Decision 2009-035
ENMAX Power Corporation
2007-2016 Formula Based Ratemaking
March 25, 2009
ALBERTA UTILITIES COMMISSION
Decision 2009-035
ENMAX Power Corporation
2007-2016 Formula Based Ratemaking
Application No. 1550487
Proceeding ID. 12
March 25, 2009
Published by
Alberta Utilities Commission
Fifth Avenue Place, 4th Floor, 425 - 1 Street SW
Calgary, Alberta
T2P 3L8
Telephone: (403) 592-8845
Fax: (403) 592-4406
Web site: www.auc.ab.ca
Contents
1
INTRODUCTION................................................................................................................. 1
2
OVERVIEW OF THE APPLICATION ............................................................................. 3
3
FORMULA BASED RATEMAKING ................................................................................ 6
3.1 Does the Commission have the Jurisdiction to Adopt Formula Based Ratemaking?.... 6
3.2 Should the Commission Approve a Formula Based Ratemaking Plan for EPC? .......... 9
3.2.1 Formula Based Ratemaking Plans in General .................................................. 9
3.2.2 Concerns with Approving an FBR Plan for EPC............................................ 11
4
GOING-IN RATES............................................................................................................. 14
4.1 The Need for Distribution and Transmission Going-In Rates and Revenue
Requirements............................................................................................................... 14
4.2 Distribution .................................................................................................................. 15
4.2.1 Commission Findings ..................................................................................... 17
4.3 Transmission ................................................................................................................ 20
4.3.1 Commission Findings ..................................................................................... 20
5
TERM OF THE FBR PLAN AND MID-TERM REBASING........................................ 20
5.1 Commission Findings .................................................................................................. 25
6
I FACTOR ........................................................................................................................... 26
6.1 Characteristics of an Inflation Factor........................................................................... 26
6.2 Proposed Factor............................................................................................................ 26
6.3 Output versus Input Indices ......................................................................................... 27
6.4 Commission Findings .................................................................................................. 30
7
X FACTOR.......................................................................................................................... 33
7.1 Background .................................................................................................................. 33
7.2 Proposed X Factor........................................................................................................ 33
7.3 Commission Findings .................................................................................................. 37
8
G FACTOR.......................................................................................................................... 41
8.1 Commission Findings .................................................................................................. 47
9
EXTRINSIC FACTORS .................................................................................................... 48
9.1 Selected Flow Through Items ...................................................................................... 52
9.1.1 AESO Costs .................................................................................................... 52
9.1.2 USA/MFR Costs ............................................................................................. 52
9.1.3 Transmission Access Deferral Account.......................................................... 52
9.1.4 Advanced Metering Infrastructure.................................................................. 53
9.2 Impact of the Treatment of Extrinsic Factors on Incentives ........................................ 53
9.3 Commission Findings .................................................................................................. 53
10 EARNINGS SHARING...................................................................................................... 56
10.1 Earnings Sharing as a Safety Mechanism .................................................................... 57
10.2 Earnings Sharing Impact on Incentives........................................................................ 57
10.3 Calculation of Net Income for the Purposes of Earnings Sharing ............................... 58
AUC Decision 2009-035 (March 25, 2009) • i
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ENMAX Power Corporation
10.4 Affiliate Transactions................................................................................................... 60
10.5 Outsourcing.................................................................................................................. 61
10.6 Commission Findings .................................................................................................. 62
11 SERVICE QUALITY ......................................................................................................... 62
11.1 Performance Standards ................................................................................................ 62
11.2 Commission Findings .................................................................................................. 65
12 MUNICIPAL RIDER ......................................................................................................... 66
12.1 Commission Findings .................................................................................................. 69
13 COMMISSION DETERMINED FBR FORMULAS ...................................................... 70
14 JUST AND REASONABLE RATES ................................................................................ 71
15 CUSTOMER COMMITTEES .......................................................................................... 71
15.1 Commission Findings .................................................................................................. 73
16 OTHER ISSUES ................................................................................................................. 74
16.1 Distribution Residential Contributions ........................................................................ 74
16.1.1 Commission Findings ................................................................................... 74
16.2 Depreciation ................................................................................................................. 75
16.2.1 Mid-term Depreciation Study ....................................................................... 75
16.2.2 Commission Findings ................................................................................... 76
16.2.3 Amortization of Variances............................................................................ 76
16.2.4 Commission Findings ................................................................................... 76
16.2.5 Asset Retirement........................................................................................... 76
16.2.6 Commission Findings ................................................................................... 77
16.3 Distribution Driven Transmission Projects.................................................................. 77
16.3.1 Commission Findings ................................................................................... 78
16.4 Fees and Non-Residential Investment Levels .............................................................. 78
16.4.1 Commission Findings ................................................................................... 78
16.5 Pension ......................................................................................................................... 78
16.5.1 Commission Findings ................................................................................... 81
16.6 Previous Board Directives ........................................................................................... 82
16.7 Generic Cost of Capital................................................................................................ 86
17 FILING REQUIREMENTS .............................................................................................. 86
17.1 Commission Findings .................................................................................................. 87
18 ORDER ................................................................................................................................ 88
APPENDIX 1 – PROCEEDING PARTICIPANTS................................................................. 89
APPENDIX 2 – ABBREVIATIONS ......................................................................................... 91
ii • AUC Decision 2009-035 (March 25, 2009)
2007-2016 Formula Based Ratemaking
ENMAX Power Corporation
List of Tables
Table 1: Reconciliation Table – Disallowed Items ................................................................ 59
Table 2: Summary of Disallowed and Inappropriate Costs................................................. 59
AUC Decision 2009-035 (March 25, 2009) • iii
ALBERTA UTILITIES COMMISSION
Calgary Alberta
ENMAX POWER CORPORATION
2007-2016 FORMULA BASED RATEMAKING
1
Decision 2009-035
Application No. 1550487
Proceeding ID. 12
INTRODUCTION
1.
On May 11, 2007, ENMAX Power Corporation (EPC) filed a Formula-Based
Ratemaking (FBR) Application with the Alberta Energy and Utilities Board (EUB or Board)
which was registered as Application No. 1512069 (the Original Application). The Original
Application was in respect of an FBR plan whereby the tariffs for both EPC Distribution Access
Service (DAS) and transmission service would be determined in accordance with separate
formulas over a 10 year term commencing January 1, 2007.
2.
More specifically, the Original Application proposed:
•
•
•
•
•
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•
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•
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A rate setting mechanism by which DAS rates, fees, non-residential investment levels
and the transmission tariff would each be determined annually by formula, to be effective
July 1 of each year;
The base rates for the FBR plan would those approved by the EUB for 2006.
Two formulas were proposed; one to be applied to DAS rates, fees, and non-residential
investment levels, and another to be applied to the revenue requirement reported to the
Alberta Electric System Operator (AESO) and included in the calculation of the
transmission tariff. This regime was to be effective January 1, 2007;
The proposed formulas would allow DAS rates and the revenue requirement reported to
the AESO and included in the calculation of the transmission tariff to increase annually
by the difference between an inflation factor (I) and a productivity factor (X);
The inflation factor was proposed to be based on the historical Calgary Consumer Price
Index (CPI);
The productivity factor (X) was proposed to be 0.5 percent;
The term of the FBR plan was proposed to be 10 years;
The plan called for the adoption of minimum performance standards, requiring that
certain penalties be paid by way of a reduction in customer rates if the minimum levels of
performance are not maintained;
The plan proposed an earnings sharing mechanism whereby one half of EPC’s earnings
above a threshold level would be shared with customers by way of a reduction in DAS
rates;
The plan included various off-ramps, re-openers, flow-through costs and other extrinsic
factors (F);
The plan proposed updated depreciation rates, effective January 1, 2007; and
The plan included various other exemptions, deferral accounts, final rates and other
implementation matters necessary for the establishment of the FBR regime.
3.
On November 22, 2007, the EUB directed EPC to file an amended application on or
before December 10, 2007 in order to facilitate the pending transition from the EUB to the
Alberta Utilities Commission (AUC or Commission).
AUC Decision 2009-035 (March 25, 2009) • 1
2007-2016 Formula Based Ratemaking
ENMAX Power Corporation
4.
On December 10, 2007, EPC filed the Amended 2007-2016 Distribution and
Transmission General Tariff Application / Formula-Based Ratemaking Application (the
Application) with the EUB. In the Application EPC indicated that, during the period from
September to October, 2007, EPC had consulted with various customer representatives with
respect to various elements of the Original Application. EPC indicated that some of the
amendments to the Original Application which were reflected in the Application were a result of
this consultation process. 1
5.
The Commission succeeded the EUB on January 1, 2008 as regulator of EPC.
6.
On January 11, 2008 the Commission issued Notice of the Application (Notice) by
electronic mail to the Commission’s notification contact list prepared in connection with the
following proceedings: 1512069 EPC 2007-2016 Distribution and Transmission General Tariff
Application/FBR, 1460995 EPC 2006-2007 Distribution Tariff Phase II, and 1422382 EPC 2006
Transmission Tariff. The Notice was also advertised on January 17, 2008 in the Calgary Herald,
Calgary Sun, Edmonton Journal and Edmonton Sun. The Notice also confirmed that the record
in respect of the Original Application would be incorporated into the record for the Application.
7.
Parties who participated in the proceeding or registered as interveners are listed in
Appendix 1 to this Decision.
8.
The Commission dealt with the Application in an oral process, following the schedule set
out below:
Summary of Process and Schedule
Process Step
Deadline Date
Application Filed
Information Requests to Applicant Round 1
Information Responses from the Applicant Round 1
Information Requests to Applicant Round 2
Information Responses from the Applicant Round 2
Intervener Evidence Round 1
Intervener Evidence Round 2
Information Requests to Interveners Round 1
Information Requests to Interveners Round 2
Information Responses from Interveners Round 1
Information Responses from Interveners Round 2
Rebuttal Evidence Round 1
Oral Hearing
Argument
Reply Argument
AUC Ruling on Sur Reply
December 10, 2007
May 1, 2008
May 15, 2008
June 5, 2008
June 26, 2008
July 3, 2008
July 10, 2008
July 17, 2008
July 24, 2008
August 7, 2008
August 14, 2008
August 28, 2008
September 24 - October 3, 2008
November 14, 2008
December 5, 2008
January 16, 2009
9.
On December 12, 2008 the Office of the Utilities Consumer Advocate (UCA) filed a
letter with the Commission claiming that EPC had abused the process of argument and reply
argument with the result that UCA and other intervener parties had been prejudiced by EPC’s
actions. UCA suggested that the Commission should reject EPC’s Reply Argument in all areas
1
Exhibit No. 0044.00.EPC-12
2 • AUC Decision 2009-035 (March 25, 2009)
2007-2016 Formula Based Ratemaking
ENMAX Power Corporation
where it did not specifically address intervener evidence in Argument, or provide UCA with the
opportunity to “file Sur-Reply Argument on EPC’s comments on Reply Argument that should
have been included in Argument.”
10.
EPC replied in a letter to the Commission on December 15, 2008 indicating in part that
EPC’s approach to argument and reply was proper. In response, UCA reiterated its position in a
letter dated December 16, 2008.
11.
The Commission issued a Ruling rejecting UCA’s request in a letter dated January 16,
2009. The Commission found that EPC’s Reply Argument was confined to responding to the
arguments of UCA and those of the other interveners and referred to the record of the proceeding
in countering the intervener positions. The Commission indicated that it had not been convinced
that EPC’s approach to Argument and Reply Argument had resulted in unfairness to UCA.
12.
The Panel assigned to the Application consisted of Mr. Willie Grieve, Chair,
Ms. Carolyn Dahl Rees, Commissioner and Mr. Mark Kolesar, Acting Commissioner.
13.
In reaching the determinations set out within this Decision, the Commission has
considered all relevant materials comprising the record of this proceeding, including the
evidence and argument provided by each party. Accordingly, references in this Decision to
specific parts of the record are intended to assist the reader in understanding the Commission’s
reasoning relating to a particular matter and should not be taken as an indication that the
Commission did not consider all relevant portions of the record with respect to that matter.
2
OVERVIEW OF THE APPLICATION
14.
EPC applied to the Commission for approval of the Application pursuant to sections 5(h),
119(1), 120 and 121 of the Electric Utilities Act. 2 EPC stated that the Application is consistent
with the purpose of the Electric Utilities Act and that, if approved, it will “streamline regulatory
oversight and provide increased DAS rate predictability to customers and revenue predictability
to EPC, while maintaining safe and reliable service at just and reasonable rates.” 3
15.
In preparing the DAS portion of the Application EPC had regard to EUB Decision
2006-002 4 and Decision 2006-023 5 which established EPC’s 2005/2006 distribution tariff
revenue requirement. The approved revenue requirement was then used to develop EPC’s final
2006 rates which were approved by the EUB in Decision 2007-022. 6 In preparing the
transmission tariff portion of the Application EPC had regard to EUB Decision 2006-079 7 and
2
3
4
5
6
7
S.A. 2003, c. E-5.1
Exhibit 0015.00.EPC-12, Application, page 16
Decision 2006-002 - ENMAX Power Corporation 2005-2006 Distribution Tariff (Application 1380613)
(Released: January 13, 2006)
Decision 2006-023 – ENMAX Power Corporation 2005 – 2006 Distribution Tariff Refiling
(Application 1446795) (Released: March 14, 2006)
Decision 2007-022 – ENMAX Power Corporation 2006-2007 Distribution Tariff Phase II and Revised Interim
2007 Distribution Tariff (Application 1460995) (Released: March 20, 2007)
Decision 2006-079 - ENMAX Power Corporation 2006 Transmission Facility Owner Tariff
(Application 14222382) (Released: July 25, 2006)
AUC Decision 2009-035 (March 25, 2009) • 3
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ENMAX Power Corporation
Decision 2006-130 8 which established the 2006 revenue requirement and the 2006 EPC
transmission facility owner (TFO) tariff.
16.
Specifically, the Application requested approval of an FBR plan whereby the tariffs for
both EPC’s DAS and transmission service would be determined in accordance with separate
formulas over a 10 year term commencing January 1, 2007. The plan provided for the following:
•
Utilization of EPC’s 2006 approved revenue requirement and resulting 2006 rates,
adjusted to take into account certain DAS revenue requirement additions, to establish the
base revenue requirement and base rates prior to application of the proposed formulas.
EPC proposed three re-basing adjustments to increase the base 2006 DAS revenue
requirement, as follows:
Short Term Incentive Plan Payment (STIP)
Vacant Position Allowance
2006 Actual Capital Costs
Total
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•
1.292 million
0.750 million
1.844 million
3.886 million
A rate setting mechanism by which DAS rates, fees, non-residential investment levels
and the TFO tariff will each be determined annually by formula, to be effective July 1 of
each year;
An effective date of January 1, 2007; 9
Two formulas: one to be applied to DAS rates, fees, and non-residential investment
levels, and another to be applied to the transmission revenue requirement reported to the
AESO and included in the calculation of the TFO tariff;
DAS rates, fees and non-residential investment levels to be governed by a price cap that
allows them to increase annually by the difference between an inflation factor (I) and a
productivity factor (X) according to the following formula: 10
Pt=Pt-1*(1+(I-X))
where
Pt = current year’s customer rate for each class,
Pt-1 = prior year’s customer rate for each class,
I = inflation factor, and
X = productivity factor;
•
8
9
10
11
The revenue requirement reported to the AESO and included in the calculation of the
TFO tariff to be governed by a revenue cap that allows the transmission revenue
requirement to increase annually by the difference between an inflation factor (I) and a
productivity factor (X) plus an amortized capital investment factor (G) according to the
following formula: 11
Decision 2006-130 – ENMAX Power Corporation Refiling of 2006 Transmission Facility Owner Tariff
(Application 1475711) (Released: December 21, 2006)
Rates as of January 1, 2007 are currently approved on an interim basis pursuant to Decision 2008-107 and
Decision 2006-130 for distribution and transmission respectively.
Application Appendix 3, page 3
Application Appendix 3, page 3
4 • AUC Decision 2009-035 (March 25, 2009)
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Rt=Rt-1*(1+(I-X))+G
where
Rt = current year’s revenue requirement,
Rt-1 = prior year’s revenue requirement,
I = inflation factor,
X = productivity factor, and
G = amortized previous year’s transmission capital investment;
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An inflation factor (I) to be based on a weighted average blending of the Alberta Average
Hourly Earnings index and the Electric Utility Construction Price Index, both published
by Statistics Canada. 12 The inflation factor would be calculated separately for distribution
and transmission;
A productivity factor (X) to be set at 1.5 percent of which 0.8 percent is the basic
productivity offset and 0.7 percent represents a stretch factor; 13
A G factor (G) to be approved annually based on the amortized previous year’s
transmission capital investment;
A term for the FBR plan of 10 years, with a rebasing of rates after an initial five year
term;
Adoption of minimum performance standards requiring that certain penalties (S) be paid
by way of changes to customer rates if minimum levels of performance are not
maintained;
An Earnings Sharing Mechanism that provides for one half of EPC’s earnings above a
threshold level (E) to be shared with customers by way of a reduction in rates with no
sharing of losses below the earnings threshold;
Various off-ramps, re-openers, flow through costs and other extrinsic factors (F) that
would not be subject to an I minus X adjustment;
Minor changes to depreciation rates, to be effective January 1, 2007;
An extended formula that accounts for an earnings sharing proposal, service quality
penalties and certain flow through cost items as follows: 14
Pt=Pt-1*(1+(I-X))+G–E-S+/-F
where:
Pt = current year’s customer rate for each DAS class (for transmission,
current year’s revenue requirement),
Pt-1 = prior year’s customer rate for each DAS class (for transmission,
prior year’s revenue requirement),
I = inflation factor,
X = productivity factor,
G = amortized previous year capital investment (not included for DAS
rates),
E = customer portion of Earnings Sharing,
S = service quality penalties, if any, and
F = flow through and uncontrollable costs;
12
13
14
Description and details provided in paragraph 125 of this Decision.
Exhibit 0044.00.EPC-12, AUC-EPC-004
Application Appendix 3
AUC Decision 2009-035 (March 25, 2009) • 5
2007-2016 Formula Based Ratemaking
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ENMAX Power Corporation
Various other exemptions, deferral accounts, final rates and other implementation matters
for the establishment of the FBR regime;
Formation of Customer Committees, one for distribution and one for transmission. The
stated purpose for the Customer Committees is to review material changes in operations
and capital and to provide feedback on annual filings requirements in an attempt to
resolve contentious issues that will require AUC approval.
17.
Further details of each element of the EPC FBR proposal are set out and discussed in the
relevant sections of this Decision.
3
FORMULA BASED RATEMAKING
18.
In its Argument, EPC stated that its FBR Application will result in benefits for its
customers and shareholders, including stable and predictable DAS rates, DAS rates that decline
in real terms, a reduction in costs, resources and time spent on hearings, benefit sharing with
customers, and a longer planning horizon that allows EPC to engage in coordinated long term
planning. 15 Similar benefits would accrue to transmission customers.
19.
The Commission is open to considering alternative approaches to the traditional method
for determining just and reasonable rates in Alberta. This approach starts with an application by
a utility to approve a forecasted revenue requirement in one or more test years followed by an
application to allocate the approved revenue requirement among the utility customers.
20.
Before considering the specifics of this Application the Commission considered two
preliminary matters. First, the Commission considered whether it has the jurisdiction to adopt an
FBR proposal. Second, in response to reservations expressed by some interveners about whether
EPC, as a municipally-owned utility, is a good candidate for FBR, the Commission considered
whether it should approve an FBR plan for EPC. Each of these preliminary matters is discussed
below.
3.1
Does the Commission have the Jurisdiction to Adopt Formula Based
Ratemaking?
21.
Pursuant to sections 102 and 119 of the Electric Utilities Act each owner of an electric
utility distribution system subject to the jurisdiction of the Commission, including the EPC
distribution system, and each electric utility, including the EPC transmission system, must
prepare a tariff and must submit the tariff for approval to the Commission. EPC has applied for
approval of a plan that would annually set its distribution tariff and transmission revenue
requirement by way of Commission approved formulas for the period January 1, 2007 to
December 31, 2016. The Commission must consider if it has the jurisdiction to approve a tariff
that is set annually by way of an incentive ratemaking formula and, if so, whether a formula
based ratemaking regime may include an earnings sharing mechanism. If the Commission
determines that it has the jurisdiction to adopt a formula based rate setting plan, the Commission
must then consider whether the FBR plan, as proposed, is the type of incentive arrangement that
is contemplated by the legislation.
15
EPC Reply Argument, pages 6-7
6 • AUC Decision 2009-035 (March 25, 2009)
2007-2016 Formula Based Ratemaking
ENMAX Power Corporation
22.
In its report prepared for EPC entitled “Theoretical and practical support for ENMAX
Power Corporation’s proposed Formula-based Ratemaking (FBR) proposal” London Economics
International LLC (London Economics) stated “[t]he Alberta Electric Utilities Act contains
references to inclusion of efficiency incentives in tariffs for AEUB regulated utilities; EPC’s
proposal provides for such measures.” 16
23.
EPC asserted that the “Electric Utilities Act expressly permits the AUC to consider and
approve the formula-based approach to rate-making advocated by EPC, so long as it will result in
rates that are just and reasonable.” 17 At page 16 of the Application, EPC referred specifically to
sections 5(h), 119(1), 120 and 121 of the Electric Utilities Act:
Subsection 5(h) of the EUA provides:
5 The purposes of this Act are
(h) to provide for a framework so that the Alberta electric industry can, where necessary,
be effectively regulated in a manner that minimizes the cost of regulation and provides
incentives for efficiency.
24.
With respect to subsection 5(h), EPC stated:
One of the purposes of the EUA is “to provide for a framework so that the Alberta
electric industry can, where necessary, be effectively regulated in a manner that
minimizes the cost of regulation and provides incentives for efficiency”. This Application
is consistent with that purpose, and will, if approved, streamline regulatory oversight and
provide increased DAS rate predictability to customers and revenue predictability to
EPC, while maintaining safe and reliable service at just and reasonable rates. 18
25.
As referenced above, Section 119(1) requires the filing of a tariff by an electric utility
with the Commission for approval. Section 120 of the Electric Utilities Act provides:
120(1) A tariff must describe how it may change over the period for which it is intended
to have effect.
(2) A tariff may provide
(a) that it is in effect for a fixed period or an indefinite period;
(b) for maximum rates;
(c) for increases or decreases in the rates to correspond to
(i) increases or decreases in fuel costs, taxes or other costs and expenses,
(ii) price indices, rates of inflation or similar measurements, and
(iii) other related costs or expenses approved by the AUC;
(d) for incentives for efficiencies that result in cost savings or other benefits that can be
shared in an equitable manner between the owner of the electric utility and customers.
16
17
18
“Theoretical and practical support for ENMAX Power Corporation’s proposed Formula-based Ratemaking
(FBR) proposal” report by London Economics International LLC, Exhibit 0018.00.EPC-12, page 10
Reply Argument of EPC, page 5
EPC Application, Exhibit 0015.00.EPC-12, page 16
AUC Decision 2009-035 (March 25, 2009) • 7
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26.
In its Application, EPC stated that section 120 “specifically contemplates a formulabased approach to rate setting” 19 by highlighting that tariffs may provide incentives that result in
benefits to utility owners and customers. 20 EPC also referred to section 121(3) of the Electric
Utilities Act stating:
Section 121 of the EUA sets out the matters the AUC must consider in connection with a
tariff application, and subsection 121(3) reinforces the principle that a tariff may include
incentives: 21
121 (3) A tariff that provides incentives for efficiency is not unjust or
unreasonable simply because it provides those incentives.
27.
Overall, EPC contended that the “[a]pplication is consistent with the purposes of the
Electric Utilities Act, and will result in just and reasonable rates, while providing significant
benefits to customers.” 22
28.
None of the interveners in the proceeding disputed the jurisdiction or authority of the
Commission to approve EPC’s proposed FBR approach to setting rates. In its Argument, UCA
stated:
In Section 2.1.1 of its amended application, EPC comments on the ability for the AUC to
approve an FBR of the type proposed by EPC including the term and rebasing
requirements. The UCA does not object to EPC’s assertion that the AUC has the ability
to approve the FBR proposal or any modifications as recommended by the UCA in its
evidence. 23
29.
Similarly, D410 also stated that the Electric Utilities Act:
…contemplates the possibility that Alberta’s electric distribution companies (“EDCs”)
may switch from traditional test year rate regulation to incentive or performance-based
regulation (“PBR”), also known as formula-based regulation (“FBR”). 24
30.
The remaining interveners did not make reference to the authority or jurisdiction of the
AUC to consider the Application.
31.
The Commission agrees with the submissions of both EPC and interveners that the
provisions of the Electric Utilities Act provide the Commission with the jurisdiction to consider
and approve distribution and transmission tariffs that include incentive ratemaking provisions.
In the Commission’s view, the legislation encourages stakeholders to consider such mechanisms
and compels the Commission to review them for the purposes of achieving regulatory and cost
efficiencies, while providing for just and reasonable rates. Specifically, subsection 5(h) of the
Electric Utilities Act clearly establishes, as one of the purposes of the legislation, providing for
effective regulation that minimizes the cost of regulation while providing incentives for
efficiency.
19
20
21
22
23
24
EPC Application, Exhibit 0015.00.EPC-12, page 29
EPC Application, Exhibit 0015.00.EPC-12, page 30
EPC Application, Exhibit 0015.00.EPC-12, page 30
EPC Application, Exhibit 0015.00.EPC-12, page 104
Reply Argument of UCA, page 10
Reply Argument of D410, page 1
8 • AUC Decision 2009-035 (March 25, 2009)
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32.
Subsection 120(2)(c) allows for a tariff that may automatically adjust rates to reflect
increases or decreases in costs and changes in price indices, rates of inflation and other similar
measurements. Subsection 120(2)(d) expressly provides that tariffs may include incentives for
efficiencies that result in cost savings or other benefits that can be shared between the utility and
its customers. In the Commission’s view, these subsections allow for the adoption of formula
based ratemaking alternatives, and allow for the adoption of an earnings sharing mechanism,
whereby additional benefits can be directly shared between the utility and its customers.
33.
Further support for the ability of the Commission to consider efficiency incentives in the
mechanisms it adopts to set tariffs is found in Section 121 of the Electric Utilities Act which
provides direction to the Commission on the matters it must consider when evaluating a tariff
application. While subsection 121(2) requires the Commission to ensure that a tariff is just and
reasonable and that it does not result in unduly preferential, arbitrary or unjustly discriminatory
rates.
34.
The Commission concludes that it has the jurisdiction to consider and if acceptable,
approve the Application.
3.2
Should the Commission Approve a Formula Based Ratemaking Plan for EPC?
3.2.1
Formula Based Ratemaking Plans in General
35.
EPC stated the following with respect to the overall benefits of an Formula Based
Ratemaking proposal:
There are four main economic and regulatory principles that informed the application.
These are: the ability to create a regime closer to the effects of a competitive market in
driving efficiency gains; the desire to create a more incentives compatible regime,
resulting in gains for both customers and EPC; the reduction of the regulatory burden on
stakeholders; and the creation of a durable set of arrangements which will allow EPC
management to focus on long term efficiency-enhancing investments.1 We will discuss
each of these principles in turn.
[1 These objectives are similar to those expressed by other regulators in Canada. See
for example OEB Decision EB-2007-0615 (Enbridge Gas Distribution) in which it
stated that an acceptable incentive rate plan “must: 1. establish incentives for
sustainable efficiency improvements that benefit customers and shareholders; 2.
ensure appropriate quality of service for customers; and 3. create an environment that
is conducive to investment, to the benefit of customers and shareholders.] 25
36.
In Appendix 3 to the Application, London Economics explored briefly the reasons why
Formula Base Ratemaking has been adopted in other jurisdictions:
FBR has proven appealing worldwide for several reasons. These include:
•
better alignment of incentives between regulated companies and ratepayer objectives;
•
reduction in overall regulatory burden, including allowing the regulator, customer
representatives and the utility to focus on sector matters other than the minutiae of
cost of service reviews;
•
predictability of treatment for companies on a variety of regulatory issues;
25
Response to AUC.EPC-001
AUC Decision 2009-035 (March 25, 2009) • 9
2007-2016 Formula Based Ratemaking
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ENMAX Power Corporation
giving companies confidence that they would be allowed to retain a portion of
efficiency gains, thereby spurring them to seek out innovative business and
operational practices; and
implementation of performance standards in conjunction with efficiency incentives
means that utilities increasingly face defined service quality targets and penalties for
failure to perform.
