secondary voltages

60%
Regional
POD
Although the voltage approach does not differentiate
between functions within a voltage level, LEI believes that
the distortions are few during the rate term (2014-2016),
and that this definition will be durable in the long term
240 kV
Existing and future lines functionalized
by voltage
1.4%
Bulk
138 kV
Bulk
Secondary voltage of 25 kV or lower is POD
Existing substations which have
contracted capacity specified in the
AESO POD database are functionalized
accordingly

Demand Transmission Service (“DTS”) contract
substations are POD

Supply Transmission Service (“STS”) contract
substations are point-of-supply (“POS”) and
therefore bulk

Substations with both DTS and STS contracts are
allocated to POD and bulk by their contract
capacity
Functionalization of capital costs > Economics approach
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Functionalization by economics compares the economics of
building a high or low voltage system
►
Functionalization by economics determines functional
categories by assessing whether it makes more
economic sense to build a high voltage line or a low
voltage line
►
Economic analysis performed on a hypothetical 240 kV
line with 240 kV PODs, compared against the cost of a
240-138 kV substation, 138 kV line and 138 kV PODs.
►
►

Option A is more economic for energy delivery with fewer
PODs and thus over longer distances

Option B is more economic if many points of delivery are
required, as the 138 kV PODs are less expensive than 240
kV PODs
Option A: 240 kV system with 240 kV PODs
Option B: 240-138 kV system with 138kV PODs
Relative cost of components determines the breakpoint
at which it would become economical to build Option B
rather than A

LEI first worked with AESO planners to determine typical
substation and POD design in Alberta

AESO 2011 Unit Cost Guide costs were applied to each of
the designs

Costs found in the 2011 Unit Cost Guide were then
validated against AESO Benchmarking Database for Alberta
Transmission Projects (March 28, 2013)
Lines that are below the breakpoint, measured in line
length, are considered regional, and lines above the
breakpoint are considered bulk
The hypothetical lines are both 150 km long, which for example
is the distance between Calgary and Red Deer, or Red Deer to
Edmonton
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Functionalization of capital costs > Economics approach
The economics approach uses a theoretical breakpoint to
functionalize 240 kV and 138 kV lines
Existing and future assets: functionalization by
economics
87.9%
Existing assets
Future assets
Functionalization by economics uses the same
rules as functionalization by voltage, except for
138 kV and 240 kV lines
►
For a low number of PODs, the 240 kV POD
system is economic, but as more PODs are
required, the 138 kV system becomes more
economic
43.0%
39.5%
600
17.5%
1.4%
Bulk
Regional
POD
Overall functionalization by economics
(weighted by NBV)
80%
300
200
100
0
0
70%
60%
40%
30%
13.0%
15.7%
Regional
POD
10
km between PODs
15
20

240 kV lines are economic when they are longer than
13.8 km, and thus, are treated as bulk; 240 kV lines
shorter than 13.8 km are more economic as 138 kV
systems, and therefore are considered regional

138 kV lines are economic when they are shorter than
13.8 km, and thus, are treated as regional; 138 kV lines
longer than 13.8 km are more economic as 240 kV
systems, and therefore are considered bulk
10%
0%
Compared to the voltage approach, the economics
approach results in slightly more bulk and less regional
functionalization; POD functionalization not affected
5
Assuming PODs are equal distance from one
another, estimated point at which the systems are
the same cost, or the breakpoint, is at 13.8 km
►
50%
Bulk
240 kV PODs
400
71.3%
20%
138 kV system
500
10.8%
Cost ($ millions)
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
►
Functionalization of capital costs > MW-km approach
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MW-km method utilizes MW loadings and line lengths
►
Functionalization by MW-km is based on the concept that bulk lines carry large amounts
of power over long distances
►
Lines with high MW-km ratings are considered bulk, while lines with lower MW-km
ratings are considered regional
►
Line lengths (km) were obtained from the data sources previously discussed
►
Line loadings (MW) were acquired from the AESO 2013 Planning Base Case Suite,
specifically using the 2015 winter peak case
►

The 2015 case was chosen in the absence of a 2016 case, as it lies within the rate period of 2014-2016,
and would thus be representative of system conditions during that time

The winter peak case was chosen, because in peak conditions, the system would be heavily loaded,
which would emphasize the function of transmission components
Functionalizing substations occurs by voltage, as there was insufficient data to match
individual substations to their respective secondary voltage lines, making it difficult to
functionalize substations by the MW-km approach
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Functionalization of capital costs > MW-km approach
One of the challenges with the MW-km approach is setting an
appropriate breakpoint
Lines with a higher MW-km rating than the
breakpoint are functionalized as bulk and lines
which are lower are functionalized as regional


►
The percentage is determined based on what
percentages of lines (by line length) are higher or
lower than a breakpoint

In the voltage approach, 240 kV lines are considered
to be bulk, while 138 kV lines are considered to be
regional
The average MW-km of 138 kV lines is 466 MW-km,
while the average of 240 kV lines is 3,662 MW-km
2,000 MW breakpoint was validated by ensuring


Higher than the maximum 69 kV MW-km rating
observed (1,614 MW-km), which ensures no 69 kV
lines will be functionalized as bulk
Lower than the minimum 500 kV line rating observed
(2,484 MW-km), which ensures no 500 kV lines will be
functionalized as regional
MW-km Rat ing
Volt age
Min.
Avg.
Max.
69 kV
0.3
87.2
1,614.0
138 kV
0.1
466.2
8,150.0
240 kV
4.4
3,661.5
27,570.8
500 kV
2,484.4
9,970.4
40,138.8
MW-km rating scatterplot
Breakpoint was chosen to be the midpoint at
2,000 MW-km

►
The MW-km method analyzes the MW-km ratings of
lines for each voltage, which determines percentage
of each voltage that are bulk or regional
MW-km rating distribution
45,000
500 kV
40,000
240 kV
138 kV
69 kV
35,000
MW-km Rating
►
30,000
25,000
20,000
15,000
10,000
5,000
0
0
200
400
MW
600
800
Functionalization of capital costs > MW-km approach
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The MW-km approach functionalizes more future assets as
regional relative to the other two approaches
Existing and future assets: functionalization by MWkm
Overall functionalization by MW-km (weighted by
NBV)
Among the three methodologies, the MW-km approach results in lowest bulk and highest regional
functionalization; POD functionalization remains the same across the three approaches
www.londoneconomics.com ■ 22
Functionalization of capital costs > Summary and recommendation
Previous cost causation study utilized an average of three
methods
Functionalization results (end of 2016)
80%
70%
71.3%
66.7%
62.5%
Economics
Voltage
MW-km
60%
50%
40%
30%
20%
13.0%
17.6%
21.8%
15.7% 15.7% 15.7%
10%
0%
Bulk
Regional
POD
www.londoneconomics.com ■ 23
Functionalization of capital costs > Methodologies
LEI recommends the voltage approach, as it reflects cost
causation and is least subjective
Method
Strengths
•
Least subjective; simple and
easy to understand
•
•
used across various
jurisdictions (Ontario,
California, and Australia)
less sensitive to evolving functions as
compared to MW-km (that uses current
loading forecasts)
•
high voltage projects serving a regional
purpose and low voltage projects serving
bulk purposes may not be taken into account
properly
•
setting theoretical line length of 150 km is
subjective
•
biased in functionalizing more costs as bulk
•
may not reflect evolving functions over time
•
may not be appropriate to apply current
economics to past projects
Voltage
•
Economics
MW-km
Weaknesses
•
results similar to other
methodologies
unique and measurable metric
•
reflects evolving functions
over time
•
subject to error in line loading forecasts
•
more representative of study
period, using forecasted flows
•
setting breakpoint is subjective
•
•
multiple metrics used
forecast is a single point in time and may not
be representative of all hours and years
Although LEI considered the MVA-km approach, it was not chosen for analysis, due to the subjective nature
of setting a breakpoint, an inability to reflect evolution of the system, and lack of prior use in Alberta or
elsewhere
Functionalization of capital costs > Clearly identifiable projects
www.londoneconomics.com ■ 24
As a method of comparing the functionalization approaches,
LEI also analyzed Clearly Identified Bulk Projects
►
Clearly Identified Bulk Projects (“CIBP”) are defined as LTP
projects that cross LTP bulk cut-planes
►
Assuming that all lines built within each clearly identified bulk
project are bulk, it is possible to compare the functionalization of
the voltage and economics methods

