RÉGIE DE L’ÉNERGIE
HYDRO-QUÉBEC TRANSÉNERGIE
FOR THE REQUEST RELATIVE TO
THE MODIFICATION OF HYDRO-QUÉBEC’S
TRANSMISSION SERVICE CONDITIONS
FILE R-3549-2004
PHASE 2
EVIDENCE OF
WILLIAM HARPER
ECONALYSIS CONSULTING SERVICES
ON BEHALF OF:
OPTION CONSOMMATEURS
OCTOBER 18, 2005
TABLE OF CONTENTS
1
2
3
INTRODUCTION .......................................................................................................................1
PURPOSE OF EVIDENCE......................................................................................................2
HQT’S CURRENT TRANSMISSION TARIFFS ..................................................................4
3.1
Basis for the Current Transmission Tariffs ..................................................................4
3.2
Use of Transmission Services Since 2001..................................................................6
3.2.1
Native Load Service .................................................................................................7
3.2.2
Network Integration Service....................................................................................7
3.2.3
Long-term Firm Point to Point Service .................................................................7
3.2.4
Short Term Point to Point Service.........................................................................8
3.2.5
Use of Interconnections...........................................................................................9
3.2.6
Ancillary Services....................................................................................................11
4 COST ALLOCATION METHODOLOGY ............................................................................12
4.1
Background.......................................................................................................................12
4.2
Definition of Cost Functions..........................................................................................13
4.2.1
Generation Connection..........................................................................................14
4.2.2
Network .....................................................................................................................15
4.2.3
Customer Connection ............................................................................................16
4.2.4
Interconnections......................................................................................................17
4.2.5
Support and Control Centre Costs......................................................................18
4.3
Cost Functionalization....................................................................................................19
4.3.1
Functionalization of Rate Base ............................................................................19
4.3.2
Functionalization of Cost of Service ...................................................................25
4.4
Classification of Costs....................................................................................................32
4.5
Allocation of Functionalized Costs to Services.........................................................34
4.5.1
Services Provided ...................................................................................................34
4.5.2
Allocation Factors....................................................................................................37
4.6
Impact of Comments Regarding HQT’s Cost Allocation Methodology ...............46
5 HQT’S PROPOSED TRANSMISSION SERVICE PRICING METHODOLOGY .......48
5.1
Overview............................................................................................................................48
5.2
Treatment of Short-Term PTP Revenues ..................................................................49
5.3
Allocation of Revenue Requirement between Native Load/Network Integration
Service and Long-term PTP Service .......................................................................................51
5.4
Determination of Long-term Point to Point Service Rates .....................................53
5.5
Determination of Native Load/Network Integration Service Rates.......................53
5.6
Determination of Short-term Point to Point Service Rates.....................................58
5.7
Consistency with Cost of Service Allocation Results..............................................61
5.8
Ancillary Service Rates ..................................................................................................63
6 CONCLUSIONS.......................................................................................................................68
6.1
HQT’s Cost Allocation Methodology ...........................................................................68
6.2
HQT’s Derivation of Transmission Service Rates....................................................71
Appendix:
CV for ECS Consultant
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
1
INTRODUCTION
2
3
On September 30th, 2004 Hydro-Québec TransÉnergie (HQT) filed an
4
Application with the Régie de l’énergie (the “Régie”) for approval of a revised
5
revenue requirement and transmission tariffs effective January 1st, 2005. For
6
purposes of review, HQT separated the Application into two phases. Phase 1,
7
which was the subject of the September 2004 Application, dealt with the
8
determination HQT’s rate base and revenue requirement for 2005. Following an
9
oral hearing, the Régie issued decisions D-2005-50 and D-2005-63 which
10
approved a rate base of $14,657.1 M and a revenue requirement of $2,581.0 M
11
for HQT for 2005. On June 22, 2005, HQT filed its Application for Phase 2 which
12
dealt with the allocation of HQT’s approved revenue requirement to services; the
13
fixing of the amount to be billed to Hydro-Québec Distribution (HQD) for
14
transmission services and the setting of rates for point to point transmission
15
service and other ancillary services effective January 1st, 2005.
16
17
HQT’s current transmission rates have been in effect since January 2001 and are
18
the result of the Régie’s first (and only) proceeding and decision (R-3401-1998
19
and D-2002-95) regarding HQT’s transmission tariffs.
20
1
Evidence of
William Harper
1
2
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
PURPOSE OF EVIDENCE
2
3
After reviewing HQD’s Application and the Procedural Order1 issued by the
4
Régie, Option Consommateurs (OC) retained Econalysis Consulting Services
5
(ECS), a Canadian consulting firm offering regulatory services to clients in the
6
electricity and natural gas sectors to provide evidence that would assist OC and
7
the Régie in assessing HQT’s proposals with respect to transmission cost
8
allocation and rate design.
9
10
The Evidence was prepared by Bill Harper who, prior to joining ECS in July 2000,
11
worked for over 25 years in the energy sector in Ontario, first with the Ontario
12
Ministry of Energy and then, with Ontario Hydro and its successor company
13
Hydro One. Since joining ECS, he has assisted various clients participating in
14
regulatory proceedings on issues related to electricity and natural gas utility
15
revenue requirements, cost allocation/rate design and supply planning. Mr.
16
Harper has served as an expert witness in public hearings before the Manitoba
17
Public Utilities Board, the Manitoba Clean Environment Commission, the Régie,
18
the Ontario Energy Board, the Ontario Environmental Assessment Board and a
19
Select Committee of the Ontario Legislature on matters dealing with electricity
20
regulation, rates and supply planning. His most recent experience with cost
21
allocation and rate design matters includes:
•
22
The preparation of evidence and appearance as an expert witness on
23
behalf of OC in both Phase 1 and Phase 2 of Régie proceeding (R-3492-
24
2002) dealing with HQD’s 2002 and 2003 cost allocation proposals.
•
25
The preparation of evidence and appearance as an expert witness on
26
behalf of OC in the Régie proceeding (R-3541-2004) dealing with HQD’s
27
2004 rate design proposals.
•
28
The preparation of evidence and appearance as an expert witness before
the Manitoba Public Utilities Board with respect to its review of proposals
29
1
D-2005-123
2
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
filed by Manitoba Hydro in both 2002 and 2004 regarding cost allocation
2
and rate design.
3
•
Providing expert advice and support to clients in British Columbia
4
participating in the BCUC proceedings dealing with BCTC’s 2004 Open
5
Access Transmission Tariff (OATT) Application.
6
•
Member of the OEB’s 2005 Technical Advisory Team regarding cost
allocation for Ontario electricity distributors.
7
8
9
A full copy of Mr. Harper’s CV is attached in Appendix A.
10
11
The evidence generally follows the structure of HQT’s Application and, after
12
providing a brief overview of HQT’s current transmission rates and past usage,
13
reviews:
14
•
revenue requirement between services,
15
16
•
HQT’s approach to determining point to point (PTP) transmission service
rates and setting of proposed rates for various forms of PTP service,
17
18
HQT’s proposed cost allocation methodology for allocating the approved
•
HQT’s methodology for establishing the revenue to be recovered annually
19
from HQD (and other potential Native Load/Network Integration service
20
customers),
21
22
•
HQT’s proposed rates for Ancillary Services and the modifications to their
Tariffs and Conditions.
23
Applicable comments are noted throughout the text and summarized in
24
concluding section.
25
3
Evidence of
William Harper
1
3
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
HQT’S CURRENT TRANSMISSION TARIFFS
2
3.1
3
Basis for the Current Transmission Tariffs
4
5
In 1996, the Québec Government approved2 the principle of open access on
6
Hydro-Québec’s transmission system and, subsequently, in 1997 introduced the
7
functional separation of Hydro-Québec’s transmission activities from its
8
distribution and generation activities with the creation of Hydro-Québec
9
TransÉnergie (HQT). Soon thereafter, An Act respecting the Régie de l’énergie
10
came into effect requiring HQT to obtain approval from the Régie for its
11
transmission tariffs.
12
13
HQT’s current transmission tariffs have been in place since January 1, 2001 and
14
are the result of an Application by HQT in 1998 (R-3401-1998) and a Régie
15
decision issued in May 2002 (D-2002-95). This Application was the first
16
transmission rate Application to be considered by the Régie. Prior to January 1,
17
2001, HQT’s rates had been established via an Order in Council3.
18
19
The rates approved by the Régie in 2002 followed the form and structure of
20
FERC’s direction regarding Open Access Tariffs4. To this end, HQT’s open
21
access tariff includes:
•
22
Rates for Native Load service, Network Integration service and long-term
firm PTP service that are established on a comparable basis.
23
•
24
Rates for Native Load service and individual Network Integration service
customers based on annual load ratios.
25
2
Hydro-Québec Byl aw number 652 respecting the conditions and rates for wholesale electric transmission
service.
3
Order in Council 276-97, March 5, 1997 (Approved Hydro-Québec Bylaw 659)
4
HQT-4, Document 3, page 13. See also FERC Order 888-A, page 256 and FERC’s Pricing Policy for
Transmission Service found at 69 FERC 61,086
4
Evidence of
William Harper
•
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Rates for short term service (firm and non-firm) that are derived from the
annual long-term firm PTP service rates.
2
•
3
Ancillary Service rates for the various “supporting” services required by
4
PTP users of transmission service and provided by either transmission or
5
generation facilities.
6
7
The rates are also compliant with the Act regarding the need for uniform rates
8
through out the territory5 served and direction from the Régie regarding:
•
9
The development of rates based on average costs for a prospective test
year 6,
10
•
11
The use of 1-CP (as an interim measure) to allocate the transmission
revenue requirement and determine long-term firm PTP rates7,
12
13
•
The use of the long-term PTP rates to establish short term PTP rates8,
14
•
The basis for distinguishing between firm and non-firm short term PTP
service rates9.
15
16
Finally, the Régie determined that a more detailed cost allocation study was
17
required before it could conclude that HQT’s approach to determining the current
18
transmission rates for Native Load service, Network Integration service and long-
19
term firm PTP was appropriate from a longer term perspective.10
5
D-2002-95, page 244 and Section 49, paragraph 1, subparagraph 11 of the Act.
D-2005-95, page 244
7
D-2005-95, page 244
8
D-2005-95, page 265
9
D-2005-95, page 265
10
D-2002-95, pages 210-215
6
5
Evidence of
William Harper
1
3.2
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Use of Transmission Services Since 2001
2
3
Table 1 below sets out the extent to which the three transmission services have
4
used HQT’s system since 2001 and the projected use for 2005.
5
TABLE 1
USE OF HQT'S TRANSMISSION SERVICES
Service Category
2001
2002
2003
2004
2005
29346
32211
31171
32244
34487
33735
35514
34295
n/a
34060
0
0
0
0
Long Term Firm PTP (MW Reserved)
3982
3306
1878
405
405
Short-Term PTP
- Monthly Firm PTP (MW Reserved)
- Monthly Non-Firm PTP
- Weekly Firm PTP (MW Reserved)
- Weekly Non-Firm PTP
- Daily Firm PTP (MW Reserved)
- Daily Non-Firm PTP (MW Reserved)
- Hourly Non-Firm PTP (TWh)
2080
0
480
0
0
0
0.1
925
0
1057
0
913
74
1.6
402
0
132
0
153
0
2.7
430
0
0
0
5227
0
7
0
0
0
0
5882
0
9.3
Native Load Service
- Maximum Annual Peak (MWs)
- Normalized Coincident Peak (MWs)
Network Integration Service
0
Sources:
a) The 2001-2005 data is based on HQT-6, Document 1, page 12, Table 8.1
6
6
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
3.2.1 Native Load Service
3
HQD is HQT’s only Native Load service customer11. While providing for a
4
network integration type of service, the Tariffs and Conditions for Native Load
5
service recognize the unique arrangements between HQD and HQP regarding
6
the provision of Heritage Pool energy and Ancillary Services12. Native Load
7
service provides HQD with the transmission services required to13:
8
•
Obtain delivery of Heritage Pool Energy from HQP,
9
•
Obtain delivery of any imports it has contracted for (or will contract for) to
meet its domestic customers’ requirements, and
10
•
11
Obtain delivery of generation purchased from 3rd parties in Québec to
meet its domestic customers’ requirements.