37.
Parties to the proceeding generally supported the adoption of FBR plans. Indeed, most
parties recognized the numerous potential advantages of FBR.
38.
UCA submitted in Argument that it “agrees with most aspects of EPC’s ‘core’ FBR
proposal.” 26 D410 recognized, in its Argument, that “ the essence of FBR is that it can vastly
improve the economic incentives for a profit-maximizing utility relative to traditional test year
regulation, to the benefit of both ratepayers and shareholders.” 27 The Consumer Group (CG), 28
despite expressing some reservations about the EPC proposal, submitted that:
…the primary driver for moving from COSR [cost of service regulation] to FBR or PBR
is to incent the utilities to achieve greater efficiencies by allowing them the opportunity to
better capture the benefits of productivity type planning and investments through
potentially improved returns over the term of the formula or cap. In theory, the utility
gains by potentially increasing its return to levels greater than available under COSR and
reducing its regulatory burden by being able to stay out of the hearing room for longer
periods of time. On the other hand, customers potentially gain through reduced regulatory
costs, more predictable rates and possible sharing, such as under EPC’s proposal, of
earnings over target levels. 29
39.
Mr. Knecht submitted on behalf of D410 that “an FBR regulated utility has the incentive
to make tradeoffs that are economically efficient over the longer term, rather than the short
term.” 30 He added that “[u]nder FBR … a utility’s rates are independent of the allowed cost of
capital, and the utility therefore has an incentive to base its investment decisions on its market
cost of capital rather than the regulated costs of capital.” 31 Mr. Knecht also noted that under
FBR, regulatory costs are reduced and that “FBR rates may be more stable and predictable than
traditional rates, because they are set based on a known formula.” 32
40.
Despite the many benefits of FBR plans in general, some parties also cautioned that there
are potential shortcomings in the adoption of FBR. Dr. Cronin, appearing on behalf of UCA,
noted that some FBR plans “suffered from serious design flaws in the rate adjustment
mechanism and the consequences on company profits and consequent regulatory backlash.” 33 In
addition, Dr. Cronin stated that “despite being potentially superior to cost of service regulation,
regulators have found it imperative that regulatory safeguards be built into PBR plans to mitigate
the tendency and severity of structural shortcomings.” 34
26
27
28
29
30
31
32
33
34
UCA Reply Argument, page 3
D410 Reply Argument, page 2
Comprised of Consumers Coalition of Alberta and Public Institutional Consumers of Alberta
CG Reply Argument, page 3
D410 Evidence, page 2
Ibid
Ibid
UCA Evidence, page 6
Ibid
10 • AUC Decision 2009-035 (March 25, 2009)
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Concerns with Approving an FBR Plan for EPC
41.
Several parties expressed concerns with the suitability of implementing an FBR
arrangement for EPC given its unique circumstances. In particular, these concerns were the
municipal ownership of EPC and the arrangements existing between EPC and its affiliates.
42.
A number of parties questioned whether the benefits espoused by EPC in the Application
would be realizable, given that EPC is a municipally owned utility. D410 argued that “while
municipal ownership does not mean that EPC has zero incentives for profit maximization, it is
likely that the profit maximization incentive at EPC will not be as strong as it is for investorowned utilities.” 35 In its Argument, D410 noted that “EPC may not be the most obvious choice
for FBR. Because it is municipally owned, EPC is much more likely than investor owned EDC’s
to be more influenced by non-economic factors in its decision making.” 36
43.
CG also questioned in Argument whether FBR is the best regulatory model for EPC:
While EPC may be seeking to reduce its regulatory workload through introduction of the
FBR, it is questionable whether such a mechanism is strictly necessary, or even the
optimal way, to incent the Company to improve efficiency through operational and
administrative innovation. In particular, CG notes EPC’s failure to earn AUC approved
levels of return (ROE) in recent years should already create more than sufficient
incentive for innovation and improved efficiency. 37
44.
However, at the hearing, when Mr. Marcus, appearing on behalf of CG, was questioned
by the Chair on the effectiveness of the proposed FBR incentives for a municipally owned utility,
he stated:
Q: So I guess I'm wondering, given all of those things, where do you actually see the
incentives for the people working in the company to be more efficient if they've got all
these protections around it? I call it the cocoon of government ownership, but you can
call it whatever you like. But where are the actual incentives to be more efficient in this
plan?
A: ...you have got a whole industry trying to disseminate best practices into the utility
industry, that I think ..., ENMAX would probably be interested in taking up. You know,
looking at the numbers on these pages, I'm think … they are not good enough, but they're
thinking, We can make them somewhat better. We're willing to live with them and try to
make them somewhat better. 38
45.
The Chair also explored the suitability of FBR for a municipally owned utility like EPC
with Dr. Cronin.
Q: So I'm curious how you think … a PBR or FBR plan like this affect[s] a government
firm differently than an investor-owned firm.
35
36
37
38
D410 Evidence, page 2
D410 Argument, page 2
CG Reply Argument, pages 4-5
Transcript Volume 6, pages 1517-1519
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A DR. CRONIN:
I think the research that we have looked at historically has found
that publicly-owned utilities, like MEUs, [Municipal Electric Utilities] are just as
efficient or possibly more efficient than investor-owned utilities. 39
46.
In addition, the Chair questioned Mr. Holden of EPC on how the incentives of FBR
would be realized by EPC, as a government owned entity.
Q: … I'm wondering how you can -- how you plan to actually bring the full power, if I
can use it, of the incentives that are created to be more efficient and more innovative into
a government-owned company, how you plan to do that.
A: MR. HOLDEN: It is an interesting discussion to have. When I took on the role of
CEO of ENMAX, my clear expectation and mandate that I established with the Board of
directors was, first of all, to verify for myself that this was indeed a board of directors
that could act like a commercial company or nongovernment-owned company and had a
mandate to operate as a board that was sufficiently independent that commercial
decisions could be made without undue political influence.
…
The second is, I try very much to run this company as if it is competing in a world
aggressively with investor-owned utilities, investor-owned competitors, private
competitors, entrepreneurs. And I'm assembling a team that has the capabilities to work
in that way. 40
47.
In this vein, the Chair questioned Mr. Holden further on the incentives at EPC.
Q: Mr. Holden, what I think I heard was that the climate, the culture you are creating
and the company, especially because the company is involved in competitive businesses
at the retail level or generation level, that … that same culture will be created in the
monopoly arms, and so you are not really concerned about the incentives that are created
under this plan being acted upon, if I can use that. Is that the idea? It's the culture there -A MR. HOLDEN: That's an accurate characterization of what I meant by the cultural
comments, that we'll instill the same belief that innovation can be rewarded there as we
are in the balance of the company. 41
48.
The Commission considers that there are potentially many benefits of a well crafted FBR
regulatory regime. These include better economic incentives for the utility that more closely
mimic the incentives in a competitive market, a reduction over time in the overall regulatory
burden, and an opportunity for the utility to capture greater productivity, subsequently allowing
for lower rates than would otherwise be enjoyed by consumers.
49.
With respect to the specific criticism that EPC, as a municipally owned utility, may not
be a good candidate for an FBR plan, the Commission notes that despite the reservations referred
to above, all parties agreed that an FBR plan could be adapted to EPC at this time. CG stated
that “there may still be merit in pursuing a properly designed FBR given the unique
circumstances of EPC at this time.” 42 D410 concluded that “if the Municipal Rider problems are
resolved, EPC is a suitable candidate for distribution FBR.” 43 The Commission is satisfied that
an FBR can provide benefits for EPC and its customers through improved efficiency and
39
40
41
42
43
Transcript Volume 7, page 1767
Transcript Volume 1, page 0328, line 3 to page 0329, line 11
Transcript Volume 1, page 0331, line 19 to page 0332, line 15
CG Reply Argument, page 9
D410 Argument, page 3
12 • AUC Decision 2009-035 (March 25, 2009)
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predictability. The Commission is also satisfied by the testimony of Mr. Holden that the
incentives and culture being created at EPC at least in part by competition in other related lines
of business lend themselves to the adoption of an FBR plan. The Commission will deal with the
specific concern of D410 with the municipal rider in more detail later in this Decision.
50.
ATCO objected to the FBR plan for EPC, on the grounds that it should not be approved
until sufficient testing of EPC’s affiliate transactions occurred. 44 In its Argument ATCO stated:
ATCO Electric has followed this proceeding closely to see how the record regarding
affiliate transactions would develop. Unfortunately, the evidence filed in this regard by
EPC is lacking and there is simply no way the AUC can or should accept that the
numerous affiliate transactions involving EPC are reasonable and appropriate. Absent a
complete testing of such transactions, ATCO Electric submits that the proposed FBR
mechanism should not be approved. 45
51.
The Commission is concerned that all transactions between a utility and its affiliates are
made in accordance with an approved code of conduct and that there is transparency and
accountability with respect to those transactions. In the case of EPC, the costs of the regulated
services must be determined by separating those costs from the costs of the unregulated services
and businesses of ENMAX Corporation and its other subsidiaries. EPC is an affiliate of
ENMAX Corporation and is required to ensure its direct costs of regulated services are separated
from the costs of ENMAX Corporation and its other subsidiaries. In some cases, EPC receives
services from other affiliates in order to provide those regulated services. The Commission
understands the concern expressed by ATCO that the charges from an affiliate to a regulated
entity for recovery through regulated rates must be carefully examined. However, the
Commission does not agree that the adoption of a formula based regulation plan for EPC should
be delayed until a separate process has re-examined the reasonableness of charges from ENMAX
Corporation and its other subsidiaries. The Commission has approved EPC’s current rates based
on existing allocations and inter-affiliate agreements. The Commission takes comfort in
Mr. Holden’s testimony that during the FBR term the allocation method is expected “… to be
verifiably the same method as it has been in the last few years.” 46 The Commission expects there to
be no changes to the allocation method during the FBR term without Commission approval. In
addition, the Commission expects there to be no new affiliate agreements to outsource services
which EPC currently provides for itself during the FBR term without Commission approval.
52.
The Commission also notes that other avenues are available to the Commission and
interested parties to ensure proper compliance with the approved code of conduct, including
audits by the Commission’s Audit and Compliance staff.
53.
The Commission finds that there is no compelling reason to conclude that a properly
crafted FBR plan cannot be adopted for EPC.
44
45
46
D410 Argument, page 3
ATCO Reply Argument, page 2
Transcript Volume 1, pages 0323-0325
AUC Decision 2009-035 (March 25, 2009) • 13
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4
GOING-IN RATES
4.1
The Need for Distribution and Transmission Going-In Rates and Revenue
Requirements
54.
A necessary starting point for an FBR plan is the determination of the revenue
requirement and accompanying rates that will be established at the beginning of the FBR term
and to which the approved formulas will apply. The Commission will refer to these initial rates
as the “going-in rates.” Going-in rates are usually established by way of a traditional cost of
service rate making process as reflected in the following extract from EPC’s response to a
request from the Commission:
Different jurisdictions with FBR arrangements in place have determined their base rates
in a variety of ways. Speaking generally, customers, the regulator, and the utility want to
ensure that the base rates have been reviewed by the regulator recently to ensure that
costs and revenues are fairly close before starting the FBR Term. 47
55.
In Alberta, the cost of service rate making process determines rates on the basis of an
application for approval of forecast revenue requirements. The utility’s forecast revenue
requirements are usually established by way of review of a comprehensive cost of service study,
during which the utility’s forecast costs of operation are analyzed or “tested” for reasonableness.
Once this testing of the revenue forecast has been completed, and any forecast cost adjustments
are implemented as ordered by the regulator, a “test year” of forecast costs is said to have been
developed for the utility. The utility will then allocate the approved revenue requirement among
various classes of ratepayers in accordance with an approved rate design methodology.
56.
EPC did not elect to develop its going-in rates based on a new test year of forecast costs.
Instead, EPC proposed that its going-in DAS rates, fees, and non-residential investment levels
should be based on its approved 2006 forecast revenue requirement and accompanying rates
adjusted to take into account certain additional costs.
57.
EPC also proposed that its going-in revenue requirement for transmission be the 2006
transmission revenue requirement.
58.
EPC explained its justification for its proposal to use an adjusted 2006 revenue
requirement rather than filing a forecasted revenue requirement for a 2007 test year as follows:
One of the anticipated advantages of this approach is a reduction in regulatory costs and
workload. Additionally, because the proposal starts from the approved 2006 revenue
requirement as adjusted by the Rebasing Adjustments, this Application is significantly
different from a traditional cost of service application. Specifically, this Application does
not request approval of a revenue requirement for a test period that has been built up from
detailed forecast cost amounts, and therefore does not generally set out that forecast cost
information. Rather, if approved, the distribution rates and the Transmission Tariff for a
test period result from the application of an approved formula to an approved base. 48
59.
The following sections of this Decision review the proposed going-in rates for both
distribution and transmission.
47
48
Application 1512069, response to Information Session Commission information request BR.EPC-043
Application, page 18
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Distribution
60.
In the Original Application, EPC proposed to use its EUB approved 2006 forecast test
year costs and going-in rates developed from those costs. EPC’s 2006 forecast costs were tested
and approved by the EUB in the proceedings which led to Decisions 2006-002 and 2006-023.
Those forecast costs were then used to develop EPC’s final 2006 rates which were approved by
the Commission in Decision 2007-022. 49
61.
As part of its Application, EPC requested that it be allowed to increase its approved 2006
forecast costs and resulting 2006 rates by $3.886 million for the following items and amounts: 50
Short Term Incentive Plan Payment (STIP)
1.292 million
Vacant Position Allowance
0.750 million
2006 Actual Capital Costs
1.844 million.
Total
3.886 million
62.
EPC provided separate reasoning with respect to each component of the proposed
adjustments and the following general rationale for requesting this increase, or “rebasing,” of its
2006 rates:
EPC proposes to amend the I-Factor and the X-Factor components of the FBR formula,
provided in the May 11, 2007 Application, as set out in section 2.1.5. As a result of these
adjustments, EPC requires a higher base at the start of the FBR Term to maintain
financial stability. 51
63.
Based on questioning from CCA 52 during cross-examination, EPC reduced the requested
rebasing amount related to 2006 Actual Capital Costs from $1.844 million to $0.922 million.53
EPC’s final proposal was to increase its 2006 forecast costs and the 2006 rates by $2.964 million.
64.
Even with this rebasing, EPC did not anticipate earning its Commission approved 2007
return on equity with respect to the first year of the proposed FBR regime. Nevertheless, EPC
suggested that it was willing to accept this tradeoff in return for other benefits.
Using the 2006 EUB Decisions, as adjusted, establishes a base for FBR that is forecast to
result in a lower actual ROE for 2007 than that allowed under the generic cost of capital
decision, EUB Decision 2004-052. Indeed, EPC’s reported Distribution ROE in 2006 was
6.99%, versus the allowed ROE of 8.93%, highlighting EPC’s challenges in managing its
business in a rising cost environment and with no DAS customer rate increases in recent
years. While the rebasing that is proposed will narrow this gap somewhat, EPC still
expects a 2007 ROE below the allowed ROE. EPC is willing to accept the trade-off of
this lower base to gain revenue certainty and the opportunity to benefit along with
customers from future efficiency improvements. EPC recognizes that significant
productivity gains must be achieved to realize the EUB’s allowed ROE. 54
49
50
51
52
53
54
Decision 2007-022 was released on March 20, 2007
Exhibit 0015.00.EPC-12, page 33, lines 6-25
Exhibit 0015.00.EPC-12, page 33, lines 1-5
Consumers’ Coalition of Alberta
Transcript Volume 5, page 1205, lines 6-19
Exhibit 0015.00.EPC-12, page 34, lines 7-17
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65.
Parties generally did not oppose EPC’s use of its approved 2006 rates as the starting point
for going-in rates. Parties did not agree, however, that EPC should be allowed to increase its
2006 rates for the items requested by EPC. Some parties suggested that certain items be
removed from EPC’s 2006 forecast costs in developing going-in rates.
66.
UCA stated:
The UCA does not object to the use of the 2006 EUB approved revenue requirement for
the FBR starting point of 2007….. 55
67.
While UCA supported the use of the 2006 EUB approved revenue requirement, it
considered that certain modifications were required.
The UCA recommends those costs discussed in its evidence (previously disallowed costs,
Head Office, IT [Information Technology] O&M [Operating and Maintenance] cost etc.)
[as] should be removed from both the earnings sharing calculations as well as the starting
point for the FBR, and therefore should not be included in rebasing. Further, the UCA
objects to EPC’s proposal to include “actual” vacancy rates in the calculation of EPC’s O
& M for 2006 as well as adjustments for 2006 actual capital expenditures and additions.
EPC’s request for inclusion of actual vacancy allowance without a request for the
remainder of the O & M “actuals” has not been supported by the evidence and should be
rejected by the AUC. Inclusion of “actual” capital expenditures and additions, has not
been rationalized if EPC chooses to ignore “actuals” for all of the O & M. The UCA also
recommends not including 2006 actual capital expenditures and additions for Distribution
as part of the rebasing.
The UCA recommends the entire STIP plan should be removed from the revenue
requirement. Further, the AUC should reject the rebasing related to STIP. All STIP costs
should be removed from the calculation of actual ROE for the earnings sharing
purposes. 56
68.
UCA further argued that approved information technology costs embedded in the
distribution rates should be reduced by $2.3 million. 57
69.
EPC responded as follows:
…The UCA argues that EPC’s IT costs should be limited to 2.1% of its revenue, based
on the “expert evidence” of Mr. Laskoski. This evidence is seriously flawed, and should
be disregarded in its entirety.
Mr. Laskoski does no independent research or analysis of his own. Rather, his evidence
and recommendation about EPC’s IT costs is based on his review of a proprietary report
that the UCA did not put into evidence, namely the Gartner 2006-2007 IT Spending and
Staffing Report: North America, publication date, 5 March 2007 (the “2006-2007 Gartner
Report”).The authors of that report did not provide evidence in this proceeding.
Furthermore, Mr. Laskoski did not use the most recent version of the Gartner IT
Spending and Staffing Report, and did not make any attempt to update his conclusions to
take account of the most recent Gartner IT Spending and Staffing Report. What Mr.
55
56
57
UCA Argument, page 11
Ibid page 13
Ibid page 14
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Laskoski has done is to take a single conclusion from the 2006-2007 Gartner Report
(namely the conclusion that the average utility respondent had an IT operating budget of
2.1% of its revenue) and applies it to EPC. There are a number of serious issues with
respect to Mr. Laskoski’s use and reliance of the 2006-2007 Gartner Report, including
the following:
•
•
•
•
The 2006-2007 Gartner Report was not in evidence.
The authors of the 2006-2007 Gartner Report were not produced, and the 2006-2007
Gartner Report could not, therefore, be tested.
Mr. Laskoski relied upon an outdated version of the Gartner Report. (He used the
2006-2007 version, when the most recent version is the one dated February 20,
2008).
Mr. Laskoski’s evidence does not discuss the stated purpose of the 2006-2007
Gartner Report, or the specific qualifications identified by the report’s authors, in
spite of his admission that one must have regard to the purpose of a study when
deciding how to use the results and the conclusions contained in it, and the concern
expressed by the D410. 58
70.
CG was in agreement with UCA that EPC not be allowed to include base increases
related to STIP, Vacant Position Allowance and actual 2006 Capital Expenditures. 59
71.
Further, CG considered that EPC was “cherry picking” only those items which would
serve to increase its going-in rates, and choosing to ignore other items which would serve to
reduce its going-in rates.
Any attempt to selectively review only three items of the 2006 Revenue Requirement for
rebasing is a clear case of cherry picking. As the only party with information necessary to
allow the Commission and other parties to assess if there are any items of revenue or
expense in 2007 which may mitigate the three proposed 2006 rebasing adjustments, EPC
could have, and should have, filed a full forecast filing of the 2007 Revenue
Requirement. EPC’s proposal to cherry pick three items of 2006 Revenue Requirement
for rebasing is an attempt to artificially escalate the base numbers EPC suggests it needs
to operate under the FBR formula, as proposed. 60
4.2.1
Commission Findings
72.
The Commission agrees with EPC and the interveners that the going-in rates for a
formula based rate regulation plan must be established based on the costs of the regulated
services determined in a regulatory rate setting proceeding.
73.
EPC had the option of choosing to file a new rate application with the Commission or
relying on the results of its 2006 rate case. EPC chose to establish its going-in rates based on the
results of its 2006 rate case and sought certain adjustments to reflect 2006 actual results. The
Commission accepts the 2006 approved rates as the starting point for determining the going-in
rates but will not accept adjustments to the going-in rates to account for 2006 actual results.
74.
The going-in rates were established through the traditional accepted rate making process.
Adjustments to account for actual results should not be made selectively but, rather, should only
58
59
60
EPC Reply Argument, pages 27-28
CG Argument, pages 9-20
CG Argument, pages 22-23
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be made in the context of a full rate case which would consider the forecast costs for a
subsequent time period. Further, in this case the Commission is considering an FBR plan for
EPC and expects costs and financial results to fluctuate from year to year. In some years, costs
will be higher than expected and in other years lower. Under the approved FBR plan, EPC will
be incented to improve its efficiency and productivity and will have the opportunity to retain a
significant share of improved earnings resulting from those incentives.
75.
As noted above in paragraph 62, EPC sought changes to its going-in rates by considering
those rates, the proposed I factor and the proposed X factor together. Mr. Goulding explained
this approach as follows:
Q: So there is a bit of engineering to get to a rate of return is the way I heard your
evidence.
A MR. GOULDING:
Sure. Let me clarify one element there, which is we couldn't
have stayed at the 0.5 and changed the inflation factor. So that was one element of the
change from the 0.5 to the 1.5.
Q Okay.
A MR. GOULDING:
But in terms of how you go about thinking about rate design in
the context of an FBR formula, what you're trying to do is set in place a regime in which
the efficient utility earns their appropriate cost of capital. And so it is not unique to take
into account cost of capital in the construction of the FBR mechanism. The question
becomes, then, Well, how hypothetical is this efficient utility? Now, in this particular
case, we only have one utility that we're talking about. And the regime has been set up to
assume that if EPC meets a relatively aggressive performance target and the rebasing
takes place, that it will then have an opportunity to earn that fair return. It's not
guaranteed that fair return. 61
76.
The establishment of just and reasonable going-in rates should not be influenced by a
consideration of the I and X factors to be applied to those rates over the FBR term. If EPC
considers the going-in rates to be unreasonable, it should file for new rates determined through a
new general tariff application. Certainly, going-in rates should not be engineered upward in
order to accommodate or make possible the adoption of a higher X factor to be applied over the
term of the FBR plan. Therefore, the Commission does not accept EPC’s proposal to increase its
2006 rates to account for actual vacant positions and actual capital costs experienced in 2006 so
as to “maintain financial viability.”
77.
The proposed adjustment to the 2006 rates to allow for the recovery through regulated
rates of the STIP costs, however, raises different considerations. There was considerable debate
during the proceeding about EPC’s change in methodology concerning the payment of STIP.
This change in methodology removed financial targets at the operational level and replaced them
with non-financial operational targets while still maintaining an overall company wide financial
target criterion as a condition of STIP payout.
78.
EPC made the following statement in support of the Application to include STIP costs in
its going-in rates.
61
Transcript Volume 3, page 0762, line 11 to page 0763, line 13
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In Decision 2006-002, the EUB disallowed certain proposed STIP costs, stating:
The Board considers that all amounts that relate to financial measures,
with the exception of revenue from new sources, provide benefits to both
EPC’s customers and the companies themselves. As a result customers
should only pay for 50% of the incentive compensation amounts related
to financial measures.
Since that decision, EPC has revised its STIP (KPIs) [key performance indicators] to
eliminate all financial measures. The prior STIP included financial targets at the business
unit level. These have been eliminated. Although ENMAX Corporation must meet a
threshold level of earnings before a bonus pool is established, EPC submits that this is
simply a prudent business practice. The key considerations are that the amount of the
bonus pool allocated to each business unit based on non-financial KPIs, and the amount
paid to individual employees based on business unit non-financial KPIs and individual
performance. The KPIs for EPC are measures related to safety, environment, reliability,
compliance and customer service. Once the bonus pool is established, no employee
payouts are a function of any financial results. Consequently, EPC submits that the
rationale for the prior disallowance no longer exists, with the result that it is appropriate
to include in the FBR base the full STIP cost. Consistent with past EUB decisions, EPC
will refund to customers any amount collected in respect of STIP but not paid out to
employees, including the situation where no STIP payments are made to employees
because the threshold level of earnings was not met. 62
79.
By removing the financial criteria at the business unit level from EPC’s STIP criteria, the
Commission finds that EPC has addressed the concerns set out in prior decisions respecting STIP
from a plan design perspective. The current STIP incents operational efficiency improvements
and, as such, complements the incentives created by a formula based regulation plan.
80.
Therefore, the Commission has determined that it will allow EPC to include in its goingin rates the previously disallowed 2006 forecast STIP amount of $1.292 million.
81.
The STIP program will continue to be an eligible expense incurred each year throughout
the life of the FBR plan. The STIP program provides additional incentives for efficiency over
and above those created by the FBR plan which should benefit both the utility and ratepayers.
This change to the 2006 rates is qualitatively different from rate adjustments made after the fact
to reflect actual results. The STIP adjustment is made based on the 2006 forecast expenditures in
order to allow a previously disallowed program that has been changed to accommodate the
EUB’s concerns to be included in revenue requirement.
82.
The Commission will not allow any of the other adjustments sought by EPC to its 2006
distribution rates. Further, the Commission will not adjust the 2006 rates downward to account
for what UCA submitted should be lower IT operating costs. The Commission is not persuaded
by the evidence offered by UCA in support of its proposed adjustment. The Commission finds
no reason to overturn previously approved IT cost forecasts included in the 2006 rates.
83.
Finally, the Commission does not approve UCA’s request to reduce EPC’s base revenue
requirement for certain actual costs (e.g Head Office, IT, O&M costs) for the same reason that it
did not allow increases to the 2006 rates to reflect higher actual costs experienced by EPC.
62
EPC Argument, pages 9-10
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84.
The going-in distribution rates for EPC’s FBR plan will be its approved 2006 distribution
rates adjusted to include the previously disallowed STIP costs.
4.3
Transmission
85.
EPC proposed to use, as its transmission going-in rates, its 2006 TFO tariff, which was
based on its 2006 transmission revenue requirement, as approved in Decisions 2006-079 63 and
2006-130. 64
86.
EPC did not propose any rebasing adjustments to its Commission approved 2006 TFO
revenue requirement or to the 2006 TFO tariff.
87.
UCA did not oppose the use of EPC’s EUB approved 2006 TFO tariff as its going-in
transmission rates, provided adjustments were made to IT costs. 65 UCA submitted that EPC’s
2006 IT costs assigned to transmission should be reduced by $1.5 million for the same reasons
put forward with respect to its proposed reduction of distribution IT costs.
4.3.1
Commission Findings
88.
Consistent with its findings on EPC’s proposed distribution going-in rates, the
Commission accepts EPC’s proposal to use the 2006 TFO tariff for the going-in transmission
rates.
89.
With respect to the submission of UCA that the going-in transmission rates should be
adjusted to deduct certain IT costs embedded in those rates, the Commission rejects this proposal
for the same reasons as a reduction to distribution rates was rejected.
90.
The Commission considers that EPC’s forecast transmission costs were properly tested in
the proceedings which led to Decisions 2006-079 and 2006-130 and does not agree with UCA
that the resulting TFO tariff should be adjusted before being approved as the going-in rates for
the FBR plan. The Commission therefore approves EPC’s proposal to use its 2006 TFO tariff as
EPC’s transmission going-in rates for the FBR program.
5
TERM OF THE FBR PLAN AND MID-TERM REBASING
91.
EPC proposed that the term of the FBR plan be ten years, commencing January 1, 2007
and ending December 31, 2016. 66 EPC stated that successful incentive-based regimes invariably
have longer terms than their cost of service based counterparts. EPC argued that longer term
arrangements provide sufficient certainty regarding regulatory treatment, and that utilities are
more comfortable engaging in long term investment programs, including investments with
benefits that go beyond the usual one or two year cost of service tariff approval periods. EPC
also stated that the longer term arrangement is more efficient as many of the parameters for ratesetting do not change frequently, thus making more efficient use of regulatory resources. 67
63
64
65
66
67
Decision 2006-079 was released on July 25, 2006
Decision 2006-130 was released on December 21, 2006
UCA Argument, page 14
Application, page 40
Exhibit 0018.00.EPC-12, page 34, Appendix 3
20 • AUC Decision 2009-035 (March 25, 2009)
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92.