As an example, within the Foothills project, which is a bulk
project, a 240 kV line was built to connect Janet 74S to ENMAX
No. 25. The voltage approach classified this line as bulk, whereas
the economics method classified this line as regional
►
Available line data showed that the voltage approach
functionalized 2% of CIBP as regional, while the economics
approach functionalized 4% of CIBP as regional
►
Data that would allow LEI to determine performance of the MWkm approach in functionalizing CIBP was not available

The MW-km approach utilizes the 2015 AESO Base Case, which identifies lines by
bus, but does not indicate the LTP project to which each line belongs
Project Name
Cost w AFUDC
(2011 $ millions)
Cutplane Crossed
East/West HVDC
2,951
SOK Cutplane
West Fort McMurray 500 kV Stage 1a
1,649
Northeast Cutplane
Foothills (FATD)
711
South Cutplane
Heartland 500 kV
537
Northeast Cutplane
Bickerdike to Little Smoky
205
Northwest Cutplane
LTP bulk cut-planes
Functionalization of capital costs > Current study results vs. previously approved
www.londoneconomics.com ■ 25
Relative to 2007 GTA, capital costs functionalized as bulk are
projected to increase by over $9 billion by end of 2016
Updated capital cost functionalization by voltage
(2014-2016)
Updated 2016 functionalization compared against
2007 GTA functionalization
80%
Bulk
70%
Regional
66.8%
POD
66.7%
60.6%
60%
50%
40%
30%
20%
20.1%19.3%
17.7%
15.6%
17.6%
15.7%
2015
2016
10%
0%
2014
Current cost causation study shows a significantly higher proportion of costs functionalized as bulk, which
is consistent with expectations, given the amount of bulk projects in the 2012 LTP. Note that this would be
true under any of the three functionalization methodologies considered
www.londoneconomics.com ■ 26
Agenda
1
Scope and approach for current study
2
Functionalization of capital costs
3
Functionalization of O&M costs
4
Classification of bulk and regional costs
5
Implementation considerations
6
Appendix
Additional reference slides
Case studies – review of international jurisdictions
Previous cost causation studies and Board decisions
O&M cost functionalization > Information received and utilized
www.londoneconomics.com ■ 27
TFOs have not projected their O&M costs up to 2016;
information for two large TFOs used for functionalization
►
Information utilized for functionalization of O&M costs was received for AltaLink and ATCO (up until
2014), EPCOR (up until 2012) and ENMAX (until 2011) for functionalization of O&M costs
►
In addition to requesting specific data from the TFOs, the following sources (provided by the AESO) were
used for obtaining information:

AltaLink: GTA 2013-2014 Schedules

ATCO Electric: GTA 2013-2014

ENMAX Power: Transmission AUC Rule 005 report: Annual Operations Financial and Operating reporting for the year
ended December 31st, 2011

EPCOR: 2012 Phase I DTA & TFO TA Refiling
80-85% of combined transmission revenue requirement is attributable to ATCO and AltaLink over the
period 2006-2011
►
Individual TFO share (%) in combined revenue
requirement
50%
45%
40%
46%
44%
39%
46%
38%
38%
46%
46%
45%
41%
39%
38%
35%
30%
20%
10%
considered projecting the revenue requirement and
capital/non-capital cost split for ENMAX and EPCOR up to
2014 by observing their cost growth patterns relative to
ATCO and AltaLink historically, and extrapolating for the
future.

However, no clear linkages were found between their respective
revenue requirement growth rates, and any such forecasts would be
highly assumptions-driven
► LEI also reviewed cost information in project progress reports
25%
15%
► LEI
10%
7%
7%8%
10%
7%
10%
7%
9%
6%
5%
8%
5%
0%
2006
2007
AltaLink
2008
2009
ATCO Electric
2010
ENMAX
2011
EPCOR
received from AESO to observe the project cost split between
the four TFOs; over 95% of costs are attributable to ATCO
and AltaLink owned projects
► Given the small share of ENMAX and EPCOR in existing and
future
projected
costs,
assumptions-driven
revenue
requirement forecasts are unnecessary, as they will have an
immaterial impact on functionalization results
www.londoneconomics.com ■ 28
O&M cost functionalization > Breakdown of revenue requirement
Non-capital cost proportion of revenue requirement has been
gradually declining given significant capital investment plans
►
After obtaining revenue requirement information, costs that are capital-related and non-capital related
were identified. Non-capital costs included:

O&M costs directly associated with the electric transmission system such as labor costs, G&A costs associated with the operation
the overall business of the TFOs, affiliate revenue offsets, i.e., revenues that offset labor costs

Fuel and variable O&M costs associated with isolated generation serving remote communities was also included as non-capital
costs
─
ATCO Electric is the only TFO that reports fuel costs. The underlying rationale is that instead of building transmission facilities (i.e.
extending the regional and POD system) to serve certain remote areas, it is more economical to operate isolated generation facilities to
serve these areas
►
Since 2009, although the actual amount of non-capital costs has been increasing, the percentage of noncapital costs has been gradually declining steadily (particularly for the two largest TFOs, ATCO and
AltaLink), reducing projected overall share of non-capital costs to 16.01% by 2014
►
Given the significant capital investment plan in the LTP and a high proportion of investment related to
AltaLink and ATCO, it can be reasonably argued that this trend will continue and the non-capital cost
share would further decline by 2016

Using 5-yr rolling averages, non-capital cost share was forecasted for 2015 (14.2%) and 2016 (12.3%)
Non-capital costs (value and as a % of revenue requirement)
Non Capit al Cost s ($)
AltaLink
ATCO Electric
ENMAX
EPCOR
Sum of Four TFO
2009
2010
2011
2012
2013
2014
63,230,001 80,346,474 84,551,219 100,207,059 107,336,440 118,860,960
62,000,000 61,962,863 72,583,190 85,167,268 91,799,633 99,502,033
20,309,000 20,881,000 23,234,000
N.A.
N.A.
N.A.
14,723,524 18,073,084 19,055,546 20,094,570
N.A.
N.A.
160,262,525 181,263,421 199,423,955 205,468,898 199,136,073 218,362,993
Non-capital cost share – trend and projection
35%
Forecast
Actual
30%
25%
20%
Non Capit al Cost s/Rev Req.
2009
2010
2011
2012
2013
2014
15%
AltaLink
ATCO Electric
ENMAX
EPCOR
Combined for TFOs
25.6%
30.0%
56.0%
27.9%
29.5%
28.3%
25.4%
55.1%
32.8%
29.2%
24.0%
23.2%
57.3%
32.5%
26.1%
24.4%
20.9%
N.A
30.7%
23.3%
20.4%
16.9%
N.A
N.A
18.62%
17.4%
14.6%
N.A
N.A
16.01%
10%
5%
0%
2010
2011
2012
2013
2014
2015f
2016f
O&M cost functionalization > Allocators and results
www.londoneconomics.com ■ 29
O&M cost functionalization results are not anticipated to
change materially over the 2014-2016 period
► Similar to capital cost functionalization, O&M costs have been functionalized bulk, regional and POD
► Not all non-capital costs have been functionalized
 G&A costs, which are not directly associated with the operations of electric transmission system, but assist in overall operation of the
business, such as expenses associated with the maintenance of the corporate head office, have not been functionalized. Instead overall
O&M functionalization results have been applied to these costs
► With regards to functionalization of some other non-capital costs (other than G&A costs), the following approach
has been taken:

Fuel costs and variable O&M costs associated with isolated generation have been functionalized as regional or POD because any
transmission system otherwise being built to serve these small remote areas would likely be regional or POD (using overall capital cost
functionalization ratio of regional to POD)

Net salaries and wages have been allocated to various groups (such as control center operations, station equipment maintenance,
overhead line expenses etc.) using proportion of full time equivalents (“FTE”) in each group, where provided

Line and substation capital cost information split between bulk, regional and POD has been used to set allocators for related O&M
costs, such as overhead line expenses and substation expenses respectively
► Given the significant transmission investment in the current decade, an increase in functionalization of bulk
costs is observed (from 16.5% in previous study to 29.1% in current study), but relative to regional and POD, bulk
has less than average O&M costs in proportion to capital costs
O&M cost functionalization
40%
37.0%
33.9%
35%
30%
29.1%
As 2015 and 2016 projections are
not available, 2014 results have
been used for functionalization
purposes
Given that there is no material
change in future capital cost
functionalization ratios between
2014 and 2016, LEI does not
anticipate a material change in
O&M functionalization ratios over
the 2014-2016 period
25%
20%
15%
10%
5%
0%
Bulk
Regional
POD
Future capital costs
functionalization
Bulk
100%
90%
Regional
86.1%
84.1%
POD
86.0%
80%
70%
60%
50%
40%
30%
20%
10%
13.6%
2.3%
12.3%
1.5%
12.6%
1.4%
0%
2014
2015
2016
www.londoneconomics.com ■ 30
Combined capital and O&M cost functionalization > Results
Combined capital and O&M cost functionalization results are
consistent with planned transmission investment
Combined capital and O&M cost
functionalization
70%
Bulk
Regional
61.2%
►
POD
Capital cost and O&M cost functionalization results
were combined using combined non-capital to
capital costs ratio estimated for 2014 to 2016
Non-Capit al t o Capit al Cost s
Non-Capital
Capital
62.0%
2014
16.0%
84.0%
2015
14.2%
85.8%
2016
12.3%
87.7%
60%
55.2%
►
The combined functionalization results show a
higher proportion functionalized as bulk, as
compared to AEUB-approved functionalization in
AESO 2007 GTA
►
This is sensible given the significant amount of
bulk and regional investment planned to come
online in the 2012 LTP, as discussed in earlier
slides
►
The decline in POD functionalization since the 2007
GTA is due to relatively higher bulk and regional
investment compared to POD investment
50%
41.7%
40.9%
40%
30%
22.5%
22.3%
20%
17.4%
Capit al cost s funct ionalized ($ million)
20.1%
18.7%
19.6%
18.4%
Bulk
Regional
POD
Total
10%
►
0%
2007 GTA
(Capital only)
2014
2015
2016
2007 GTA
2014
2015
2016
678
233
572
1,482
6,681
2,215
2,124
11,020
9,685
2,561
2,261
14,507
10,175
2,677
2,397
15,248
Increase
(2016 vs. 2007)
9,497
2,444
1,825
13,766
Between 2007 and end of 2016, bulk system costs
are expected to increase by approximately $9.5
billion, regional system costs by $2.4 billion, while
POD costs by around $1.8 billion
www.londoneconomics.com ■ 31
Agenda
1
Scope and approach for current study
2
Functionalization of capital costs
3
Functionalization of O&M costs
4
Classification of bulk and regional costs
5
Implementation considerations
6
Appendix
Additional reference slides
Case studies – review of international jurisdictions
Previous cost causation studies and Board decisions
www.londoneconomics.com ■ 32
Classification > Methodologies
Classification separates functionalized costs into demand,
and energy
►
Classification separates functionalized costs typically to:
Demand costs (vary with kW
demand)
►
There are no standardized methods; all methods described below could be adapted for
use on the transmission system

►


First deployed for distribution systems, though PSTI previously adapted the minimum system approach
for the transmission system
A minimum system is defined and used to determine the demand component, since minimum system
costs are driven by serving total load
Additional costs for the optimized system are allocated to energy since costs incurred beyond the
minimum system are driven by energy usage considerations and to optimize for energy losses
Zero intercept method regresses installed costs to capacity, in order to find a no-load
intercept which represents the customer component


►
Previous cost causation studies utilized the minimum system and zero intercept methods
Minimum system approach utilizes the ratio between a minimum transmission system
and an optimized system to determine demand and energy components

►
Energy costs (vary with kWh
energy)
NARUC argues that it is more data intensive and the differences may be relatively small
Used in 2005 PSTI study to classify POD costs
LEI also considered marginal cost approach and average and excess approach, though
these were ruled out as they have been previously rejected in Alberta
Source: National Association of Regulatory Utilities Commissioners (NARUC) Electricity Cost Allocation Manual
www.londoneconomics.com ■ 33
Classification > Methodologies
LEI selected the minimum system approach for classification of bulk
and regional costs as it reflects cost causation and has been
accepted previously by the regulator
Method
Strengths
Minimum system
approach
•
results reflect cost causation
•
commonly used in distribution systems, though
can be adapted for use in transmission systems
•
previously approved by the Alberta Energy and
Utilities Board for bulk and regional classification
•
Minimum
intercept
Marginal cost
approach
Average and
excess approach
Weaknesses
•
actual minimum size can be subjective
may be more granular
•
requires considerably more data than minimum system approach
•
results reflect cost causation
•
results may be similar to minimum system approach
•
previously approved by the Alberta Energy and
Utilities Board for POD classification
•
may contributes to efficient resource allocation
•
marginal costs for transmission related investments are difficult to
determine
•
has been rejected in the past in Alberta
•
precision and simplicity of embedded cost method may be superior
•
no generally-accepted standard methodology
•
has been rejected in the past in Alberta
•
may provide a poor price signal to customers
•
takes into account actual line loadings
► To perform the minimum system approach, a minimum line and optimized line must be identified
► To approximate demand versus energy related costs, LEI has defined “minimum” and “optimal”
conductor sizes as comparable lines that TFOs would consider, where the optimized line minimizes
losses over the minimum line
► Cost information for various conductor sizes was sourced from the AESO cost benchmarking data file,
which was also used to determine future line details

The AESO cost benchmarking data file is estimated to contain 95% of the projects since 2005, and was filtered for new
projects with no missing conductor size or voltage data
www.londoneconomics.com ■ 34
Classification > Bulk conductor classification
Bulk system classification took into account 240 kV and 500
kV lines
LEI identified the commonly used conductor sizes in Alberta,
with input from AESO staff
►
Two most common 240 kV constructed conductor sizes are
2x795 and 2x1033 thousand circular mils (“MCM”) ACSR