12
13
Native Load service also covers the transmission service required by HQP in the
14
event that it must purchase imports to meet its Heritage Pool obligations. As a
15
result, HQD does not contract for short term PTP service14.
16
17
18
3.2.2 Network Integration Service
19
HQT currently has no Network Integration service customers15.
20
21
3.2.3 Long-term Firm Point to Point Service
22
Since 2002, HQP has been HQT’s only long-term firm PTP service customer16.
23
For 2005, HQP has four long-term PTP service contracts with HQT. Two of the
24
contracts (totaling 100 MW) are for points of receipt in Quebec and delivery to an
25
interconnection point with another network in Quebec (i.e., Cedar Rapids
26
Limited). The other two are for delivery from points inside Quebec to the New
11
HQT-6, Document 7, Question 32 c)
D-2002-95, pages 336-337
13
HQT-6, Document 7, Question 32 d) & f)
14
HQT-6, Document 7, Questions 2 b); 21 b): 32 d) & e)
15
HQT-2, Document 1, page 10
16
HQT-6, Document 7, Question 13 a)
12
7
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
England or New York systems17. Only one of the four contracts (45 MW with
2
Cedar Rapids) extends beyond the end of 200518.
3
4
5
3.2.4 Short Term Point to Point Service
6
While there are a number of customers that have contracted with HQT for short
7
term PTP transmission service, HQP accounts for most of the contracted MW
8
and resulting revenues19. Furthermore, in the case of HQP, the contracts for
9
short-term service would all be for deliveries to either customers/systems in
10
Quebec, other than HQD, or to neighbouring systems since use of transmission
11
for delivery to HQD is covered by Native Load service20.
12
13
Over the years 2001 through 2003, revenues from parties other than HQP
14
accounted for between 17.6% to and 26.4% of total short-term PTP revenues 21.
15
However, in 2004, HQP accounted for 93.9% of these revenues and, for 2005,
16
the percentage is projected to be even higher22. Indeed, for 2005, the only
17
projected use of HQT’s transmission services by parties other than HQP is 0.4
18
TWh of hourly service and what appears to be a minimal requirement for daily
19
service. In contrast, HQP is expected to require short-term PTP service to move
20
roughly 9 TWh23 in 2005.
17
HQT-6, Document 7, Question 13 b)
HQT-6, Document 7, Question 19 a). Note: The 45 MW contract figure excludes losses.
19
HQT-6, Document 7, Question s 16 b) and 18 b)
20
HQT-6, Document 7, Questions 21 a)-c) and 24 b)
21
HQT-6, Document 7, Question 16 b)
22
Based on HQT-2, Document 2, page 10, Table 5 and HQT-4, Document 1, page 21, Table 6
23
HQT-2, Doc 2, page 10, Table 5 and HQT-6, Document 1, page 12, Question 8.1
18
8
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
3.2.5 Use of Interconnections
3
In its evidence, HQT uses the term “interconnections” to refer to both
4
connections with networks inside Quebec (such as CRT and Brascan), as well as
5
connections with neighbouring networks in other provinces and the US24.
6
7
According to HQT’s evidence25, from 2001 to 2004, most of the deliveries over
8
these interconnections were for HQP transactions and all of the receipts over the
9
interconnections were for HQP transactions.
10
11
Comment
12
13
This information is somewhat contradictory to that published26 by the National
14
Energy Board (NEB) which indicates that from 2001 to 2004, parties other than
15
HQP have used HQT’s international inter-ties for both imports and exports.
16
Table 2 summarizes the imports and exports reported by the NEB for the same
17
period – broken down between those by HQP and other parties. The response
18
to OC Information Request 17.a) is also at odds with HQT’s evidence27
19
elsewhere that there is third party use of transmission service for the purpose of
20
wheeling through power through HQT from one interconnection point to another
21
(which would result in transactions where the interconnections were a point of
22
receipt).
24
HQT-6, Document 7, Question 13 b) and HQT-6, Document 1, pages 39- 40, Question 16.1
HQT-6, Document 7, Question 17 a)
26
National Energy Board, Electricity Exports and Imports
(http://www.neb.gc.ca/Statistics/ElectricityExportsImports/index_e.htm#Year2004)
27
HQT-6, Document 8, page 21, Question 14.1; HQT-6, Document 7, page 27, Question 21.a); HQT-6,
Document 7, page 30, Question 23.a) and HQT-2, Document 5, page 13, Table 1
25
9
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
TABLE 2
Quebec Exports and Imports Reported by the NEB
Exports
HQP
Others
Total
HQP
2001
2002
2003
2004
13.56
13.58
7.49
7.72
1.26
1.16
1.55
1.76
14.82
14.74
10.04
9.48
3.38
2.30
3.35
3.20
Imports
Others
Total
0.07
0.25
0.58
0.26
3.45
2.55
3.92
3.46
Source: Electricity Imports and Exports (http://www.neb.gc.ca/Statistics/ElectricityExportsImports/index_e.htm#Year2004)
Note:
1) Includes firm and interruptible exports
2) Values reported are in TWh
1
2
3
Regardless of the inconsistencies noted above, from a comparison of Table 2
4
and the information provided by HQT, one can conclude that:
•
5
The vast majority of the transactions involve HQT’s interconnections with
neighbouring systems in the US28,
6
•
7
The majority of the receipts and deliveries to HQT’s interconnections are
for transactions by HQP29, and
8
•
9
Exports to neighbouring systems outside of Quebec (as opposed to
10
wheeling deliveries to networks located inside Quebec or wheeling
11
through between networks located outside of Quebec30) account for most
12
of HQP’s use of short-term PTP services.
13
What remains unclear is the nature of the use of HQT’s transmission services by
14
3rd parties.
28
Compare HQT-2, Document 2, page 9, Table 4 with Table 2 above
HQT-6, Document 7, Question 17 a), Table R.17.a
30
HQT-2, Document 3, page 14
29
10
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
3.2.6 Ancillary Services
3
Of the six Ancillary Services provided for in FERC’s pro-forma Open Access
4
Transmission Tariff (OATT) 31 and offered by HQT in its 2001 approved Tariffs,
5
point to point customers are required to purchase two of them (System Control
6
and Voltage Control) from HQT. Point to point customers can also obtain the
7
other four services (Frequency Control, Energy Imbalance, Spinning Reserve
8
and Non-Spinning Reserve) from HQT or “self supply” by obtaining a comparable
9
service from other providers located in HQT’s control area. In the case of
10
System Control, the service is not billed for separately but, rather, included in the
11
transmission service rates32.
12
13
In the case of Native Load service, HQD (as the Native Load customer) is
14
responsible for providing all of the identified ancillary services with the exception
15
of System Control service which is provided by HQT33.
16
17
HQP self-supplies the Ancillary Services required to support its PTP service
18
contracts with HQT34. However, the other customers purchasing PTP
19
transmission service from HQT do not “self-supply” and, instead, purchase their
20
requirements for these four services from HQT35.
21
22
Of the six Ancillary Services, HQT only self-provides one of them (System
23
Control), the other five are provided by HQP 36. In addition, only the costs for
24
System Control are reflected in HQT’s revenue requirement. The costs for the
25
other five services are not included as they are effectively a “pass-through” from
26
HQP – based on the tariffs approved by the Régie37.
31
HQT-2, Document 1, page 11
HQT-4, Document 1, page 29
33
HQT-6, Document 7, Question 62 a)
34
HQT-6, Document 7, Question 3 a)
35
HQT-6, Document 7, Question 3 b)
36
HQT-6, Document 7, Question 35 c.1)
37
HQT-6, Document 7, Question s 35 c.1) and 64 a)
32
11
Evidence of
William Harper
1
4
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
COST ALLOCATION METHODOLOGY
2
4.1
3
Background
4
5
Typically, rates are established for regulated utilities following a three-stage
6
process in which: a) the revenue requirement is first determined; b) a cost
7
allocation study is then undertaken to apportion the revenue requirement to the
8
utility’s various service/customer classes; and c) rates are designed for each
9
service/customer class, taking into consideration the results of the cost allocation
10
study and other rate setting objectives. Cost allocation studies are used as a
11
guide in establishing both rate level and rate design by customer classes, given
12
that one of the principle considerations in setting fair and reasonable rates is that
13
the rates are cost-based. Traditionally, cost allocation studies also employ a
14
three-step process where:
•
15
The revenue requirement is functionalized according to the services the
utility provides,
16
•
17
The costs in each function are classified according to the system design or
operating characteristics that caused the costs to be incurred, and then
18
•
19
The costs in each function are allocated to the various customer classes
based on each class’ contribution to the specific cost driver selected38.
20
21
22
The determination of rates based on FERC’s pro-forma OATT does not require a
23
full cost allocation study to be carried out39. However, in its first decision
24
regarding HQT’s rates, the Régie concluded40 that such a study should be
25
undertaken. The Régie also provided a number of specific directives as to how
26
the cost allocation methodology should be structured and which HQT has
27
summarized in its current Application41.
38
D-2002-95, page 210
HQT-6, Document 9, pages 53-54, Questions 42.1 & 43.1
40
HQT-3, Document 1, pages 5-6
41
HQT-3, Document 1, pages 7-8
39
12
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
4.2
2
Definition of Cost Functions
3
4
HQT’s proposed cost allocation methodology separates the revenue requirement
5
(and rate base) into six functions42. There are four main functions (Generation
6
Connection, Network, Customer Connection and Interconnections), each of
7
which are broken down into a number of sub-functions. The two other functions
8
(Control Centre and Support) are not broken down into sub-functions. In
9
addition, the costs assigned to both the Control Centre and Support functions are
10
pro-rated over the four main functions prior to the step where costs are allocated
11
to services.
12
13
Comments
14
15
The functional groupings proposed by HQT generally utilize the same asset
16
categories as presented43 in R-3401-98 and deemed by the Régie, in its
17
subsequent decision, to be a reasonable starting point. The most notable
18
exception is the separation of Churchill Falls interconnection costs which is a
19
direct response to Régie’s finding in D-2002-9544.
20
21
Also, as noted by HQT, this functionalization is similar to that suggested by
22
NARUC for transmission facilities45. It is also similar to the functionalization of
23
transmission assets as proposed by both Nova Scotia Power46 and New
24
Brunswick Power47 in their recent applications for approval of open access
25
transmission tariffs and subsequently approved by their respective regulators.
42
HQT-3, Document 1, pages 13-14 and page 17
R-3401-98, HQT-10, Document 1, page 3
44
D-2002-95, page 212
45
HQT-3, Document 1, page 11
46
Application by NSPI for Approval of an Open Access Transmission Tariff, May 12, 2004
47
NB Power Transmission Tariff Design, June 2002
43
13
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
4.2.1 Generation Connection
3
The Generation Connection function includes the step-up sub-stations used to
4
convert power to higher voltages for purposes of transmission along with
5
transmission lines used to connect a generation plant to the transmission
6
network. As a result, it consists of two sub-functions: a) Step-up Substations
7
and b) Connection Lines48.
8
9
Comments
10
11
In other jurisdictions49, these types of facilities are generally referred to as
12
Generation-Related Transmission Assets (GRTAs) and are often excluded from
13
the transmission revenue requirement used to determine their open access
14
tariffs. However, in HQT’s case the assets concerned are specifically designated
15
as “transmission” under the Act50 and are therefore recoverable through
16
transmission charges.
17
18
Furthermore, in BC and Manitoba, GRTAs include various types of facilities that
19
HQT has chosen to include in Networks function. In particular, while HQT
20
functionalizes the extra-high voltage lines and the high voltage direct current
21
(HVDC) lines that connect generation as “Network” facilities, in both BC and
22
Manitoba similar facilities are treated as GRTAs. In the case of these two
23
jurisdictions, the distinction is important as the costs associated with GRTAs are
24
treated as generation costs and excluded from the Transmission revenue
25
requirement used to derive the transmission tariffs51. The significance of the
26
categorization of GRTAs by HQT as Generation Connection vs. Network facilities
27
will depend upon whether there are any differences in how each of the two
48
HQT-3, Document 1, page 13 and HQT-6, Document 7, Question 36 a)
For example, Nova Scotia and New Brunswick
50
HQT-3, Document 1, page 12
51
Instead the costs are treated as generation costs and recovered from the generators and, where generation
is regulated, the associated rates.