EPC also argued that a longer term more closely matched the life of assets, and that it
provided better opportunities to plan and invest, resulting in potential efficiency savings that will
be shared with consumers through the earnings sharing mechanism. EPC further argued that a
10 year term is justified because:
•
•
•
•
•
•
rate payers will benefit from better alignment of incentives;
the overall design of FBR mimics the results of more frequent regulatory
proceedings;
EPC is not seeking compensation for the additional risk of a longer term;
the FBR Customer Committees will help resolve issues;
the proposed performance measures and earnings sharing mechanism ensure fairness
to customers; and
cost savings from more frequent proceedings can be reallocated to more productive
uses. 68
93.
In the Original Application, EPC proposed a ten year FBR plan without any cost of
service rebasing before the end of the term. However, during the information sessions held in
the fall of 2007, interested parties expressed concerns about the length of the FBR term. In
response to these concerns, EPC proposed, in the Application, a mid-term rebasing. 69 EPC stated
it would file
a rebasing application that is similar to a traditional Phase I application to allow for the
examination of costs and the resetting of rates, if necessary, to ensure that rates remain
aligned with costs.75 EPC does not, however, propose to “re-open” the FBR formula at
the mid-term rebasing. 70
[75 Response to CG.EPC-001 (Exhibit 0060.01.EPC-12,) provides further detailed information
regarding the midterm rebasing. See also 1T271:9-272:25 and 2T506:21-507:6; 76 2T507:2-6.]
94.
Although EPC applied for a mid-term rebasing, it stated:
EPC does not believe that the midterm rebasing is a necessary component of FBR and, as
an alternative to midterm rebasing, would support a decision by the AUC not to rebase,
either in the context of a ten or seven year term. 71
95.
Interveners put forward alternative proposals with respect to the length of the FBR term
and the need for mid-term cost of service rebasing, as well as the need for mid-term adjustments
to the parameters of the FBR formulas. D410 provided a clarification with respect to the term:
EPC’s proposed “10-year” term for FBR creates some confusion, because, at least for
creating economic incentives, it is really an 8-year term. While rates may be set for the
10-year period from 2007 through 2016 based on the formula, EPC will not really see the
economic incentives that are at the heart of an FBR mechanism until 2009 at the earliest.
For the purposes of this Reply Argument, the word “term” shall mean the period
beginning in 2007. 72
68
69
70
71
72
Appendix 3 to the Application, pages 34-39
Transcript Volume 2, pages 0533-0534
EPC Argument, pages 15-16
EPC Argument, page 16
D410 Reply Argument, page 3
AUC Decision 2009-035 (March 25, 2009) • 21
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96.
The Commission finds this observation useful and, in this Decision, when referring to the
term of the FBR plan the Commission considers its term to commence on January 1, 2007.
97.
In response to Commission questions, EPC stated it would prefer a ten year term to a
seven year term and would support no mid-term rebasing regardless of whether a seven or ten
year term were approved. 73 EPC stated that a ten year term with a mid-term rebasing would only
provide EPC and its customers with three years of actual FBR experience and would thus result
in a smaller amount of information with which to calculate productivity and examine
productivity growth at the time of the mid-term rebasing. 74
98.
UCA stated that rebasing after three years “may be too short in UCA’s view.” 75
99.
that:
UCA provided conditional support for a ten year term with a mid-term rebasing, provided
… the inclusion of line losses discussed in Section 1.1 above, and the conditions
proposed by Dr. Cronin and Mr. Motluk are met.65 One of these conditions includes the
provision of the data and information necessary to assess EPC’s historical productivity
performance and efficiency within a short period of time and a possible adjustment to the
customer rates dependent on whether EPC is “at or very close to the frontier” at the time
of the rebasing. [Exhibit 0064.03.UCA-12, page 77] 76
100. UCA argued that the productivity and efficiency information was required as FBR plans
“especially in their earlier generations, have shown a remarkable tendency to get key features
wrong.” 77
101. Mr. Marcus, CG’s witness, stated that while the study proposed by UCA would be
desirable, it was questionable whether it could be done. Mr. Marcus stated several objections but
noted in particular an issue with capital.
Even from an academic perspective, the allocative inefficiency of having too much
capital … also cannot be eliminated with a stroke of a pen. For example, for ENMAX
distribution, over half the gross plant projected in 2016 (nominal dollars) and well over
that amount (based on replacement cost) has already been installed in 2006, cannot
readily be removed to improve productivity, and will not reduce rates very much even if
removed (because a retirement reduces plant in service and depreciation reserve by an
equal amount). 78
102. In a similar vein, the Commission asked UCA “…how or whether, existing capital
infrastructure influences or constrains allocative efficiency gains.” UCA responded:
73
74
75
76
77
78
EPC Argument, page 15
Transcript Volume 2, pages 0535-0536
UCA Reply Argument, page 10
UCA Argument, page 17
PBR Evidence, page 7
Information Response UCA.CG-1 a)
22 • AUC Decision 2009-035 (March 25, 2009)
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These are interesting questions that require further empirical research to answer.
Dr. Cronin has touched on these issues in his research but cannot offer any specific
observations on these issues. This is a topic for further research going forward. 79
103. In cross examination, Mr. Marcus indicated that the skills required to develop efficiency
benchmarks are rare.
Q: Are you aware, sir, that the regulator in Norway, the NVE regulator, has actually
benchmarked utilities to the frontier of LDC [local distribution companies] efficiency?
Are you aware of that?
A: I would say that it's a skill set that's extremely rare in North America is I guess what I
would tell you, sir.
Q And you're generally aware of that because you have read the evidence of Dr. Cronin;
is that right, sir?
A MR. MARCUS:
In reading his evidence, in the experience in cases I have been
involved with, and the experience with other PBRs in North America, I have seen -- it's a
different skill set than most regulators have and it's not been done terribly well here.
I'm not going to tell you that people that never started with a North American regulatory
regime might not have figured it out. 80
104. CG objected to the ten year term and stated that “…a 5 year FBR Term more
appropriately balances the potential to reduce regulatory costs with EPC’s ability to effectively
operate under the FBR parameters.” 81 CG stated “…it does not accept the contention EPC would
manage its operations any differently were it to be allowed a 5-year Term” 82 rather than a seven
or ten year term. CG stated that “…there is no evidence, including any filed by EPC, indicating
utilities on a FBR/PBR term shorter than 10 Years have actually experienced any reduced
‘productivity improvement opportunities’ as suggested by EPC.” 83
105.
EPC 84 and D410 rejected CG’s argument. D410 stated:
The D410 Group submits that if EPC does not have any incentive to be efficient, there is
no purpose to this entire exercise. Without incentives, FBR is a waste of time. It is
unclear why CG would support even an effective 3-year FBR mechanism if there are no
useful economic incentives. 85
106.
D410 went further and stated:
A key advantage of FBR is that it allows a utility to make efficient long-term tradeoffs.
Unfortunately, while cost-of-service rebasing provides protections to both ratepayers and
shareholders, these protections tend to defeat the benefits of long-term efficiency. As Mr.
Knecht indicated in his pre-filed evidence:
Under FBR, base rates are established on a test year basis, but they remain
in effect for a much longer period of time than they do under test year
regulation, adjusted only for cost inflation and productivity gains. Because
79
80
81
82
83
84
85
Information Response AUC-UCA-8
Transcript Volume 6, pages 1465-1466
CG Argument, page 49
CG Argument, page 46
CG Argument, page 49, citing Transcript Volume 4, page 989
EPC Reply Argument, pages 12-13
D410 Reply Argument, page 4
AUC Decision 2009-035 (March 25, 2009) • 23
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the rates are in effect for a longer period of time, an FBR-regulated utility
has the incentive to make tradeoffs that are economically efficient over the
longer term, rather than the short term32
[32:Exhibit 0071.02.D410-12, D410 Direct Evidence, p. 2/7]. 86
107.
D410 went on to state that:
… the longer-term efficiencies associated with FBR can only be achieved by establishing
a relatively long period before any cost-of-service rebasing takes place. EPC’s proposal,
with only a three-year initial period, is too short to be effective. EPC will simply have
little or no incentive to make substantial capital investments to reduce O&M costs, if
those benefits will simply lower rates in three years. Similarly, EPC may be tempted to
make substantial capital investments in the initial three-year period that will not produce
O&M savings until the subsequent five-year period. That is, EPC will be able to roll the
capital into the cost-based rates and then retain the O&M savings in the second FBR
period. 87
108. D410 supported a seven year term in preference to a ten year term with cost of service
rebasing.
109. In the oral hearing the issue of term was summarized by EPC’s expert Mr. Goulding as
follows:
Q: Mr. Goulding, based on your experience, can you tell me, is there any sort of
guidelines or principles to determine what is an appropriate period of time when the
rebasing should occur, be it mid-term, final, whatever?
A: MR. GOULDING:
I think that the issue of rebasing is effectively one of term,
right? And the tradeoff is always in, to what extent do you want the incentive to be high
powered? You want to provide as much of an incentive to the company to invest in
efficiency improvements and improve its performance over time. And conversely, to
what extent do you feel that customers have a set of protections against what might be
considered unreasonable levels of earnings, right? And so from that perspective, and
jurisdictions will differ in their degree of comfort in those areas, what you want to look at
is, first of all, does the formula itself provide some degree of protection with regards to
that divergence? And if it does, then you can achieve greater comfort in going with a
longer term.
And so, you know, in terms of those kinds of principles, what you'd say is, you know, the
fewer the shock absorbers for customers, the shorter you might make the term, and the
more the shock absorbers for customers, the more you might make the term. In this
particular case, we have got the earning-sharing mechanism, and we effectively have a
rebasing after five years, and those two things working together, I think, would tend to
argue that this timing is appropriate.
I think, in particular, when you couple the ESM [earnings sharing mechanism] with some
broader sets of off-ramps that then a ten-year term does provide, through the formula
itself, sufficient protections that you could do without a mid-term rebasing. The one thing
I want to point out is the difference between a symmetrical and an asymmetrical earningsharing mechanism. And the fact that we have an asymmetrical earning-sharing
mechanism, I think, can allow us to have more confidence in a longer term in the sense
86
87
D410 Argument, pages 12-13
D410 Argument, page 13
24 • AUC Decision 2009-035 (March 25, 2009)
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that the benefits are shared with ratepayers, but any failure to achieve what would
otherwise be the rate of return is purely at the risk of the regulated company. So this is
another element that I think can help to add comfort to the idea of a longer term. 88
110. In addition to the considerable debate with respect to the need for mid-term cost of
service rebasing, some parties proposed that there be mid-term adjustments made to the
parameters of the FBR formulas, particularly the X factor, potentially in lieu of a cost of service
rebasing.
111. CG indicated that it did not support rebasing if a term longer than 5 years was approved.
However, if the Commission approved a longer term and rebasing, CG stated that:
such rebasing should be limited to an assessment of whether the FBR parameters requires
further adjustment. Details regarding the nature and extent of such a review should be
determined by the Commission shortly before the time of the mid-term rebasing with
input to be provided by EPC and the Customer Committee. 89
112.
D410 stated that:
… simply adjusting the productivity factors after five years would also create better
incentives for EPC to make efficient productivity improvements than cost of service
rebasing. 90
113. D410 also stated that simply adjusting the productivity factor, however, will not result in
EPC losing all of the benefit of the efficiency gains that it makes in the initial FBR period, nor
will it create incentives for EPC to make improvements in the initial period that only bear fruit in
the latter period. It is also less distortive. 91
114. As noted earlier, UCA supported “…a possible adjustment to the customer rates
dependent on whether EPC is ‘at or very close to the frontier’ at the time of the rebasing.” 92
115. EPC proposed that no adjustments be made to the proposed formulas. Further EPC did
not see rebasing as a necessary component of FBR. 93
5.1
Commission Findings
116. The Commission recognizes that the longer the term of an FBR plan, the stronger the
incentives for utilities to improve their efficiency.
117. This is the first time a utility in Alberta has applied for an FBR plan of the scope being
proposed by EPC. The Commission notes the testimony of Dr. Cronin that the Commission has
imperfect information when establishing an FBR plan. The Commission recognizes that parties
to the proceeding considered the earnings sharing mechanism, the re-openers and the off ramps
proposed in the Application to be “safety valves” for customers and the company were
something significant and unexpected to occur. The Commission agrees.
88
89
90
91
92
93
Transcript Volume 2, pages 0531-0534
CG Argument, page 52
D410 Argument, page 15
Ibid
UCA Argument, page 17
EPC Argument, page 16
AUC Decision 2009-035 (March 25, 2009) • 25
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118. In the circumstances of EPC, the Commission finds that five years for the initial FBR
term would be reasonable and sufficient to allow the company to achieve significant efficiency
gains. However, the first two years of EPC’s proposed FBR plan have already passed.
Therefore, the Commission finds that a seven year plan will provide significant efficiency
incentives for the benefit of both the company and customers. Accordingly, the Commission
approves an FBR term from January 1, 2007 to December 31, 2013. Given the duration of the
approved FBR plan, the Commission considers that neither a mid-term cost of service rebasing
nor a mid-term adjustment to the parameters of the FBR formulas is warranted.
119. Before the end of the FBR term, the Commission expects EPC to file, in a timely manner,
its proposal for its regulatory framework to be implemented after December 31, 2013.
6
I FACTOR
6.1
Characteristics of an Inflation Factor
120. EPC stated that there is no single ideal inflation rate that applies across all jurisdictions
and that the choice of the I Factor “…influences the parameters by which X is set.” 94
121. EPC stated that an ideal I factor should reflect the firm’s cost behavior, be exogenous to
the firm, be based on publicly available and frequently updated data, be generally accepted by
ratepayers, be transparent and easily understood, and be reasonably reflective of the goods and
services the firm buys. 95
122. In the Original Application EPC proposed the use of the Calgary Consumer Price Index
(CPI), an output index, as its inflation measure. EPC stated that the CPI is well-understood by
all parties, available from an independent source on a timely basis, and subject to neither
periodic revisions nor manipulation by participants in the FBR plan. After filing the Original
Application, EPC undertook discussions with stakeholders to examine what they considered to
be most appropriate for various components of the formula, and ultimately arrived at something
which is effectively a tailor made input index for EPC. 96
6.2
Proposed Factor
123. In the Application, EPC proposed a blended I factor using input indices for both
distribution and transmission. 97 The proposed blended factor was based on the Canadian Electric
Utility Construction Price Index (EUCPI) and monthly Alberta Average Hourly Earnings (AHE).
EPC proposed the following I factor for distribution: 98
w*[EUCPI ] + (1-w)*[AHE]
D
94
95
96
97
98
Response to AUC.EPC-003
Exhibit 0044.01.EPC-12, AUC.EPC-003 a)
EPC Argument, page 18
Application, Section 3.1.2
Application, page 49
26 • AUC Decision 2009-035 (March 25, 2009)
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124.
ENMAX Power Corporation
EPC proposed the following I factor for transmission: 99
z*[EUCPI ] + (1-z)*[AHE]
T
125. “w” and “z” in the above formulas represent EPC’s capital expenditures relative to total
expenditures for distribution and transmission respectively. The relative weightings are
discussed in a subsequent section of this Decision. EPC described the EUCPI and AHE indices
as follows: 100
The Electric Utility Construction Price Index (“EUCPI”) series, as described by Statistics
Canada, measures the price change for constructing two types of plants, distribution
systems and transmission lines systems, representing electric utility capital expenditure
construction projects. This definition and description is available online from Statistics
Canada at: http://www.statcan.ca/cgibin/imdb/p2SV.pl?Function=getSurvey&SDDS=2316&lang=en&db=IMDB&dbg=f&ad
m=8&dis=2.
Average Hourly Earnings (“AHE”), as described by Statistics Canada, is a calculation of
average hourly earnings for salaried employees (paid a fixed salary), calculated through
the Survey of Employment, Payrolls and Hours or “SEPH”), including overtime,
unadjusted for seasonal variation, for selected industries classified using the North
American Industry Classification System (“NAICS”). This description is available online
from Statistics Canada at: http://cansim2.statcan.ca/cgi-win/CNSMCGI.PGM. As shown
in the data of Alberta AHE in the response to D410.EPC-002 Attachment, EPC proposes
to use average hourly earnings for salaried employees (paid a fixed salary), as defined by
SEPH, within Alberta (under the heading “Industrial aggregate excluding unclassified”).
A complete definition and description of SEPH, is available online from Statistics
Canada at:
http://www.statcan.ca/cgibin/imdb/p2SV.pl?Function=getSurvey&SDDS=2612&lang=en
&db=IMDB&dbg=f&adm=8&dis=2
6.3
Output versus Input Indices
126. In the Original Application, EPC discussed the significance of using an output index and
an input index in determining the I factor.
An additional feature of the choice of inflation parameter is that it is complementary to
the level of X factor chosen; as discussed in the subsequent section, CPI already
incorporates economy wide total factor productivity (TFP) gains. This means that the X
factor need only reflect the extent to which EPC productivity is expected to differ from
economy-wide levels.
Overall, use of CPI-Calgary in the formula is the best choice for an inflation index
because it is congruent with the level of X factor (productivity factor) selected, calculated
in a series consistent with EPC’s service territory, readily available, carefully scrutinized,
exogenous to the firm, and is likely to be reasonably well understood by stakeholders. 101
99
100
101
Application, page 49
Response to AUC.EPC-061(b)
London Economics Evidence Appendix 3, page 16
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127. Other parties also noted the linkages, interrelationships and issues involved in the
selection of an I and X factor. The primary issue noted is that the choice of an I factor can
influence the X factor depending upon the various degrees of productivity which may be
embedded in a particular I factor. The manner in which one ‘backs out’ or adjusts for such
duplication is technical and can be complicated. For example, EPC noted that if using an output
measure of I, such as CPI, then X must be adjusted as follows:
Technically, it is not only the TFP differential but also the Input Price Differential [IPD]
that needs to be added if one is to use an output-based inflation measure. However, in
practice for most countries many economists assume the IPD =0, and simply add on the
multifactor productivity for the economy as a whole. So formula would be:
Price Cap Rate of Change = (CPI + IPD) – (TFPfirm-TFPeconomy). 102
128. UCA agreed in principle that adjustments to X are required when using an output index
such as a GDP price index. UCA stated:
…that the difference in output price changes is a function of two terms: the first representing the
difference between input price changes between the utility and the aggregate economy is called
the input price differential (IPD); the second representing the difference between productivity
changes between the utility and the aggregate economy is called the productivity differential
(PD). 103
129. UCA stated that the I factor proposed in the Application is an improvement over the I
factor in the Original Application. In particular, UCA noted the movement from “a macro,
output price index to reflect electric distribution input prices.” 104
130. Despite recognizing an improvement in the I factor in the Application over the Original
Application, UCA recommended further changes and that the use of an aggregate input price
index be adopted as a measure of inflation in the FBR because it eliminates the need to calculate
an input price differential and a productivity differential in the calculation of the X factor. 105
UCA stated that using its recommended input price index obviates the need for frequent cost of
service proceedings because it sets an automatic adjustment of costs, mitigates the likelihood that
mistakes in the plan with a macroeconomic index will under/overcompensate the local
distribution company, establishes a benchmark, and provides proper price signals for the local
distribution companies and customers. 106
131. UCA proposed 107 that the AUC adopt a “comprehensive input price index” which
includes factors for materials, labor, line losses and capital. The components were as follows:
•
102
103
104
105
106
107
Material costs be calculated as the non-labor cost portion of the following accounts:
O&M, billing and collection, and administration. The price of materials would be
represented by the “Industrial Producer Price Index” published by Statistics Canada;
Response to AUC.EPC-063
EPC PBR Evidence, page 31
UCA Argument, page 19
UCA PBR Evidence, page 35
UCA PBR Evidence, page 33
UCA PBR Evidence, pages 37-41
28 • AUC Decision 2009-035 (March 25, 2009)
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•
•
•
132.
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The price of labor be represented by the “Fixed Weighted Average Hourly Earnings for
All Employees, Excluding Overtime for Alberta Utilities (v1606330) which is also
published by Statistics Canada;
Line losses would be calculated based on reported line losses and the price of purchased
power;
The capital cost component would be calculated assuming a perpetual inventory model
adjusted for the annual depreciation rate, inflation adjusted additions and inflation
adjusted retirements.
The basic formula proposed for cost of capital C is:
k
C =r *X
kt
kt
kt
where
R is the capital price index calculated as the Canada long bond rate (i) plus the annual
kt
depreciation rate (d) times the Electric Utility Distribution Price Index published by
Statistics Canada (r ), so that:
at
R = (i + d) r
kt
t
at
Expanded, the formula would be:
C = ((it + d) rat) *((1 – d ) (xkt -1 ) + Akt / rat - Rkt / rat-n)
kt
where
Ak is the addition to capital book value, and Rk is retired capital. The annual depreciation
rate is calculated as the average annual share of depreciation to gross book value.
Retirements are assumed to have aged 15 years. The share of capital in total distribution
costs ranges between approximately 40 and 60 percent. The Canadian long bond rate, i, is
a measure of opportunity cost.
133.
EPC indicated that while index accuracy could be improved, it would come at a cost.
Index cost reflectiveness can be improved by creating a composite index made up of two
or more published indices weighted according to the average relationship over time
among various inputs deployed by EPC. However, the better one makes the historical fit
of the composite index to EPC cost behavior, the more complex the composite becomes.
Furthermore, such indices are less likely to be completely exogenous to the firm, and rely
on smaller sample sizes. This complexity, though sometimes improving historical
accuracy, risks creating the impression that the inflation factor is being manipulated to
the company’s benefit. Indeed, other Canadian jurisdictions (Ontario, for example) which
experimented with use of composite indices in electricity FBR ultimately rejected them in
favor of a single, well known, publicly available measure. 108
134. D410 expressed some of the same concerns as EPC and objected to UCA’s proposed
labour index on the grounds that:
By choosing a labor price index based only on Alberta utility wages, the UCA proposal
may end up discouraging efforts by Alberta EDCs to keep wages in line with labor costs
108
Application Appendix 3, page 12
AUC Decision 2009-035 (March 25, 2009) • 29
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in other industries. That is, if all Alberta EDCs adopt an FBR mechanism that relies on
average utility industry wages, the industry may be tempted to reduce its efforts to keep
costs reasonable, because any such effort will simply result in lower rates. 109
135. D410 indicated that UCA’s proposal had “…not been thoroughly vetted.” 110 However, it
also indicated:
… other aspects of the UCA proposal have merit, such as the need to reflect current
capital costs and the advantage of segregating labor and materials cost in the index. In
addition, the D410 Group is concerned about the uncertainty associated with EPC
updating the weighting factors for its “I” factor each year. Therefore, the D410 Group
respectfully recommends that the issue of the “I” factor be re-evaluated after the initial
FBR period, as part of the rebasing process. 111
136. EPC and D410 commented on the lack of detail surrounding the calculations of UCA’s
proposed I factor. 112
137.
CG considered EPC’s proposed I factor and UCA’s proposed I factor and argued:
In CG’s submission, Dr. Cronin’s method for determination of the I factor would be a
more appropriate method as compared to EPC’s as it takes into consideration the impact
of input price increases applicable to each input cost component. In CG’s view, the EPC
method would likely overstate the input price escalations, particularly for distribution,
because it implicitly assumes capital related costs associated with the initial rate base, as
well as growth related capital additions are escalating at the same rate as the EUCPI and
does not consider changes in volume of capital due to retirements and depreciation nor
any changes in the opportunity cost of capital.
However, in the event the Commission were to proceed on the basis of EPC’s proposed I
factor, CG notes, despite the noted weakness in EPC’s proposed I factor, EPC’s financial
model suggests use of the proposed I factor is not likely to result in excessive earnings
over the FBR period. In particular, Attachment AUC.EPC-82D (2006 rebase correction
of $.922 million and 1.5% X factor) shows the average return on equity before sharing
for the first 5 years and 10 years of FBR is 6.45% and 6.91% respectively for distribution
and 7.16% and 8.44% for transmission. 113
6.4
Commission Findings
138. The Commission is satisfied that an input index for the inflation factor should be adopted
in this case. Such an index should reflect changes in the costs experienced by as large a sample
of distribution and transmission companies as possible. The Commission recognizes that the
development of such an index can be made extremely complex by attempts to track discretely
inflation rates for multiple cost elements and also recognizes that increased complexity does not
necessarily lead to a superior index. The Commission recognizes that the Ontario Energy Board
experimented with the development of such an inflation index and ultimately rejected it. 114
109
110
111
112
113
114
D410 Argument, page 17
D410 Argument, page 16
D410 Argument, page 17
EPC Reply Argument, page 31, D410 Argument, pages 15-16
CG Argument, page 34
Application Appendix 3, London Economics Evidence, page 12
30 • AUC Decision 2009-035 (March 25, 2009)
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139. In this proceeding, UCA proposed development of a comprehensive input price index
that would include factors for materials, labour, line losses and capital. However, UCA was
unable to calculate such an index because of an apparent lack of data. 115 Nevertheless, UCA was
asked to clarify the calculation of the capital component of its proposed index. Its response
demonstrated that its proposal is more data intensive and more complex than the Commission
considers desirable for purposes of an FBR plan. For example a portion of UCA’s response
stated:
Real stock in 1980 (i.e., constant dollar capital) is estimated by deflating undepreciated
capital by a capital asset price constructed by “triangularizing” the pre-benchmark asset
prices back to 1960. 116
140. Nevertheless, the Commission has considered whether a more specific approach should
be employed for capital in an FBR index. The Commission is prepared to examine, in a future
proceeding, whether specific adjustments for capital need to be incorporated in an inflation
index.
141. The Commission is concerned, however, with what appears to be an effort to move closer
to an inflation index that tracks the experience of the specific utility to which the FBR plan
would apply rather than a more broad measure. For example, as noted above, D410 expressed
the concern that by choosing to include Alberta utility wages in its inflation index the UCA
proposal could end up discouraging Alberta utilities to keep labour costs in line with other
industries. EPC expressed a similar concern from the perspective of the applicant that using
small sample sizes could leave the impression that the index is being manipulated to benefit the
company.
142. D410 identified in the UCA proposal the unintended consequence of dampening the
incentive to keep certain costs in line with other industries when the labour component of the I
index is limited to the utility industry in a small geographic area such as Alberta. In doing so,
D410 has identified a part of the attraction of an FBR plan, that the establishment of broadly
based I and X factors require the regulated company to, in effect, compete with the other
companies and industries included in the indices.
143. As noted above, EPC first proposed Calgary CPI as its inflation index. Later, it changed
its proposal to a combination of two input price indices, EUCPI and AHE. Unlike an output
index, an input price index does not require an adjustment to the X factor to reflect differences in
input price changes between the utility and the aggregate economy (the input price differential)
or an adjustment to reflect differences in productivity changes between the utility and the
aggregate economy (the productivity differential). Accordingly, one result of the change made
by EPC is that the Commission can proceed to consider the new index without having to
consider making adjustments for an input price differential or a total factor productivity
differential in the calculation of the X factor.
144. As described above, the EUCPI is a national index that tracks the rate of inflation in the
cost of construction of electricity distribution and transmission. Also as described above, the
AHE is a calculation of average hourly earnings for salaried employees of all Alberta industries.
EPC proposes to use both the Alberta AHE and EUCPI as reported by Statistics Canada. These
115
116
EPC Reply Argument, page 31, D410 Argument, pages 15-16
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indices are sufficiently broadly based to avoid potential concerns about the ability of EPC or
ENMAX Corporation to significantly affect the results. In addition, the indices are produced and
available from an independent source. While UCA and others have argued that there should be
more individual cost elements included in the inflation index employed for the EPC FBR plan,
the Commission is satisfied that these indices are reasonably reflective of the goods and services
purchased by EPC. While UCA sought to include separate indices for material, labour, line
losses and capital, the Commission recognizes that materials, labour and capital are included in
the indices proposed by EPC. In addition, the labour component of the EPC indices is broadly
based. The AHE reflects the rate of change of an industrial aggregate of salaried employees for
Alberta across all industries and the EUCPI reflects the rate of inflation for materials, capital
costs and capitalized labour embedded in the index.
145. With respect to the UCA’s proposal to deal with line losses in the calculation of an I
factor, the Commission notes that it has received an application for a proposal to address
incentives to reduce line losses within an FBR plan and will consider this application in a
subsequent proceeding.
146. The Commission notes that the issue of annual weighting did not, and would not arise
under EPC’s original proposal for a single output based inflation factor. D410 expressed
concern about the uncertainty associated with the annual weighting of capital expenditures
relative to total expenditures in the calculation of EPC’s inflation factors for both distribution
and transmission. For this reason, D410 recommended that the Commission re-evaluate the I
factor after the initial FBR period.