These were defined to be minimum and optimal respectively

Minimum costs are average of 14 lines and optimal costs are
average of 18 lines from AESO cost benchmarking data file; costs
were compared against June 2013“Capital Cost Benchmark Study
For 240kV Transmission and Substation Projects”


►
Costs were normalized to a double circuit line strung both sides,
which is a common configuration in Alberta
The 240 kV conductor classification results in a ratio of 91.8%
demand to 8.2% energy
Limited data was found for 500 kV conductors in Alberta, so
costs were sourced from the California Independent System
Operator (CAISO)

The minimum was defined to be a 2x2156 MCM ACSR conductor
and the optimal was defined to be a 3x1590 MCM ACSR conductor

The 500 kV conductor classification results in a ratio of 90.5%
demand to 9.5% energy
The final bulk classification was determined by weighting 500 kV and
240 kV classifications together
The bulk conductor classification results in a ratio of 91.6% demand to
8.4% energy
240 kV - minimum and optimal
conductor size costs
1,800,000
1,600,000
Cost of Conductor ($/km)
►
1,591,085
1,460,991
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0
240 kV Line - 2 X 795
240 kV Line - 2 x 1033
Minimum System
Optimal System
500 kV - minimum and optimal
conductor size costs
www.londoneconomics.com ■ 35
Classification > Conductor and substation classification
Bulk conductor classification results in more than 90%
demand related costs
Regional Classification
►
►
Two most commonly constructed 138 kV conductor
sizes are 266 and 477 MCM ACSR, considered
minimum and optimal respectively
Costs were normalized to single circuit lines in order
for them to be comparable
Minimum costs are average of 46 lines and optimal
costs are average of 21 lines from AESO cost
benchmarking data file
138 kV - minimum and optimal conductor size
costs
$450,000
$416,963
Cost of Conductor ($/km)
$400,000
$350,000
$345,492
$300,000
$250,000
$200,000
► The optimized substation is defined as one which
minimizes losses over a minimum substation
► LEI was able to obtain a quote for a POD transformer
which included both:

a “Standard Losses and Sound Level” transformer, which
LEI has considered a minimum system, and

a “Lower No-Load Loss & Sound Level” transformer,*
which given its lower loss characteristic, LEI considers
the optimal system
Classification Percentage
►
Substation Classification
100%
2.8%
80%
60%
97.2%
40%
20%
0%
Demand Related Costs
$150,000
Energy Related Costs
► The
"minimum
system"
POD
transformer
is
approximately 2.8% less expensive than an "optimal
system" POD transformer
$100,000
$50,000
$138 kV Line - 266
138 kV Line - 477
Minimum System
Optimal Lines
The regional conductor classification results in a ratio
of 82.9% demand to 17.1% energy
► Regional and bulk power transformers are expected to
have a similar percentage cost increase in material and
manufacturing costs for an "optimal system"
transformer, and thus, the same results apply to both
regional and bulk power transformers
Classification > Substation classification and classification results
www.londoneconomics.com ■ 36
Classification results show that a majority of costs are
demand-related
Overall bulk and regional classification results
► To obtain final bulk and regional classification results, the line classification results were weighted
with substation classification results using line and substation asset values
► LEI’s classification results for both bulk and regional systems, which as one would expect, have
significantly higher proportions for demand-related costs as compared to energy-related costs
2007 Board decision:
►
Board does not consider that significant adjustments should be necessary in the foreseeable future; the Board
considers that the portion of wires costs classified as energy related should remain fairly low and be
determined by the cost of service study
Board decision quote
www.londoneconomics.com ■ 37
Agenda
1
Scope and approach for current study
2
Functionalization of capital costs
3
Functionalization of O&M costs
4
Classification of bulk and regional costs
5
Implementation considerations
6
Appendix
Additional reference slides
Case studies – review of international jurisdictions
Previous cost causation studies and Board decisions
www.londoneconomics.com ■ 38
Implementation considerations
LEI recommends using combined capital and O&M cost
functionalization results separately in each of the three years
Following three considerations analyzed by studying
the resulting revenue requirement breakdown:
I.
II.
III.
Whether results from the study would result in
reversing trends in rates that could give confusing price
signals;
If one part of the study would result in a change that
was opposite to a change from another part of the
study; and
Whether functionalization and classification
recommendations justify averaging or trending results
in order to improve stability of rates
Revenue requirement breakdown after applying
combined functionalization and classification results
Revenue Requirement Split ($ million)
Bulk - Demand
Bulk - Energy
Regional - Demand
Regional - Energy
POD
Total
2014
764
63
2015
1,011
83
2016
1,136
93
295
41
315
44
342
48
333
1,497
335
1,787
365
1,984
I: The resulting revenue requirement breakdown in table
above (after implementing combined functionalization and
classification results) shows that the requirement across bulk
and regional rate components is increasing on an annual
basis, indicating no reversing trends
* With the exception of POD where revenue requirement reduces slightly in 2015
Revenue requirement breakdown after applying
capital cost results only
Revenue Requirement Split ($ million)
Bulk - Demand
Bulk - Energy
Regional - Demand
Regional - Energy
POD
Total
2014
834
69
2015
1,100
90
2016
1,221
100
266
37
278
39
307
43
291
1,497
280
1,787
313
1,984
II: If one part of the study, i.e., only capital cost
functionalization results were applied (table above), the
impact is not in opposing directions, i.e., revenue
requirement trend remains positive and increasing across
most of the rate components*
 More costs being functionalized as bulk
 Sensible given that the bulk system function has less than
average associated O&M costs in proportion to capital
costs, as compared to the regional and POD functions
 LEI recommends applying combined capital and O&M
functionalization results as they are consistent with cost
causation, and they do not pose an issue of declining bulk
charges in the face of extensive bulk investment planned
III: Finally, to be consistent with cost causation, LEI
recommends applying 2014, 2015 and 2016
functionalization results separately to each of the three
years
www.londoneconomics.com ■ 39
Agenda
1
Scope and approach for current study
2
Functionalization of capital costs
3
Functionalization of O&M costs
4
Classification of bulk and regional costs
5
Implementation considerations
6
Appendix
Additional reference slides
Case studies – review of international jurisdictions
Previous cost causation studies and Board decisions
Appendix > Special projects
www.londoneconomics.com ■ 40
LEI was separately asked to identify ‘special’ projects, not
primarily planned to serve peak load
►
►
►
►
►
Discussions with the TCCWG indicated that members desired a distinction
between ‘conventional’ transmission projects in the LTP, which are primarily
driven by load, and ‘special’ projects
LEI has defined projects which are clearly driven to interconnect renewable
energy or driven by reliability purposes, but not primarily driven by load as
“special”
NIDs and details from the LTP have been used for initial identification of
special projects

LEI reviewed all 2012 LTP projects with costs greater than $100 million, accounting for
$12.3 billion (approximately 91% of all planned projects by value in the 2012 LTP)

Due to limited data availability/matching, LEI was unable to take a quantitative approach
to identify and/or validate special projects by analyzing utilization rates during winter
peak in the 2015 base case suite
Project Name
South Area
Transmission
Reinforcement
(SATR)
Bickerdike to
Little Smoky*
Cost w
AFUDC
(2011 $
millions)
Comments
2,287
Primarily
planned to
interconnect
renewable
energy (wind)
205
Primarily
planned to serve
under abnormal
system
conditions
LEI believes that special transmission projects are triggered as a result of public policy, and despite distinct purposes,
arguably have similar cost causation drivers to the rest of the system. The costs of special projects may be recovered in
one of two ways:

Treating it broadly as a social good, and recovering it as a tax (i.e. taxing every MWh equally); or

Recovering it consistent with purpose or key driver
‘Purpose’ may not necessarily be the same as the ‘cost causation driver’. For instance, for grid strengthening related to
emissions-free projects, it may be considered prudent to recover costs from customers who are causing some
environmental impact

Peak use likely causes greater emissions, which in turn drives demand for zero-emitting resources

While a line’s purpose may be to serve renewables, ultimately the needs for it may be driven by peak users
►
Furthermore, although a project may be built for the purposes of interconnecting renewable energy, significant portions
of the project are likely to serve peak load as well
►
Similarly, projects which are built for reliability purposes may not be primarily serving peak, but in practice, are likely to
still serve load in some capacity
* Note: Bickerdike to Little Smoky has not yet progressed to the NID stage, and should be re-evaluated once an NID is published. In addition, the June 2013 AESO Draft
Transmission Rate Impact Projection model states this project is scheduled to be in service in 2017
www.londoneconomics.com ■ 41
Appendix > Special projects
Special projects include costs that are primarily
functionalized as bulk
70%
Bulk
Regional
60%
POD
58.4%
Special
57.9%
52.5%
50%
41.7%
40.9%
40%
30%
22.2%
20%
22.3%
19.8%
17.4%
18.7%
19.2%
18.4%
10%
3.0%
4.4%
3.0%
0%
2007 GTA
2014
2015
2016
Implications of separating out special projects will depend on how these projects are classified and
incorporated into rates, if in a different manner, compared to other projects
Appendix > O&M cost functionalization > Impact of changing allocation basis
www.londoneconomics.com ■ 42
Impact of changing method for allocating certain line and
substation related O&M costs is not significant
O&M costs differently allocated
Current Study allocation
Substation expenses (station
equipment maintenance, substation
vegetation management)
Overhead line expenses
Previous O&M study allocation
•
Based on substation capital cost split
between bulk, regional and POD
•
Based on number of transformer split between
bulk/regional/POD
•
Based on line costs, i.e., line capital cost
split between bulk, regional and POD
•
Based on line lengths, i.e., line kilometers split between
bulk/regional/POD
•
Based on combined number of lines and transformers
•
Based on line lengths, i.e., line kilometers split between
bulk/regional/POD
•
Internal assessment; Data not received for current
study, using combined number of lines and
transformers instead
Control center costs
Miscellaneous transmission expenses
•
Based on combined line and substation
capital costs split between bulk, regional
and POD
Contracted manpower (AltaLink only)
Impact of revised allocation basis on O&M cost
functionalization
50.0%
Current Allocators
Similar to Previous allocators
40.0%
30.0%
60.0%
33.9%
30.4%
29.1%
Similar to Previous allocators
62.0% 61.6%
37.0%
35.0%
Current Allocators
70.0%
43.5%
45.0%
Impact of revised allocation basis on combined
functionalization (end of 2016)
26.1%
50.0%
40.0%
25.0%
20.0%
30.0%
15.0%
20.0%
19.6% 20.8%
18.4% 17.6%
10.0%
10.0%
5.0%
0.0%
0.0%
Bulk
Regional
POD
Bulk
Note: Due to change in AltaLink accounting systems, certain O&M cost categories and allocators were revised for AltaLink as well.
Slide revised after technical meeting to add impact on O&M functionalization graphic (bottom left hand side)
Regional
POD
Appendix > Rate design principles
www.londoneconomics.com ■ 43
AESO has identified five rate design principles, based on
Principles of Public Utility Rates by Bonbright et al
1
Recovery of total revenue requirement
2
Provision of appropriate price signals that reflect all costs and benefits
3
Fairness, objectivity and equity that avoids undue discrimination and
minimizes inter-customer subsidies
4
Stability and predictability of rates and revenue
5
Practicality, such that rates are appropriately simple, convenient,
understandable, acceptable and billable
Source: Bonbright, James. Principles of Public Utility Rates. 1988
www.londoneconomics.com ■ 44
Approach > Cost allocation process
Cost allocation exists at the boundary between transmission
planning and pricing
Identify
potential
projects
Evaluate project
net benefits
Select projects
to pursue
Allocate
costs/benefits across
customers
Planning
►
Develop set of
customer
charges
Pricing
Three main steps to cost allocation process
Functionalization
Classification
Allocation
►
Dominant method of cost allocation is embedded cost studies, which are based on historical or known
costs
►
Functionalization is defined as grouping costs together with others that perform similar functions.
Typical functions for the entire system include: (i) Production or purchased power; (ii) Transmission; (iii)
Distribution; (iv) Customer service and facilities; and (v) Administrative/general
►
When a transmission system is functionalized into only one transmission cost group, it is referred to as
the “rolled-in method” and when placed into more groups, it is referred to as the “subfunctionalized
method”

Rolled-in method is used for highly integrated transmission facilities (where the network allows many alternative
flows for power to flow). It is treated as a single system as all elements are considered to contribute to the
economic and reliable operation of the overall system

Subfunctionalized method is used to further distinguish the network. It can be based on line configuration,
geography, or voltage, as well as other features. Due to high data requirements, this method should be used only
for categories which have different cost consequences
Source: National Association of Regulatory Utilities Commissioners (NARUC) Electricity Cost Allocation Manual
www.londoneconomics.com ■ 45
Appendix > Economics approach cost updates
LEI has updated costs associated with ‘economics’
functionalization approach using AESO's 2011 unit cost guide
2005 Analysis
Station
Type
Element
240 kV circuit breaker (“CB”), ring
buss & termination
240/138-100
MVA Station
Number of
Elements
Cost per
element
Number of
Elements
Cost per
element
2
$1,000,000
3
$2,010,000
1
$3,810,000
Site development & control bld
240/138-100 MVA transformer
1
$1,990,000
1
$4,000,000
138 kV CB, disconnects &
termination
4
$750,000
3
$1,490,000
240 kV CB's, ring buss &
termination
2
$1,000,000
3
$2,010,000
1
$3,810,000
1
$3,000,000
1
$1,960,000
Site development & control bld
240/25 kV 25
MVA POD
240/25-25 MVA transformer
2
$660,000
25 KV switch gear & buss
25 kV CB's
4
$250,000
4
$230,000
138 kV CB & termination
2
$750,000
1
$1,490,000
1
$1,460,000
1
$2,400,000
1
$1,960,000
4
$230,000
Site development & control bld
138/25 kV 25
MVA POD
Update using AESO's 2011 unit
cost guide
138/25-25 MVA transformer
2
$600,000
25 KV switch gear & buss
25 kV CB's
4
$250,000
www.londoneconomics.com ■ 46
Agenda
1
Scope and approach for current study
2
Functionalization of capital costs
3
Functionalization of O&M costs
4
Classification of bulk and regional costs
5
Implementation considerations
6
Appendix
Additional reference slides
Case studies – review of international jurisdictions
Previous cost causation studies and Board decisions
www.londoneconomics.com ■ 47
Case Studies > Overview
LEI reviewed relevant methodologies in four other
jurisdictions with unbundled transmission charges
2012 Peak Transmission
Jurisdiction
Load (MW)
Lines (km)
10,609
21,000
Alberta
Australia
California
Ontario
31,084
25,865
23,954
57,086
Great Britain
Voltages
Used
500kV
240kV
138/144 kV
115/70 kV
40,000
500
330
275
132
kV
kV
kV
kV
41,600
500 kV
230 kV
115 kV
70 kV
30,000
500 kV
230 kV
115 kV
7,200*
400 kV
275 kV
132 kV
Degree of
Unbundling
Most Recent Tariff Decision
Period
Date of
Decision
Transmission
December
charge
2011-2013
2010
unbundled
Transmission
charge
2012-13 to
unbundled
2016-17
Transmission
charge
unbundled
Transmission
charge
unbundled
April
2012
Entity
Regulator
AESO
Alberta
Utilities
Commission
(“AUC”)
Powerlink
Australian
Energy
Regulator
(“AER”)
September
San Diego
December
2012
Gas & Electric
2011
onwards
Company
2012
Transmission
charge
2011-2012
unbundled
FERC
November
2011
Hydro One
Ontario
Energy
Board
(“OEB”)
March
2011
National Grid
Electricity
Transmission
Office of
Gas &
Electricity
Markets
(Ofgem)
Sources: AESO, Alberta Energy, IESO, Australian Energy Regulator, NEM, CAISO, UK Department of Energy and Climate Change, National Grid; *National Grid only
www.londoneconomics.com ■ 48
Case Studies > Ontario
In Ontario, transmission costs are functionalized, which are
used to set uniform rates for all customers
►
Assets functionalized into categories by voltage and what transmission elements they connect