49
14
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
functions are allocated and to which services they are allocated – both of which
2
are discussed below.
3
4
5
4.2.2 Network
6
In general, the Network function consists of those lines (and associated
7
transformers) that operate at a high voltage (44 kV and above) and are not
8
dedicated to the connection of either a generation plant or a high voltage
9
customer52. More specifically, the Network function consists of those
10
transmission facilities53 that:
•
11
Operate at extra-high voltage and are used to carry electricity from
12
generation zones to centres of consumption and interconnections (the
13
Extra-High Voltage Transmission sub-function),
•
14
Constitute the 450 kV direct current (DC) link between James Bay’s
15
Radisson sub-station and the Nicolet sub-station (the 450 kV
16
Transmission sub-function), or
•
17
Form the shared transmission network and associated transforming
equipment (the High Voltage Transmission sub-function).
18
52
53
HQT-6, Document 7, Question 36 a)
HQT-3, Document 1, page 13
15
Evidence of
William Harper
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
4.2.3 Customer Connection
2
3
The Customer Connection function consists of the following of equipment used to
4
connect the transmission network to the distribution network and to individual
5
customers receiving service at high voltage (HV):
•
6
High voltage transformation stations that connect to distribution lines (the
Step-down Stations sub-function), and
7
•
8
High voltage lines put in place to supply a specific high voltage customer
or plant (the HV Customer Connection sub-function).
9
10
Furthermore, for purposes of this definition, HQD is not considered to be a high
11
voltage customer, as it is not supplied at a transmission voltage but, rather, at a
12
distribution voltage54.
13
14
Comments
15
16
It would appear from the definitions provided and the illustrative examples set out
17
in OC’s information requests55 that, while the Customer Connection function
18
includes the cost of the high voltage transformation stations servicing HQD, the
19
function does include the cost of any “radial” HV lines that may be required to
20
connect these transformation stations to HQT’s transmission network. Such lines
21
serve essentially the same function as “direct connection lines” to HV customers
22
except that they connect to a high voltage transformation station owned by HQT
23
instead of one owned by a “customer”. There is insufficient information on the
24
record to establish the costs associated with such facilities but, in principle, these
25
facilities should be identified and assigned to the Customer Connection function.
26
Such an approach would be consistent with the practice in Ontario and Nova
27
Scotia.
54
55
HQT-6, Document 7, Questions 36 d) and 36 g)
HQT-6, Document 7, Question 36
16
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
4.2.4 Interconnections
3
The Interconnections function consists of equipment used to connect HQT’s
4
transmission network with a neighbouring transmission network56. It is made up
5
of:
•
6
Lines and sub-stations that connect the Churchill Falls generating station
in Labrador to HQT’s system (the Churchill Falls sub-function), and
7
•
8
Lines and other facilities used for interchange with neighbouring systems
(the Other Interconnections sub-function).
9
10
11
Comments
12
13
The separation of the Churchill Falls interconnection from other interconnection
14
facilities was done in response to direction from the Régie57 regarding the need
15
to recognize the different role such facilities play on HQT’s overall system relative
16
to other interconnection facilities. However, it is questionable as to whether the
17
facilities used to integrate the power from Churchill Falls into HQT’s transmission
18
network should be considered part of the Interconnections function. In terms of
19
the role they play on HQT’s system they are more akin to the Generation Related
20
Transmission Assets (GRTAs) discussed earlier. However, as long as the cost is
21
tracked in a separate sub-function, the question of which “function” they are
22
assigned to is moot. What is critical is how the costs of the sub-function are
23
ultimately allocated to services (i.e., customers).
56
57
HQR-6, Document 7, Question 37 b)
D-2002-95, page 212
17
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
4.2.5 Support and Control Centre Costs
3
During the initial stages of HQT’s cost allocation methodology, the costs
4
associated with the System Control Centre and the Telecontrol Centres are
5
identified and tracked in a separate “Control Centre” function. Similarly, the costs
6
of support activities are assigned to a “Support” function. However, before the
7
various functions’ costs are allocated to services, the costs accumulated in these
8
functions are pro-rated over the other four main functions using on the “rate
9
base” directly allocated to each of the functions58.
10
11
Comments
12
13
The prorating of support activities across the main cost allocation functions is
14
consistent with direction given by the Régie in its last transmission rate decision59
15
and is a generally accepted approach60 for allocating such costs. The underlying
16
principle is that the associated activities support all the primary functions of the
17
utility and there is generally no clear cost driver that can be associated with the
18
function due to the wide variety of activities reflected in the costs.
19
20
However, in the case of the Control Centre function, the activities involved and
21
the services provided are more clearly defined and it may be possible to allocate
22
them on a more direct basis. This issue will be discussed further in the
23
subsequent sections.
58
HQT-3, Document 1, page 17 and HQT-3, Document 6, page 4
D-2005-95, page 214
60
NARUC Cost Allocation Manual, page 105
59
18
Evidence of
William Harper
4.3
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Cost Functionalization
2
3
4
4.3.1 Functionalization of Rate Base
5
HQT’s approved rate base for 2005 is $14,657.1 M and the authorized weighted
6
average cost of capital is 8.34%61. The rate base consists of the following items:
7
•
Fixed Assets
8
•
Intangible Assets (Actifs Incorporels)
9
•
Unamortized Expenses
10
•
Working Capital (including inventories and an allowance for working
funds).
11
12
HQT’s approved rate base reflects the average value of assets expected to be in-
13
service throughout 2005. However, HQT’s accounting records do not provide the
14
monthly detail necessary to categorize the assets by function. So, instead, the
15
year-end value of the rate base is assigned to functions (and sub-functions) and
16
the results are used to allocate the authorized return on capital to the various
17
functions and sub-functions62.
18
19
Fixed Assets
20
21
HQT’s fixed assets consist of lines, stations, other network assets and support
22
assets:
23
•
In the case of lines and stations, the assets are allocated directly to the
four main functions.
24
•
25
In the case of the other network assets, the assets associated with the
26
System Control Centre and the Telecontrol Centres are directly assigned
27
to the Control Centre function. The balance of the other network assets
61
62
HQT-1, Document 1, page 6
HQT-3, Document 1, page 15 and HQT-6, Document 7, Questions 39 a) & b)
19
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
are directly assigned to either one of the major four functions or the
2
Support function.
•
3
In the case of support assets, the costs are assigned directly to the
Support function.
4
5
6
Intangible Assets
7
8
HQT is able to directly assign the intangible assets to the various functions63.
9
10
Unamortized Expenses
11
12
Unamortized expenses consist of employee future benefits, staff reduction costs,
13
development expenses and outstanding government refunds (regarding the ice
14
storm):
15
•
Employee future benefits are allocated across the functions based on the
salary costs associated with each.
16
•
17
Staff reduction costs are also allocated to across the functions based on
the salary costs associated with each.
18
•
19
Development expenses are allocated across the functions based on the
fixed assets associated with each function.
20
•
21
The outstanding government refund is allocated across functions based
22
on the value of overhead lines in the Southern Territory associated with
23
each function64.
63
64
HQT-3, Document 1, page 15 and HQT-3, Document 6, page 7
HQT-3, Document 1, page 16 and HQT-3, Document 6, pages 7-8
20
Evidence of
William Harper
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Working Capital
2
3
The working cash portion of working capital is allocated to the functions based on
4
the direct gross expenditures assigned to each function, while the inventory
5
portion of working capital is allocated to the functions based on the fixed and
6
intangible assets assigned to each function65.
7
8
9
Comments
10
11
The components of HQT’s rate base are very similar to those of HQD (i.e., fixed
12
assets, intangible assets, unamortized expenses and working capital). Since the
13
HQD cost allocation methodology has gone through extensive consultation with
14
stakeholders and review by the Régie, it is useful to look at the approach used by
15
HQD in assigning its rate base to functions. In response to an OC information
16
request66, HQT provided a comparison of the methods used by itself and HQD to
17
assigned rate base to functions. The resulting schedule is replicated below.
65
66
HQT-3, Document 6, page 8
HQT-6, Document 7, Question 40 a)
21
Evidence of
William Harper
1
2
3
4
5
6
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
TABLE 3
Tableau 40.a - Comparison of the HQT and HQD Methodologies – Rate
Base
Assets
Capital Assets in operation
Intangible Assets
Distributor
Transmission Company
Direct assignment except
for some support assets
(actifs de soutien)
Direct assignment except
for some intangible assets
Direct assignment
salary costs (or payroll)
salary costs
salary costs
salary costs
salary costs
salary costs
Direct assignment
Net capital assets + net intangible
assets – NOTE 1
Net capital assets aerial lines South
Terr. - NOTE 2
Direct assignment
Non-amortized expenses
and other assets
Future social advantages - active
Future social advantages - passive
Measures for the reduction of the
FTEs
Development fees and other
deferred fees
Government reimbursement
Direct assignment
Working Capital
Cash balance
Materials, fuel and supplies
7
8
9
10
11
12
13
14
15
16
17
Direct Gross Expenses; taxes; bad
credit
Direct assignment
Direct gross expenses –
NOTE 3
Net capital assets + net intangible
assets – NOTE 4
Note 1: The deferred fees for HQD and HQT are not of the same nature.
Note 2: Direct attribution for HQD and then allocation according to capital assets and intangible assets of the
aerial distribution network. For HQT, attribution according to the net capital assets of the aerial lines of the
Southern Territory.
Note 3: Allocation of HQD’s cash balance according to different line items of the cash balance, and, in the case of
HQT, on the basis of gross direct charges, taking into account the insignificance of its cash balance.
Note 4: Direct attribution, for HQD as well as for HQT, and then allocation according to capital assets and net
intangible assets.
18
The only significant points of difference between the methodologies of the two
19
business units are in the areas of unamortized development expenses and
20
working capital:
•
21
For unamortized development expenses, HQD is able to directly attribute
22
them to functions whereas in HQT’s case they must be allocated67 to
23
functions.
•
24
HQD’s assignment methodology for working capital is also more detailed
as it uses an inventory analysis to assign inventories to functions and, in
25
67
Note: In reality, costs that HQD directly attributes to distribution network assets must be “allocated” to
individual sub-functions and this is generally done on the basis of net book value.
22
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
the case of working cash, the individual components are assigned
2
separately based on the assignment of the associated expense. In
3
contrast, HQT’s methodology uses a simpler and more aggregate
4
approach to assigning these rate base components.
5
6
The Régie, in its D-2003-93 decision, acknowledged that there was a need for a
7
balance between the level of analysis of cost allocation and the oversimplification
8
of the methods used.68 It observed that the method must simultaneously reflect a
9
sufficient degree of precision and take into account available data. Applying this
10
principle to the treatment of working capital, it is worth noting that the details
11
which would allow for direct assignment of inventories are not available69 and
12
that the type of inventory analyses undertaken by HQD could require a significant
13
effort on the part of HQT. Therefore, HQT’s proposed approach is reasonable.
14
15
In contrast, the information is readily available for HQT to undertake a finer
16
allocation of working cash requirements similar to that performed by HQD. HQT
17
rationalizes the simpler treatment of working cash on the basis of materiality70.
18
However, given that the information is readily available and modelling a more
19
precise treatment would require minimal to no effort, this argument is not
20
compelling.
21
22
The evidence71 filed by HQT in Phase 1 provides a detailed breakdown of the
23
sources of the working cash requirements. Over half the requirements are due to
24
the working cash needed to manage the revenue tax payments to the Québec
25
government while the next two largest contributors are for salaries (15%) and
26
capital taxes (10%). Based on these facts it is not clear why HQT selected direct
27
gross charges72 as the allocation factor for working cash requirements. The fixed
28
and intangible assets attributed to each function better reflect the relative
68
D-2003-93, page 144
HQT-6, Document 7, Question 45 b)
70
HQT-6, Document 7, Question 40 a), Table 40.a, Note #4 and HQT-6, Document 7, Question 45 c)
71
HQT-7, Document 1, page 34 of R-3549-2004 - Phase 1
72
HQT-3, Document 6, page 8
69
23
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
proportion of the overall revenue requirement by function73 and are also a
2
reasonable basis for allocating capital taxes. The use of fixed and intangible
3
assets as the allocation factor would also be consistent with the way the
4
allocation methodology assigns the expenses associated with capital and
5
revenue taxes to functions74.