147. The Commission also has concerns with the EPC annual weighting adjustment proposal.
In the Commission’s view, because the inflation rates applied in the formula each year are the
actual inflation rates from the previous year, allowing EPC to adjust the weight of capital in its
annual inflation index filing, based on its own actual weighting results from the prior year, could
create incentives for the company to adjust its capital program in response to its perceptions
about the relative rates of inflation reported by the EUCPI and the AHE rather than for the
purpose of improving overall efficiency. The Commission recognizes that in the circumstances
of this case, the incentives created may be relatively small. Nevertheless, the Commission
prefers to simplify the inflation index calculation and remove the incentives for EPC to adjust its
capital program.
148. The Commission has examined the distribution and transmission capital ratios projected
by EPC to 2016. In 2006, the distribution capital to expense ratio is approximately 55:45. In
2016, the distribution ratio is projected to be 50:50. For transmission, the 2006 capital ratio is
40:60. In 2016, the ratio is projected to be 35:65. However, for 2007 to 2009, the EPC
transmission ratio is projected to be in the 60:40 range. Despite the range in these forecasts, the
Commission notes that the 11 year average for capital is 54 percent for distribution and 45
percent for transmission. 117 Therefore, the Commission will accept the inflation indices proposed
by EPC for distribution and transmission with one change. Instead of allowing an adjustment in
the weighting of capital annually, the Commission will require EPC to hold constant the capital
ratios throughout the FBR period. In this way, EPC’s incentives will not be influenced by
relative rates of inflation of the indices.
117
Calculated from “Input” tab, Application Appendix 5, Model
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149. The Commission has noted that the 11 year average for capital is 54 percent for
distribution and 45 percent for transmission. Based on this average ratio the Commission is
prepared to approve a capital ratio in the inflation index for both distribution and transmission
held constant at 50 percent for the duration of the FBR period. If EPC wishes to change the ratio
to another constant for either distribution or transmission, it may apply to the Commission in its
compliance filing accompanied by the rationale for choosing a different ratio. The constants
chosen may but need not apply equally to both distribution and transmission.
7
X FACTOR
7.1
Background
150.
EPC stated that:
The purpose of the X factor is to set forth a minimum level of the productivity
improvements a regulated entity is expected to attain during the regulatory period. If the
regulated entity fails to achieve this minimum threshold level of productivity
improvements, its profits suffer. Traditional cost of service ratemaking focuses primarily
on what costs are, rather than on what level they should be. Notwithstanding the fact that
a cost of service prudence review may involve some analysis of what costs should be, a
competent utility under a cost-of-service ratemaking regime can develop a reasonable
justification for a broad range of costs incurred; the X factor in an FBR plan changes this
focus entirely. Instead of focusing on whether it can justify its forecast costs for the next
test year to the regulator, a utility can focus on identifying the optimal level of costs to
assure that it is able to meet reliability and customer service standards. 118
151.
London Economics explained the purpose of the X factor as follows:
Because infrastructure industries such as electricity distribution and transmission are
often subject to decreasing unit costs across broad ranges of output, competition is
normally limited and, in the absence of regulation, incentives to minimize costs and
provide the cheapest and best possible quality service to users can be weak. The use of
CPI-X (FBR) regulation in such industries strengthens the incentive to operate efficiently
by imposing pressures on the network operator that are similar to those experienced in a
competitive market. It does this by constraining the network operator’s output price to
track the level of estimated efficient unit costs for the industry.
Prices are thus capped at the level of price change the business faces for its inputs less the
rate of productivity growth in the industry as a whole. This ensures the benefits of
productivity improvements at the industry level are passed on to consumers, while giving
individual firms an incentive to achieve productivity growth better than that for the
industry as a whole. 119
7.2
Proposed X Factor
152. In the Original Application EPC proposed a value of 0.5 percent for X, however this was
revised to 1.5 percent in the Application. EPC noted that :
…during discussions with stakeholders, EPC developed the opinion that customers might
be more comfortable using input measures of inflation rather than output measures.
118
119
Information Response AUC.EPC-004 a)
Appendix 3 to the Application, page 17
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Because the CPI embeds within it productivity improvements in the economy as a whole,
X factors that are coupled with a CPI inflation mechanism tend to be lower. This is
because the X factor need only represent the difference between economy-wide and
industry specific productivity growth. Due to the maturity of the industry mentioned
previously, EPC could initially have justified an X factor of zero or less, given that utility
productivity gains tend to be lower than the economy as a whole.10 Because of EPC’s
desire for a stretch factor, however, the X factor was initially set at 0.5%. When the
proposed inflation factors were changed to input measures, EPC had to adjust its
proposed X factor as well; thus, adding back assumed economy-wide productivity growth
leads to the proposed X factor of 1.5%; given that Canada-wide productivity growth for
2000-2004 averaged 0.8% per year, the choice of a 1.5% X factor actually indicates that
the stretch factor for EPC could be as high as 0.7%. It is important to emphasize that
economy-wide productivity estimates, as well as published inflation rates, are at best
relatively crude estimates. Thus, the impact of changing from use of an output measure to
an input measure of inflation on embedded productivity estimates cannot be considered to
be precise. 120
153.
EPC stated that it:
… anticipates being able to implement productivity improvements sufficient to offset the
1.5% X-Factor throughout the FBR Term. … Nevertheless, a Productivity Factor of
1.5% represents a significant challenge for EPC. 121
154.
•
•
•
•
•
•
EPC submitted that the proposed 1.5 percent X factor is appropriate because: 122
EPC is already an efficiently run distribution and transmission utility;
EPC’s internal benchmarking studies against Ontario LDC’s “indicate that EPC has generally
performed favorably in comparison to Ontario distribution utilities for the period from 2002
to 2005”; 123
EPC filed an analysis which “found that an acceptable productivity range is 0 to 0.8
percent.”; 124
“Given the proposed FBR term, a 1.5% X-Factor is considered a stretch goal, because the
Productivity Factor has a compounding effect, resulting in EPC requiring significant
productivity improvements in the later years”; 125
The X factor “effectively embeds a portion of increases in rates needed to fund distribution
capital expenditures; and
the benefits provided to customers through the X factor are significant.
155. EPC provided data from various jurisdictions around the world with X factors ranging
from minus 2. 0 percent to 2.0 percent. EPC noted that in those rare cases where the X factors
were negative, it was “…usually due to the need for the utility to make substantial ongoing
capital expenditures.” 126
120
121
122
123
124
125
126
AUC.EPC-004(b)
Application, Section 3.2
Application Section 3.2, pages 57-59
Application, page 58
London Economics in Appendix 3, page 23
Application, page 58
Response to AUC.EPC-004(c)
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156. EPC also filed data from studies of various distribution companies which showed average
total factor productivity growth rates ranging from 0.6 percent to 0.8 percent. The Table is
reproduced below.
Application, Appendix 3 LEI [London Economics] Evidence
Figure 6. Summary of Average Annual Distribution TFP Across Different Jurisdictions
Jurisdiction
Time
Avg. Annual
Frame
TFP Growth
Ontario (Canada) -- 40 companies
1988-1997
0.8%
Ontario (Canada), Massachusetts, Maine and California
Varied
0.7%
-- distribution
United States -- 75 distribution companies
1993-2003
0.7%
Victoria (Australia)--5 distribution companies
2001-2005
0.6%
New Zealand -- 29 distribution companies
2000-2003
0.8%
157. EPC further stated in AUC.EPC-004 that it “believes it is operating close to the
efficiency frontier for a similarly situated utility.”
158. UCA responded that EPC’s benchmarking study against Ontario local distribution
companies does not include capital costs and line losses and that “we cannot draw any
conclusions about a comparison based on total costs.” 127
159. Dr. Cronin provided evidence on other jurisdictions “that can shed some light on the
reasonableness of the EPC proposal.” 128 He provided evidence from Norway that “in the
Norwegian context, ENMAX would have been required to be among the top 15 to 20 percent of
distributors to earn a 1.5 percent productivity factor.” 129
160.
With respect to Ontario Dr. Cronin stated:
Recall that from 1988 to 1993 the growth in TFP for Ontario was about zero. From 1993
to 1997, while operating under a de facto PBR these distributors had achieved a robust
rate of productivity growth of 2. Over the whole period, the average was just under 0.9.
However, I also examined the performance of the frontier (most efficient) LDCs versus
interior (less efficient) LDCs. [footnote omitted] These frontier firms made up about 19
percent of the LDCs analyzed.
I found that the LDCs that were judged to be most efficient at the start of the period had
consistently higher growth in TFP than did less efficient LDCs. This was true over both
the 1988-1993 and the 1993-1997 periods. Over the full ten-year period, the average
annual growth in TFP for these frontier firms is about 1.6 percent. During the higher
incentive period from 1993 to 1997, their productivity growth was well in excess of 2
percent per year. These results are quite consistent with those of NVE: I find, as did
NVE, that the long term growth in efficiency (i.e., frontier firms) is 1.5, quite close to the
1.5 to 2.0 used by NVE. 130
127
128
129
130
UCA PBR Evidence, pages 25-27
Exhibit 0064.03-UCA.12, UCA PBR Evidence, page 26
Ibid, page 27
Ibid, pages 27-28
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161. Dr. Cronin concluded that “ENMAX’s proposed 1.5 percent would be consistent with the
productivity factor expected of a frontier firm” but “were it not to be on the frontier … the
productivity factor would be set higher.” 131
162. UCA recommended “given the absence of data to empirically examine the company’s
efficiency and given the prior research supporting a 1.5% PF [productivity factor] for frontier
firms … that the proposed 1.5% be adopted subject to certain conditions.” Specifically, UCA
proposed that:
•
•
163.
the data and information to assess the company’s historical productivity performance and
efficiency must be provided to stakeholders as requested in UCA.EPC-017.
If an assessment of EPC’s productivity shows that EPC is not at the frontier, then the
AUC can “ascertain the extent of technical and allocative inefficiency and determine
what reduction in rates is required for the start of the second 5 year term. 132
In other words, as D410 noted:
…if EPC is found to be below the frontier efficiency, it would have a greater potential for
improvement and therefore the productivity factor should be set higher (or the rates
should be re-based to a lower level). 133
164. CG supported the 1.5 percent factor but indicated that “…a Productivity Factor of 1.5%
represents a significant challenge for EPC.” 134
165.
CG acknowledged UCA’s argument. However, CG commented:
Although in theory an…adjustment to rates at the beginning of the second 5 year term
seems logical, if allocative and technical efficiency were sub optimal, it is almost certain
such an assessment would not be free of controversy due to reasons of EPC’s data
limitations, comparability of the peer group and other inherent differences between EPC
and the peers. 135
166.
CG then argued that given that EPC’s financial model shows below average returns:
… it is not clear to what extent it is even practical to make a downward … adjustment at
the beginning of the second 5 year term even if the relative efficiency study indicates
EPC’s allocative and technical efficiency are sub optimal. 136
167.
In Argument, CG stated:
In CG’s submission, one of the objectives of FBR is to provide the right incentives for
the utility to achieve efficiencies over the FBR period. This means, through the price
cap/revenue cap mechanism, the utility is being provided the tools to improve its
allocative and technical efficiencies. The result of this will be evident in the amount of
earnings available for sharing between EPC and its customers. If EPC is not presently at
131
132
133
134
135
136
Ibid, page 28
UCA PBR Evidence, page 28
D410 Argument, page 18
CG Argument, page 35
Ibid
Ibid
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the efficiency frontier, the earnings over the first 5 years ought to exceed the financial
model projections, given the FBR incentives. 137
168. D410 originally proposed an M factor adjustment to the FBR formula via X to account
for the no cost capital implications of the municipal rider. D410 recommended “if the AUC
desires to implement a revenue-neutral M-factor, which would correct the economic incentives
without disadvantaging EPC relative to its filed proposal … that the X factor be reduced from
1.5 percent to 0.9 percent.” 138 The M factor adjustment to the X factor is discussed later in this
Decision.
169. As a result of the amended EPC municipal rider proposal, D410 reduced its proposed
adjustment to maintain a revenue neutral X factor and M factor to 0.2 percent. D410 stated that
this was not a material difference and no adjustment was required. D410 stated that the proposed
1.5 percent X factor was reasonable.
7.3
Commission Findings
170. The Commission recognizes that any formula based rate setting plan that allows the
regulated entity to retain any increased earnings (and requires it to absorb any losses) will
increase incentives to improve efficiency and increase the rate of productivity growth. The
purpose of the X factor in such a plan is to ensure that customers share automatically in the
benefits of the enhanced incentives through rate increases that are less than the rate of inflation
(in this case measured by an input price index).
171. The Commission acknowledges that the X factor it establishes must allow EPC a
reasonable opportunity to recover its prudently incurred costs over the FBR period. Therefore,
the Commission cannot set out to establish an X factor that it knows will be unattainable. At the
same time, the record of this proceeding clearly establishes that all parties expect that the
approval of an FBR plan will increase EPC’s incentives to improve its efficiency and rate of
productivity growth. The challenge is to determine the rate of productivity growth that the
company can reasonably be expected to achieve over the seven year FBR term recognizing that
two years have already passed.
172. Given the choice of the inflation factor, there is no need in this case for the Commission
to consider adjustments to the X factor for input price differentials or productivity changes
embedded in the inflation rate chosen.
173. Two principal approaches were employed by the parties to assist the Commission in
determining the X factor. EPC focused on its projected financial performance over the FBR
period. This is strongly reflected by the fact that EPC proposed an X factor of 1.5 percent,
provided that the 2006 rates were first increased by certain adjustments. Since the Commission
has not allowed the entire requested increase in going-in rates, EPC cannot be said to have
agreed to the 1.5 percent X factor. CG also focused on earnings projected by EPC’s financial
model and commented that a 1.5 percent X factor represented a significant challenge for EPC.
UCA adopted a 1.5 percent X factor in this case based partially on Dr. Cronin’s observation that
in Norway, an X factor of 1.5 percent would be the annual rate of productivity growth expected
of an electric distribution company operating at the efficiency frontier. Companies found to be
137
138
CG Argument, page 36
D410 Evidence, page 11
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less efficient would be assigned a higher X factor. Dr. Cronin believed his research in Ontario
was consistent with the Norwegian expectation that a firm at the efficiency frontier should be
able to sustain higher than average annual productivity improvements. UCA was willing to
accept the 1.5 percent X factor until it had the data to determine whether EPC is operating at the
efficiency frontier.
174. With respect to the EPC and CG approach, the Commission understands the attraction of
setting an X factor on the basis of expected earnings. Doing so, however, is similar to engaging
in a multi-year cost of service rate setting exercise and changes the theoretical basis for utilizing
the X factor, which is to emulate the incentives of a competitive marketplace for the benefit of
ratepayers and shareholders alike.
175. With respect to the UCA approach, the Commission notes Dr. Cronin’s reliance on
Norwegian evidence as well as his analysis of Ontario local distribution companies. With
respect to the Norwegian results, the Commission is reluctant to choose a productivity number,
such as 1.5 percent, from another jurisdiction to establish a minimum offset without
understanding more about the operating circumstances of the sample companies and the industry
rate structure. 139 With respect to Ontario, Dr. Cronin observed that the average total factor
productivity growth for the local distribution companies was just under 0.9 percent over a ten
year study period, while local distribution companies that were judged to be the most efficient at
the start of the ten year period had consistently higher growth in total factor productivity than did
less efficient firms. Indeed, Dr. Cronin stated that “[o]ver the ten year period, the average annual
growth in TFP for these frontier firms is about 1.6 percent.” 140 Based on the evidence in this
proceeding, the Commission considers that it would be difficult to conclude that all electric
utilities should be able to consistently achieve a minimum 1.6 percent annual growth in
productivity over an extended period, when the historical average productivity growth for the
industry was approximately 0.9 percent. In addition, the Commission is concerned that the total
factor productivity studies upon which Dr. Cronin relies appear to have made no attempt to
segregate the productivity improvements in regulated services from other services offered by the
companies. 141 The Commission is therefore reluctant to impose an X factor for EPC in the range
of 1.5 or 1.6 percent.
176. In this case, the Commission prefers an approach to setting the X factor that requires the
company to, at a minimum, achieve the average rate of productivity growth in the industry as a
whole. Therefore, the starting point for determining the X factor should be the historical
industry average total factor productivity growth 142 for the services being included in the FBR
plan. Unfortunately, as all parties recognized, there is no industry average total factor
productivity data available for Alberta electric utilities or for all Canadian electric utilities. In
addition, the information that is available is limited to a sampling of distribution companies,
although it appears some companies in the sample may also provide transmission services.
139
140
141
142
Rate structure itself is important. For example, Dr. Cronin when asked about the performance of a telephone
company in California under a price cap plan, acknowledged that it is important to understand whether
customers are billed on a fixed charge or a variable charge basis when comparing PBR plans.
Transcript Volume 7, pages 1779-1782
Cronin Evidence, page 27
Transcript Volume 7, pages 1776-1778
London Economics defines TFP at page 18 of Appendix 3 to the Application as: “TFP is a comprehensive
productivity measure which compares changes in the quantity of all outputs produced to changes in the quantity
of all inputs used in the production process.”
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There is no separate information on the record about total factor productivity growth in the
electric transmission business.
177. The electric distribution total factor productivity information filed on the record by both
EPC and UCA discloses that 0.8 percent falls within the range of a reasonable estimate of the
average annual rate of total factor productivity growth. The Commission does recognize that the
Ontario data for some years prior to PBR type arrangements discloses zero annual productivity
growth while the data for later years shows an average of 2 percent annual productivity growth.
The Commission also recognizes that EPC’s analysis of the Ontario companies found an
“acceptable” productivity range of 0 to 0.8 percent. Dr. Cronin noted that “[o]ver the whole
period, the average was just under 0.9.” EPC also filed total factor productivity information for a
number of distribution companies in various countries including Canada. 143 Despite there being a
range of numbers disclosed by the evidence, parties in the hearing seemed to acknowledge 0.8
percent as a reasonable estimate of average historical total factor productivity performance for
the electric distribution industry, most notably the distribution companies in Ontario.
Mr. Goulding in his testimony stated “[w]e have got the average productivity…of the electricity
sector. We’ve said that that was 0.8.” 144 For these reasons, 0.8 percent average industry
productivity will be the Commission’s starting point for determining the X factor.
178. Having established the starting point for developing the X factor, the Commission must
consider whether adjustments need to be made. As noted above, the choice of the blended input
price index selected by the Commission for the I factor makes adjustments to X for an input
price differential and differences in productivity unnecessary. The Commission will, however,
consider whether a stretch factor is justified and, if so, how much of a stretch factor.
179. A stretch factor is a percentage amount added to the percentage amount of the X factor so
as to strengthen incentives to improve productivity at a greater rate than the industry average. In
the Original Application EPC proposed an X factor of 0.5 percent which it said represented a
stretch objective given the use of the CPI output index as the I factor. In the Application, EPC
proposed an X factor of 1.5 percent (after adjusting upward the going-in rates). EPC stated that
“given that Canada-wide productivity growth for 2000-2004 averaged 0.8% per year, the choice
of a 1.5% X factor actually indicates that the stretch factor for EPC could be as high as 0.7%.” 145
180. According to the evidence and opinions filed by parties, including EPC and UCA
(although from different perspectives), in order to consider a stretch factor, the Commission must
consider how efficient the company’s operations are and how efficient they could be. 146
Unfortunately, while it is possible to construct measures of EPC’s efficiency and even to refine
those measures to provide information about technical and allocative efficiency, it is not possible
to know how efficient EPC could become and still provide the level of service it is required to
provide for the services under FBR. Dr. Cronin proposed that the Commission compare EPC’s
efficiency to efficiency measures of companies operating at the efficiency frontier.147 In that
way, the Commission could determine how much potential there is for EPC to improve its
efficiency and set the X factor accordingly. Dr. Cronin explained that the approach of the
143
144
145
146
147
Application Appendix 3, London Economics Evidence, Figure 6
Transcript Volume 2, page 0622, line 11-13
AUC.EPC-004(b)
Application Appendix 3, London Economics Evidence, Schedule 4.4; Exhibit 0064.03.UCA-12, UCA PBR
Evidence, page 5
Exhibit 0064.03.UCA-12, UCA PBR Evidence, page 28
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Norwegian regulator had been to set a base level of annual productivity improvement that all
local distribution companies should have available to them and then added an additional
productivity target depending on how efficient or inefficient they were judged to be. The base
amount was set at 1.5 percent and the additional productivity target (which the Commission
considers to be similar to a stretch factor) was set at zero for the most efficient firms. 148 In this
case the Commission is setting the base amount of 0.8 percent, being the industry average, based
on the record in this proceeding.
181. There is limited evidence on the record to compare EPC’s efficiency with that of other
companies. In addition, there is no available method to precisely compare the relative efficiency
of companies operating in different geographic areas under different conditions and there is little
evidence of what the efficiency measures for comparison purposes should be. What evidence
there is may be subject to methodological difficulties. For example, Dr. Cronin suggested EPC’s
evidence comparing its performance to Ontario local distribution companies was deficient
because it did not include capital costs and line losses in the analysis. 149
182. The Commission recognizes that there is a general view that companies operating under
cost of service regulation are not as efficient as they would be operating in a competitive market
and therefore are capable of improving their rate of productivity growth over historical average
rates at least for a period of time after entering an incentive regulation plan. Indeed, this is borne
out by the experience of the Ontario companies to which Dr. Cronin referred. 150 Therefore the
Commission will include a stretch factor for EPC.
183. Determining a stretch factor for EPC is particularly difficult for a number of reasons
including the fact that it is proposing an FBR plan for both distribution and transmission and this
is the first FBR case for the Commission. In these circumstances, better evidence on stretch
factors would have been helpful. Other than the UCA’s proposal to adopt an efficiency frontier
analysis in a future FBR proceeding, parties did not provide the Commission with any evidence
related specifically to how stretch factors should be determined or, more importantly, how the
Commission should approach determining the stretch factor in this case. Instead, all parties to
the proceeding appeared to agree to an X factor of 1.5 percent. Unfortunately, while 1.5 percent
was the nominal amount proposed, upon reviewing the evidence it is clear that EPC did not agree
to 1.5 percent unless its going-in rates were first increased. Indeed, EPC changed its X factor
filed in the Original Application after discussions with interveners but filed the same expert
evidence in the Application and little rationale for the new number. For its part, CG agreed to
the 1.5 percent X factor but provided no analysis of how the number was derived. It analyzed
the number relative to forecast financial performance over the FBR period and expressed
concerns about 1.5 percent being a significant challenge for EPC. The justification of UCA’s
choice of 1.5 percent was supported partially in reliance on the Norwegian X factor discussed
above and partially on Dr. Cronin’s Ontario analysis.
184. The Commission recognizes that EPC offered a qualified acceptance of a 0.7 percent
stretch factor embedded implied in the 1.5 percent X factor (qualified by the requirement for
higher going-in rates). The Commission is concerned that the adoption of a 0.7 percent stretch
factor would require EPC (on both the distribution and transmission sides) to improve its
productivity at almost double the average annual rate for electric distribution companies and put
148
149
150
Exhibit 0064.03.UCA-12, UCA PBR Evidence, pages 26-27
AUC.EPC-004(b)
Exhibit 0064.03.UCA-12, UCA PBR Evidence, page 27
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a strain on the company’s ability to preserve service quality for customers. The Commission has
considered that the rate of productivity growth among the Ontario distribution companies
increased from zero to 2 percent in the first few years after the introduction of PBR type
arrangements. However, the Commission has also considered that as a result of various
company efficiency initiatives 151 EPC believes that it compares favorably to the Ontario
distribution companies thereby implying that it has already achieved at least some of the
efficiency improvements expected under an FBR plan. In addition, the Commission has
considered that while the I minus X formula is to be applied to both distribution and
transmission, its calculation is based on productivity improvements experienced by companies
that are predominantly distribution companies only. This is significant for EPC because its FBR
plan will apply to both distribution and transmission. In addition, while the I minus X formula is
applied to customer rates on the distribution side, it is applied to revenue requirement on the
transmission side. Under the EPC proposal, because there is only one rate and one customer for
the revenue requirement (AESO), there is no measured increase in transmission outputs and, as a
result, there appears to be less of an opportunity for productivity improvements on the
transmission side. In the Commission's view, it is also significant that the term for this FBR plan
is seven years and that the stretch factor applies for the whole period without there being a mid
term rebasing as requested by EPC. Finally, the Commission is also cognizant of the fact that at
least in this first FBR period, an earnings sharing mechanism will be in place for earnings above
the allowed rate of return. No symmetrical mechanism for earnings losses has been provided.
185. Based on the above analysis and in the specific circumstances of EPC and the record
before the Commission, the Commission considers it reasonable to add a stretch amount to the
0.8 percent average productivity growth rate so that EPC will be required to improve its
productivity at a fifty percent greater rate than the estimated historical industry average
productivity. This results in a stretch amount of 0.4 percent. Therefore, the X factor for the FBR
period will be 1.2 percent.
8
G FACTOR
186. In the Application, EPC proposed that during each year of the FBR term, the transmission
revenue requirement would be adjusted by a transmission growth factor (G factor). The G factor
is proposed to “recover the necessary increase in revenue requirement related to infrastructure
growth of the transmission system since, unlike the distribution revenue requirement, the
Transmission revenue requirement does not increase automatically with load growth,” 152 because
EPC only has one transmission customer, the AESO. 153 Without the G factor, EPC indicated that
it will have insufficient revenue and cash flow to fund new transmission capital over the FBR
term.
151
152
153
Application, pages 57-58, Appendix 3, page 21
Exhibit 0015.00.EPC-12, Application page 73
Application, page 73
AUC Decision 2009-035 (March 25, 2009) • 41
2007-2016 Formula Based Ratemaking
187.
is:
ENMAX Power Corporation
As noted above, EPC’s proposed formula for the transmission portion of the FBR plan
154
Rt = Rt-1* (1+(I-X)) + G
where:
Rt = Current year’s revenue requirement
Rt-1 = Prior year’s revenue requirement
I = Inflation Factor
X = Productivity Factor
G= Transmission Growth Factor
188.
The proposed G factor is calculated as:
G = (Mid-Year Rate Base) * [WACC + Depreciation Rate] 155
189. In the Application, EPC provided an example of the calculation of the G factor in
Table 3.4.A and in its financial model filed as Appendix 5 of the Application.
190. All transmission capital expenditures, including capital maintenance and direct assigned
projects, are proposed to be included in the calculation of the G factor. EPC’s forecast capital
expenditures are based on four categories of spending: (1) asset replacement and modification;
(2) direct assign; (3) facilities with AESO-required capital contributions; and (4) information
technology, general plant and other. 156
191. EPC stated that the G factor only compensates EPC for its actual AESO reviewed
expenditures. 157 As such, EPC submitted that the G factor provides little if any incentive for
EPC to overestimate future transmission capital needs that could cause ratepayers to overfund
investment, but at the same time gives EPC sufficient confidence that it will recover its
legitimate investments. EPC stated that, should a transmission cost subsequently be found to be
imprudent upon review by the AUC, EPC would make a retroactive adjustment, given that such
costs are included in the calculation of the G factor. 158
192. EPC proposed to submit annual reports to the proposed Customer Committees regarding
the status of transmission investments, their cost, and EPC’s communications with the AESO. 159
EPC confirmed that, although the Customer Committees would be in place to review EPC’s
capital business cases over $500,000, the final determination as to the prudence of EPC’s capital
expenditures rests with the AUC. 160 EPC stated that the AUC has the authority to test the
prudence of all capital investments made at the end of the FBR term or at the time of the
proposed rebasing. 161
154
155
156
157
158
159
160
161
Exhibit 0015.00.EPC-12, Application, page 35
Exhibit 0059.01.EPC-12, D410.EPC-006
Exhibit 0015.00.EPC-12, Application, page 70-71
Exhibit 0018.00.EPC-12, page 32
EPC Argument, pages 26-27
Exhibit 0018.00.EPC-12, page 33
Exhibit 102, Proceeding No. 1512069, Information Session UCA.EPC-047, Transcript Volume 2, page 0508,
line 6 to page 0509, line 7
Transcript Volume 4, page 1007, lines 03-15
42 • AUC Decision 2009-035 (March 25, 2009)
2007-2016 Formula Based Ratemaking
193.
ENMAX Power Corporation
With regards to approving direct assigned projects, EPC stated:
Q Given that the AUC is responsible for determining or adjudicating on the ultimate costs
of direct-assigned projects, at what point would you see the AUC being able to undertake
that review?