►
Network, Dual Function Line (Network and Line Connection), Line Connection, Transformation Connection, Generation
Station Switchyards, Wholesale Meter, Common, and Other (details on next slide)
Functional categories are then assigned directly to four rate pools

Network Pool, Line Connection Pool, Transformation Connection Pool, and Wholesale Meter Pool
►
The transmission system in Ontario sets uniform rates for all customers, which means the rate for network, line
connection and transformation connection services are the same for all customers connected to the transmission
system
►
2013 approved monthly rates ($/kW) are assigned on a demand basis

Network Service Rate: $3.63 (at higher of coincident peak, or 85% of peak demand on weekdays between 7AM and 7PM)

Line Connection Service Rate: $0.75 (at Non-Coincident Peak demand (MW) in any hour of the month)

Transformation Connection Service Rate: $1.85 (at Non-Coincident Peak demand (MW) in any hour of the month)
Ontario Cost Allocation Process
Sources: ‘Description of Cost Allocation Methodology’: Hydro One
Hydro One 2013 Revenue Requirement
www.londoneconomics.com ■ 49
Case Studies > Ontario
Hydro One assets in Ontario are functionalized into eight
categories
Line
Connection
Assets
Network Assets
500 kV or 230 kV
transmission facilities
which connect network
stations to each other
Used for the benefit of
all customers


Transmission circuits
and stations operating
at 230 kV or 115 kV

Transformation
Connection Assets

Transformer
stations which step
down from above 50
kV to below 50 kV
Wholesale
Meter Assets

Metering facilities
used for billing and
settlement for
transmission and/or
wholesale energy
charges
Dual Function
Line Assets
Used both for the
benefit of all customers
and as a line connection
asset

Generation Station
Switchyards Assets

Switchyards which
connect generating
stations to the
transmission system
Common
Assets

Network, Line Connection, and
Dual Function Line Assets
Assets that serve
the operation of the
overall provincial
system (e.g. control
rooms,
administration
buildings)
Sources: ‘Description of Cost Allocation Methodology’: Hydro One.
 Network Assets link network
substations, major sources of generation,
or major sources of load
Other

Transmission
facilities which
cannot be assigned
to any other
category
 Line Connection Assets connect
network stations to load and/or
generating stations
 Dual Function Line Assets are tapped to
load and are normally operated parallel
with network circuits or other Dual
Function Lines or connect the
interconnection circuits
www.londoneconomics.com ■ 50
Case Studies > California
California Transmission Access Charge functionalized into
two categories, further functionalized by voltages
►
Transmission Access Charge (TAC) includes costs for transmission facilities under CAISO operational
control
►
Functionalized into two categories, then by voltage, and is recovered through variable energy rates
►
CAISO uses a $/MWh charge as it believes that it best captures use of the transmission system. Any
demand related costs are indirectly built into this $/MWh charge
Location Constrained Resource
Interconnection Facility (LCRIF)
Network Transmission
Facility
►
High voltage, 200 KV and above

►
►
High Voltage Access Charge is a uniform $/MWh rate for all
Participating Transmission Owners (PTO) loads

Charge is the sum of individual PTO high voltage transmission
revenue requirements divided by the sum of the PTO loads in
MWh

Similar to Alberta’s bulk classification by voltage approach
Low voltage, below 200 KV
Location Constrained Resource
Interconnection Facility (LCRIF)

►
Ratemaking and financing methodology
to encourage the development of
transmission in resource rich areas with
inadequate transmission
PTO rate recovery from:

Generators that subscribe to a portion
of the capacity

Low Voltage Access Charge is a unique $/MWh rate for each
PTO’s area load


Charge is the PTO’s low voltage transmission revenue
requirement divided by the PTO’s area load in MWh
Unsubscribed capacity costs are added
to the TAC


Similar to Alberta’s regional classification by voltage approach
As generation is developed and
subscribes to the line, cost recovery is
transferred to the generator and the
TAC reduced accordingly
Sources: Fifth Replacement California ISO tariff
Case Studies > Australia
www.londoneconomics.com ■ 51
In Australia, costs are functionalized into entry, exit, common
transmission and transmission use of system services
►
Separate prices are developed for each category of prescribed transmission service, which are recovered on
fixed annual charges and variable energy charges

Entry service – connection assets servicing a generator or a group of generators at a connection point - must be a fixed
annual amount, which can vary by customer. It is recovered on a fixed $/day price

Exit services – connection assets servicing a customer or group of customers at a connection point - must be a fixed
annual amount, which can vary by customer. It is recovered on a fixed $/day price

Transmission Use of System (TUOS) services cover the costs of shared network assets and non-asset related grid
support

►
─
Location component is based on contract agreed maximum demand basis ($/MW/day)
─
Non-location component is postage-stamp based. It is determined on the basis of either a contract agreed maximum
demand or historical energy and is calculated annually, depending on how the customer sets up their contract terms
Common transmission services that provide equivalent benefits to all transmission customers – “postage-stamp” basis
(same fixed cost for all customers). Recovered on the basis of contract agreed maximum demand or historical energy
Transmission assets are attributed directly to each category as much as possible, and if not, are attributed
using an “appropriate causal cost allocator”

E.g. cost allocation based on number of circuit breakers that can be attributed to the different categories
ElectraNet Prescribed Transmission Service Price Schedule – July 1, 2012 to June 30, 2013
Case Studies > Great Britain
www.londoneconomics.com ■ 52
Great Britain performs cost causation differently from North
American jurisdictions
►
National Grid charges for the use of the transmission system on behalf of National Grid Electricity
Transmission, Scottish Power Transmission and Scottish Hydro-Electric Transmission, using the
Transmission Network Use of System (“TNUoS”) tariff

Unlike the majority of North America, the TNUoS is paid for by both generation and demand resources, where generation pays
for 27% and demand pays for 73% of the costs

Generators that directly connect to the transmission system or embedded generators with a Bilateral Embedded Generation
Agreement (“BEGA”), and those that are equal to 100 MW or larger are liable to pay TNUoS charges
►
The TNUoS is composed of two components: a locational charge and a residual charge
►
The locational component is classified using a marginal cost
methodology known as the Investment Cost Related Pricing
(“ICRP”)
►