6
7
Another factor which should be taken into account when determining the level of
8
precision required is the purpose of the cost allocation study in terms of what the
9
results of the study will be used for. In HQD’s case, the results are used to judge
10
the appropriateness of the relative rate levels of the various customer classes
11
served and can lead to rate adjustments that will impact on the customers
12
concerned. The results are also used to guide the rate design for each customer
13
class. As a result, a fair degree of precision is required. Similarly, if the intent is
14
to directly use the dollars assigned to each category of transmission service in
15
determining the “rates” then a fair degree of precision is desirable.
16
17
However, if the purpose of the analysis is to gauge the reasonableness of HQT
18
using the approach set out in FERC’s pro-forma OATT for assigning costs to
19
services and developing rates (but not as the basis for actually setting the rates)
20
then precision of the results may not be as critical (relative to ease of application)
21
in determining the procedures to be used in the cost allocation methodology.
22
23
It was not totally clear from the Régie’s Decision (D-2002-95) which of these two
24
purposes it had in mind when requesting the study. In its Application, HQT has
25
adopted the latter of these approaches and used the results of the cost allocation
26
methodology to demonstrate the reasonableness of its proposed rate
27
methodology and the resulting rates75.
73
Return on rate base and amortization represent a larger portion of the revenue requirement than direct
gross charges.
74
HQT-3, Document 6, page 16
75
HQT-4, Document 1, pages 22-25
24
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
4.3.2 Functionalization of Cost of Service
3
HQT’s approved revenues for 2005 (excluding return on capital) are $1,368.1
4
M76.
5
This revenue requirement consists of the following items:
6
•
Operating Expense
7
•
Shared Services (including a return to the supplier)
8
•
Capitalized Costs (represents a credit)
9
•
Internal Billings
10
•
Purchases of Electricity and Transmission Services
11
•
Depreciation and Amortization
12
•
Taxes
13
•
Corporate Expenses
14
•
Interest Related to Outstanding Government Refund (credit)
15
•
Revenue from External Invoicing.
16
17
Operating Expense
18
19
HQT’s operating expense is tracked by cost centre77 and, subsequently,
20
assigned to the cost allocation functions as follows:
•
21
The costs for the support units in the Corporate Centre (e.g., human
22
resources, planning & management, regulatory affairs, etc.) are assigned
23
directly to the Support function.
•
24
The costs of the Energy Dispatch Control directorate within the Corporate
Centre are assigned directly to the Control Centre function.
25
•
26
The costs for the support units in Facilities Operations are allocated
across all the functions (including the Support and Control Centre
27
76
77
HQT-3, Document 6, page 23
HQT-3, Document 1, R-2549-2004 – Phase 1
25
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
functions) based on the hours of maintenance on the assets associated
2
with each function78.
•
3
The costs of the Telecontrol Centres in Facilities Operations are allocated
directly to the Control Centre function.
4
•
5
The costs for each territorial unit in Facilities Operations are allocated to
6
functions based on the hours of maintenance on the assets associated
7
with each function.
8
9
Shared Services Costs and Supplier Return / Capitalized OM&A / Internal Billings
10
11
These expenses are also tracked by cost centre and assigned to functions in the
12
same way as operating expenses. The only exception is capitalized OM&A costs
13
which are assigned to the functions based on the investment hours associated
14
with each function79.
15
16
Electricity Purchases
17
18
These purchase costs are assigned directly to the Support function.
19
20
Transmission Service Purchases
21
22
These are assigned directly to the Other Interconnections function.
23
24
Depreciation and Amortization
25
26
The depreciation associated with fixed and intangible assets is assigned directly
27
to the function based on the types of assets associated with each function.
78
79
Maintenance hours is defined in HQT-6, Document 7, Question 46 a.1)
HQT-6, Document 7, Question 46 b.1)
26
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
The amortization of other costs (and credits) is allocated to the functions based
2
on the net book value of the fixed and intangible assets assigned to each
3
function.
4
5
Taxes
6
7
Municipal and school taxes are assigned directly to the Support function while
8
revenue and capital taxes are allocated to all functions based on the net book
9
value of the fixed assets and intangible assets associated with each function.
10
11
Corporate Expenses
12
13
Corporate expenses are allocated to the functions based 50% on the assignment
14
of direct OM&A to functions and 50% on the assignment of net fixed assets.
15
16
Interest on the Government Refund
17
18
The interest credit is allocated on the same basis as the unamortized balance for
19
the Government refund (under Rate Base).
20
21
External Invoices
22
23
24
External billings are tracked by cost centre and then assigned as follows:
•
The external billings to the support units in the Corporate Centre (e.g.,
25
human resources, planning & management, regulatory affairs, etc.) are
26
assigned directly to the Support function.
27
•
Corporate Centre are assigned directly to the Control Centre function.
28
29
30
The external billings to the Energy Dispatch Control directorate within the
•
The external billings for the support units in Facilities Operations are
allocated across all the functions (including Support and Control Centre)
27
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
based on the hours of maintenance for the assets associated with each
2
function80.
•
3
The external billings for the Telecontrol Centres in Facilities Operations
are allocated directly to the Control Centre function.
4
•
5
The external billings for each territorial unit in Facilities Operations are
6
allocated to functions based on the hours of maintenance for the assets
7
associated with each function.
8
9
Comments
10
11
The components of HQT’s cost of service are also very similar to those of HQD
12
(i.e., direct OM&A, shared services, corporate costs, depreciation and
13
amortization, taxes, etc.). As with the allocation of rate base, it is useful to look
14
at the approach used by HQD in assigning its cost of service to functions. In
15
response to an OC information request81, HQT provided a comparison of the
16
methods used by itself and HQD to assign rate base to functions. The resulting
17
schedule is replicated below.
80
81
Maintenance hours is defined in HQT-6, Document 7, Question 46 a.1)
HQT-6, Document 7, Question 41 a)
28
Evidence of
William Harper
1
2
3
4
5
6
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
TABLE 4
Tableau 41.a - Comparison of HQD and HQT Methods – Expenses
Necessary to the Cost of Service
Distributor
Transmission Company
Direct assignment except for some
support units according to average
FTEs, salary costs and use of
services
same
Direct assignment or according to
the shared services expenses
Direct assignment except for some
support units according to average
FTEs
Direct assignment except for some
support units according to salary
costs
Direct assignment and
maintenance hours – NOTE 1
Expenses necessary to the
cost of service
Net operating expenses
Gross direct expenses
Shared services expenses
Supplier return
Capital costs
Facturation interne émise
same
same
same
same
Other Expenses
Transmission services purchases
Electricity purchases
Depreciation and declassification
of capital and intangible assets
Depreciation and declassification –
others
Municipal & School Taxes
Other taxes
Corporate charges
Interest related to
government reimbursement
Facturation externe
(external billing)
7
8
9
10
11
12
13
14
15
16
17
18
N/a
Direct assignment
Direct assignment except for some
support units according to average
FTEs, salary costs and use of
services
Direct assignment except for some
support units according to average
FTEs, salary costs and use of
services
Direct assignment except for some
support units according to salary
costs
Direct assignment, net capital
assets and intangible assets
50% gross expenses & 50% net
capital assets
Direct assignment and net capital
assets and intangible assets
aerial lines
Direct assignment
Direct assignment
Direct assignment
Direct assignment
Net capital assets + net intangible
assets – NOTE 2
Direct assignment
Net capital assets + net intangible
assets
50% gross expenses & 50% net
capital assets
Net capital assets and aerial lines
Southern Territory – NOTE 3
Maintenance hours – NOTE 1
Note 1: Accounting information from HQT not available by function with the exception of Corpo. Support, Corpo.
CMÉ and Téléconduite (Remote Management). Allocation based on hours of maintenance or on hours of
investments allows an approximation with direct attribution.
Note 2 : Difficult for HQT to directly attribute these depreciations to corresponding functions, hence the use of
the best available inductor, i.e. fixed capital and net intangible assets.
Note 3: Direct attribution for HQD and, as a result, allocation according to fixed capital and net intangible assets
of the lines of the aerial network. For HQT, attribution according to the net capital assets of the aerial lines of the
Southern Territory.
29
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
The major differences between the two cost allocation methodologies are in the
2
allocation of direct OM&A expenses, depreciation of fixed assets, amortization of
3
other expenses and external billings. Most of these differences are due to the
4
fact that HQT’s functions are virtually all “asset based” whereas HQD’s functions
5
are a mix of asset based functions (e.g., distribution network – primary lines) and
6
activity based functions (e.g. customer care and accounting).
7
8
In the case of direct OM&A, HQD allocates the costs associated with distribution
9
networks across the various sub-functions based on net book value. In contrast,
10
HQT uses maintenance hours as its allocation factor in assigning maintenance
11
costs from cost centres to functions. Indeed, maintenance hours are likely a
12
more appropriate “allocator” than net book value. However, in the case of HQD
13
such information is not likely to be readily available. A similar observation
14
applies for shared services (including the service provider’s return), internal
15
billings and external billings82.
16
17
In the case of fixed asset depreciation, HQT is able to directly assign the
18
depreciation to functions – since the assets associated with each function and
19
sub-function are clearly defined and tracked. In contrast, in some cases, HQD
20
has to allocate the depreciation associated with a cost centre to functions and/or
21
sub-functions (e.g., the cost centres for Customer Care - Support; Networks -
22
Support and Networks - Operations).
23
24
In the case of amortization of other expenses, HQT allocates the total to
25
functions based on the net book value of the fixed and intangible assets
26
associated with each function. In contrast, HQD uses a variety of allocators
27
selected according to the nature of the costs associated with each of the
28
components of its amortization of other expenses (e.g., the amortization of the
29
government refund is based on the overhead lines associated with each
30
function).
82
HQT-6, Document 7, Questions 46 a.3); 46 c); and 46 e)
30
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
HQT claims that it is difficult for it to directly attribute the amortization of its
3
individual line items for unamortized expenses to functions and, therefore, a
4
single global allocator is used83. While, direct attribution may be difficult, the rate
5
base values associated with many of these line items are assigned separately by
6
HQT and, in each case, a unique allocator is used based on the nature of the
7
costs. Furthermore, it is interesting to note that while HQT uses the net book
8
value of fixed and intangible assets to allocate the amortization of the
9
government refund to functions, the interest credit on the outstanding balance is
10
allocated based on the net book value of the overhead lines of the Southern
11
Territory associated with each function84. There is no reason why the same
12
allocator could not be used to assign the annual amortization associated with
13
each rate base item as is used by HQT to allocate the outstanding unamortized
14
balance. This would yield, with very little additional effort, more accurate results
15
in terms of cost causality.
16
17
Finally, there is an inconsistency in HQT’s evidence regarding how the external
18
billings associated with the four territorial units in Facilities Operations are
19
allocated to functions:
•
20
The text in the evidence suggests that the allocation is done based on the
21
net book value of the fixed and intangible assets associated with each
22
sub-function85, whereas
•
23
The schematic provided in the evidence suggests that the allocation is
done based on the hours of maintenance associated with each function86.
24
83
HQT-6, Document 7, Question 41 a), Table 41.a, Note 3
HQT-3, Document 6, page 16
85
HQT-3, Document 6, page 16
86
HQT-3, Document 6, page 17
84
31
Evidence of
William Harper
4.4
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Classification of Costs
2
3
The purpose in “classifying” the costs in each function (and sub-function) is to
4
establish, based on system design and operating characteristics, the major
5
drivers that determine the level of cost the utility has incurred or will incur for
6
each function. These cost drivers will then be used to allocate the cost in each
7
function to customer classes (or in HQT’s case - classes of services). Functions
8
are typically classified as either:
•
9
Demand costs – considered to be those incurred to meet customers’
maximum system usage,
10
•
11
Energy costs – considered to be those incurred to provide energy over a
period of time, or
12
•
13
Customer costs – considered to be those related to the number of
customers or contracts served by the utility’s system.
14
15
16
In its evidence, HQT asserts87 that transmission assets are designed, planned,
17
operated and maintained in order to meet the maximum power requirements of
18
its customers. As a result, HQT proposes to classify all of the costs in its various
19
cost allocation functions as demand-related. HQT goes on to explain88 that the
20
classification of transmission assets as demand-related applies equally to
21
generation connection assets and to network assets, as the former are designed
22
to allow for the integration of the capacity of the generating stations.