MR. KADONAGA:
it.
I believe that would be done at the mid-term rebasing, and that's
Q And which brings me back to my original question is, if at that point they determined
that all or a portion of a capital expenditure was imprudent, would EPC be prepared to
make a retroactive adjustment?
A MR. KADONAGA:
Yes, we would.
194. However, in Argument, EPC submitted it would not be appropriate to make any kind of
retroactive adjustment or disallowance, because no portion of the capital investment will have
been recovered from customers through the AUC approved FBR rates. It is only when EPC’s
rates are adjusted following any adjustments to its rate base, potentially at the time of any midterm rebasing, that EPC would begin to recover from customers, through the AUC approved
rates, the capital investments that it made since the FBR going-in rates were last approved. 162
195. Mr. Marcus, Dr. Cronin, Mr. Motluk, and Mr. Knecht all raised concerns about EPC’s
proposed transmission FBR mechanism.
196. Witness for CG, Mr. Marcus, identified two concerns with EPC’s proposed G factor
structure:
First, ENMAX is shortchanging itself by starting the “G” factor treatment about 6 months
later than I believe would be appropriate. I would recommend basing the “G” factor on
growth in the previous year; rather than waiting six months until the second half of the
following year. The “G”-factor allowed in the first half of the year would be an estimate
which would be trued up in the second half of the year.
Second, and on the other side of the ledger, ENMAX is overcharging for the “G” factor
because it does not include any impact for the continuing reduction of rate base due to the
depreciation of the existing system. The depreciation of the existing system in 2007 is
$6.53 million per year. The cumulative amount of reduced rate base due to increased
depreciation of the existing system should be subtracted from the G-Factor rate base in
the model starting in 2009 (with a mid-year convention applied to the figures). 163
197. CG submitted that although the revised G factor recommended by Mr. Marcus results in
about the same G-factor revenue over the first 5 year period, it would equate to around $10
million less than EPC’s figures over a 10 year time frame. 164 In other words, the impact of the
two concerns becomes more notable after the first 5 years and increases the further out one
162
163
164
Transcript Volume 4, page 0978, line 13 to page 0981, line 8
Exhibit 0068.01.CG-12, CG Evidence, page 10, lines 16-26
Ibid, pages 10-11
AUC Decision 2009-035 (March 25, 2009) • 43
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ENMAX Power Corporation
goes. 165 CG submitted the revised structure recommended by Mr. Marcus will be more
consistent with tracking of costs related to transmission rate base.
198. CG submitted the G factor amounts should be subject to review by the Customer
Committee and the committee should be afforded the opportunity to raise any issues concerning
the prudence of the G factor costs, if any, each time EPC submits a G factor application to the
AUC for approval. CG stated this would ensure review of these generally sizable expenditures is
done on a timely basis and avoid the potentially significant problems if the proper review and
any adjustments were delayed until the end of the FBR term or any mid-term rebasing.
199. CG also noted the G factor calculation includes amounts for contributions received by the
TFO in connection with optional facilities. The counterpart to the contribution received by the
TFO is found in the distribution capital additions made as contributions to the AESO.
200. Mr. Marcus noted, in the transmission function, the contributions are ultimately trued up
to actual (with a lag) through the G factor. On the other hand, for distribution, the rates are
forecast with the major impact of any difference in transmission contributions flowing through
the municipal surcharge. 166 Accordingly, for distribution ratemaking purposes, Mr. Marcus
recommended the impact of transmission contributions on the distribution revenue requirement
be trued up to actual levels with one year’s lag. Mr. Marcus proposed that the difference in
revenue requirement (depreciation or amortization plus return) resulting from cumulative actual
contributions versus ENMAX’s forecast (including prepaid O&M) should be calculated on a
half-year basis and charged to, or refunded to, customers. 167
201. CG supported the evidence of Mr. Marcus and recommended the difference in revenue
requirement for contributions, as between distribution and transmission, be trued up each time
the G factor application is filed for approval by the AUC.
202. EPC replied it does not consider it necessary to change the structure of the G factor
during the initial 5 years of the FBR plan due to the neutral impact of the changes during this
period. 168 Consequently, EPC does not accept that its proposed G factor is flawed in the manner
suggested by Mr. Marcus. In light of the off-setting nature of the alleged flaws, EPC submitted
that it is appropriate to approve the G factor as applied for, and to review the performance of the
G factor at the end of the term. 169
203. EPC stated that it would welcome feedback from the FBR Customer Committee, but
anticipated that the G factor calculation will be a relatively mechanical calculation. 170 EPC
submitted the transmission expenditures used in the G factor calculation will have already been
subjected to an appropriate level of oversight. For example, ISO Rule 9.1 specifies the manner
by which the AESO directs the construction of new transmission facilities, and how a TFO,
including EPC, must respond to such directions and report on its progress, including the
preparation of estimates and reporting of costs. EPC must follow the ISO rules, including Rule
9.1.5, which deals with procurement. Other costs, such as Allowance for Funds Used During
165
166
167
168
169
170
Exhibit 0068.03.CG-12, Comparison of ENMAX and Revised G-Factor Estimates
Exhibit 0068.01.CG-12, CG Evidence, page 11, lines 23-26
Ibid, page 12
Transcript Volume 4, page 0999 line 21
Transcript Volume 4, page 0999, line 18 to page 1000, line 1 and EPC Reply Argument, page 10
Transcript Volume 4, page 1003 lines 17-22 and EPC Reply Argument, page 10
44 • AUC Decision 2009-035 (March 25, 2009)
2007-2016 Formula Based Ratemaking
ENMAX Power Corporation
Construction, follow practices that have been tested before the AUC and the EUB in past general
tariff applications.
204. EPC was not certain that it understood CG’s suggestion that the difference in revenue
requirement for contributions, as between distribution and transmission, be trued up each time
EPC files the G factor adjustments with the AUC for approval. 171 EPC submitted that there is no
specific evidence with respect to this point on the record. Further, EPC submitted that the AUC
should be concerned about potential timing differences, with the result that it may not be
appropriate to “true up” any differences until the relevant projects have been completed.
205.
UCA experts, Dr. Cronin and Mr. Motluk 172 stated:
…the growth factor that EPC is proposing is atypical and not what is usually seen in
revenue-cap plans. 173
206.
Further, they concluded:
Under such a plan, all capital projects (whether due to growth or maintenance capital) are
outside of the revenue cap plan. This clearly dampens the incentives of the revenue-cap
and is not the intent of a comprehensive revenue-cap type PBR plan. 174
207. Dr. Cronin and Mr. Motluk recommended adoption of an alternate equation in their
evidence as an appropriate G factor. The equation referenced as formula (9) is:
(9) Rt = Rt-1 * (1+ (I-PF) + G)
where Rt is revenue in period t, Rt-1 is revenue in period t-1, (I-PF) is the net
inflation factor after productivity offset, and G is a growth factor based on past and
expected growth in customers or throughput. 175
208. UCA supported Dr. Cronin’s and Mr. Motluk’s G factor calculation of 2.8 percent 176 for
2007. 177
209. In Argument, EPC submitted that its proposal to calculate the G factor based on actual
expenditures is superior to the UCA proposal given the inherently “lumpy” nature of
transmission additions.
210. D410 submitted that Dr. Cronin and Mr. Motluk did not provide a specific growth factor
recommendation in this proceeding until the undertaking stage after the close of the hearing. As
such, D410 submitted that neither the parties nor the Commission have had a chance to fully
examine the UCA proposal. Moreover, UCA offered no evidence that the “lumpy” nature of
transmission additions is in any way parallel to the three-year average load growth used to create
the UCA multiplicative G factor.
171
172
173
174
175
176
177
EPC Reply Argument, page 10
Exhibit 0064.03.UCA-12, UCA PBR Evidence, page 76
Ibid, page 76
Ibid, page 76
Ibid, page 76
Exhibit 0157.04.UCA-12, Undertaking
UCA Argument, page 26
AUC Decision 2009-035 (March 25, 2009) • 45
2007-2016 Formula Based Ratemaking
211.
ENMAX Power Corporation
Mr. Knecht summarized his view of EPC’s methodological problems as follows:
As the arithmetic shows, this model is mis-specified in two ways. . . . Under EPC’s
proposal, O&M costs are implicitly permitted to grow at the rate of I-X. However,
because O&M costs are likely to also increase with the expansion of the system (through
load growth and higher capital investment), this model cannot accommodate this cost
growth. Thus, the mechanism will tend to understate EPC’s reasonable increases in
O&M costs. . . .
In addition, the second term of the revenue formula indicates that the cost of historical
rate base is also inflated at the I-X growth rate. However, because the costs associated
with incremental capital investment are fully recovered in the third term of this model
(the G-Factor), there is no reason to inflate the base costs that are associated with
historical investment. These costs remain essentially the same over time. (In fact, they
should decline slightly as rate base depreciates.) That is, the model overstates EPC’s
capital costs, because it is inflating fixed historical costs.
Thus, EPC’s proposed approach has methodological problems in both directions. 178
212. D410 stated that in addition to the methodological problems, some specific details as to
how EPC will operate the transmission FBR remain unclear. First, as the formula shows, the G
factor is not subject to the incentive mechanism at all, and is really just a pass-through of net
capital costs. 179 Second, in addition to the G factor, EPC proposed a separate “flow through” of
costs required for AESO system upgrades. 180 D410 submitted that it is not clear how costs will
be distinguished between these two categories, nor is it clear how these costs will be regulated.
213. D410 is also concerned that the FBR mechanism will allow EPC to increase its existing
rates based on the I minus X calculation and then simply add in all costs associated with future
capital expenditures.
214. Nevertheless, D410 recognized that there are many ratepayer protections built into the
mechanism, and therefore observed that a short trial period with this mechanism may be
reasonable. Mr. Knecht indicated in response to an information request from CG:
As stated at page 16, lines 3 to 5, of his evidence, Mr. Knecht’s primary recommendation
is that the transmission FBR proposal be rejected. However, the following considerations
suggest that a five-year term may not be totally unreasonable:
178
179
180
•
The mis-specification effects tend to offset one another;
•
If anything, the mis-specification issue benefits the ratepayer, in that it implies a
higher productivity effect;
•
Additional transmission investments remain effectively regulated;
•
FBR reduces regulatory costs;
•
A sharing mechanism is in place for earnings above a threshold.
Exhibit 0071.02.D410-12, D410 Direct Evidence, page. 15
D410 Argument, page 5
Exhibit 0015.00.EPC-12, EPC FBR Application, Section 3.7.2.1
46 • AUC Decision 2009-035 (March 25, 2009)
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ENMAX Power Corporation
However, because the mechanism is mis-specified, Mr. Knecht does not believe that
simply rebasing rates and maintaining the rest of the FBR mechanism in its proposed
form is reasonable. If it is accepted at all, Mr. Knecht recommends that the entire
mechanism be revisited in five years. 181
215. D410 expressed reservations about the reasonableness of a transmission FBR. 182
Consequently, D410 submitted that, should the Commission decide that there is merit in
implementing both a distribution and transmission FBR mechanism in this proceeding, the
Commission should approve the EPC transmission FBR mechanism as a “pilot project” only.
8.1
Commission Findings
216. The Commission recognizes the unique circumstances of the electric transmission system
in Alberta, whereby the TFO has only a single customer, the AESO. Therefore, it is necessary to
provide for capital additions to the transmission system of a TFO in an FBR plan. The
Commission has received a number of proposals to address this issue. EPC proposed the G
factor, CG proposed modifications to EPC’s G factor, UCA proposed a modified form of G
factor that employed smoothing of capital additions through multi-year averaging, and D410
suggested that the transmission FBR proposal should not be adopted but could go ahead on a
pilot project basis.
217. CG did not disagree in principle with the G factor. 183 CG proposed that the mechanism
for the G factor needed to be revised to eliminate the six month lag and to account for the
depreciation of existing rate base. The Commission considers there is some merit in the proposal
presented by CG and disagrees with EPC’s submission that since the effect of the CG proposal is
revenue neutral, CG’s concern is not worth reviewing. 184 Nevertheless, the Commission notes
that EPC has agreed to review the G factor in five years 185 and that EPC would consider
revisions, if required, including the proposal by CG. 186 Since the forecast of the G factor in the
next five years is forecast to be revenue neutral, 187 the Commission does not see any benefit to
adding the additional complexity at this time. As such, the Commission rejects the CG proposal
but expects EPC to consider the CG proposal in its filing for its next regulatory framework
before the end of the initial FBR term.
218. With respect to CG’s recommendation that the impact of transmission contributions on
the distribution revenue requirement be trued up to actual levels with one year’s lag, and CG’s
recommendation that the difference in revenue requirement for contributions as between
distribution and transmission be trued up, the Commission notes that EPC did not understand
these proposals and considers they lack clarity. Therefore, the Commission will not address
them further.
219. The Commission rejects UCA’s revised FBR formula for two reasons. First, there is no
evidence to support UCA’s revised formula, which is intended to account for capital additions
evenly each year, assist EPC with the fact that EPC’s capital additions are major projects that
181
182
183
184
185
186
187
Exhibit 0115.01.D410-12, CG.D410-2(b)
D410 Argument, pages 3-8
Exhibit 0068.03.CG-12, CG Evidence, page 10, lines 8-11
Transcript Volume 3, page 0751, line 5 to page 0753, line 18
Transcript Volume 3, page 0999, lines 6-25
Ibid
Exhibit 0068.03.CG-12, Comparison of ENMAX and Revised G-Factor Estimates
AUC Decision 2009-035 (March 25, 2009) • 47
2007-2016 Formula Based Ratemaking
ENMAX Power Corporation
occur at irregular intervals. Second, the Commission agrees with D410 that, since the UCA
proposed G-factor of 2.8 percent was brought forward in an undertaking, it has not been tested in
this proceeding.
220. The Commission considered D410’s concern with respect to a separate flow through of
costs required for AESO system upgrades. However, the Commission notes that EPC stated
during the hearing that Section 3.7.2.1 of the Application, which relates to flow through of
AESO system upgrade costs, is no longer needed. 188 Given that the flow through of AESO
system upgrades has been removed from the EPC proposal, D410’s concern is no longer
warranted.
221. The Commission agrees with D410 that, when EPC stated “[h]owever, in EPC’s
respectful submission, it would not be appropriate to make any kind of retroactive adjustment or
disallowance, because no portion of the capital expenditures will have been recovered from
customers through the AUC approved FBR rates,” 189 EPC must be referring to the DAS FBR
mechanism because capital expenditures are recovered through the G factor in the transmission
FBR mechanism.
222. The Commission agrees with D410 and UCA that an FBR mechanism is not as well
suited to transmission in Alberta as it is to distribution. Nevertheless, the Commission considers
that it is in the public interest to approve an incentive regulation plan for transmission in order to
promote efficiency of operations and efficiency of the regulatory process. The Commission has
recognized some of the effects of the structure of the regulatory framework for transmission in
determining the X factor. The structure of the regulatory framework for transmission also
requires specific adjustments in an FBR plan to recognize capital additions each year.
Accordingly, the Commission approves EPC’s applied for G factor as calculated in its financial
model filed as Appendix 5 of the Application. The success of the G factor is to be reviewed at
the time EPC files for its next regulatory framework after the initial FBR term.
223. With respect to the question of prudence reviews, it is unclear whether EPC is proposing
that the prudence of the transmission capital investments be reviewed prior to each year’s
application of the G factor or whether the prudence evaluation will take place at the end of the
initial FBR term. 190 The Commission considers the prudence review should take place prior to
July 1 of each year during the FBR term. As such, the Commission directs EPC to provide all
the relevant support for its G factor in its annual filing. If final costs are found to be imprudent
the G factor will be amended accordingly.
9
EXTRINSIC FACTORS
224. In the Application EPC proposed a number of potential adjustments to rates arising from
various unforeseen and uncontrollable extrinsic factors. EPC also proposed certain flow through
costs that would be included in rate riders or as automatic rate adjustments. Additionally, EPC
proposed a number of events that would result in re-openers and off-ramps to the FBR plan.
188
189
190
Transcript Volume 5, page 1210, lines 06-16
EPC Argument, page 27
Transcript Volume 3, pages 0916-0917, Transcript Volume 4, page 1007, lines 03-15
48 • AUC Decision 2009-035 (March 25, 2009)
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225.
ENMAX Power Corporation
EPC’s Argument stated:
As a result of the length of the proposed FBR term, it is important that the FBR proposal
include a means of dealing with unexpected and unanticipated events that may occur
during the term, and which are outside the reasonable control of EPC’s management.
EPC has proposed three mechanisms for dealing with such events. The occurrence of
significant events that impact the viability of the continuation of the FBR proposal as a
whole are addressed by Off-Ramps, under which the FBR tariff is either terminated or
wholly re-opened. The occurrence of events that impact one or more elements of the
tariff, but which do not imperil the tariff as a whole are addressed by Reopeners, under
which only those elements that are affected by the unexpected or unanticipated event are
subject to review. Finally, EPC proposes to flow-through certain discrete costs that are
beyond its reasonable control, including changes in law. 191
226. The following is a summary of the various items that EPC proposed as events that may
result in rate adjustments outside of the normal annual I minus X adjustments, or as re-openers
and off-ramps to the FBR plan.
Summary Table of Possible Rate Adjustments, Off-Ramps and Re-Openers
Application
Proposed Adjustments
Section
1.4.3
Possible AMI Adjustment
3.7
Extrinsic Factors
Extrinsic factors are items that may impact rates but are outside the FBR
formula. These items include:
3.7.1
Change in Law
• the distribution or transmission system
• the electricity sector
• changes in the AESO tariff
• the environment
• interpretation or administrative position of laws
• change in governmental approvals required
• changes in metering or measuring equipment
Costs would be refunded/allowed, including carrying costs
3.7.2
Flow through Costs
3.7.2.1
AESO System Upgrades Not Included in Application Appendix 5 Forecast
3.7.2.2
Other AESO Costs Including Load Settlement Costs
3.7.2.3
USA/MFR Costs
3.7.2.4
Material Unforeseen, Uncontrollable Changes In
• financial conditions
191
EPC Argument. page 31
AUC Decision 2009-035 (March 25, 2009) • 49
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•
•
•
•
•
ENMAX Power Corporation
law and regulations related to:
o
the distribution or transmission system
o
the electricity sector
o
changes in the AESO tariff
o
the environment
o
interpretation or administrative position of laws
o
change in governmental approvals required
changes in metering or measuring equipment
natural disasters
force majeure events defined in Application Glossary including:
strikes, walkouts, lockouts, lightning, fires, storms, floods, high
water, washouts, inclement weather, laws, orders, explosions,
breakdown of equipment or lines of the electric transmission and
distribution systems,
new regulatory compliance costs. EPC stated “an of example of an
uncontrollable and unforeseen cost could be a significant increase
in the annual Alberta Utilities Commission Admin Levy Fee.” 192
3.7.2.6
Off-ramps
• circumstances change in a substantial or unforeseen manner
• change in regulatory status
• change in EPC control
• misrepresentation by EPC
Off-ramps would result in the FBR application being wholly 193 re-opened
or terminated.
3.7.2.7
Re-openers
• failure to meet a specific performance standard for two consecutive
years;
• material changes in accounting standards that have an annual
impact greater than $5 million;
• expansion of EPC’s service area where more than 10,000
customers are included within the expanded area;
• actual ROE is +/- 300 basis points above / below target ROE for
two consecutive years; and
• actual ROE is +/- 500 basis points above / below target ROE for
one year.
The FBR would only be re-opened to the extent required to address the
issue that triggered the re-opening.
3.8.1
Hearing Cost Reserve Account
227. EPC’s proposal is unclear as to the practical differences and distinctions among several
of the proposed adjustments. For example, it is not clear how a request for approval of a rate
change for a statutory change under section 3.7.2.4 of the Application would differ from a
192
193
Response to AUC-EPC-12 (b)
The Application states “re-opened” (page 90) whereas EPC Argument states “wholly re-opened”
50 • AUC Decision 2009-035 (March 25, 2009)
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ENMAX Power Corporation
change in circumstances due to a statutory change under section 3.7.2.6 of the Application.
Similarly, it is not clear what the practical distinctions are as between a change in law as defined
in sections 3.7.1 and 3.7.2.4 of the Application.
228. It was also not clear whether an item such as a change in law would trigger a rate change
under different categories of proposed adjustments. CG sought clarification of this point when it
stated:
To the extent such changes [in law] are addressed as re-openers and/or off ramps, they
should not be included within the Change of Law provision. 194
229. EPC’s proposal is also unclear with respect to off-ramps. The Application states that the
FBR plan could be re-opened 195 if an off-ramp is triggered. However, the only distinction
between a re-opener and an ‘off-ramp’ appears to be that the FBR arrangement could be
terminated under an off- ramp application but may not be terminated by way of a re-opener. In
Argument, EPC attempted to clarify that with off-ramps, the FBR Application could be “wholly
re-opened” or terminated, whereas with re-openers, the FBR would only be re-opened to the
extent required to address the issue that triggered the application for a re-opener.
230. Concerns were expressed with respect to the broad sweep of the potential adjustments.
CG argued that the change in law provisions are too broad 196 and “to the extent such changes are
addressed as re-openers and/or off ramps, they should not be included within the Change of Law
provision.” 197 UCA recommended that such provisions should exclude laws passed by The City
of Calgary. 198
231. EPC’s proposed financial thresholds, that would trigger an adjustment, are scattered
throughout the Application, in responses to Information Requests and in Argument and Reply.
In a response to a question regarding the dollar limits proposed “for changes to rates as a result
of changes in law, extrinsic factors, force majeure, off ramps, material unforeseen uncontrollable
cost and reopeners” EPC stated that:
EPC proposes a $1 million limit for each event and not cumulative. 199
232. However, in Application section 3.7.2, EPC proposed that a number of costs, such as
Uniform System of Account/Minimum Filing Requirement costs, should be flowed through as
they arise, presumably even when they are less than $1 million. Confusion arises in that this
section also refers to material unforeseen and uncontrollable costs and off-ramps. EPC stated
that material unforeseen and uncontrollable costs and off-ramps would only be flowed through to
rates if costs exceeded $1 million.
233. EPC’s definition of flow through costs in section 3.7.2 does not include change in law,
however EPC also proposes to flow-through these costs, if in excess of $1million. 200
194
195
196
197
198
199
200
CG Argument, page 54
Application, page 90
CG argument, pages 53 and 54
CG Argument, page 54
UCA Argument, page 33
AUC.EPC-016 (b)
EPC Argument page 35
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234. The Commission notes that there does not appear to be a consistent classification or
nomenclature set out in the Application for the various types of extrinsic factors proposed by
EPC. Notwithstanding these classification and definitional issues, EPC stated that it would seek
approval for any items which, in its opinion, required adjustments to the rates. In this regard,
EPC proposed to seek a rate adjustment for individual events and stated that these adjustments
would not be cumulative. EPC confirmed that there be a class of items, such as Uniform System
of Account/Minimum Filing Requirement costs where the related costs would be flowed
through, regardless of the amount of the adjustment. However, certain other costs would be
flowed through to rates only upon reaching a threshold amount of $1 million.
9.1
Selected Flow Through Items
9.1.1
AESO Costs
235. EPC’s proposed flow through items included AESO system upgrade costs, including but
not limited to technical studies, field checks, estimating, designing, procuring and constructing
facilities. However, the Commission notes that during the hearing, EPC testified that the AESO
system upgrade costs no longer needed to be included as a flow through. 201
236. EPC also proposed, as a flow-through, other costs, including Load Settlement Costs,
charged to EPC by the AESO. EPC argued that it does not control these costs and therefore can
not adequately forecast them. EPC further proposed that the System Access Service (SAS) rates
related to the AESO tariff be charged to customers at cost and not be part of the FBR formula.
EPC also proposed procedures for determining and applying the final AESO rates, which have
been interim since January 1, 2007.
9.1.2
USA/MFR Costs
237. EPC proposed that all costs associated with implementing the Uniform System of
Account/Minimum Filing Requirements that are approved by the AUC, be charged to customers
as a flow through item. EPC estimated a projected capital expenditure of $6.7 million for these
costs and stated that there would also be unspecified incremental operating costs commencing
January1, 2008. 202
9.1.3
Transmission Access Deferral Account
238. EPC proposed to continue the Transmission Access Charge (TAC) Deferral Account
Rider, as a flow through cost “to charge or refund any non-volume variances between forecast
and actual AESO tariff charges as well as any other applicable AESO rates, deferral account
dispositions or riders. The TAC Deferral Account Rider would continue to vary by rate class”. 203
EPC proposed that any changes to the SAS rates or TAC Deferral Account Rider be filed with
the AUC for approval, and implemented on July 1 of each year.
239. EPC also proposed that the flow through costs be collected in separate flow through
deferral accounts for distribution and transmission. These deferral accounts would be recovered
through the annual FBR rate adjustment for flow through costs relating to distribution and an
adjustment to the monthly charge to the AESO for transmission. Flow-through deferral accounts
201
202
203
Transcript Volume 4, page 1210, lines 05-16
EPC Application, 89
Ibid page 95
52 • AUC Decision 2009-035 (March 25, 2009)
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are proposed to be allocated to rates based on cost causation, following a proposed methodology
to be set out in EPC’s Phase II application. 204 (Currently AUC Proceeding ID. 90)
9.1.4
Advanced Metering Infrastructure
240. Finally, EPC proposed that advanced metering infrastructure (AMI) will be no different
than any other productivity improvement and innovation contemplated under FBR and will be
implemented by EPC in the normal course of business under the FBR regime. Under these
circumstances, EPC did not propose to seek any additional AMI-specific regulatory approval. If
EPC’s AMI implementation requires approval under any legislation or if it cannot be funded
with the revenue generated by the FBR formula, EPC proposed to file an application with the
Commission. 205
9.2
Impact of the Treatment of Extrinsic Factors on Incentives
241. Dr. Cronin argued that “the inclusion of pass-through or other “exogenous” adjustments
can provide perverse incentives for firms to “maximize” costs that are passed through outside the
I minus X adjustment. This may result in unanticipated cost shifts and also compromise
efficiency of the firm on a total cost basis.” 206 Dr. Cronin recommended that any adjustment for
an extraordinary event must satisfy the following criteria. 207
•
•
•
•
The expense must be clearly outside the base upon which rates were derived;
The cost must be material, which means it must have a significant influence on the
operation of the utility otherwise it should be expensed in the normal course and
addressed through organizational productivity improvements;
The cost must be attributable to some event outside management’s ability to control; and
The expense must have been prudently incurred.
242. In reference to the materiality criterion, Dr. Cronin referred to the experience in Ontario,
where the materiality threshold for first generation PBR for electricity distribution was set at
0.25 percent of utility net assets. 208 In addition, Dr. Cronin noted that an adjustment for an
extraordinary event is transitory and is not subject to the inflation factor or productivity
adjustment. 209
9.3
Commission Findings
243. EPC explained the conceptual purpose of its proposed adjustments for extrinsic variables
as follows:
EPC sought to exclude from the formula only those factors truly beyond its control, such
as uncontrollable events which have a material impact on its financial stability, changes
in law, direct assign transmission projects, and some regulatory compliance costs and
benefits. This leads to a set of obvious principles: first, is the event truly beyond EPC’s
control? Second, if the event occurs, is it likely to result in a material (positive or
negative) impact on EPC? If EPC can demonstrate that an event is both beyond its
204
205
206
207
208
209
Ibid pages 89-90
Ibid page 26
UCA PBR Evidence, page 71
Ibid page 72
Ibid page 72
Ibid page 75
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control and material, it then must apply to the AUC prior to incorporating it into the F
factor in rates. 210
244. The Commission agrees that the FBR plan must have the facility to account for the
impact of extrinsic events. If there were no adjustments for extrinsic events, EPC would be
required to unfairly bear the risks associated with events and costs beyond its control that may
increase its costs to a significant extent. Conversely, consumers using EPC’s services would not
benefit from cost savings that could be passed on to them through such adjustments, should
extrinsic events result in a significant unexpected reduction in costs to EPC.
245. The Commission notes that no party objected to these kinds of adjustments. However it
was perhaps necessarily difficult to catalogue a definitive set of events that would qualify as
truly extrinsic events.
246. The Commission makes a distinction among 1) exogenous events that require an
adjustment to rates under the FBR plan, 2) flow-through items that should result in automatic
rate adjustments that are unaffected by the I minus X adjustment, and 3) other items that may
require the FBR plan to be re-opened and potentially adjusted or terminated.