The ICRP estimates long run marginal costs of investment required for the
transmission system, caused by an increase in demand or generation at
each connection point or node. Hence, different costs are calculated for
different locations in the market

A metric used to measure investment costs is MW-km, which is unrelated to
the MW-km method described for functionalization. In the context of the
TNUoS, marginal costs are estimated in terms of increases or decreases in
units of kilometers of the transmission system, for a 1 MW injection to the
system.
The residual, non-locational component of the TNUoS tariff is
meant to recover the remaining amount of the revenue
requirement that is not recovered by the locational component

This portion exists because the marginal cost model for the locational
component assumes smooth, incremental investment. However, in reality
this capital investment is “lumpy”

Large investments can be made for future requirements, which mean the
system becomes non-optimal. The difference between the actual, nonoptimal system is accounted for by the residual component.
Great Britain demand use of
tariff zones
www.londoneconomics.com ■ 53
Case Studies > Summary
Cost causation methodologies differ from one jurisdiction to
another
Jurisdiction
Functional Groups
Classification Groups
Allocation Method
Alberta
Bulk, Regional, Point of Delivery
Demand, Energy, Point of
Delivery
Based on 12CP and NCP
peak demands and energy
Australia
Entry Service, Exit Service, Transmission Use of System Service, Common
Transmission Service
Based on fixed $/day and
$/MW/day maximum
demand rates
Network Transmission Facility,
Location Constrained Resource
Interconnection Facilities
Based on locational and
uniform $/MWh rates
California
High Voltage, Low Voltage
(referred to as further
functionalization)
Network Pool, Line Connection
Pool, Transformation
Connection Pool, and Wholesale
Meter Pool (referred to as rate
pools)
Ontario
Network, Line Connection, Dual
Function Line, Transformation
Connection, Generation Station
Switchyards, Wholesale meter,
Common, Other
Great Britain
Loads that pay the TNUoS can be differentiated into half-hourly (“HH”)
metered (peak loads larger than 100 kW), and non-half-hourly (“NHH”)
metered (smaller than 100 kW)
Based on Coincident or
Non-Coincident Peak
demand
Locational charge
(calculated using marginal
cost classification
approach) and residual
charge
►
While Alberta’s methodologies may seem unique, there is no single template or standard transmission
cost causation methodology observed across jurisdictions
►
Elements of voltage approach observed across jurisdictions, probably because it is ‘simple and easy to
understand’
www.londoneconomics.com ■ 54
Agenda
1
Scope and approach for current study
2
Functionalization of capital costs
3
Functionalization of O&M costs
4
Classification of bulk and regional costs
5
Implementation considerations
6
Appendix
Additional reference slides
Case studies – review of international jurisdictions
Previous cost causation studies and Board decisions
www.londoneconomics.com ■ 55
Appendix
Previous cost causation studies and Board decisions
2005 Cost Causation Study and Decision 2005-096
2006 Cost Causation Update and Decision 2007-106
2009 O&M Study and Decision 2010-606
2005 Cost Causation Study
www.londoneconomics.com ■ 56
In the 2005 study, the system was separated into three
functions, allowing each to be studied independently
►
►
►
The transmission system wires costs were viewed as
providing three functions: bulk delivery of electric energy,
regional delivery, and the points of delivery (POD)

Bulk system delivers large amounts of electric energy to a
large group of customers, while the regional system
provides service to a small group of customers, while the
point of delivery provides service at one location,
generally to one customer

The current study will call the local system the “regional”
system
Functionalization by Voltage Level
Three options identified to achieve functionalization

By voltage level

By economics

By MW-kM
Functionalization by voltage level


Three voltage levels considered
─
Bulk: 500kV and 240kV
─
Regional: 138/144 kV and 69/72 kV
─
Point of delivery (POD): radial lines and POD substations
May not provide accurate view in remote areas where
facility may be both bulk and regional
─
Each of the approaches takes a different perspective – this is
one of the reasons why weighing results from the approaches
may make sense
─
Other approaches have a more detailed way of functionalizing
these types of projects
Source: 2005 Cost Causation Study
Summary of Functionalization Results
2005 Cost Causation Study
www.londoneconomics.com ■ 57
Functionalization by voltage, economics and MW-km gave
similar results, which were averaged
By economics
►

High voltage lines are more economical and are typically used for
longer distances

By economics, if 240 kV line (which would be bulk by voltage) length is
shorter than 6km, it is actually being used for regional system
functions and is functionalized as such

Similarly, if a 138 kV line (which would be regional by voltage) is longer
than 6 km, it is actually being used for bulk system functions and is
functionalized as such

All radial lines are POD; 69/72 kV lines are regional

Biased to functionalizing towards bulk system, may not reflect function
of how system evolved
─
Functionalization By Economics
Given the available history of documented need for projects, LEI is in the process
of reviewing Need Identification Documents (NIDs), which may be useful to
validate recommendations of the current study
By MW-km
►

Bulk electricity system transports high amount of energy for a long
distance, hence MW-km measure. Higher MW-km indicates a line is
operating for the bulk system

MW loading was forecast during winter peak because all transmission
elements are in service

3,000 MW-km chosen to differentiate between bulk and regional

All radial lines are POD

69/72 kV lines are regional; 500 kV lines are bulk

Can functionalize lines as regional system if lightly loaded in winter,
although it could be heavily loaded and bulk system during other
periods
Functionalization By MW-km
Source: 2005 Cost Causation Study
2005 Cost Causation Study
www.londoneconomics.com ■ 58
Costs associated with each function were classified as
demand, energy or customer related
►
Three categories of classification:
(i) Customer , (ii) Demand, (iii) Energy
►
Minimum System Approach used
to differentiate between demand
and energy classification for bulk
and regional functional groups
►

No customer class

Approach compares a minimum
system to an optimal system

Minimum system is based on smallest
construction standard, and cost is
considered demand related

Optimized system, which minimizes
total cost of capital and energy losses,
is considered energy related

Additional cost of upgrading the
design to optimize the system is
considered energy related because it
is the transportation of additional
energy that drives this cost
Bulk and regional costs are about
80% demand related and 20%
energy related
Source: 2005 Cost Causation Study
Classification of Bulk Transmission Lines by
Minimum System Approach
Substation and Line Costs Weighted to calculate
Final Bulk Classification
Summary of Classification Results
2005-096 Decision
www.londoneconomics.com ■ 59
2005 Decision noted that conducting the Transmission Cost
Causation Study (TCCS) was a unique process
►
TCCS considered to be a good first step, though improvements suggested for future studies:

A reasonable portion of TFO costs are related to O&M and a material percentage of these may be energy related –
need to be researched in further studies

TCCS appears to have studied only two of many bulk lines in its analysis; in future studies, AESO will conduct a
more thorough review of all those lines comprising the bulk system, in order to provide a more accurate
indication as to the exact portion of costs that are energy related
►
Wires costs should be classified as 20% energy to be collected evenly over all hours; balance of wires
costs should be collected through two demand charges – one related to the bulk system and the second
relating to regional system and POD related costs
►
Amount of dollars related to the bulk system, and therefore the percentage of costs allocated to bulk
system costs, may increase in the future
Potential implications for current study
►
MW-km method noted as the strongest because it most closely aligns the purpose of transmission facilities to
their functional category, however relevant input data for significant planned projects may not be available
►
Averaging of the three different approaches provides sufficient balance; LEI will also explore weighting or
eliminating one ore more methods
►
Board considers NBV to be an appropriate basis upon which to base the functionalization of costs (NBV drives
the return, tax and depreciation calculations of the TFO revenue requirements)
►
Demand charge for bulk costs should be collected on the basis of coincident peak (12 CP approach); for
regional and POD costs, demand costs should be collected on the basis of non-coincident peak (NCP),
including the use of a ratchet
Source: EUB 2005-096 Decision
www.londoneconomics.com ■ 60
Appendix
Previous cost causation studies and Board decisions
2005 Cost Causation Study and Decision 2005-096
2006 Cost Causation Update and Decision 2007-106
2009 O&M Study and Decision 2010-606
2006 Capital Cost Update
www.londoneconomics.com ■ 61
AESO commissioned the Transmission Cost Causation Update
(TCCU) to conduct a more thorough analysis
►
TCCU constituted a “more thorough review of all those lines comprising the bulk system,”
as directed by the Board in Decision 2005-096