23
24
Comments
25
26
The classification of transmission costs as demand-related is consistent with the
27
industry practice as outlined in the NARUC manual89 and seen in Canadian
28
utilities prior to the unbundling of service and the wide-spread adoption of
87
HQT-3, Document 1, pages 20-21
HQT-3, Document 1, page 23
89
1992 NARUC Electric Utility Cost Allocation Manual, page 75
88
32
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
FERC’s pro-forma OATT90. Furthermore, the rationale for classifying
2
transmission costs by these utilities as demand-related was the same as that
3
currently put forward by HQT – the system was designed and operated to meet
4
customer and system peak demand requirements. To a large extent, the assets
5
and services provided by HQT are similar to those of “transmission” as defined in
6
a traditional bundled utility environment and thus this traditional rationale
7
continues to apply. However, given the unbundling of transmission and
8
generation services and the statutory definition of transmission in Québec, there
9
is a need to carefully reconsider whether it is appropriate to classify all of HQT’s
10
costs as demand-related.
11
12
The first area where this occurs is with respect to HQT’s System Control Centre
13
and Telecontrol Centres. While larger systems likely require larger and more
14
costly control centres and telecontrol support, it is not evident that system
15
demand is any more a defining factor than say system energy requirements.
16
Furthermore, since the control centres manage the operation of the system
17
throughout the year91, they serve to deliver both capacity and energy. Finally,
18
prior to “unbundling” and open access, generation dispatch and transmission
19
system management/control were typically performed as one activity. Indeed, in
20
various jurisdictions,92 this continues to be the case. As a result, one could
21
question whether, conceptually, HQT’s Control Centre function should be pro-
22
rated over the four main functions and, ultimately, classified as demand-related –
23
as proposed by HQT. As discussed later in Section 4.5.2, this Evidence
24
concludes that the Control Centre function should be classified as energy-related
25
and its costs allocated directly to services.
26
27
Generation Connection is another area that requires some reflection with respect
28
to the appropriateness of the proposed classification, as noted by the Régie in D90
Note: Implementation of the FERC pro-forma OATT does not require a full and comprehensive cost
allocation study as evidenced by HQT’s first Tariff Application.
91
HQT-6, Document 1, page 34, Question 13.1
92
For example, BC and Ontario
33
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2002-9593 . As discussed above in Section 4.2.1, generation integration costs
2
are often considered to be “generation” costs and are not included in
3
transmission for purposes of cost allocation94 or open access tariff design95.
4
Their inclusion as transmission cost by HQT arises as a result of the statutory
5
definition of transmission. As generation costs, the costs of these facilities would
6
likely be classified as both energy and demand-related. However, since there is
7
no generally accepted method for doing so96 and the impact on the overall results
8
of the cost allocation methodology would likely be minimal97, HQT’s proposal to
9
treat them as demand-related should be acceptable.
10
4.5
11
Allocation of Functionalized Costs to Services
12
13
14
4.5.1 Services Provided
15
As discussed in Section 3.2, the services provided by HQT are Native Load
16
service, Network Integration service and PTP service. Furthermore, point to
17
point service is broken down as between long-term firm PTP service and various
18
short-term PTP services of terms lasting less than one year. For purposes of its
19
cost allocation methodology, HQT groups all PTP services together and treats
20
them as a single service98. Also, since there have never been and there are not
21
expected to be any customers taking Network Integration service, this service is
22
not considered separately in the cost allocation methodology,99 but rather
23
grouped with Native Load service.
93
page 213
Examples would be BC and Manitoba
95
Examples would be New Brunswick and Nova Scotia
96
Just as there is no generally accepted method for classifying generation related costs. See also HQT-6,
Document 1, page 46 (second bullet point)
97
HQT-6, Document 1, page 47, Question 19.2 a)
98
HQT-6, Document 1, Question 17.1, page 42
99
HQT-3, Document 1, page 27
94
34
Evidence of
William Harper
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Comments
2
3
Typically, in establishing customer classes or services for purpose of cost
4
allocation (and, ultimately rate design), a utility will group together customers (or
5
services) that use the utility’s system and its various cost allocation functions in a
6
similar manner.
7
8
In HQT’s case, Native Load service and PTP service customers are
9
fundamentally different in terms of how they contract for service, what services
10
they are charged for, and how they are billed. As a result, it is appropriate to
11
separate them for cost allocation purposes.
12
13
Furthermore, while there are currently no Network Integration customers, the
14
treatment of such customers more closely matches that of Native Load Service
15
than PTP service. As a result, should a customer request Network Integration
16
service it would be reasonable for HQT to group such customers with Native
17
Load Service for purposes of cost allocation.
18
19
However, HQT’s grouping of all PTP customers and defining them as one
20
“service” for cost allocation purposes, ignores the fact that there are fundamental
21
differences between the nature of the service provided to the different types of
22
PTP customers:
•
23
Customers contracting for non-firm short-term PTP service have a lower
24
service priority than those contracting for firm short-term PTP service. In
25
turn, customers contracting for long-term PTP service have a higher
26
service priority than those contracting for short-term firm PTP service and,
27
indeed, long-term firm PTP customers have equal service priority with
28
Native Load and Network Integration service100.
•
29
In the case of requests for firm PTP service, HQT is required to use due
diligence to expand or modify its transmission system to provide the
30
100
HQT-6, Document 1, Question 35.1 and HQT-5, Document 1, page 13, Table 1
35
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
requested firm PTP transmission Service, provided the transmission
2
customer agrees to compensate HQT in accordance with a prescribed
3
capital contribution policy101. However, for practical purposes, it is unlikely
4
that HQT would be able to expand its system to meet requests for short-
5
term PTP service, unless such requests were made well in advance of the
6
timelines required under the current terms and conditions of service102.
7
8
In reality, short-term PTP service customers (both firm and non-firm) will typically
9
be served from existing available capacity and the objective in offering such
10
services is to improve the utilization of (and the revenue generated by) the
11
transmission system 103. In contrast, the loads associated with long-term firm
12
PTP service are incorporated into the utility’s planning processes (like Native
13
Load and Network Integration service) and used to determine future capacity
14
needs and the resulting facilities required. Put another way, customers receiving
15
short-term service (firm and non-firm) generally utilize a transmission system
16
designed and constructed to meet the needs of long-term firm PTP, Native Load
17
service and Network Integration service customers. Short-term service is
18
provided if the utility determines that the transmission capacity needed to meet
19
their service requests is not otherwise required104.
20
21
In order to reflect this fundamental difference, short-term and long-term PTP
22
service need to be addressed separately in the cost allocation methodology.
23
Some may argue that it is possible to retain the long-term and short-term PTP
24
customers as a single customer class and recognize these differences in the
25
nature of the service provided through the factors used105 in the allocation of the
101
HQT-5, Document 3, Section 13.5
HQT-6, Document 9, Questions 52.5 and 52.6
103
HQT-3, Document 1, pages 30-31and HQT-4, Document 1, page 11
104
This could be due to either the existence of excess transmission capacity overall and/or the fact that the
service requirements of long-term firm PTP, Native Load service and Network Integration service
customers will vary throughout the year.
105
For example, if short-term PTP customers are not considered in determining the network facilities
required then their requirements would not be included in the allocation factors used to assign the costs of
the network function to PTP services.
102
36
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
functionalized transmission costs. However such an approach would also credit
2
all of the revenues from short-term PTP customers to the PTP service category
3
for purposes of benchmarking revenues and costs for Native Load/Network
4
Integration service and PTP service. This would be inappropriate since:
•
5
The rates for short-term PTP service are not strictly cost-based and to
some extent are based on opportunity pricing106, and
6
•
7
Allocating all of the revenues arising from short-term PTP service to the
8
PTP service category fails to recognize that the revenue arose as a result
9
of short-term service customers utilizing a transmission system built to
serve both Native Load and long-term PTP customers107.
10
11
Indeed, HQT’s proposed derivation of Native Load and long-term PTP service
12
rates properly recognizes this point and removes short-term PTP service
13
revenues from the total revenue requirement before determining the annual
14
rates108 for either Native Load service or long-term PTP service.
15
16
In order to properly reflect short-term PTP service in the cost allocation
17
methodology:
•
18
It needs to be separated out as a different service category from long-term
PTP service, and
19
•
20
The net revenue (i.e., total short-term PTP service revenues less any
21
allocated costs) from short-term PTP service should be “allocated” to both
22
Native Load/Network Integration service and long-term PTP service,
23
thereby reducing the costs for both classes of service.
24
25
26
4.5.2 Allocation Factors
27
In the previous stage, HQT categorized all the costs assigned to each of the cost
28
allocation functions as being demand-related. For purposes of actually allocating
106
HQT-4, Document 3.1, page 7
HQT-6, Document 9, Question 46.5
108
HQT-4, Document 1, page 15, Table 3.
107
37
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
each function’s costs to services, HQT proposes to directly assign costs where
2
possible and then to use each service’s contribution to the annual transmission
3
system peak to allocate the remaining costs. This methodology is referred to as
4
the 1-CP (i.e. one coincident peak) method, as it looks at each service’s load
5
coincident with the annual (or single) system peak. The loads actually included
6
in the 1-CP allocation factor for each “function” are then based on the services
7
utilizing the assets assigned to the function109.
8
9
Selection of 1-CP
10
11
HQT acknowledges that there are other allocation factors besides 1-CP that are
12
used elsewhere to allocate costs categorized as demand-related110 and, in
13
particular, notes the use of 3-CP, 4-CP and even 12-CP elsewhere for purposes
14
of allocating such costs. However, HQT argues that the predominance of electric
15
space heating distinguishes its system from others in that its annual load
16
significantly exceeds its average annual demand. HQT goes on to note that the
17
results of various FERC tests conducted by its expert, Dr. Ren Orans, clearly
18
show that 12-CP should be rejected and that 1-CP is appropriate111.
19
20
Comments
21
22
Some form of coincident peak allocation factor is the most common method of
23
allocating transmission-related costs. This is supported both by practice in the
24
US (as reported112 by Dr. Ren Orans) and the practice of many Canadian utilities
25
both in the cost allocation methodologies supporting their retail rates113 and those
26
supporting their open access transmission tariffs114.
109
HQT-3, Document 1, pages 25-27
HQT-3, Document 1, pages 26-27
111
HQT-3, Document 1, page 29
112
HQT-4, Document 3, page 15
113
Based on Consultant’s review of practices approved by regulators in other Provinces most use some
form of CP as the allocation factor for transmission costs in their cost allocation methodologies supporting
retail rates.
114
HQT-6, Document 7, Question 49 a)
110
38
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
However, as noted by Dr. Orans115, the actual CP allocation factor approved by
3
FERC varies across US utilities from 12-CP (i.e., the average contribution of
4
each service to the 12 monthly peaks of the transmission system) to 3 or 4-CP
5
(i.e., the average contribution of each service to the monthly peaks in the 3 or 4
6
months of the year with the highest transmission peaks) to 1-CP. Dr. Orans
7
observes that if a utility experiences a pronounced peak during 1, 3 or 4 months,
8
then FERC precedent supports the use of an allocation factor other than 12-CP.
9
However, according to Dr. Orans, the examples of the use of 1-CP appear to be
10
limited116.
11
12
In contrast to FERC practice, data published by NARUC117, indicates that even
13
for US states which are strictly winter or summer peaking, the state regulators
14
using coincident peak allocation tend to have adopted 4-CP and 12-CP as
15
frequently as 1-CP (i.e., there was roughly an equal use of all three methods).
16
17
In Canada, the majority of the other utilities, using the FERC pro-forma OATT,
18
utilize 12-CP to allocate costs between Network and PTP customers118. In
19
contrast, 1-CP appears to be the predominant allocation factor used for
20
transmission costs in cost allocation studies performed in support of retail
21
rates119.
22
23
The conclusion to be drawn from the preceding observations is that there are no
24
hard rules or clear precedents to direct when 1-CP vs. 3- or 4-CP vs. 12-CP
25
should be used. A good example of this is the methodology used to derive
26
BCTC’s open access tariff. As Dr. Orans has noted120, the methodology used by
27
the BCTC OATT is even more extreme than the 1-CP allocation factor.