247. With respect to exogenous events, the Commission considered the evaluation criteria
proposed by Dr. Cronin, and has determined that the following criteria for an exogenous
adjustment should be adopted.
1) The impact must be attributable to some event outside management’s control;
2) The impact of the event must be material. It must have a significant influence on the
operation of the utility otherwise the impact should be expensed or recognized as income,
in the normal course of business;
3) The impact of the event should not have a significant influence on the inflation factor in
the FBR formulas; and
4) All costs claimed as an exogenous adjustment must be prudently incurred.
248. With respect to the materiality threshold to be utilized, the Commission notes that the
0.25 percent of net assets test employed in Ontario is approximately $1.25 million. The
Commission considers that, given the size of EPC’s revenue requirements, the threshold for
materiality should be $1 million.
249. The Commission also considers that EPC, or any party with a valid interest, can make an
application for an exogenous adjustment to rates during the term of the FBR plan. The
Commission also recognizes that it can commence such a proceeding on its own initiative. The
Commission will consider all applications for exogenous adjustments to rates under the FBR
Plan according to the criteria adopted above. Exogenous adjustments to rates will be included in
the Commission approved FBR formulas as a “Z” adjustment, as set out later in this Decision.
The Commission recognizes that, in some cases, a “Z” adjustment for an extraordinary event will
be transitory and will not be subject to the I minus X adjustment. In other cases, the
extraordinary event may require a “Z” adjustment that is subject to the I minus X adjustment
going forward. The Commission will make this determination on a case by case basis.
210
AUC.EPC-005
54 • AUC Decision 2009-035 (March 25, 2009)
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250. In order to ensure fairness to all stakeholders, EPC or other parties are directed to notify
the Commission of all proposed exogenous adjustments as soon as possible after the event that
gives rise to them is identified. The Commission also directs that the impact of any proposed
exogenous adjustment be initially captured in a separate account pending a ruling from the
Commission. The impact of any proposed adjustment is to be measured from the time the event
occurred. The disposition of the account would follow the Commission's ruling on the proposed
adjustment.
251. With respect to flow-through rate adjustments, the Commission considers that flow
though rate adjustments arise from cost elements that are not unforeseen one time events. Flow
through items arise in the normal course of business, but are such that the company has no
control over them. The Commission approves the following three items for flow through
treatment.
•
SAS rates in the distribution tariff
•
TAC Deferral Account
•
AESO load settlement costs
252. EPC proposed that the above items be included in the Commission approved FBR
formulas as an “F” adjustment. The Commission does not consider it necessary to include these
elements in the rate adjustment formulas because they are not rates adjusted by the formulas.
They will continue to be treated as they are currently.
253. The Commission denies flow through treatment for all other flow through items proposed
by EPC. EPC is directed to file the above flow through items and related rate changes with the
Commission for approval as it currently does. Should the company determine that any additional
items should be included for flow through treatment, EPC may file an application with the
Commission.
254. With respect to EPC’s potential AMI proposal, because of the potential for extremely
large expenditures, the Commission directs EPC to apply to the Commission for approval even if
EPC determines that it does not require approval under any legislation, or that AMI can be
funded with the revenue generated under the FBR formula.
255. The Commission is cognizant of Dr. Cronin’s argument that “the inclusion of passthrough or other ‘exogenous’ adjustments can provide perverse incentives for firms to
“maximize” costs that are passed through outside the I-X adjustment.” 211 Therefore the
Commission will be considering the impact of any proposed adjustment on incentives in
response to these applications.
256. Finally, with respect to other items that may require the FBR plan to be re-opened and
potentially adjusted or terminated, the Commission accepts that EPC, or other interested parties,
may apply for an adjustment to or termination of the FBR plan in the circumstances set out in
Application sections 3.7.2.6 and 3.7.2.7.
211
UCA PBR Evidence page 71
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257. In order to ensure fairness to all stakeholders, EPC or other parties are directed to notify
the Commission of all proposed re-openers or off-ramps as soon as possible after they have been
identified. The Commission also directs that any material financial impact of a proposed reopener or off-ramp be initially captured in a separate account pending a ruling from the
Commission. Any proposed financial impact is to be measured from the time the event occurred.
The disposition of the account would follow the Commission's ruling.
10
EARNINGS SHARING
258. EPC’s FBR proposal includes an earnings sharing mechanism by which fifty percent of
earnings that are 100 basis points above the target return on equity established by the
Commission will be shared with customers through a reduction in rates. EPC’s proposed
earnings sharing mechanism is asymmetrical in that customers share earnings above the target
ROE, but EPC alone bears the risk of under-earning. 212 EPC stated that many companies with
earnings sharing mechanisms do not adopt an asymmetrical sharing mechanism in which the
company takes on all of the downside risk but shares the upside risk. 213 EPC stated that the
earnings sharing mechanism included in the FBR proposal represents a trade-off between highpowered efficiency incentives and a view that the company and ratepayers should be partners in
ongoing operational and financial gains. 214
259.
is:
The general formula for calculating actual ROE for each of distribution and transmission
Actual ROE for DT = [Rt – OM&At - Dt – (RBt * 61.0% * CODt]/ (RBt * 39%)
Actual ROE for TT = [Rt – OM&At - Dt – (RBt * 65.0% * CODt]/ (RBt * 35%)
where:
Rt = actual total revenues in year t
OM&At = actual operating, maintenance and administrative expenses in
year t (excluding Performance Penalties)
Dt = actual depreciation expense in year t
RBt = actual rate base in year t
CODt = actual weighted average cost of debt % in year t 215
260. EPC proposed that the difference between actual ROE and target ROE plus 100 basis
points will be calculated and, if positive, will be equally shared between customers and EPC.
Distribution customers’ share of earnings above the 100 basis point deadband will be recorded in
a deferral account and applied as a reduction to DAS rates in the following year on a percentage
of revenue basis. The transmission share of earnings above the deadband will also be recorded
in a deferral account and applied as a reduction to the transmission revenue requirement in the
following year. 216
212
213
214
215
216
Application, page 83
Exhibit 0018.00.EPC-12, page 28
Exhibit 0018.00.EPC-12, page 27
Application, page 84
Application, pages 84 and 85
56 • AUC Decision 2009-035 (March 25, 2009)
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261. Earnings sharing will be calculated using Generally Accepted Accounting Principles and
verified by the FBR Customer Committees and ENMAX’s external auditors. The calculation
will be based on the information provided in EPC’s Annual Rates and Technical Report. 217
10.1
Earnings Sharing as a Safety Mechanism
262. Most parties suggested that earnings sharing should be adopted if the Commission
considers that there is a significant risk of setting the productivity target either too high or too
low. UCA in particular noted that PBR design errors, such as mistaken estimates of potential
productivity, can result in sizeable increases in regulated monopolies’ profits. For this reason a
number of prominent regulators in the U.K and North America found it necessary to revise
upward their initial/early productivity factors. 218 The earnings sharing mechanism was viewed
by parties as an important safety measure to limit such increases.
263. Some evidence was provided that other jurisdictions have had sufficient confidence,
beyond the first round of price cap regulation, to establish a productivity target without earnings
sharing. EPC noted that
Outside of North America, it is relatively uncommon for an earnings sharing mechanism
to be incorporated into an RPI-X mechanism; within North America, many US
jurisdictions have yet to make the transition to incentive rates. 219
264. D410 noted “The ESM method will allow ratepayers to share in any substantial gains in
efficiency that EPC achieves in excess of the FBR productivity factor, and it is one of the
significant protections built into EPC’s proposal for ratepayers.” 220 CG noted “EPC’s proposed
earnings sharing mechanism should be included as an integral part and safeguard in the FBR.” 221
UCA supported the earnings sharing mechanism, with caveats respecting the operation and
reporting of financial data as discussed below. 222
10.2
Earnings Sharing Impact on Incentives
265. One issue discussed during the hearing was the issue of whether the earnings sharing
mechanism blunts FBR type incentives. Mr. Goulding, representing EPC stated:
I think your question was, Do ESMs blunt incentives? And the answer is yes, absolutely.
And it's really a question of where do you draw the line in terms of what you view as
fairness to customers, along with a recognition that you are operating a monopoly utility.
You know, really, you know, where do you draw that line? I think that that is something
that you can say with regards to all the ESMs, whether or not they've got a hundred-basispoint dead band or not, they do tend to blunt incentives. 223
217
218
219
220
221
222
223
Application, page 85
UCA PBR Evidence, page 17
AUC.EPC-004 (a)
D410 Argument, page 21
CG Argument, page 40
UCA Evidence, page 17
Mr. Goulding, Transcript Volume 2, page 0595
AUC Decision 2009-035 (March 25, 2009) • 57
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266.
ENMAX Power Corporation
Dr. Cronin agreed in principle that incentives can be blunted:
In PBR/IR, regulators must balance numerous tradeoffs across several dimensions of the
Plan. Often, these trade-offs are in conflict with other aspects of the Plan. One critical
trade-off is between increased incentives and risk. The fundamental driving force behind
IR is aligning utility performance toward increased efficiency and its concomitant
rewards. Monetary rewards and their incentive will be maximized if the utility were to
retain all of the profits from efficient performance. However, IR plans, especially in their
earlier generations, have shown a remarkable tendency to get key features wrong. These
mistakes have manifested themselves across countries, across sectors, and across
regulating agencies. Often, these mistakes have resulted in substantial and prolonged
“windfalls” to earnings.
Concern over such mistakes carries over into plan design aspects such as the term of the
plan (shorter is less incentivized), earning sharing mechanisms (sharing is less
incentivized), and non price aspects such as service quality regulation to counter the
firm’s profit-driven incentive to potentially reduce O&M and capital projects below
adequate levels for reliability. 224
10.3
Calculation of Net Income for the Purposes of Earnings Sharing
267. While parties supported the earnings sharing mechanism, they noted that the proper
calculation of net income is an important component to the mechanism. UCA stated:
With respect to earnings sharing and reporting of actual earnings UCA’s main concern
can be summed up in one word ‘transparency’. This starts with the provision of Audited
Financial Statements for EPC. In its evidence, UCA recommended that EPC prepare
Audited Financial Statements. 225
268. UCA raised concerns with the proper inclusion or exclusion of costs related to donations,
certain advertising costs, legal and consulting costs in excess of Commission scale, incentive
plan costs, CEO/CFO certification, business development and affiliate transactions. 226
269. UCA recommended the inclusion of schedules that reconcile the audited results of EPC
to the return for sharing purposes. These schedules are set out below. The Commission has
edited the tables below by removing the line “Short Term Incentive Plan costs. 227
224
225
226
227
UCA PBR Evidence, page 7
UCA Argument, page 28
UCA Argument, pages 28-33
Exhibit 0064.02.UCA-12, UCA Evidence, page 10
58 • AUC Decision 2009-035 (March 25, 2009)
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Table 1:
ENMAX Power Corporation
Reconciliation Table – Disallowed Items
20XX
Actual
Percent
($000's)
Return on That Portion of the Rate
Base Considered to be Financed by:
Common Equity
XX,XXX
Long Term Debt
XX,XXX
Utility Income
XX,XXX
Long Term Interest Expense
(XX,XXX)
Short Term Interest Income (Expense)
(XXX)
AFUDC
X,XXX
Other Income (Expense)
(XXX)
Disallowed and Inappropriate Costs
(XXX)
Earnings Attributable to Common
XX,XXX
Portion of Rate Base Considered
to be Financed by Common Equity
XXX,XXX
Mid-year Book Value of Common Equity
XXX,XXX
Table 2:
X.XXX
X.XXX
Summary of Disallowed and Inappropriate Costs 228
20XX Actual
($000's)
228
Donations
Advertising costs other than safety
Legal and Consulting fees in excess of Commission
Scale
Long Term Incentive Plan costs,
Medium Term Incentive Plan costs
Other Disallowed or Inappropriate Costs (itemized)
X,XXX
X,XXX
X,XXX
X,XXX
X,XXX
X,XXX
Total Disallowed and Inappropriate Costs
XX,XXX
Exhibit 0064.02.UCA-12, UCA Evidence page 11
AUC Decision 2009-035 (March 25, 2009) • 59
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270.
ENMAX Power Corporation
UCA stated that:
Audited financial statements provide an independently attested starting point for the
calculation of actual returns. Without this independent review and attestation the
statements of EPC results are simply a management estimate of results and as such will
require more scrutiny by the Customer Committee. Audited financial statements should
eliminate the need for the Customer Committee to have to conduct the same exercise in
auditing the data.” 229
271.
EPC responded:
EPC proposes to provide third party validation of its costs. Specifically, at the time that
ENMAX Corporation’s financial statements are audited, EPC’s operating performance,
financial results and customer rates set out in the Annual Rates and Technical Report will
be reviewed by external auditors, who will prepare a report setting out their findings. In
EPC’s submission, this approach is appropriate. EPC is not opposed to providing audited
financial statements, provided that EPC is permitted to recover the incremental costs of
providing such statements through its rates. However, EPC respectfully submits that it is
not clear that the benefits of providing audited financial statements for EPC outweigh the
additional costs. Furthermore, it is important to note that EPC’s businesses include not
only the regulated distribution and transmission businesses, but also the Regulated Rate
Option and ENMAX Power Services Corporation businesses. Consequently, distribution
and transmission related costs could not be directly drawn from audited financial
statements for EPC, but would have to be derived, or the audit restricted to reporting only
on distribution and transmission business functions (which is not materially different
from the third party validation of those costs that already forms part of EPC’s FBR
proposal). 230
10.4
Affiliate Transactions
272. UCA also raised concerns about head office cost allocations to EPC. UCA stated that
EPC receives accounting, finance, human resources, information technology, treasury and legal
services from ENMAX Corporation and that these shared costs constitute 44 percent of
distribution and 35 percent of transmission costs for EPC management and administrative
costs. 231
273.
When asked if EPC would maintain the current allocation methodology, EPC stated:
No. EPC will not commit to maintaining the cost allocation methodology identified in the
2007 COS Forecast document. If a fairer, more precise way to allocate shared services
costs is found, EPC would expect to see the new allocation methodology implemented.
However, as set out in the response to D410.EPC-003, if EPC proposes a change to the
methodology during the term of the test period, the Customer Committee will be advised
of the proposed change and the impact of the proposed charge. 232
274. Notwithstanding the position stated in UCA-EPC-42(a), Mr. Holden stated that no
changes would be made to the corporate allocation method.
229
230
231
232
Exhibit 0103.01.UCA-12, AUC-UCA-3
EPC Reply Argument, pages 37-38
UCA Evidence, pages 12-15, Exhibit 0064.02.UCA-12
Response to UCA-EPC-42 (a), September 14, 2007 Submission
60 • AUC Decision 2009-035 (March 25, 2009)
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Q But at a conceptual level, how would you satisfy us; how would you -- if you were in
our shoes, what would you be looking for from ENMAX to satisfy us that this formula
was being done consistent over the years with the allocations?
A MR. HOLDEN:
Right. That's a very good question, and I think some of our
groups have prepared well for that question. But I'll answer it from the high level. I
think we have now a track record of allocation that was based on taking our total shared
service costs and doing some allocations on a number of parameters, depending on the
area of the company we were talking about, whether it be IT or HR or what have you.
Each of those parameters blended together to create an allocation. We would expect that
that allocation methodology would not change... But the allocation method we would
expect to be verifiably the same method as it has been in the last few years. 233
275. However, EPC reiterated the position taken in UCA-EPC-42 in Reply and indicated that
changes in the allocation methodology would have no impact on rates. EPC proposed that
parties would have an opportunity to comment any changes when FBR rates were rebased. 234
276. UCA recommended that EPC be required to file all working papers in support of the head
office allocation each year, during the term of the FBR. EPC agreed to do so.
For the purposes of the ESM, EPC will provide the Customer Committee with a
breakdown of shared services costs on an annual basis. Like any other cost in the ESM
calculation, in the event that any Customer Committee member believes that EPC has
over or under allocated shared services costs to EPC, the dispute mechanism process (that
EPC plans to negotiate in the upcoming negotiated settlement process) may be used in
order to resolve the issue. 235
10.5
277.
Outsourcing
UCA raised concerns that:
…there may be opportunities for ENMAX Power to offload services at a for-profit fee to
unregulated affiliates and effectively take any gains that would have been shared with
customers and put that into an unregulated affiliate through a profit margin. 236
278. UCA stated that EPC should not be allowed to outsource any of its services to an affiliate
where there is a profit component in the prices and that there must be the same transparency of
costs as there is today.
279.
EPC stated:
EPC strongly objects to any suggestion that its existing right to manage its business,
including entering into affiliate transactions or outsourcing services should be fettered
during the FBR term. So long as EPC’s affiliate transactions meet the requirements of the
approved ENMAX Code, they are permitted. Similarly, the requirements for determining
whether a utility may outsource a service are well established, and so long as EPC abides
by those requirements, there is no justification for interfering with EPC’s right to manage
its business.
233
234
235
236
Transcript Volume 1, pages 0323, line 23 to page 0325, line 15
EPC Reply Argument, page 38
September 14, 2007 Submission, D410-EPC-003 (d)
Transcript Volume 5, page 1379
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EPC does not seek, through its FBR proposal, to alter any of the requirements that
currently apply to it with respect to outsourcing or affiliate transactions. 237
10.6
Commission Findings
280. Both UCA’s and EPC’s expert witnesses agreed that an earnings sharing mechanism
dampens efficiency incentives. Mr. Goulding stated that there is no doubt that earnings sharing
mechanisms blunt incentives. 238 .The Commission agrees.
281. Notwithstanding this concern, the Commission recognizes that all parties support the
earnings sharing mechanisms proposed by EPC and view it as an important safeguard in the
early stages of an FBR plan. Therefore, the earnings sharing mechanism is approved, as
proposed.
282. The Commission finds that the correct calculation of ROE for EPC is an issue since
earnings determine whether sharing occurs and the Commission may rely on ROE as a measure
of the correctness of the FBR parameters on a going forward basis. The earnings sharing
mechanism cannot be relied upon to serve its intended purpose as a safeguard if the calculation
of ROE is suspect. Therefore, the absence of audited or otherwise verifiable statements for EPC,
separate from the audited statements of ENMAX Corporation, is a major concern.
283. The Commission accepts that the Annual Rates and Technical Report filed with the AUC
will provide useful information. However, the adoption of an earnings sharing mechanism in the
FBR plan requires that the annual reporting of ROE must be independently verified and be
attested to by an officer of the company. EPC is directed to have its reported ROE independently
verified and to have an officer of the company attest to its validity. The Commission also directs
EPC to include in its annual filings the reconciliation tables proposed by UCA.
284. The Commission is concerned that the allocations from ENMAX Corporation should not
result in cross-subsidies that impact the reported earnings of EPC. The Commission relies on
Mr. Holden’s assurance, as noted at paragraph 274, that the allocations will not change. The
Commission also expects there to be no changes to arrangements with affiliates, such as
outsourcing arrangements, during the FBR term without Commission approval. The
Commission expects there to be no changes to the allocation method during the FBR term
without Commission approval. In addition, the Commission expects there to be no new affiliate
agreements to outsource services which EPC currently provides for itself during the FBR term
without Commission approval.
11
SERVICE QUALITY
11.1
Performance Standards
285. In the Application, EPC proposed performance standards along with penalties for failing
to meet those performance standards as part of the FBR plan. EPC indicated the performance
standards are designed to preserve the high level of safe and reliable service that already exists.
The penalties proposed by EPC are asymmetrical. EPC must pay a penalty for failing to meet
237
238
EPC Reply, page 38
Mr. Goulding, Transcript Volume 2, page 0595
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the specified performance standards, but is not financially rewarded for meeting or exceeding
these performance standards. 239
286. The three FBR performance standards proposed by EPC are All Injury/Illness Frequency
Rate (AIIFR), System Average Interruption Frequency Index (SAIFI) and System Average
Interruption Duration Index (SAIDI). 240
287. AIIFR measures the number of workplace injuries per 200,000 hours worked and is based
on the total number of medical aid injuries, disabling injuries and fatalities experienced in both
distribution and transmission in a calendar year multiplied by 200,000 and divided by the
number of employee exposure hours worked in a calendar year. EPC proposed an AIIFR
performance standard target of 6.50. 241
288. SAIFI is defined as the average number of times a customer is interrupted during a year
and is determined by dividing the total annual number of customer interruptions by the average
number of customers served during the year. EPC proposed a system-wide SAIFI performance
target of no more than 1.00 interruptions per customer per year, measured as a five-year rolling
average. 242
289. SAIDI is defined as the annual average service interruption time for customers and is
determined by dividing the total duration of all customer service interruptions in a year by the
average number of customers served during the year. EPC proposed a system-wide SAIDI
performance standard target of no more than 30 minutes per customer per year, measured as a
five-year rolling average. 243
290. SAIFI and SAIDI were proposed because they are well established objective measures of
reliability. AIIFR was proposed as an objective safety measurement. EPC stated that
collectively, SAIDI, SAIFI and AIIFR provide a comprehensive, objective and verifiable method
of assessing the extent to which EPC continues to provide safe and reliable service.
291. EPC proposed to place $2 million at risk for the first year of the FBR term as a
performance penalty for failing to meet the performance standards. The performance penalty for
each subsequent year will be escalated to be the prior year’s penalty multiplied by (1+I). Any
performance penalty incurred will be paid out as a reduction to DAS rates in the following
calendar year as a percentage of gross revenue. Any performance penalties incurred will be at
the expense of EPC’s shareholders and will not be included in the earnings sharing mechanism
calculation. EPC proposed to allocate a $200,000 penalty for failing to achieve any one of the
three performance targets, with the remaining $1.4 million allocated across the three
performance standards as determined by the FBR Customer Committees. 244
239
240
241
242
243
244
Exhibit 0015.00.EPC-12, Application, Section 3.5
Exhibit 0015.00.EPC-12, Application, page 77
Ibid, page 78
Ibid, page 79
Ibid, page 80
Exhibit 0015.00.EPC-12, Application, page 81
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292. EPC indicated that a number of potential performance standards were also considered,
including those already reported to the AUC under Rule 002. 245 EPC rejected most of them
because they are too narrow. 246
293.
(a)
(b)
EPC also proposed the following additional performance commitments: 247
within one year of approval of the FBR Application, EPC will examine each major
class of assets and identify the key drivers that affect asset deterioration and any change
to the maintenance practices associated with these key drivers will be filed with the
AUC for information purposes three months in advance of the change; and
within one year of approval of the FBR Application, EPC will develop a new customer
connection time target and will report annually to the FBR Customer Committees
regarding its performance relative to this target.
294. CG submitted that the performance standards proposed by EPC are objective and well
recognized within the industry and are an appropriate measure, at least for purposes of the initial
FBR term. However, CG proposed that an additional re-opener be established in the event EPC
fails to meet one or more performance standard for three consecutive years.
295. EPC replied that, in light of the significant penalties that EPC will incur if it fails to meet
any of the service standards in any year, an additional re-opener is not necessary.
296. Dr. Cronin and Mr. Motluk did not disagree with the performance standards and penalties
proposed by EPC, however, they believe the “socially optimal” approach to performance
standards is a better alternative on a long term basis. 248 UCA submitted EPC’s proposed
performance standards seem adequate for the first five years of the FBR but EPC should examine
more optimal performance standards at the time of rebasing in five years.
297. Dr. Cronin and Mr. Motluk make the following specific proposals in respect of EPC’s
proposed penalties:
Yes, there are four areas where Dr. Cronin and Mr. Motluk believe changes in EPC’s
proposal need to be implemented. These changes have to do with the average nature of
EPC proposal. In general, they believe the program needs to be better targeted.
First, Dr. Cronin and Mr. Motluk recommend that EPC not base its performance on a
rolling 5-year average, but rather on each year’s results. Use of a 5-year average could
mean that significant deterioration in service performance for 1 or even 2 years might not
prompt penalty payments when rolled up over 5 years and averaged out. Someone losing
a freezer of frozen food is probably not ameliorated that the rolling average discounts
their loss.
Second, Dr. Cronin and Mr. Motluk recommend that a penalty payment for service
degradation be targeted to those customers suffering the lower reliability, and not rebated
back to all EPC customers, even those not experiencing the lower reliability. Rebates to
all customers could mean pennies in penalty payments. In addition, Dr. Cronin and Mr.
245
246
247
248
AUC Rule 002: Electric Distribution System Owner (Wire Owner) Service Quality and Reliability Performance,
Monitoring, and Reporting Rules
Application 1512069, Exhibit 83, BR.EPC-019
Exhibit 0015.00.EPC-12, Application, pages 82 and 83
Exhibit 0064.03.UCA-12, UCA PBR Evidence, page 79
64 • AUC Decision 2009-035 (March 25, 2009)
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Motluk recommend that the rebate be paid one lump sum at the start of the next annual
cycle, not over 12 months.
Third, Dr. Cronin and Mr. Motluk recommend that EPC be required to report information
on “best and worst performing areas.” This would allow the Board to review the
geographical distribution of performance and take action if need be to ensure that all
locations are within a reasonable range of the top performance locations. . . .
Fourth, EPC penalty payments could be quite small on a per customer, maybe pennies or
a few dollars per customer. This hardly compensates customers suffering from
significant degradation in reliability performance. 249
298. D410 stated that, at this time, the UCA experts’ proposal does not appear to be
particularly well defined and recommended that EPC’s proposal to credit all reliability penalties
to DAS ratepayers be adopted.
299. D410 further recommended that EPC provide the Customer Committee with specific
statistics about which customers are interrupted and the size of the load being interrupted. D410
stated that the Customer Committee and EPC can work collaboratively to evaluate whether
enhancements to the penalty mechanisms could be developed to (a) better reflect the size and
cost of the interruptions, and (b) share the penalty payments more equitably with the affected
customers.
11.2
Commission Findings
300. The Commission has had a quality of service reporting obligation since the adoption of
EUB Directive 002 250 on January 1, 2004. Under this rule, EPC must file quarterly reports on its
performance with respect to certain quality of service indicators.
301. The Commission agrees that SAIDI and SAIFI are well established standards in the
electric utility industry. The Commission notes that these metrics are currently reported by EPC
under AUC Rule 002. The Commission accepts EPC’s proposal to adopt SAIDI and SAIFI as
performance measures for the FBR plan. EPC also proposed to report the AIIFR results. While
the AIIFR metric is not an industry standard, the Commission accepts EPC’s proposal to adopt
this performance measure for the FBR plan.
302. The Commission also notes that, for the period from the start of the FBR up to the
proposed mid-term rebasing, none of the interveners objected to using EPC’s proposed
performance metrics or objected to the $2 million EPC proposed to place at risk for the
performance penalties. Parties further agreed that each of the proposed metrics would have
$200,000 at risk and that the Customer Committees would work with EPC to determine how the
remaining $1.4 million would be divided among the three metrics.
303. The Commission agrees with EPC’s statement that “[t]he magnitude of the penalties
proposed is not trivial. Based on EPC reported allowed equity returns for 2006, had the
performance standard penalties been in place then, EPC would have put at risk over 10% of its
allowed return. … The potential for earnings to fall by more than 10% means that performance
standards should be clearly meaningful to management, and sufficient for performance impacts
249
250
Exhibit 0104.01.UCA-12, D410.UCA-6
Now Commission Rule 002
AUC Decision 2009-035 (March 25, 2009) • 65
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to be considered in investment plans.” 251 Accordingly, the Commission considers $2 million to
be an adequate amount of dollars to be put at risk for performance penalties. The Commission
accepts the proposed metrics and the $2 million to be put at risk.
304. However, the Commission does not agree with the proposal for how the $2 million will
be allocated among the metrics. The Commission is concerned about the Customer Committee
and EPC setting out the proposed penalty amount for the remaining $1.4 million. The
Commission expects to be reviewing the types of performance metrics required and associated
penalty amounts in conjunction with Rule 002 at a future date. The Commission considers it
would not be efficient for EPC and the Customer Committees to spend time and resources on this
matter at this time. Therefore, the Commission rejects EPC’s proposal for it to work with the
Customer Committees to set out the penalties for the remaining $1.4 million. The Commission
directs EPC to determine how the penalties for the remaining $1.4 million will be divided among
SAIFI, SAIDI and AIIFR and provide that information in its compliance filing.
305. For the same reasons discussed in the preceding paragraph, the Commission rejects
D410’s recommendation for EPC to provide the Customer Committee with specific statistics
about which customers are interrupted and the size of the load being interrupted.
306. The Commission considers that EPC’s proposal to develop a new customer connection
time target within one year of approval of the Application and to report its performance relative
to this target is worthwhile. However, the Commission considers that this metric will be for
reporting purposes only and that the reporting of this target can be included along with the
reporting of the other performance metrics as part of EPC’s annual filing requirements.