Qualitative analysis included interviewing AESO system planners (regarding transmission paths, upgrades to the
bulk transmission system, and causes of maximum stress on bulk transmission lines)

Quantitative analysis to assess the correlation between the time of maximum stress on the bulk system and the
time of Alberta Internal Load (AIL) peak load
►
The qualitative review showed that transmission planning is a complex process; instead
of being dominated by any one simple factor such as AIL peak load, it is driven by various
independent factors such as the location and daily/seasonal profiles of load and
generation and the configuration of the electric transmission system
►
Quantitative analysis* showed a correlation of only 1% (in 2004) and 8% (in 2005)
between individual bulk line loads (weighted by line length) and AIL

Analysis based on metered data for the 8,760 hours and individual bulk line loads over seventy nine 240 kV bulk
transmission lines.

TCCU acknowledged certain shortcomings: transmission planning is conducted without including opportunity sales;
however actual meter data includes actual imports and exports (opportunity sales).

The AESO maintained that the total amount of exports was small in comparison to the Alberta load (1.5%) and
therefore any adjustment for exports would have only a minimal impact on the circuit loading data.

No provision was made for adjustments to the meter data to account for abnormal conditions, such as transmission
contingencies or generator outages.
As discussed on next slide, the quantitative analysis presented by TCCU was heavily criticized by the
interveners and the Board
* For purposes of this study the 240 kV circuits were assumed to represent the bulk system.
Source: 2006 Transmisison Cost Causation Update
2007-106 Decision
www.londoneconomics.com ■ 62
In the 2007 Decision, Board found significant adjustments in
rate design may not be necessary in the foreseeable future
►
As a result of TCCU, final functionalization and classification results were very slightly revised as
compared to Decision 2005-096
►
TCCU presented the hypothesis that peak load did not correlate to maximum stress on the system and
that it was load in all hours that mattered

Board rejected this hypothesis that there is a weak correlation between circuit load and the system peak; Board
considers that system peak is more important than load in every hour
►
Unbundled costs (that is, separate rate components for bulk and regional wires) will allow the
flexibility to design rates more reflective of cost causation and allow for more appropriate and effective
price signals to customers
►
AESO proposed to use an Average & Excess (A&E) methodology to classify wires costs

In the A&E approach, the average component is determined by the average system load factor, which determines
the energy-related classification of transmission costs (estimated at 48.6%); excess component represents the
amount of system load above the average (estimated as 1 - 48.6% = 51.4%)

The Board rejected this approach; transmission assets represent a long-term fixed investment, and vary very little
based on usage; classifying 48.5% of costs as energy-related provides a poor price signal to customers to shift
their load away from peak hours to reduce demand at the system peak
Potential implications for current study
►
Continue to use minimum system approach to classify wires costs (as performed in TCCS and updated in
TCCU)
►
Bulk and regional wires costs are to continue to be unbundled so that the balance of these costs could be
collected through two different demand charges; demand charges related portion of bulk and regional wires
costs are to be collected through a 12 CP and NCP respectively
►
Board does not consider that significant adjustments should be necessary in the foreseeable future; the Board
considers that the portion of wires costs classified as energy related should remain fairly low and be
determined by the cost of service study
Source: 2007-106 Decision
www.londoneconomics.com ■ 63
Appendix
Previous cost causation studies and Board decisions
2005 Cost Causation Study and Decision 2005-096
2006 Cost Causation Update and Decision 2007-106
2009 O&M Study and Decision 2010-606
2009 Operating and Maintenance Cost Study
www.londoneconomics.com ■ 64
The O&M study functionalized by voltage level only, and
classified largely on the same basis as capital costs
►
►
Revenue requirement

Capital is approximately 70% of revenue requirement

Non-capital costs are 30% of revenue requirement
─
Made up of O&M costs (related to in service transmission facilities) and General and Administrative (G&A)
─
O&M is primarily labor related
Functionalization by voltage level easy to understand and correlates to electric transmission facilities
Bulk Transmission System
Defined as the 240 kV and 500
kV transmission facilities,
including substations that
transform voltage to a lower
transmission voltage (i.e.
240/138 kV substation).
►
Regional Transmission System
Consists of the 138/144 kV and
69/72 kV transmission facilities

Studied data from 2008

Functionalized by O&M costs, but applied to all-non capital costs

Examples of functionalization
Point of Delivery (POD)
Includes radial transmission lines
and point of delivery substations
─
Lengths of underground lines at each voltage were used to functionalize underground line costs
─
Transformer counts at each voltage were used to functionalize station equipment expenses
Classification

Fuel is classified as energy related as it is related to energy consumption in off-grid communities served by remote
generators

Other O&M costs classified on the same basis as capital costs
Source: 2009 O&M Cost Study
2010-606 Decision
www.londoneconomics.com ■ 65
The Board directed AESO to consider future capital build over
the entire next tariff term in its 2010 Decision
►
The Commission was generally favourable towards the O&M study, stating the “Commission considers that the
Transmission O&M Cost Study results provide useful information which, under normal circumstances, should be
reflected in the AESO’s rate design
►
The Commission did not incorporate the O&M study into the AESO rate design, given the results would increase
regional/POD rates with respect to bulk, whereas the major capital additions during the tariff term would do the
opposite
►
Interveners raised concerns about study data, including use of just a single year, unavailability of ENMAX data,
as well as the lack of detailed accounting data available to the Consultant

►
The Commission was satisfied that the study was undertaken ‘in good faith and on a best efforts basis that provided
reasonable results’
Despite requests to complete a cost causation study earlier, the Commission agreed the GTA and cost causation
should be submitted together to maximize efficiency, no later than March 31, 2013
Potential implications for current study
►
The commission agreed with the AESO that isolated generation charges should be functionalized into regional and
POD charges; however, the Commission denied classification of those charges as energy, rather preferring the
proportions used for all other regional and POD costs
►
The commission directed AESO to consider a forecast of capital build for the entire expected effective term of the
AESO’s next tariff, using the Long Term Transmission Plan (LTP) as a starting point
►
Dual Use Customers (DUC) requested AESO use derived replacement cost new (RCN) values for the next study.
Although the commission did not direct the AESO to make this change, it also did not preclude it from doing so
►
Interveners noted that there is likely to be a significant increase in the proportion of bulk transmission facilities
built for reasons other than providing reliable delivery at times of peak load and, as a result, there is a strong
possibility that the classification of bulk transmission facilities will change to a more energy-intensive
classification

Some other reasons suggested are as follows: (i) facilitating exports and connection of renewable generation, (ii)
opening markets for generators and rendering markets more competitive, and (iii) relieving congestion that would
otherwise require the operation of generation out of merit order in accordance with government policy
Source: AUC 2010-606 Decision