115
HQT-6, Document 7, Question 51 d) and HQT-4, Document 3, pages 15-16
HQT-6, Document 7, Question 51 d); HQT-4, Document 3, page 15 and HQT-6, Document 9, Question
56.1
117
NARUC, Utility Regulatory Policy in the United States and Canada 1995-1996, page 495
118
Of the five utilities – four use 12-CP.
119
Based on the Consultant’s understanding of various provincial utility practices.
120
HQT-6, Document 7, Question 51 d)
116
39
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
However, application of the FERC tests to BCTC data would appear to support
2
the use of the 12-CP allocation factor121.
3
4
Overall, Dr. Orans rejection122 of 12-CP in the case of HQT is reasonable – in
5
light of the winter peaking nature of the system and the monthly variation in
6
transmission system peaks123. Dr. Orans also suggests that while the choice as
7
between 1-CP and 3- or 4-CP is not as clear124, the application of the FERC tests
8
generally support a 3- or 4-CP allocation125. As a result, while HQT and Dr.
9
Orans support the continued use of 1-CP126, there are equally compelling
10
reasons for adopting a 3-CP allocation factor, including:
•
11
The relatively close proximity of the December, January and February
12
transmission system peak requirements127 and Dr. Orans’ observation that
13
the coldest day of the year can fall in any of these three months128,
•
14
The fact that over the past 4 winters the maximum utilization of the
transmission system has occurred in December, January or February 129,
15
•
16
US state regulatory practice to adopt 1-CP, 3- or 4-CP and 12-CP for
utilities with single seasonal peaks130, and
17
•
18
The lack of any broad adoption of 1-CP for purposes of setting
transmission tariffs.
19
20
When issues of year-to-year stability are also taken into account, it would be
21
prudent for the Régie to adopt the 3-CP allocation factor.
121
HQT-6, Document 7, Question 74 e)
HQT-4, Document 3, page 17
123
HQT-6, Document 7, Question 50.a) and HQT-4, Document 3, page 18, Table 3
124
HQT-6, Document 9, Question 52.3
125
HQT-6, Document 9, page 68, Question 52.3
126
HQT-6, Document 9, page 63, Question 50.1
127
HQT-6, Document 7, Question 50 a) and HQT-6, Document 9, Question 55.1
128
HQT-4, Document 3, page 19
129
HQT-6, Document 1, page 35, Question 14.1.a).
130
NARUC, Utility Regulatory Policy in the United States and Canada 1995-1996, page 495
122
40
Evidence of
William Harper
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Allocation of Generation Step-Up Function Costs
2
3
HQT’s proposal is to allocate the costs assigned to the Generation Step-Up
4
function between Native Load Service and PTP service based on:
•
5
Native Load’s forecasted demand (MW ) at the time to the transmission
6
system peak – less the capacity of the Churchill Falls interconnection
7
point131, and
•
8
9
The anticipated MW of contracted long-term PTP service.
HQT explains132 that the capacity of the Churchill Falls interconnection is
10
excluded from Native Load since Churchill Falls’ costs are allocated elsewhere
11
as part to the Interconnections function.
12
13
Comments
14
15
As mentioned earlier, the role of the Churchill interconnection more closely
16
matches that of facilities which integrate generation into the utility’s transmission
17
system network (than facilities that interconnect two neighbouring systems).
18
However, it is not immediately evident that the power from Churchill Falls is used
19
exclusively to service Native Load as opposed to being used to meet HQP’s
20
other delivery obligations. As a result, it would be more appropriate to “allocate”
21
the Generation Step-Up function costs between Native Load/Network Integration
22
and PTP service based on the total requirements of each service.133
23
24
Allocation of Network Function Costs
25
26
HQT’s proposal is to allocate the costs of this function between Native Load
27
service and PTP service based on:
131
HQT-3, Document 1, page 31
HQT-6, Document 7, Questions 53 a) & b)
133
Allocation Factor “B” from HQT-3, Document 6, page 23, Table 10
132
41
Evidence of
William Harper
•
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Native Load’s forecasted demand (MW ) at the time to the transmission
2
system peak – including the capacity of the Churchill Falls interconnection
3
point134, and
•
4
The anticipated MW of contracted long-term PTP service.
5
6
Comments
7
8
Inclusion of all service loads is appropriate since all transmission services utilize
9
the network facilities.
10
11
Allocation of Connection Function Costs
12
13
HQT’s proposal is to directly allocate the costs of transformer stations connecting
14
to distribution lines135 and the cost of lines dedicated to the connection of a high
15
voltage customer136 to Native Load service.
16
17
Comments
18
19
This is reasonable as, by definition, all of the facilities in the function are used
20
specifically by HQD and its customers for the receipt of power.
134
HQT-3, Document 1, page 31
HQT-6, Document 7, Question 36 h)
136
HQT-6, Document 7, Question 36 b)
135
42
Evidence of
William Harper
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Allocation of Interconnection Function Costs
2
3
HQT’s proposal is to allocate the costs assigned to the Churchill Falls sub-
4
function between Native Load Service and PTP service based on:
•
5
Native Load’s forecasted demand (MW ) at the time of the transmission
6
system peak – including the capacity of the Churchill Falls interconnection
7
point137, and
•
8
9
10
The anticipated MW of contracted long-term PTP service.
However, the costs assigned to the Other Interconnections sub-function would be
allocated between Native Load Service and PTP service based on:
•
11
The import capability of the Interconnections (as the allocation factor for
Native Load), and
12
•
13
The export capability of the Interconnections (as the allocation factor for
PTP service).138
14
15
16
Comments
17
18
As discussed above, the power from Churchill Falls could be used (by HQP) to
19
meet either Native Load requirements or fulfill its obligations to other customers.
20
As a result, the proposed allocation of the Churchill Falls inter-tie costs is
21
reasonable.
22
23
In the case of the facilities associated with the Other Interconnections sub-
24
function, they can be used either as a point of receipt or a point of delivery for
25
HQT’s transmission service. If used as a point of receipt (i.e., for the import of
26
power to Quebec), the facilities could be supporting either PTP or Native Load
27
service. However, if used as a point of delivery (i.e., for the export of power from
28
Quebec), the facilities are only supporting PTP service. As a result, it is
137
138
HQT-3, Document 1, page 31
HQT-3, Document 1, page 31
43
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
appropriate to split the cost of the sub-function between imports and exports, as
2
HQT has done. But then the two parts should be allocated as follows:
•
3
The 39.57% 139 associated with imports should be allocated to both Native
4
Load and PTP service based on their total requirements (as opposed to
5
just Native Load as proposed by HQT); while
•
6
The remaining 60.43% associated with exports should be allocated solely
to PTP service.
7
8
9
Allocation of the Support Function and Control Centre Function Costs
10
11
As mentioned earlier, the HQT pro-rates the costs of these two functions over the
12
four major functions - prior to the costs of the four functions being classified and
13
allocated to customers.
14
15
Comments
16
17
In the case of the costs assigned to the Support function, this approach is
18
reasonable and consistent with industry practice for allocating such costs140 and
19
the directions of the Régie from D-2002-95141.
20
21
However, in the case of the Control sub-function, such an approach would result
22
in the cost allocation methodology failing to recognize that while short-term PTP
23
service does not impact on the total facilities required by HQT (i.e., short-term
24
PTP utilizes lines, stations, etc. constructed based on Native Load and long-term
25
PTP service requirements), the level of activity and requirements of the system
26
control centre are likely driven by all transactions on HQT’s system – including
27
short-term transactions.
139
HQT-6, Document 7, Question 54 a) and HQT-3, Document 6, page 23, Table 10
NARUC Cost Allocation Manual, page 105
141
D-2002-95, page 214
140
44
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
As a result it would be appropriate to retain the Control Centre function through
2
the classification and allocation steps of the cost allocation methodology and,
3
ultimately, allocate a portion of the function’s costs to short-term PTP service as
4
well.
5
6
Such an approach means an appropriate allocation factor must be identified for
7
assigning the Control function costs to Native Load service, long-term PTP
8
service and short-term PTP service. While some variation of coincident peak
9
demand is a reasonable allocation factor for the four main functions, such a
10
factor is not appropriate in the case of the Control Centre function. Given the
11
role of system control in managing all the transactions on HQT’s system 142, a
12
broader measure of “system usage” is required that considers the whole year
13
and is not focused just on usage at the time of the system’s monthly peaks or
14
annual peak.
15
16
There are a number of possible alternatives including 12-NCP by service class,
17
total contracted volume by class (i.e., contracted MW times contract period), and
18
total energy transmitted by service class. Of these, total contracted volume by
19
class is the recommended allocation factor. It provides the best measure of the
20
transactions associated with each service class that must be managed by system
21
control.
22
23
Once the costs attributable to short-term PTP service have been identified, the
24
net revenues associated with the service (i.e., projected short-term PTP
25
revenues less allocated costs) should be pro-rated over the other two services
26
based on the total costs already assigned to both.
142
HQT-6, Document 7, Question 35 c.2)
45
Evidence of
William Harper
1
4.6
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Impact of Comments Regarding HQT’s Cost Allocation Methodology
2
3
Table 5 sets out the allocation of 2005 total cost service to Native Load and long-
4
term PTP service using the foregoing recommendations regarding the allocation
5
of each function and sub-function’s costs. The table does not reflect the impacts
6
of any of the suggested changes as to how cost should be allocated to functions.
46
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
TABLE 5
Generation Step-Up
- Stations
- Lines
Network
- Very High Voltage
- 450 kV
- High Voltage
596.4
409.6
25.4
161.3
9,859.3
812.4
1408.8
1584.4
0.9879
0.0121
0.0000
1565.2
19.2
0.0
Customer Connections
- Stations
- HV Customer
203.3
181.6
21.6
1,863.4
153.6
356.9
401.3
1.0000
0.0000
0.0000
401.3
0.0
0.0
Interconnections
- Churchill Falls
- Others
79.4
16.2
63.2
815.5
194.0
621.6
67.2
16.0
51.2
146.6
32.2
114.4
164.9
36.2
128.7
0.9879
0.3909
0.0121
0.6091
0.0000
0.0000
35.8
50.3
0.4
78.4
0.0
0.0
Control Centre
158.3
159.6
13.2
171.5
192.8
0.9391
0.0127
0.0483
181.1
2.4
9.3
Support
252.8
417.9
34.4
287.2
Sub-Total
1368.1
14,840.6
1222.9
2591.0
2591.0
2478.3
103.4
9.3
-78.0
0.0
0.0
-78.0
2513.0
2478.3
103.4
-68.7
ST PTP Revenues
Total Recovery From NLS
and LT PTP
Rate
Allocated
Base
Return
($M)
($M)
1,724.8
142.1
Total
Costs
($M)
220.1
Total Costs
with Support
($M)
247.6
Initial Service Allocation Factor
Initial Cost Allocation
Native
LT
ST
Native
LT
ST
Load
PTP
PTP
Load
PTP
PTP
($M)
($M)
($M)
0.9879
0.0121
0.0000
244.6
3.0
0.0
Cost of
Service
($M)
78.0
66.2
11.7
Final Cost Allocation
Native
LT
Load
PTP
($M)
($M)
2412.3
100.7
47
Evidence of
William Harper
1
5
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
HQT’S PROPOSED TRANSMISSION SERVICE PRICING
METHODOLOGY
2
3
4
5.1
Overview
5
6
HQT’s transmission service pricing for Native Load and firm PTP service is not
7
based on a detailed cost allocation analysis but rather follows the approach set
8
out by FERC in its pro-forma OATT 143. According to Dr. Orans’ direct
9
testimony144, this involves the following seven-step process:
1. Determine HQT’s TRR for the appropriate forward test year period, which
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
2.
3.
4.
5.
6.
7.
143
144
is calendar year 2005 for this application. The TRR was approved by the
Régie in Phase 1 of the current case.
Estimate the revenues to be collected from ST-PTP sales over the same
test year period.
Subtract the ST-PTP revenues from the TRR from Step 1 to develop an
estimate of the Net TRR to be collected from NITS, NLS and LT-PTP
customers.
Estimate the transmission system’s single coincident peak (1-CP), the
total transmission load at the time of the transmission system’s annual
peak. This step entails estimating the coincident peak loads of the LTPTP, NITS and NLS customer classes. The peak load estimates of NLS
are based on a normal weather forecast and include losses. The LT-PTP
forecast is based on reservations.