307. The Commission notes that while the UCA witnesses recommended that EPC report the
worst performing circuits, EPC already does so in accordance with Rule 002, albeit without an
attached penalty. The Commission may explore the merits of compensating individual
customers affected by poor performance in its review of Rule 002.
308. The Commission does not consider EPC’s proposal to examine each major class of assets
and to file such data with the AUC for information purposes necessary and does not require EPC
to provide the Commission with this data at this time.
309. The Commission rejects CG’s proposal for an additional re-opener since the Commission
has already approved a re-opener with respect to performance standards as discussed earlier in
this Decision. Further, the Commission agrees with EPC that the penalties in place are sufficient
to incent EPC to ensure that the performance standards are met.
12
MUNICIPAL RIDER
310. EPC proposed that capital requirements for the distribution system, in excess of the
amount of capital additions that can be funded internally through EPC’s distribution operations,
be funded through a rate rider imposed by The City of Calgary pursuant to subsection 138(3) of
the Electric Utilities Act. This municipal rider would be collected from ratepayers by EPC and
would be capped at $15 million per year. 252 If the municipal rider capital requirements exceed
251
252
Exhibit 0018.00.EPC-12, LONDON ECONOMICS Evidence, page 25
Exhibit 0015.00.EPC-12, Application, page 21
66 • AUC Decision 2009-035 (March 25, 2009)
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the $15 million cap in a given year, the excess capital requirement would be carried over to the
next year and recovered in the next year’s municipal rider. EPC indicated that the municipal
rider will only be used to fund capital required by the distribution system and will not be used to
fund operating expense. 253
311. In accordance with Decision 2006-002, EPC proposed that the funds provided by The
City of Calgary to EPC through the use of the municipal rider will be treated as no-cost capital
and will be applied directly to the distribution rate base as construction funds collected from
customers. EPC will not earn a return on capital received from the municipal rider and the
depreciation expense will be offset by treating the funds collected as contributions in aid of
construction, which will be amortized over the expected life of the underlying facilities.
312. EPC indicated that it would fund, within the FBR formula, distribution capital at the
greater of:
(a)
(b)
the EUB approved level of net capital set out in Decision 2006-002 ($65.5 million),
increased each year by the Inflation Factor less the Productivity Factor; or
the amount of capital that can be funded from the previous year’s net earnings less
dividends (30 percent of previous year’s earnings) plus depreciation, while maintaining
a debt to equity ratio of 61/39.
313. Any distribution capital expenditure requirements in excess of what would be funded
under the FBR formula would be funded through a municipal rider.254
314. In a letter dated September 17, 2008, 255 EPC revised the proposed funding formula which
had a further impact on the use of the municipal rider. In that letter, EPC indicated that the
entirety of net earnings would be used to fund capital projects before deduction of dividends.
EPC estimated its decision to reinvest the entirety of its net earnings, rather than net earnings less
dividends, should reduce the amount of the municipal rider collected over the term of the FBR
from $110 million to $50 million. 256 EPC subsequently further revised its financial forecasting
model, and reduced the forecast amount of the municipal rider required over the FBR term to
$36.8 million. 257
315. Prior to the September 17 letter, interveners offered evidence from three separate experts,
all of whom identified a distortion in economic incentives resulting from the use of the municipal
rider. 258,259,260
316. While UCA stated that the municipal rider weakens incentives, it also stated that the
Commission does not retain specific jurisdiction over EPC’s use of a municipal rider. In
Argument, UCA indicated it appreciated that EPC chose to amend its Application to reduce the
magnitude of and annual use of the municipal rider to fund excess requirements for distribution
253
254
255
256
257
258
259
260
Proceeding No. 1512069, Exhibit 102, UCA.EPC-038
Exhibit 0015.00.EPC-12, Application, page 21
Exhibit 131.02.EPC-12
Exhibit 0131.01.EPC-12 and Exhibit 0131.02.EPC-12
Exhibit 0152.07.EPC-12, Attachment B
Exhibit 0064.03.UCA-12, UCA PBR Evidence, page 73, lines 3-7
Exhibit 0068.01.CG-12, CCA/PICA Direct Evidence, page 6, lines 6-13
Exhibit 0155.01.D410-12, Opening Statement of Robert D. Knecht, page 2, lines 1-12
AUC Decision 2009-035 (March 25, 2009) • 67
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capital. UCA submitted that this amendment largely addressed its concerns over the use of a
municipal rider. 261
317. Mr. Marcus stated that the municipal rider places EPC’s contribution policy at issue. The
Commission addressed Mr. Marcus’ proposal regarding EPC’s contribution policy in Section
16.1 of this Decision.
318. CG submitted that the Commission should approve a stipulation that EPC should not be
allowed to change the municipal rider formula, as amended on September 17, 2008, during the
FBR term. As an alternative, CG submitted that any change in the municipal rider formula must
be considered an automatic re-opener to EPC’s FBR plan. CG further stated that if the change
cannot be justified based on funding criteria for capital projects, the FBR formula should then be
adjusted along the lines recommended by Mr. Knecht.
319. Mr. Knecht indicated if the Commission cannot find a solution to the problems with the
municipal rider, it should simply reject the FBR proposal. 262
320. Mr. Knecht proposed that an “M-Factor” be incorporated, which would impose a deemed
cost on EPC for its use of the municipal rider equal to the capital cost EPC would incur if it had
to go to the capital markets for the same funds. The M-Factor would be calculated as follows: 263
Mt-1 = (r+d) * MRRt-1
Where r is the weighted average cost of capital, d is the average depreciation rate and
MRR are the funds collected through the municipal rider.
321.
Mr. Knecht proposed that the FBR mechanism be modified as follows: 264
Pt = Pt-1 * (1+I-X-Mt-1/Rt-1)
Where Rt-1 is the prior period DAS revenues.
322. Mr. Knecht calculated that, without the proposed D410 modification of the FBR formula,
the threshold capital cost rate of return of would be 6.2 percent. Mr. Knecht explained that since
this is down from the 6.3 percent that would be used if no municipal rider was in place, EPC
would approve projects below the 6.3 percent threshold even though the project is not
economic. 265 D410 stated that the municipal rider, to the extent it is being used as a source of
financing, provides free capital. EPC can use that free capital to expand its business, serve more
customers, and thereby generate more revenues. He argued that increasing revenues with nocost capital provides EPC with many opportunities to earn profits from the facilities built with
the no-cost capital.
323. D410 suggested that the X factor could be modified from 1.5 percent to 1.3 percent in
order to implement a revenue-neutral M-Factor; however it indicated that there is not a material
261
262
263
264
265
UCA Argument, page 7
Exhibit 0112.01.D410-12, EPC.D410-002
Exhibit 0156.03.D410-12
Ibid
Exhibit 071.02.D410-12, pages 10 and 11, Exhibit 071.03.D410-12
68 • AUC Decision 2009-035 (March 25, 2009)
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difference between the 1.3 percent and 1.5 percent X factors and that the proposed X factor of
1.5 percent used in conjunction with the M-Factor is reasonable.
324. In addition, Mr. Knecht, similar to CG, proposed that any change in the municipal rider
formula by EPC be considered an automatic “re-opener” to EPC’s FBR mechanism.
325. EPC disagreed with Mr. Knecht’s assessment and stated that D410’s argument focuses
exclusively on the “no-cost” aspect of municipal rider funds and ignores the countervailing “noprofit” aspect of municipal rider funds, as Mr. Holden testified. 266
326. Ms. Emes pointed out that such an argument assumes that EPC is only concerned about
cash flow and not earnings, which is incorrect. 267 Furthermore, as Mr. Hawrelko testified, when
EPC evaluates its capital projects, it does not consider no-cost capital.
Q. … When EPC evaluates its projects, what do you use for your weighted average cost
of capital?
A. Ms. Wall, I’ll try that. It’s the combination of the generic cost of capital weight and
our cost of debt. But I don’t actually have that number in front of me, but …
Q. But can you confirm to me that you don’t include any no cost capital dollars?
A. That’s correct. We don’t include a no-cost capital.
Q. Okay. And do you evaluate each project separately on that basis?
A. Yes, ma’am, that’s the case. 268
12.1
Commission Findings
327. Witnesses for three interveners all expressed concerns over the municipal rider and
provided evidence that the incentives associated with an FBR are weakened when EPC raises nocost capital through a municipal rider. However, after EPC changed the formula for the
municipal rider in the September 17, 2008 letter, UCA stated that the change largely addressed
its concerns regarding the municipal rider. CG and D410 continued to have concerns with the
municipal rider following the filing of the September 17 letter.
328. The Commission notes that UCA withdrew its objection to the municipal rider. The
Commission also notes, from the example provided by Mr. Knecht, that the municipal rider
changes the cost of capital threshold from 6.3 percent to 6.2 percent. 269 However, the
Commission finds that a difference of 10 basis points or a 1.5 percent change in the cost of
capital decision making threshold is not material and is unlikely to influence capital cost
decisions. The Commission further notes that EPC testified that it did not include no cost capital
when evaluating capital projects. 270 Subsequent to the changes in the use of the municipal rider
reflected in EPC’s letter of September 17, 2008, the Commission finds that the municipal rider
266
267
268
269
270
Transcript Volume 1, page 0125, line 23 to page 0126 line 10. See also Transcript Volume 1, page 0219, line 12
to page 0220, line 5
Transcript Volume 2, page 0502 lines 19-23
Transcript Volume 4, page 1142, lines 8-24
Exhibit 071.02.D410-12, pages 10 and 11, Exhibit 071.03.D410-12
Transcript Volume 4, page 1142, lines 7-24
AUC Decision 2009-035 (March 25, 2009) • 69
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will have little or no impact on the FBR rate setting mechanics. Therefore, the interveners’
proposals with respect to the municipal rider are dismissed.
329. CG and D410 submitted that the Commission should approve a re-opener contingent
upon EPC changing its formula for the municipal rider. The Commission considers that a
material change to the use of the municipal rider could be a significant event requiring a
reexamination of the FBR proposal. As such, the Commission considers that a change to any of
the following undertakings will require a proceeding to consider whether a re-opener is
warranted in the same manner as the re-openers addressed in Section 9 of this Decision:
1. the municipal rider set at a maximum of $15 million per year;
2. the funds from the municipal rider treated as set out in Decision 2006-002;
3. the magnitude of the annual municipal rider determined as set out in the
September 17, 2008 letter.
13
COMMISSION DETERMINED FBR FORMULAS
330.
The FBR formulas for each of distribution and transmission are approved as follows:
Distribution: Pt = Pt-1* (1+(I-X))
the following adjustments will be made on an annual basis as required
Ptadjusted = Pt – E – S +/- Z 271
Transmission: Rt = Rt-1* (1+(I-X)) + G
the following adjustments will be made on an annual basis as required
Rtadjusted = Rt – E +/- Z 272
Where:
Pt = Current year’s customer rate for each class
Pt-1 = Prior year’s customer rate for each class
Rt = Current year’s revenue requirement for transmission
Rt-1 = Prior year’s revenue requirement for transmission
I = Inflation Factor
Where I=(EUCPIt-1+AHE t-1)/2
X = Productivity Factor =1.2
G = return plus depreciation on transmission capital investment 273
E = Customer portion of Earnings Sharing
S = Service quality penalties, if any
Z = Exogenous Adjustment
271
272
273
It is possible that a Z factor may result in a permanent rate change whereby the I minus X formula would apply
annually on a going forward basis.
Ibid
Exhibit 0020.00.EPC-12, Amended Appendix 5, 10 Year FBR Model
70 • AUC Decision 2009-035 (March 25, 2009)
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331. The flow through costs approved by the Commission in Section 9 of this Decision will
not be subject to the FBR formulas and will continue to be treated as they are currently.
14
JUST AND REASONABLE RATES
332. In Section 4 of this Decision, the Commission approved distribution and transmission
going-in rates. For the reasons set out in Section 4, the Commission considers these going-in
rates to be just and reasonable. The Commission is satisfied that the application of the formulas
approved in Section 13 above, when applied to the going-in rates, will result in just and
reasonable rates for the term of the FBR plan.
15
CUSTOMER COMMITTEES
333. EPC proposed the establishment of Customer Committees to ensure an appropriate
degree of transparency and accountability and to provide a forum to consult with customers and
AUC staff to resolve tariff issues and reduce the regulatory burden during the FBR term.
334. Additional proposed roles for the Customer Committees included reviewing and
providing feedback on the following:
•
•
•
•
•
335.
•
•
•
•
•
•
•
Annual Rates and Technical Report, including Flow-Through Costs;
Capital business cases (over $500,000);
Annual load forecasts, business plans and shared services costs;
Terms and Conditions of Service and the Cost of Service Study to be filed in 2012;
Additional performance commitments as set out in section 3.5.4;
EPC proposed that the role of the AUC be as follows: 274
review and approve disputed costs or benefits associated with Extrinsic Factors, as
described in section 3.7 of the Application, if any;
review and approve the Annual Rates and Technical Report;
approve deferral and rider account reconciliations, as described in section 3.7.2.5 and
section 4.3 of the Application, if required;
receive applications for and rule on changes to DAS and SAS rates as a result of the 2012
Cost of Service Study, if any;
approve changes to the Distribution Terms and Conditions or Transmission Terms and
Conditions, if any;
approve the make-up of the FBR Customer Committees; and
approve the budget and cost claims for members of the FBR Customer Committees.
336. EPC regarded Customer Committee participation throughout the FBR term as critical to
the success of its FBR proposal. As Mr. Holden stated:
274
Application, Section 6.1
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EPC does not have a monopoly on good ideas, and we want to work closely with
customer representatives to make the most of this opportunity for both customers and
EPC. 275
337. EPC expects to discuss with the Customer Committees any matter prior to bringing an
issue, matter or application before the AUC, with the goal of enhancing the efficiency of the
process so that any matter brought before the AUC is focused, streamlined and straightforward.
EPC stated that it is desirable for EPC to have a complete understanding of its customers’
position and EPC’s customers have a complete understanding of EPC’s position prior to bringing
a matter before the AUC. 276
338.
CG appeared to agree with this approach when it noted:
… to the extent issues can be resolved as between EPC and customers; it should
minimize the number of contentious issues referred to the Commission and better focus
the issues of greatest significance as, and when, they are brought forward to the
Commission for final review and approval. 277
339.
D410 went further and indicated:
…the customer committee needs to be stronger than EPC has suggested in its application,
and needs to have the ability to carry out reasonable scrutiny of EPC’s ongoing activities
on a regular basis… Thus, the ability to use an information request process and get full
and meaningful responses on a timely basis is essential. 278
340. In Argument, 279 D410 cited Mr. Hemstock’s comments regarding the committee as
follows:
A MR. HEMSTOCK:
I would say the purpose of the customer committee is to
provide transparency, feedback opportunities, and a forum to consult with customers and
AUC staff to resolve tariff issues and really reduce the regulatory burden. And that's the
fundamental purpose of it at a high level.
341. D410 280 also cited Mr. Holden’s testimony that substantial savings could accrue with
respect to the regulatory burden “…if it could be replaced with a well functioning customer
committee.”
342.
Mr. Holden also stated that EPC is committed to a new regulatory process:
Q And I've heard you say once you get in, you don't want to get out. You don't want to
come back to cost of service. You'll look at that for rebasing, but this is a new way of
thinking, and you'll stick with it?
A MR. HOLDEN:
Ye[s]. If we go to the effort of crafting a new regime, then we
want to put all the energy we possibly can to making it work. 281
275
276
277
278
279
280
281
Transcript Volume 1, pages 0092-0093
Transcript Volume 1, page 0178
CG Argument, page 66
D410 Argument, page 24
D410 Argument, page 26
D410 Argument, page 25
Transcript Volume 1, page 0306
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343.
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Mr. Gray, witness for UCA, also indicated that PBR requires a different approach.
But I do agree the ultimate end result should be to try and go to a full-blown formulabased or performance-based ratemaking system, 282
344. EPC stated that the Customer Committees are not intended to act as a surrogate regulator.
This was reaffirmed by Mr. Hemstock who stated:
But, ultimately, the litmus test of customer representation, wherever there was a
disagreement, is whatever happens before the Commission itself, just like we're doing
today.
…
One is the customer committee framework doesn't have to exist for the Board ultimately
to make a decision, so long as the Board has a proceeding where it does listen to the
interests of customers. 283
345. As noted below, EPC confirmed it could continue with a Customer Committee should the
Commission not require one.
Q Now, there's nothing in your view that would prevent EPC from establishing a
customer committee if, for example, the Commission decided, well, we're not going to
embark on directing this to happen, but if you think it's valuable …you could go ahead.
There would be nothing in your view that would stop this from happening, would it?
A MR. HOLDEN:
I can't think of anything that would stop that. 284
346. Ultimately, CG and D410 supported the Customer Committees. 285 UCA did not appear to
take any position on the Customer Committees apart from ensuring that “…the Commission put
out a very clear definition of what it expects out of that ongoing role.” 286
15.1
Commission Findings
347. The Commission notes the general agreement of parties that the proposed role of the
Customer Committee is to support and assist EPC in determining rates and potentially reducing
areas of litigation.
348. As D410 noted in quoting Mr. Hemstock, a benefit of the committees often cited by
parties was that it would reduce the regulatory burden. The Commission supports any efforts to
reduce the regulatory burden, but observes that D410’s suggestion that Information Request
powers be granted to the Customer Committees sounds very similar to today’s litigated, line by
line regulatory process. This appears to the Commission to be contrary to the views of UCA and
EPC that a new way of thinking and a new approach is required to make PBR work.
349. The Commission also notes the testimony of Mr. Holden that the Customer Committees
could exist whether or not the Commission required them.
282
283
284
285
286
Transcript Volume 5, page 1404
Transcript Volume 1, pages 0318-0319
Transcript Volume 1, pages 0292-0293
CG Argument, page 67, D410 Argument, page 27
Transcript Volume 5, page 1375 as quoted in UCA Argument, page 35
AUC Decision 2009-035 (March 25, 2009) • 73
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350. The Commission agrees with Mr. Holden that the opportunity for a reduced regulatory
burden exists with a well functioning Customer Committees, however there is no assurance that
that will be the case.
351. EPC stated that well functioning Customer Committees will reduce EPC’s costs. In the
Commission’s view, this translates into productivity improvement. The Commission considers
that, if the committees are funded by customers through intervener cost awards recovered
through rates, there is less incentive on the part of parties to resolve issues in an expeditious
manner.
352. For these reasons, the Commission will not require EPC to establish the Customer
Committees. However, if EPC determines that it would benefit from establishing and working
with Customer Committees to assist with its regulatory filings, it is free to do so. However, the
costs associated with Customer Committees will not be recovered through the Hearing Cost
Reserve Account and the remuneration paid to members of the Customer Committees will not be
eligible for reimbursement under AUC Rule 022. EPC should treat any expenses related to the
Customer Committees in the same way that it treats other costs of its regulatory department.
16
OTHER ISSUES
16.1
Distribution Residential Contributions
353. CG proposed that Distribution Residential Contributions be increased to partially offset
the requirement for funds that EPC would collect through the municipal rider. Mr. Marcus
questioned why EPC should not collect more contributions from new customers, as opposed to
collecting up-front contributions from all ratepayers through the unregulated municipal rider to
pay for those new customers. While Mr. Marcus noted the Commission does not regulate the
municipal rider; it does regulate EPC’s contribution policy. 287 To better match the collection of
costs with those creating the costs, Mr. Marcus recommended EPC’s contribution policy be
harmonized with EPCOR’s, which requires a payment of $1,050 per customer, starting in 2009.
After 2009, the figure would increase by I minus X. 288
354. EPC responded that CG offered no rational explanation as to why EPC’s long-standing
investment policies should be harmonized with EPCOR’s investment policies. EPC indicated
that it is clear from Mr. Marcus’ evidence and CG’s argument that CG’s real goal is to find a
way to reduce the amount that EPC will raise using the municipal rider. EPC stated that this is
not a sufficient justification for changing EPC’s long-standing investment policies. EPC also
stated that lowering the investment levels would result in intergenerational inequities. 289
16.1.1
Commission Findings
355. The Commission considers that the level of investment for new customers is independent
of whether EPC has a municipal rider. In addition, the Commission considers that there is
insufficient evidence in this proceeding to warrant an adjustment to EPC’s investment level, at
this time. Accordingly, the Commission rejects CG’s proposal to change the residential
investment level.
287
288
289
Exhibit 0068.01.CG-12, CG Evidence, page 6
Exhibit 0068.01.CG-12, CG Evidence, page 10
Transcript Volume 4, page 995, line 9
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16.2
ENMAX Power Corporation
Depreciation
356. EPC forecast its 2007 depreciation expense to be $35.8 million for distribution and $6.5
million for transmission. 290 EPC based its depreciation expense forecast on a study prepared by
Larry Kennedy of Gannet Fleming Inc.
357.
•
•
•
•
•
This study was developed using the following:
A mortality study to determine the average service life estimates (excepting those for
which simplified methods are used);
Net salvage percentages developed as a result of a net salvage study;
Continued use of simplified depreciation methods for certain accounts, as directed by the
EUB in Decision 2006-002;
Application of Equal Life Group 291 (ELG) calculations; and
Discontinuance of the traditional method of truing-up the accumulated depreciation
variances between book and calculated amounts, in favour of a 10-year amortization of
the variances. 292
358. The study determined the 2007 composite depreciation rates for distribution and
transmission to be 3.73 percent and 2.7 percent, respectively. EPC proposed to use the 2007
depreciation rates for each subsequent year in the FBR term. 293
359. UCA submitted depreciation evidence and was the only intervener to address the subject
of depreciation in either Argument or Reply Argument. Although UCA did not agree with all of
Mr. Kennedy’s evidence, UCA, in its Argument, indicated that the differences did not have a
significant impact on depreciation expense. As such, UCA did not take issue with the results of
the study prepared by Mr. Kennedy. However, UCA ,in its Argument, submitted that the AUC
should direct EPC:
•
•
•
360.
16.2.1
to file a new depreciation study with the rebasing of the customer rates at the end of the
five-year period;
to revert to the current remaining life methodology at the end of the FBR term; and
to retire assets being depreciated using the Simplified Depreciation method at the end of
the amortization period for each vintage of the respective assets.
These issues are discussed separately in the following sections.
Mid-term Depreciation Study
361. EPC proposed to rebase depreciation rates and true-up the accumulated depreciation
through either a technical update or a full depreciation study as part of the proposed rebasing of
customer rates after five years. 294 In Argument, UCA submitted that the Commission should
direct EPC to include a new depreciation study as part of the rebasing of EPC’s customer rates
290
291
292
293
294
Exhibit 0015.EPC-12, EPC’s Application, dated December 10, 2007, page 71
Application, Appendix 13, Part II, “Methods Used in the Estimation of Depreciation”
EPC Application, page 71
EPC Application, page 71 of 104
Information Response UCA.EPC-045 b)
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after five years. 295 EPC, in Reply Argument, indicated that it was not opposed to UCA's
recommendation. 296
16.2.2
Commission Findings
362. As stated elsewhere in this Decision, the Commission has approved a 7-year FBR term
with no mid-term rebasing. As a result, the Commission rejects UCA’s proposal. There is no
need for either a technical update or a full depreciation study commensurate with a mid-term
rebasing.
16.2.3
Amortization of Variances
363. EPC proposed “…the discontinuance of the traditional method of truing-up the
accumulated depreciation variances between book and calculated amounts, in favour of a tenyear amortization of the variances.” 297 EPC submitted that the incorporation of a ten-year period
for the true-up of accumulated depreciation variances resulted in a reduction of depreciation
expense of approximately $3.6 million over the term of the FBR. 298
364. In Argument, UCA submitted that the AUC should direct EPC to revert to the current
remaining life methodology at the end of the FBR term. 299
365. In Reply Argument, EPC confirmed that the ten-year amortization period was specific to
this Application. 300
16.2.4
Commission Findings
366. The Commission notes that, other than UCA’s concerns, there were no other intervener
concerns with respect to the proposed amortization period. Considering the above and given that
UCA and EPC agreed that the proposed amortization period was specific to the term of the
Application, the Commission finds EPC’s proposal to amortize accumulated depreciation
variances over the term of the FBR to be reasonable.
367. Consequently, given that the Commission has approved a seven year FBR term, the
Commission directs EPC to recalculate the amortization of depreciation variances over the
approved term of seven years instead of the proposed 10 years. Further, the Commission directs
EPC, in its compliance filing, to submit EXCEL spreadsheets complete with formula and cell
linkages that reflect the calculations and the subsequent changes to related schedules and its
revenue requirement.
16.2.5
Asset Retirement
368. EPC stated that, for its mass property accounts, EPC booked an asset’s retirement when
the asset was physically taken out of service. 301
295
296
297
298
299
300
301
UCA Argument, page 24
EPC Reply Argument, page 35
EPC Application, dated December 10, 2007, page 72
BR.EPC-013, dated June 21, 2007
UCA Argument, dated November 14, 2008, page 25
EPC Reply Argument, page 35
UCA.EPC-025 a), dated September 14, 2007
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369. UCA stated that it did not agree with EPC’s proposal to retire assets on a physical basis.
UCA pointed out that EPC’s proposal was not consistent with EPCOR’s approved approach,
wherein EPCOR amortizes and retires assets on a straight line basis, regardless of physical life.
UCA submitted that the AUC should direct EPC to retire assets at the end of the amortization
period for each vintage of asset. This would ensure that each vintage of asset is fully depreciated
at the end of its respective amortization period. 302
370. In Reply Argument, EPC pointed out that, unless it maintained two depreciation
accounting systems, UCA’s recommendation would result in the permanent loss of future
retirement experience, which EPC submitted would be imprudent. 303
16.2.6
Commission Findings
371. The Commission notes that EPC’s and EPCOR’s retirement policies differ with respect to
the retirement of assets. EPCOR retires an asset at the end of the amortization period whereas
EPC retires an asset when it is physically taken out of service.
372. The Commission also notes that EPCOR uses a simplified depreciation method, referred
to as the Direct Life Method, for all assets except vehicles and mobile equipment. 304 Further, the
Commission understands that under the Direct Life Method:
…an asset will remain in service until that asset’s pre-determined asset life has passed.
As an example, if an asset has a 10-year life and is physically removed from service in
year 8, for accounting purposes, the net book value of that asset will remain in service
until year 10 when the net book value reaches zero. Conversely, if the asset physically
remained in the field for 12 years, for accounting purposes, the asset would have retired
after year 10. 305
373. The Commission considers the Direct Life Method may have advantages in that the
method appears to be simple and transparent. Considering the above, the Commission finds that,
if adopted, UCA’s recommendation would ensure that each vintage of asset is fully depreciated
at the end of its respective amortization period. However, given the limited amount of testing in
this Application, the Commission is of the view that no changes should be made at this time with
respect to EPC’s policy of retiring assets when they are physically taken out of service.
16.3
Distribution Driven Transmission Projects
374. In the Application, EPC has included, in its distribution rate base, the expected cost of the
Distribution Driven Transmission projects, including pre-paid O&M, while EPC Transmission
has reflected an offsetting receipt of CIAC. The capital facilities will reside in the distribution
rate base until the AESO and the AUC approve the transfer of these assets to the TFO at book
value.
375. UCA stated it does not take issue with the process associated with Distribution Driven
Transmission projects. However, UCA recommended that any Distribution Driven Transmission
projects, where the transmission projects have deferral account treatment, also be given deferral
302
303
304
305
UCA Argument, dated November 14, 2008, page 25
EPC Reply Argument, dated December 5, 2008, page 36
Decision 2006-054, dated June 15, 2006; page 98
EPCOR Distribution Inc., 2005-2006 Distribution Tariff Application, Application 1389885
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account treatment. UCA also submitted that the issue of which distribution projects are deferral
account eligible, should be dealt with in the Customer Committee meetings.
376. EPC stated that the AESO and AUC review and approval process provides ample
opportunity to assess the impact of a project prior to the anticipated in-service date. EPC
submitted that UCA’s proposal provides no benefits since the distribution FBR formula adjusts
DAS rates and is not based on assets in service. As such, a deferral account would have no
impact on rates.
16.3.1
Commission Findings
377. The Commission agrees with EPC that a deferral account for Distribution Driven
Transmission Projects provides no benefit since the DAS rates are subject to the FBR mechanism
and are independent of the asset base. As such, the Commission rejects UCA’s proposal.
16.4
Fees and Non-Residential Investment Levels
378. In the Application, EPC requested that fees approved in Decision 2006-002, except as
modified by approved changes to the Distribution Terms and Conditions, if any, will be
calculated by EPC so that each year’s fees will be the prior year’s fees multiplied by (1+(I-X)).
379. EPC also proposed that the non-residential investment levels approved in Decision
2006-002 be calculated so that each year’s investment levels will be the prior year’s investment
levels multiplied by (1+(I-X)).
380. EPC further stated that any proposal to implement new fees or new investment levels will
be reviewed with the FBR Customer Committees and filed with the AUC for approval.
16.4.1
Commission Findings
381. EPC referred to the fees and non-residential investment levels approved in Decision
2006-002. The Commission notes that these were approved in Decision 2007-022 306 not
Decision 2006-002. Further, no interveners objected to EPC’s proposal for fees and nonresidential investment levels and EPC has indicated that it will file any new fees or new
investment levels with the AUC for approval. The Commission approves EPC’s proposal for the
treatment of fees and non-residential investment levels.
382. The Commission directs EPC to identify the impact of fee revenue on its rates as part of
its annual filing requirements.
16.5
Pension
383. EPC submitted that an accrual treatment is appropriate for pension plans when the
regulatory period is greater than one or two years. During the hearing, EPC explained the basis
for the change from a cash method to an accrual method. 307 EPC stated that, if it were applying
for a standard cost of service approval over a one or two year test period, EPC would not have
proposed to change from cash to accrual accounting treatment. 308
306
307
308
EPC 2006-2007 Distribution Tariff Phase II and Revised Interim 2007 Distribution Tariff
Transcript Volume 4, page 1100, line 21
Transcript Volume 4, page 1101, lines 11-18
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384. CG raised a number of concerns regarding EPC’s pension costs. These concerns were
EPC’s change from an accrual accounting treatment to a cash accounting treatment, the
previously directed pension deferral account and the magnitude of the solvency deficiency.
385. CG pointed out that in Decision 2006-002, the Board allowed EPC to transition its
supplemental retirement plan from an accrual to a cash basis in part to be consistent with the
cash funding treatment used with EPC’s defined benefit pension plan. 309 CG stated that EPC’s
proposal to revert back to the accrual method for the defined benefit and the supplemental
retirement plan on the basis it is filing a long term FBR is flawed and should be denied. CG
submitted the term of regulatory review is largely irrelevant to the method used. It was not
relevant in the past and should not now dictate EPC’s regulatory or accounting principles.
386. In Argument, CG submitted that the fairness principle requires that EPC follow the Board
approved cash method for EPC in Decision 2006-002, which is also followed by the ATCO
Group of Companies (Decision 2001-105 310 ), FortisAlberta (Decision 2008-011 311 ), AltaLink
Management (Decision 2003-061 312 ) and EPCOR Distribution and Transmission (in the recently
concluded 2007-2009 Negotiated Settlement Agreement filed for approval on September 2,
2008).
387. CG pointed out that the importance of maintaining consistent accounting treatment was
highlighted by the Board in the uniform systems of accounts and minimum filing requirements
proceeding.
The Board agrees with parties that consistency of information is an important benefit of
the implementation of the USA and MFR. The continual changing of cost accounting
policies by utilities makes it extremely difficult to analyze a utility’s operations from year
to year. As well, the continual change in how utilities report their operations in regulatory
applications also makes analysis and understanding quite difficult. The Board sees value
in ensuring that utilities are accounting for and reporting items on a consistent basis year
over year. 313
388. CG also submitted that the Board expressed a desire for standardized and consistent
recording and reporting of information as between utilities.
However, the Board does consider there are benefits in the ability to compare the
operations of the different utilities in the Province….The Board believes that the
standardization and consistency of recording and reporting information will allow parties
to develop and calculate certain metrics and performance measures that can be used for
comparison purposes. This will afford all parties the opportunity to identify any major
areas of concern between the utilities. The Board realizes that there probably are valid
reasons that could explain the differences in performance measures between the utilities
309
310
311
312
313
Decision 2006-002, page 35
Decision 2001-105 – ATCO Electric Ltd., ATCO Gas and Pipelines Ltd. And Northwestern Utilities Limited
(ATCO Companies) Pension Filing – Negotiated Settlement (Application 2000328, File 5678-2)
(Released: December 31, 2001)
Decision 2008-011 – FortisAlberta Inc. 2008/2009 Phase I Distribution Tariff and Negotiated Settlement
Agreement (Application 1514140) (Released: March 20, 2007)
Decision 2003-061 – AltaLink Management Ltd. and TransAlta Utilities Corporation, Transmission Tariff for
May 1, 2002 – April 30, 2004 and TransAlta Utilities Corporation Transmission Tariff for January 1, 2002 –
April 30, 2002 (Application 1279345, 1279347, and 1287507) (Released: August 3, 2003)
Decision 2007-017, page 12
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and the Board sees value in exploring and understanding these reasons. The Board
believes that this would benefit not only customers and the Board, but utility management
as well. 314
389. CG submitted that EPC did not file the pension deferral account that was required to be
established for extinguishing the solvency deficit. 315 This deferral account was order by the
Board in Decision 2006-002. 316
390. CG noted that, while the solvency deficit was $34.1 million in 2004, it had been reduced
to $21.5 million as at December 31, 2006. 317 In response to questions as to why it did not make
adjustments to the $2.2 million amortization amount to reflect the revised lower solvency deficit
at December 31, 2006, EPC responded that it did not have this data when it filed the original
FBR Application on May 11, 2007, and wanted to minimize changes to the model when it refiled on December 10, 2007. 318 CG did not accept this response.
391.
CG recommended that EPC be directed to:
i)
Provide a proper pension deferral account, commencing with the $34.1 million of
solvency deficiency at December 31, 2004, amounts paid in respect of such solvency by
customers, as well as the actual cash amounts paid by EPC to terminate the solvency
deficiency, and the amount remaining at the end of each year for regulatory purposes
(with 10 year amortization) and book purposes (with 5-year amortization). The
reconciliation should be provided both at the ENMAX Corporation level, as well as the
EPC level for each year;
ii)
Address the extent to which the $2.2 million amortization payment ordered in Decision
2006-002 should be reduced in light of the reduction in the solvency deficit from $34.1
million in 2004 to $21.5 million as at December 31, 2006; and
iii)
Explain why customers should be responsible for the “on-going payments from prior
valuations” which are “insufficient to cover the current deficiency.” 319
392.
EPC responded to CG’s recommendations by making the following three points:
First, these two numbers are actuarial “snapshots.” It is not appropriate to make decisions
about pension funding based on such snapshots, in the manner proposed by the CG. The
CG points to these two snapshots and argues that the funding amount should be changed
for the next seven or ten years (depending upon the FBR term approved by the AUC).
However, as an example of the folly of such an argument, the AUC and the CG are well
aware of what has happened to market conditions recently, and may draw the reasonable
inference that those recent conditions are going to have a detrimental impact on all
pension plans, including EPC’s. No one knows how long current conditions will last.
Under EPC’s proposal, EPC is prepared to assume the risks associated with pension plan
funding for the FBR term. However, this proposal is based upon inclusion in FBR base
314
315
316
317
318
319
Decision 2007-017, page 13
Transcript Volume 1, page 0118, lines 3-7
Decision 2006-002, page 36
Application 1512069, Exhibit 107, Actuarial Valuation as at December 31, 2006, page 5
Response to Undertaking Information Request, CCA.EPC-002 (h)
CG Argument, pages 27-28
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rates of the currently approved pension funding amount of $2.2 million. If this amount is
altered, the risk to EPC changes, with the result that EPC’s proposal to assume the risk
associated with pension plan should also be reviewed.
The second point is that the reduction to which the CG points is really only an apparent
reduction. As EPC explained in its response to CCA.EPC-002(h), and as the 2006
actuarial evaluation 320 shows, funding obligations established by an actuarial valuation
(including solvency deficiency payment) continue through the amortization period and
are recognized by the next valuation as an on-going expense. While the solvency position
of the plan appeared to improve from $34.1 million to $21.5 million, on-going payments
from prior valuations are actually insufficient to cover the current deficiency, which
indicates that an additional deficiency has arisen since the December 31, 2004 actuarial
valuation was filed. The amount of this additional deficiency is $6.345 million. 321 This
additional deficiency will require an additional series of payments to be made, as shown
in the December 31, 2006 actuarial valuation. 322
The third point is that customers have not funded all of the solvency deficiency
retirement payments made since 2005. EPC is required by law to adopt a payment
scheme that is forecast to retire solvency deficiencies over a period of no longer than 5
years. However, in its 2005- 2006 DT application, EPC proposed, for ratemaking
purposes, to amortize the solvency deficiency over ten years, rather than the five years
required by law. This was approved by the EUB, 323 and provided a significant benefit to
customers, who paid less through rates than they would have if EPC had applied to
synchronize its ratemaking amortization period with the amortization period that EPC
actually follows, as required by pension legislation. 324
393. CG further recommended that the Commission direct EPC to reflect, in the pension
deferral account, an adjustment that reflects the movement of cash in and out of the deferral
account to ensure the benefits from cost reductions in future years accrue to customers.
394. EPC replied that the FBR financial model in the Application shows an adjustment that
reflects the movement of cash in and out of the deferral account should the Commission reject
EPC’s proposal for accrual accounting treatment.
16.5.1
Commission Findings
395. The Commission considers that EPC has not provided sufficient evidence to demonstrate
that a long term FBR plan requires an accrual treatment for pension costs. The Commission
agrees with CG’s submission regarding consistency among utilities. The Commission continues
to share the views of the Board cited above. As such, the Commission rejects EPC’s proposal to
change the accounting treatment from a cash basis to an accrual basis.
396. The Commission notes that, in Decision 2006-002, EPC was allowed to collect $2.2
million per year for ten years to eliminate a solvency deficiency which resulted in going-in rates
being $2.2 million greater than if the solvency deficiency had not been allowed. The
Commission does not agree with CG that the previously approved $2.2 million 325 per year
320
321
322
323
324
325
Application 1512069, Exhibit 107
Application 1512069, Exhibit 107, page 10, third bullet
Application 1512069, Exhibit 107, page 10, third bullet
Decision 2006-002, pages 35-36
EPC Reply Argument, pages 7-8
Approved in Decision 2006-002, pages 35-36
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payment to recover the solvency deficiency should be reduced. While CG pointed out that the
solvency deficit has been reduced from $34.1 million in 2004 to $21.5 million as at
December 31, 2006, the Commission agrees with EPC’s statement that “the AUC and CG are
well aware of what has happened to market conditions recently, and may draw the reasonable
inference that those recent conditions are going to have a detrimental impact on all pension
plans, including EPC’s.” 326 The Commission rejects CG’s proposal for a pension deferral
account because EPC bears the risks associated with pension plan funding under the FBR plan.
16.6
Previous Board Directives
397. EPC provided responses to EUB directives in the Application. 327 The Commission notes
that parties did not comment on EPC’s responses to these Board directions in either Argument or
Reply Argument. After completing a review of EPC’s responses to these directions, the
Commission is satisfied and finds that EPC has satisfactorily complied with the outstanding
directions other than with respect to certain issues arising in the directions and responses that are
included in the following sections.
Decision 2006-002, Direction 25 – Overhead Capitalization
However, the Board directs EPC, in its next GTA, to provide greater detail on the
calculation of the capitalized overhead rate. The Board considers that information similar
to that presented in Exhibits 174, 278 and 314 of this proceeding would be beneficial to
parties in understanding how the capitalized amounts are derived. The Board further
directs EPC to clearly set out the components of shared services and other OM&A
expenses that are considered to be subject to administrative overhead capitalization
including reasons why the capital component of these accounts cannot be determined by
direct assignment.
398.
EPC filed the information in to BR.EPC-014 b) Attachment A 328 .
399. EPC, in response to a Board information request, confirmed that it was proposing to use a
capitalization rate of 19 percent. However, in BR.EPC-014 b) Attachment A, EPC submitted
… In view of the foregoing, EPC has decided, for continuity purposes, that the 19%
currently in use for the years 2000 to 2007, will be continued for both Distribution and
Transmission for 2008.
Commission Findings
400. The Commission approves EPC’s use of a 19 percent capitalization rate for each year of
the FBR plan.
Decision 2006-002, Direction 34 – Depreciation Study Adjustments
With respect to Finding #2, the Board concludes that notwithstanding that the GF
[Gannet Fleming] ELG [Equal Life Group] Method has loaded a full-year’s depreciation
accrual on the 2003 vintage as of December 31, 2003, the GF ELG Method has properly
credited the accumulated depreciation with only one-half of the 2003 vintage accruals.
However, the Board has observed a second order problem in that the GF ELG Method
326
327
328
EPC Reply Argument, page 7
Application, Appendix 1, dated December 10,2007
Application No. 1512069, Exhibit 084, dated August 10, 2007
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determines for each vintage the vintage theoretical accumulated depreciation factor
as of December 31, 2003 by multiplying each vintage accrual rate by the age of that
vintage as of December 31, 2003. The Board notes that these vintage accrual factors
are applied to actual December 31, 2003 account plant balances to arrive at the
composite year-end theoretical accumulated factor for each account. The Board
considers that this method ignores the retirements that were predicted to occur for
each ELG within the study year. For example the accumulated accrued factor for the
2003 vintage as of December 31, 2003 should be the 2003 vintage rate times the age less
the first equal life group which is predicted to be retired as of December 31, 2003. This
would result in an accumulated accrual factor of 0 for the first equal life group of 13.2%
assumed to retire on December 31, 2003. The Board is satisfied that the GF ELG Method
does not appear to introduce any material errors respecting this finding. However, the
Board directs EPC to correct these minor distortions in the next Depreciation Study.
[Emphasis added]
401. In BR.EPC-025 d), EPC was directed to use the “theoretically correct ELG depreciation
rate” to calculate the composite 2007 distribution and transmission rates resulting from the use of
the Gannet Fleming Equal Life Group Method and the Board Equal Life Group Method. 329 EPC
filed a worksheet for each of the 10 distribution plant accounts, 16 transmission plant accounts,
and 3 general plant accounts for which an Iowa curve was used to calculate depreciation
expense. 330 The total depreciation expense calculated using the GF ELG method was
$18,786,692 while the depreciation expense calculated using the Board ELG method was
$18,444,406.
Commission Findings
402. The Commission approves EPC’s proposal to use the Gannet Fleming Equal Life Group
method. The Commission finds that the resulting difference in depreciation rates is insignificant.
Decision 2006-002, Direction 35 – Implement the One-Half Year Convention
The Board was not provided any of the back-up data for the calculation of the
depreciation expense for General Accounts and is therefore unable to determine if the
half year convention has been violated. The Board will, for the purposes of this Decision,
accept EPC’s calculation of the General Accounts for 2005 and 2006. However, the
Board directs EPC to implement the one-half year convention for the most recent vintage
at the time of the next GTA.
403. In response to this Board Direction EPC stated that Gannet Fleming reports that the
calculations made in accordance with the traditional Gannet Fleming method result in the
application of the mid-year convention. However, the modifications as developed by the Board
in Decision 2006-002 were also applied to comply with this directive. EPC submitted that the
use of the depreciation rate calculated in accordance with the Board’s directive results in the
application of only a one-quarter year convention.
Commission Findings
404. The Commission has reviewed EPC’s response and accepts that the method used by EPC
results in the application of the mid-year convention.
329
330
The average of the past 5 years was used as a proxy for the 2007 forecast additions in absence of this data on
the record
Exhibit 140, BR.EPC-024 d) Attachment, dated September 14, 2007
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Decision 2006-002, Direction 37 – Net Salvage
The Board considers that EPC’s decision not to roll over cost of removal places an
additional burden on separating and recording the cost of removal by vintage. The Board
directs EPC to track the additional costs incurred in data requirements to track the net
salvage by vintage within each account.
405. EPC submitted that, if the Commission were to mandate that the vintage year be tracked
within the accounting system for net salvage transactions, a significant re-configuration (which is
non-standard) of the accounting systems would be required at a significant cost. Therefore, EPC
did not track the additional costs incurred in data requirements to track the net salvage by vintage
within each account.
Commission Findings
406. The Commission accepts EPC’s explanation that there would be significant costs
associated with altering EPC’s accounting system to allow EPC to track net salvage by vintage.
Therefore, the Commission will not require EPC to comply with this Direction.
Decision 2006-130, Direction 1 – Attribution of Disallowed AFUDC to Specific Property Accounts
(A fall out of Decision 2006-079, Direction 16)
While the Board has approved EPC’s proposed allocation of all of the AFUDC
adjustment to account 4575, with the increase in the AFUDC disallowance as described
above in section 3.2, the Board directs EPC to ensure that the full $452,016.35 amount of
the AFUDC adjustment is removed from EPC’s account 4575 opening balance at the
time EPC files its next TFOT Application.
407. EPC indicated in its response to this Direction 331 that the $452,016.35 adjustment is
composed of two components:
1) $317,499.37 identified in EUB Decision 2006-079
2) $134,516.98 identified in EUB Decision 2006-130
408. EPC stated that it had recorded the initial adjustment of $317,499.37 in 2006 and as such,
the adjustment was included in the 2006 actuals as a reduction to account 4575. However, due to
timing issues, EPC was unable to record the subsequent adjustment of $134,516.98 in its 2006
records. Instead, EPC made the adjustment to the 2007 application to reflect this.
Commission Findings
409. The Commission, at this time, is unable to confirm that the above direction has been
complied with. EPC is directed to clarify this issue in its compliance filing.
Decision 2007-022, Direction 1 – Feeder Loading Study
Nevertheless, the Board is concerned that EPC may not be adequately loading its feeders
and therefore does see merit in studying this matter further. However, the Board
considers this to be primarily a Phase I revenue requirement matter since it is unclear
331
Application, Appendix 1
84 • AUC Decision 2009-035 (March 25, 2009)
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whether EPC is making an efficient use of the assets currently in place. At this time, the
Board is uncertain of the timing and costs of completing a feeder loading study. The
Board therefore directs EPC to:
•
To the extent it is able to do so, include in the Phase I component of its next GTA
an analysis of the time, steps involved, feasibility of, and anticipated costs and benefits
involved in completing a feeder loading study, and to either incorporate such data into its
forecast test year(s) or explain why it was unable to incorporate such data into its forecast
test year(s); or
•
To the extent EPC is unable to complete the analysis directed above, to instead
include in the Phase I component of its next GTA the steps involved, related expense and
anticipated costs, benefits and timing required to complete such an analysis.
410. EPC indicated in its response to this Direction, that since it was only recently issued 332
there has not been sufficient time to prepare a feeder loading study and incorporate the results
into forecast years.
411. However, EPC did provide an analysis of the steps involved, related expense and
anticipated costs in completing a feeder loading study. The steps would include engaging an
independent consultant to assess, review and validate EPC’s planning and operating philosophies
and practices as they pertain to the feeder loading study. The study would include:
•
•
•
•
a survey of other urban utilities;
document urban industry practices;
feeder loading practices for EPC and comparators; and
the rationale for the current peak loading levels of all existing EPC Network and NonNetwork feeders.
412. EPC expected the study would take approximately six months to complete and the costs
are expected to exceed $400,000 plus or minus 20 percent. The study would be expected to
provide interested parties a more detailed understanding of the loading of EPC’s feeder system
and assistance in the examination of cost causation of primary feeders.
Commission Findings
413. The Commission considers that EPC has complied with this Direction in terms of setting
out an analysis of the time and anticipated costs and benefits involved in completing a feeder
loading study. However the Commission considers that the cost of engaging an independent
consultant to complete the feeder loading study is not justifiable and will not require EPC to
complete this study.
Remaining Directions from Decision 2007-022, Directions 2 through 23
414. In the Application, EPC indicated that the remaining directions would be addressed in
EPC’s 2008 Phase II Application.
Commission Findings
415. The Commission agrees with EPC’s proposal to address the remaining directions in its
2008 Phase II Application.
332
Decision 2007-022, dated March 20, 2007.
AUC Decision 2009-035 (March 25, 2009) • 85
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16.7
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Generic Cost of Capital
416. The 2006 generic cost of capital return on equity is embedded in the adjusted 2006 DAS
rates and the 2006 transmission revenue requirement. Because the proposed FBR formula does
not include an ROE adjustment, to the extent necessary, EPC has requested an exemption from
section 4 of Decision 2004-052. 333
417. The Commission acknowledges that the Commission approved generic ROE will not be
used in resetting distribution or transmission rates under the FBR plan.
418.
In Section 3.6.1 of the Application EPC stated:
the target ROE for ESM purposes for any year is proposed to be the generic ROE
established by the AUC for that year.
419. The Commission agrees with EPC’s proposed use of ROE in the earnings sharing
mechanism calculation.
17
FILING REQUIREMENTS
420. EPC has proposed annual financial reporting, earnings sharing mechanism calculations
and performance penalty calculations as part of the review and approval process for the FBR.
EPC stated it will continue to prepare and file annual reports for submission to the AUC during
the FBR term, in accordance with AUC Rule 005, which includes information regarding EPC’s
operating performance, financial results and customer rates.
421. At the present time, the ENMAX group of companies does not prepare segmented
audited financial statements. The financial statements of ENMAX Corporation are audited, but
the financial statements of EPC are not. EPC stated that it is not opposed to providing audited
financial statements at the EPC level, provided that EPC is permitted to recover the incremental
cost of providing such statements through its rates. EPC submitted, it is not clear that the
benefits of providing audited financial statements at the EPC level outweighs the additional cost
of doing so.
422. EPC proposed to adjust rates on July 1 of each year during the FBR term, by which time
EPC will have the previous year’s financial and technical information required to calculate rates
using the FBR formula.
423. EPC proposed that the Commission’s reviews and approvals specific to FBR will include
the following: 334
•
•
333
334
review and approval of disputed costs or benefits associated with extrinsic factors and
flow through costs;
review and approval of new fees;
Decision 2004-052 – Generic Cost of Capital – AltaGas Utilities Inc., AltaLink Management Ltd., ATCO
Electric Ltd. (Distribution), ATCO Electric Ltd. (Transmission), ATCO Gas, ATCO Pipelines, ENMAX Power
Corporation (Distribution), EPCOR Distribution Inc., EPCOR Transmission Inc., FortisAlberta (formerly
Aquila Networks), NOVA Gas Transmission Ltd. (Application 1271597) (Released: July 2, 2004)
EPC Argument, page 41
86 • AUC Decision 2009-035 (March 25, 2009)
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•
•
•
•
•
•
•
•
ENMAX Power Corporation
review and approval of the Annual Rates and Technical Report to be filed annually on or
before April 15;
approval of deferral and rider account reconciliation, if required;
receipt of application for and ruling on changes to DAS and SAS rates as a result of the
proposed mid-term cost of service study, if any;
approval of changes to the distribution terms and conditions or transmission terms and
conditions, if any;
approval of the make-up of the FBR Customer Committees;
approval of the budget and cost claims for members of the FBR Customer
Committees; and
resolve disputes between the Customer Committees and EPC.
424. The annual timeline for reporting and administrative items is proposed to commence, for
the first year of the FBR plan, after a decision is issued by the AUC and is set out at Table
6.3.1A of the Application.
425. No parties commented on the content of the annual filing requirements, with the
exception of the proposal that audited statements be provided, as discussed elsewhere in this
Decision.
17.1
Commission Findings
426. The Commission has approved numerous changes to the FBR plan proposed by EPC. In
light of these changes, the Commission directs EPC to file a compliance filing on or before
April 15, 2009, setting out the rates and tariffs to be implemented effective July 1, 2009. The
compliance filing will include the following items:
•
Revised Going-in rate calculation
•
Formulas for each of distribution and transmission for each of 2007, 2008 and 2009 as
applicable including the values for:
•
I factor,
•
G factor to be applied to transmission,
•
E factor if any,
•
S factor if any,
•
Z factor if any,
•
Flow-through costs if any,
•
Final distribution and transmission tariff rate schedules effective July 1, 2009.
427. The Commission directs EPC to set out its proposal for annual filings during the term of
the FBR plan in its compliance filing.
AUC Decision 2009-035 (March 25, 2009) • 87
2007-2016 Formula Based Ratemaking
18
428.
ENMAX Power Corporation
ORDER
IT IS HEREBY ORDERED THAT:
ENMAX Power Corporation’s application for Commission approval of its Formula Based
Ratemaking plan for the derivation of its distribution access service tariff and transmission tariff
is granted subject to the modifications, directions and further required approvals of the
Commission set out in this Decision.
Dated in Calgary, Alberta on March 25, 2009.
ALBERTA UTILITIES COMMISSION
(original signed by)
Willie Grieve
Chair
(original signed by)
Carolyn Dahl Rees
Commissioner
(original signed by)
Mark Kolesar
Acting Commissioner
88 • AUC Decision 2009-035 (March 25, 2009)
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APPENDIX 1 – PROCEEDING PARTICIPANTS
(Return to text)
Name of Organization (Abbreviation)
Counsel or Representative (APPLICANTS)
ENMAX Power Corporation (EPC)
D. Nering
ATCO Electric Ltd. (AE)
L. Keough
J. Beckett
AltaLink Management Ltd.
R. Lavergne
The City of Calgary (Calgary)
D. Evanchuk
M. Rowe
Consumers Coalition of Alberta (CCA)
J. Wachowich
A. Merani
D410 Group
L. Manning
D. Hildebrand
C. Wiggins
EPCOR Distribution & Transmission Inc. (EDTI)
P. Wong
FortisAlberta Inc.
K. Angel
Industrial Power Consumers and Cogenerators Association (IPCAA)
C. Terry
R. Mikkelsen
City of Lethbridge
O. Lenz
M. Turner
Public Institutional Consumers of Alberta (PICA)
N. McKenzie
R. Retnanandan
W. Marcus
The City of Red Deer
L. Gan
M. Turner
AUC Decision 2009-035 (March 25, 2009) • 89
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Name of Organization (Abbreviation)
Counsel or Representative (APPLICANTS)
Office of the Utilities Consumer Advocate (UCA)
R. McCreary
R. Henderson
R. Bell
G. Hill
B. Shymanski
H. Vander Veen
Consumer Group – Representing
Consumers’ Coalition of Alberta
Public Institutional Consumers of Alberta
Red Deer / Lethbridge Group – Representing
The City of Red Deer
City of Lethbridge
Alberta Utilities Commission
Commission Panel
W. Grieve, Chair
C. Dahl Rees, Commissioner
M. Kolesar, Acting Commissioner
Commission Staff
C. Wall (Commission Counsel)
B. McNulty (Commission Counsel)
J. Thygesen
K. Van Kosh
D. Ploof
B. Clarke
90 • AUC Decision 2009-035 (March 25, 2009)
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APPENDIX 2 – ABBREVIATIONS
Abbreviation
Name in Full
AESO
AFUDC
AHE
AIIFR
AMI
ATCO
AUC
Board or EUB
CIAC
CPI
DAS
DLM
EDC
EDI
ELG
ENMAX or EPC
EPC or ENMAX
ESM
EUB or Board
EUCPI
FBR
GDP
GTA
IPD
IPI
IPPI
IT
KPI
O&M
OM&A
PBR
ROE
SAIDI
Alberta Electric System Operator
Allowance for Funds Used During Construction
Average Hourly Earnings
All Injury/Illness Frequency Rate
Advanced Metering Infrastructure
ATCO Electric Ltd.
Alberta Utilities Commission
Alberta Energy and Utilities Board
Contributions in Aid of Construction
Consumer Price Index
Distribution Access Service
Direct Life Method
Electric Distribution Companies
EPCOR Distribution Inc.
Equal Life Group
ENMAX Power Corporation
ENMAX Power Corporation
Earnings Sharing Mechanism
Alberta Energy and Utilities Board
Electric Utility Construction Price Index
Formula-Based Ratemaking
Gross Domestic Product
General Tariff Application
Input Price Differential
Input Price Index
Industrial Producer Price Index
Information Technology
Key Performance Indicator
Operating and Maintenance
Operating, Maintenance and Administrative
Performance-Based Regulation
Return on Equity
System Average Interruption Duration Index
SAIFI
System Average Interruption Frequency Index
AUC Decision 2009-035 (March 25, 2009) • 91
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Abbreviation
Name in Full
SRP
Supplemental Retirement Plan
STIP
Study
Short Term Incentive Payment
Study prepared by Larry Kennedy of Gannett Fleming Inc.
T&C
TAC
TFO
TFP
USA/MFR
Terms and Conditions
Transmission Access Charge
Transmission Facility Owner
Total Factor Productivity
Uniform System of Accounts / Minimum Filing Requirements
92 • AUC Decision 2009-035 (March 25, 2009)