Divide the Net TRR by the 1-CP load from Step 4 to develop the annual
LT-PTP rate.
Estimate the LT-PTP revenues as the product of LT-PTP rate times an
annual forecast of LT-PTP reservations.
Subtract the LT-PTP revenues from the Net TRR to develop an estimate
of the network revenues. Network revenues are then allocated to each
network customer, who may receive NITS or NLS, based on the
customer’s load ratio share of HQT’s 1-CP.
HQT-4, Document 3, page 13 and HQT-6, Document 9, page 56, Question 46.1
HQT-4, Document 3, pages 13-14
48
Evidence of
William Harper
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Comments
2
3
Table 6 sets out how HQT’s proposed seven steps align with the traditional
4
three-stage rate setting process of revenue requirement determination; cost
5
allocation and rate design (see Section 4.1).
6
7
Table 6
8
Comparison of Rate Setting Processes
9
Tradition Rate Setting Process
HQT’s Transmission Service Rate
Setting Process
Stage 1 – Revenue Requirement
Steps #1 and #2
Determination
Stage 2 – Cost Allocation
Steps #3 and #4
Stage 3 – Rate Design
Steps #5, #6 and #7
10
11
12
5.2
Treatment of Short-Term PTP Revenues
13
14
HQT subtracts the anticipated revenues from short-term PTP service from the
15
total approved revenue requirement prior to allocating the costs between Native
16
Load/Network Integration service and long-term PTP service.
17
18
Comments
19
20
Using the revenues from short-term PTP service to offset the costs used to
21
derive firm transmission rates is consistent with FERC’s application of its pro-
22
forma tariff145 and practice elsewhere146. It is also consistent with the fact that:
145
146
Order 888-A, page 256
HQT-6, Document 9, page 54, Question 46.5
49
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
a) HQT’s transmission facilities are designed to meet its service
1
2
commitments to Native Load/Network Integration service and long-term
3
PTP service147,
b) the objective in offering short-term service is to improve the utilization of
4
5
the overall transmission system and generate additional revenues that will
6
offset the costs otherwise recovered from long-term firm customers148, and
7
c) short-term PTP service rates are frequently discounted in order to achieve
the objectives set out in (b) 149.
8
9
10
In its Application, HQT noted that by marketing of both long-term and short-term
11
PTP transmission service, it can optimize the use of the system and obtain
12
additional revenues to reduce the share of the revenues that must be borne by
13
Native Load service. Moreover, HQT observed that in the absence of PTP
14
service, the entire cost of service would have to be borne by native load150.
15
HQT’s expert, Dr. Orans, has also indicated151 that the typical allocation between
16
Native Load/Network Integration service and long-term PTP service entails
17
subtracting short-term PTP revenues from the total revenue requirement prior to
18
determining the rates for both service categories. However this practice is not
19
universal. In its recent application for an open access tariff, BCTC took the
20
position, when dealing with this issue, that since its Network Customers (the
21
rough equivalent to HQT’s Native Load service) “backstop the entire
22
Transmission Revenue Requirement”152, it was appropriate for short-term
23
revenues to be credited against the revenue to be paid by network customers
24
(and not long-term PTP service customers).
147
HQT-6, Document 9, page 71, Question 52.6
HQT-4, Document 1, page 11
149
HQT-4, Document 3.2, pages 7-8
150
HQT-4, Document 1, page 11
151
HQT-6, Document 7, Question 49 a)
152
BCTC Response to BCOAPO 8.0.g
148
50
Evidence of
William Harper
1
5.3
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Allocation of Revenue Requirement between Native Load/Network
Integration Service and Long-term PTP Service
2
3
4
As described above, HQT allocates the net revenue requirement (i.e., the total
5
revenue requirement less short-term PTP revenues) between Native
6
Load/Network Integration service and Long-term PTP service based on the
7
contribution of each to the transmission system’s annual peak load (i.e., based
8
on 1-CP). HQT’s rationale for using 1-CP to allocate the revenue requirement
9
between these two services is similar to that put forward to support the use of 1-
10
CP in HQT’s proposed cost allocation methodology – namely, that the
11
transmission system is designed to meet the system peak153. Furthermore,
12
HQT’s expert, Dr. Ren Orans, notes154 that “if a utility experiences a pronounced
13
peak, during 1, 3 or 4 months, the FERC precedent supports the use of another
14
CP method” (i.e., other than 12-CP) and, subsequently, concludes that the
15
standard tests developed by FERC provide a basis for rejecting the 12-CP
16
method in HQT’s case155. Dr. Orans then presents the results of various
17
supplementary analyses and concludes that “it is reasonable to allocate HQT’s
18
transmission revenue requirement according to each transmission service class’
19
contribution to the single system coincident peak load in January”156.
20
21
Comments
22
23
As the Comments offered in Section 4.5.2 indicate, when practice across
24
Canada, FERC and US state regulators is considered, there is no clear and
25
consistent precedent for the use of 1-CP versus 3- or 4-CP versus 12-CP for
26
allocating transmission costs – even for seasonal peaking utilities. However, in
27
cases such as HQT’s, it is reasonable to conclude157 that use of a 12-CP
28
allocation factor would be inappropriate given the wide variation in monthly
153
HQT-4, Document 1, pages 23-24
HQT-4, Document 3, page 15
155
HQT-4, Document 3, page 17
156
HQT-4, Document 3, page 20
157
As the application of the FERC tests demonstrates (HQT-4, Document 3, page 16).
154
51
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
system peaks throughout the year. Furthermore, while the original FERC pro-
2
forma tariff158 would appear to support the use of 12-CP, the Commission has
3
made it clear that utilities are free to propose alternative allocation factors,
4
provided they are consistent with the utility’s transmission system planning and
5
would not result in an over-collection of the utility’s revenue requirement159.
6
7
However, the choice between 1-CP and, say, 3-CP becomes more judgmental.
8
Therefore, while it may be “reasonable” to allocate transmission costs using 1-CP
9
(as concluded by Dr. Orans), there are compelling reasons for using 3-CP as
10
already discussed in Section 4.5.2. Table 7 sets out the determination of the
11
annual rate for 2005 based on a 3-CP allocation factor.
12
13
Table 7
14
2005 Annual Transmission Service Rate
15
Based on 3-CP
16
Approved Required Revenues (a)
Short-term Point to Point Revenues (b)
Residual Revenues Required (a)
Native Load Service (c)
17
18
19
20
21
22
$2,591 M
$78 M
$2,513 M
33,168 MW
Long-term PTP Transmission Service (a)
405 MW
Total Transmission Service Requirements
33,573 MW
Annual Rate
$74.85 / kW
Sources:
158
159
a) HQT-4, Document 1, page 15
b) HQT-4, Document 1, page 15. Assumes short-term rates unchanged. If these
rates were adjusted in accordance with the annual rate then the annual rate
would be slightly lower, i.e. $74.79 / kW
c) HQT-6, Document 7, page 79, Question 52.a)
Order 888, page 296 and Order 888, Appendix D, Section 34
FERC Order 888-A, pages 239 and 258.
52
Evidence of
William Harper
1
5.4
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Determination of Long-term Point to Point Service Rates
2
3
HQT sets the annual rate for long-term PTP service by dividing the net
4
transmission revenue requirement (i.e., total approved revenue requirement less
5
revenues from short-term PTP service) by the combined peak (i.e., annual peak)
6
for Native Load, Network Integration and long-term PTP service160. This is the
7
same “divisor” HQT uses to allocate the net revenue requirement between Native
8
Load/Network Integration service and long-term PTP service. Payments for long-
9
term PTP service are actually made monthly, based on 1/12th of the annual
10
demand charge times the reserved capacity for the year.
11
12
Comments
13
14
The HQT approach is equivalent to one where the rate is derived by taking the
15
net revenue requirement allocated to long-term PTP service and dividing it by the
16
forecasted level of long-term firm PTP service used in the initial allocation (i.e.,
17
step 4 of the seven step process). This is the approach used by many (but not
18
all161) Canadian utilities in setting their long-term PTP service rates. Overall, the
19
HQT approach to setting rates for long-term PTP service is reasonable.
20
21
5.5
Determination of Native Load/Network Integration Service Rates
22
23
HQT’s charges for Native Load service are not specified in terms of a “rate”,
24
which is then applied to a monthly or annual billing determinant, but rather as an
25
annual fixed dollar amount, which is billed to the Distributor in 12 equal monthly
26
payments, until modified in a subsequent rate application. The proposed annual
27
charge is $2,483.3 M for 2005.
160
HQT-4, Document 1, page 14
This approach is used by New Brunswick and Nova Scotia but not British Columbia. See also HQT-4,
Document 3.1, page 5
161
53
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
Comment
3
4
Based on a 3-CP allocation factor the annual charge for Native Load Service
5
would change to $2482.6 M162.
6
7
HQD is HQT’s only Native Load customer and HQT has no Network Integration
8
service customers. As a result, there is currently no need for HQT to “divide” up
9
the costs between Native Load and Network Integration service. All of the costs
10
are recoverable from Hydro Quebec Distribution – the Native Load Service
11
customer. However, the question arises as to how, in principle, the revenue
12
requirement would be charged if there was more than one Native Load/Network
13
Integration customer. In the Tariffs and Conditions, HQT provides for the
14
situation where other network customers may emerge in that the amount payable
15
by HQD is “less any amount payable during the month by a customer whose load
16
was previously part of the Distributor’s Native Load and who has reserved, to
17
supply such load, a Transmission Service under Part II (Point to Point service) or
18
Part III (Network Integration Service) herein, until such time as the exclusion of
19
such load from the Distributor’s Native Load has been taken into account by the
20
Régie in determining applicable transmission rates under the provisions
21
herein”163.
22
23
Furthermore, in the Tariffs and Conditions164, HQT establishes how new Network
24
Integration customers would be charged:
25
26
27
28
29
Monthly Demand Charge: The Network Customer shall pay a monthly demand
charge, which shall be determined by multiplying its Load Ratio Share times onetwelfth (1/12) of the Transmission Provider's annual transmission revenue
requirement specified in Attachment H herein. A new Network Customer shall
162
Based on the annual charge of $74.79/kW and a Native Load of 33,168 MW.
HQT-5, Document 3, Section 42.1
164
HQT-5, Document 3, Sections 1.27, 34.1, 34.2 and 34.3
163
54
Evidence of
William Harper
1
2
3
4
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
pay the monthly demand charge commencing on the first day of the month during
which Network Integration Transmission Service is initiated.
Where the various terms used are defined as follows:
5
6
7
8
9
“Load Ratio Share: The ratio of the annual load of the Network Integration
Transmission Service customer to the annual load of the Transmission System,
both computed in accordance with Sections 34.2 and 34.3 concerning the
Network Integration Transmission Service under Part III herein.”
10
11
12
13
14
15
16
17
18
19
Network Customer's Annual Load: The Network Customer’s annual load
corresponds to the projected annual peak demand of that Network Customer over
the calendar year during which Network Integration Transmission Service is
provided.
Transmission Provider's Annual Transmission System Load: The
Transmission Provider’s Annual Transmission System Load corresponds to the
projected annual peak demand for the Native Load plus the sum of the projected
annual peak demand for each of the Network Customers.
20
The overall effect is that the total revenue requirement allocated to Native
21
Load/Network Integration service would be distributed amongst individual
22
customers (if there were more than one) on the basis of their relative annual
23
peaks regardless of when they occurred (i.e., based on a 1-NCP allocation
24
factor)165. This interpretation of the current (and proposed) wording of the Tariffs
25
and Conditions differs from Dr. Ren Orans’ evidence which indicates166 that HQT
26
is proposing to allocate costs between network customers on the basis of 1-CP
27
(as opposed to 1-NCP).
28
29
There are a couple of issues arising from HQT’s proposal:
•
30
First, is it appropriate to use a different determinant for rate design as
opposed to cost allocation, and
31
•
32
Second, if so, is 1-NCP the appropriate billing determinant for Native
Load/Network Integration Service?
33
165
166
HQT-4, Document 1, pages 19-20
HQT-4, Document 3, page 14
55
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
This distinction between cost allocation and rate design is well recognized by
2
regulators – including the Régie167.
3
objectives associated with each. While cost allocation focuses primarily on cost
4
tracking and cost causality, rate design considers a number of other objectives
5
such as economic efficiency, stability, practicality, etc168. Also, it is interesting to
6
note that there are a number of Canadian utilities169 which, like HQT, utilize a
7
different method for designing the rates to individual network service customers
8
than is used for purposes of allocating the revenue requirement between Native
9
Load/Network Integration service and long-term PTP service. It is also useful to
10
observe that a similar phenomenon exists on the retail side in terms of the rate
11
setting practices for these Canadian utilities. While most use 1-CP170 to allocate
12
transmission costs to their retail rate classes, for rate-setting purposes demand-
13
billed customers are virtually all charged based on their monthly NCP.
Indeed, there are frequently different
14
15
Therefore, it is not necessary for HQT to adopt the same approach when
16
designing rates for Native Load and Network Integration service as was used to
17
initially allocate costs.
18
19
HQT’s proposal to use 1-NCP at the billing parameter for Native Load/Network
20
Integration Service is at odds with the practice by other Canadian utilities with
21
OATT-type transmission tariffs:
•
22
Nova Scotia Power:
Billed monthly based on each network service’s
monthly non-coincident peak (12-NCP).
23
•
24
New Brunswick Power: Billed monthly based on each network service’s
12-NCP.
25
•
26
Saskatchewan Power: Billed monthly based on each network service’s
12-CP.
27
•
28
Manitoba Hydro: Billed monthly based on each network service’s 12-CP.
167
D-2002-0095, page 210
Phillips Jr., Charles F. The Regulation of Public Utilities, page 410
169
Specifically, BCTC, New Brunswick and Nova Scotia
170
Nova Scotia uses 3-CP and Manitoba Hydro uses 2-CP
168
56
Evidence of
William Harper
•
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
British Columbia: Billed monthly based on each network service’s 12-CP.
2
HQT’s 1-NCP and Dr. Orans’ 1-CP also both differ from the standard practice in
3
the US which is to use 12-CP (as per the FERC’s pro-forma tariff)171.
4
5
Furthermore, there are a number of the traditional rate design objectives for
6
which the use of either 12-CP or 12-NCP would be preferable to the use of 1-CP
7
(or 1-NCP) as a billing parameter:
•
8
Stability: The year-to-year rates for Native Load/Network Integration
service are likely to be more stable if based on either 12-CP or 12-NCP
9
10
(which effectively involves taking an average of 12 monthly peaks) as
11
opposed to 1-CP (which effectively involves relying on the value for just
12
one month).
•
13
Acceptability: Use of 12 months recognizes the fact that the transmission
14
assets are “used and useful” for 12 months of the year and avoids
15
concerns regarding “free-riders” that frequently arise when rates are
16
developed using coincident peak. Also, NCP is frequently considered
17
more acceptable as a billing determinant perspective since it is a value
18
over which the customer has total accountability. Customers do not have
19
the same degree of self-responsibility for their contribution to the utility’s
20
overall peak, since they frequently don’t know (in advance) when the peak
21
will occur and, indeed, in trying to avoid the peak could actually create a
22
new system peak for the utility.
•
23
Economic Efficiency: As noted in the last sentences of the previous point,
24
the use of CP billing and, particularly 1-CP billing, could lead to a
25
phenomenon known as “peak chasing” where customers, in seeking to
26
avoid the peak, actually create a new system peak and, therefore their
27
response to the price signal provides no benefit to the transmission
28
system overall.
171
HQT-4, Document 3.2, page 9
57
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
Overall, it would be more appropriate for HQT to adopt, in principle, either 12-CP
2
or 12-NCP, as the basis for billing Native Load/Network Integration customers
3
and revise its Tariffs and Conditions accordingly.
4
5
5.6
Determination of Short-term Point to Point Service Rates
6
7
HQT derives its short-term PTP service rates from its annual long-term PTP
8
service rate as follows172:
9
•
Monthly Firm Rate = Annual Rate/12 months
10
•
Monthly Non-Firm Rate = Annual Rate/12 months
11
•
Weekly Firm Rate = Annual Rate/52 weeks
12
•
Weekly Non-Firm Rate = Annual Rate/52 weeks
13
•
Daily Firm Rate = Annual Rate/52 weeks/5 days
14
•
Daily Non-Firm Rate = Annual Rate/365 days
15
•
Hourly Non-Firm Rate = Daily Non-Firm Rate/24 Hours
16
HQT does not offer hourly firm PTP service rates.
17
18
Comments
19
20
For firm short-term PTP service rates, the approach used by HQT is similar to
21
that adopted by most Canadian utilities173. It is also consistent with FERC ‘s pro-
22
forma tariff and the Appalachian method adopted by FERC for pricing peak
23
period service. Under Appalachian pricing, firm hourly rates are based on usage
24
for 16 hours per day, five days a week, and 52 weeks per year. While HQT does
25
not offer firm hourly rates, the principles underlying the Appalachian pricing
26
method support the derivation of the daily firm rate based on 5 days per week (as
27
opposed to seven).
28
172
173
HQT-4, Document 1, page 21, Table 6
HQT-6, Document 7, Question 78 a) and HQT-4, Document 3, pages 37-38
58
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
For non-firm PTP service rates, the approach used by HQT is fundamentally
2
different from that of other Canadian utilities. For other utilities, the non- firm
3
rates are “capped” at the firm rates and discounted from there as required to
4
improve system usage174. In contrast, HQT’s non-firm rates were initially
5
proposed as predetermined levels – with no provision for flexible discounting175.
6
The proposal reflected the following considerations:
7
1. The Régie’s conclusions176 in D-2002-95 that it could not approve a
8
flexible discounting policy for HQT (similar to that used in other
9
jurisdictions), due to the statutory requirements of Act, and
10
2. HQT’s conclusions, following its analysis of its past discounting practices,
11
that fixed discounts would lead (overall) to a lower short-term PTP service
12
revenues177.
13
HQT indicated178, in its initial application, that for a discount policy to be
14
successful in improving system utilization and revenues, it would have to meet
15
the following criteria:
•
16
It would have to be based on the prices differences in neighbouring
17
jurisdictions and calibrated so as to allow customers to undertake
18
transactions that would otherwise not occur, and
•
19
The prices would have to be able to vary by “path” in order to avoid a loss
of revenues.
20
21
Subsequent to the initial filing, the Régie requested179 that HQT file a discounting
22
proposal that would meet these criteria and HQT did so on August 10th, 2005180.
23
24
This evidence does not include an assessment of HQT’s new discounting
25
proposal, which would apply to the hourly off-peak short-term PTP service. It is
26
our understanding that evidence being prepared by other parties will address this
174
HQT-6, Document 7, Question 78.a and HQT-4, Document 3.1, page 7
HQT-4, Document 2, page 3
176
D-2002-95, page 282
177
HQT-2, Document 1, page 21 and HQT-2, Document 3, page 19
178
Find reference in original application other than HQT-2, Doc 5
179
HQT-2, Document 5, page 6
180
HQT filed HQT-2, Document 5.
175
59
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
topic and, therefore, this evidence has continued to focus on the topics initially
2
identified by the client.
3
4
Apart from the proposed discounting policy, a question arises as to whether HQT
5
should adopt an on-peak hourly pricing formula similar to that used by other
6
utilities (i.e., based on the Appalachian pricing formula). Based on HQT’s rate
7
derivation, such an approach would yield an on-peak hourly rate181 of
8
$17.52/MWh. Theoretically, such a rate could contribute significantly to HQT’s
9
overall revenues since hourly PTP service accounts for over 98% of total
10
projected short-term PTP revenue for 2005182 and 80% of total hourly short-term
11
service reservations (and roughly 90% of HQP’s hourly short-term service
12
reservations) are for the peak period183.
13
14
However, the evidence provided by HQT indicates that most of the use of hourly
15
short-term PTP service (in both the peak and off-peak) has been by HQP for
16
purposes of exporting power184. In such cases, the type of analyses undertaken
17
by Dr. Orans (although not perfect185) provides an indication as to the value of
18
transmission service. Dr. Orans original analyses suggested that increasing the
19
on-peak rate would raise the percentage of blocked hours from 2.5% to over
20
30%. However, based on updated information regarding transmission service
21
pricing in neighbouring jurisdictions, Dr Orans revised his analyses186. The new
22
results suggest that the currently proposed hourly transmission service rate of
23
$8.33 / MWh would block trade aimed at arbitraging between peak and off-peak
24
prices almost 20% of the time; while increasing the rate to $17.52 is likely to
25
block such trades roughly 60% of the time. This suggests that roughly doubling
26
the rate would cut in half the period of time when peak/off peak arbitrage would
181
Based on annual rated of $72.90/kW divided by 4,160 hours.
HQT-4, Document 1, page 21
183
HQD-2, Document 3, page 13
184
HQT-6, Document 8, pages 27-28, Question 18.4, Table R18.4 and HQT-2, Document 3, page 14.
185
Limited by the fact that all neighbouring jurisdictions do not have “markets” and some exports could
arise simply due to an overall available surplus. See also OC 80.f) and OC 23.c)
186
HQT-6, Document 7, Question 22 b)
182
60
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
be economic such that there would be little overall benefit to HQT implementing a
2
higher on-peak hourly rate187.
3
4
Finally, the revised hours of blocked transactions in Dr. Orans analyses188 (up
5
from 2.5% to 19.4% of the time) give rise to the question of whether or not HQT
6
should consider introducing a discount policy for hourly peak period transactions.
7
However, reducing the rate by 25% (to $6.25 / MWh) would only reduce blocked
8
hours to 12% - such that the increase in volume would not make for the loss in
9
unit revenue. Therefore, introducing a discount policy for hourly peak PTP
10
service would not be appropriate.
11
12
5.7
Consistency with Cost of Service Allocation Results
13
14
Table 8 compares the anticipated revenues for Native Load and Long-term PTP
15
service with cost allocation results from Table 5 above.
16
17
Table 8
18
Transmission Service Revenues and Costs
19
Costs
Revenue
1-CP
3-CP
Native Load Service
$2412.3 M
$2483.5 M
$2482.7 M
Long-term PTP Service
$100.7 M
$29.5 M
$30.3 M
-
$78 M
$78 M
$2591 M
$2591 M
Short-term PTP
Net Transmission Service
$2513 M
Costs
Total Transmission Service
$2591 M
Costs and Revenue
187
This analysis is similar to that performed by Dr. Orans – see HQT-6, Document 4, page 25, Question
23.1
188
HQT-6, Document 7, Question 22 b)
61
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
While Native Load revenues exceed allocated costs by slightly less than 3%, the
3
revenues from Long-term PTP service cover less than 30% of the allocated
4
costs.
5
6
These results are dramatically different than those presented by HQT189 which
7
suggested that:
•
8
Native Load Service revenues were slightly less than allocated costs (i.e.,
99.9%), and
9
•
10
Point to Point services revenues more than covered allocated costs (i.e.,
102%).
11
12
The differences in results arise from two factors. The first factor is the proposed
13
changes in the allocation factors for the cost of service allocation put forth in this
14
Evidence. The second, and more significant, is the fact that HQT has combined
15
the revenues for short-term and long-term PTP service when presenting the
16
results. Given that no costs are allocated to short-term PTP service in HQT’s
17
methodology, HQT’s presentation of the results tends to mask the under
18
recovery of costs associated with long-term PTP service.
19
20
It is inappropriate to include short-term PTP revenues with long-term PTP
21
revenues for purposes of comparing revenues and costs for the following
22
reasons:
23
•
First, this approach is inconsistent with the way the revenues from short-
24
term PTP service are treated by HQT (and the FERC pro-forma OATT) in
25
the derivation of the proposed transmission rates. In the derivation, short-
26
term PTP revenues were used to reduce the total revenue requirement to
27
be recovered from both Native Load and long-term PTP service
28
customers 190.
189
190
HQT-4, Document 1, page 25
HQT-6, Document 9, page 57, Question 46.5
62
Evidence of
William Harper
•
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Second, the approach is inconsistent with principle that both Native Load
2
and long-term PTP service customers should both benefit from the
3
offering of short-term PTP service191.
4
5
Based on these results the rates for long-term PTP service would have to be
6
increased significantly relative to those proposed by HQT in order for long-term
7
PTP service to be priced in accordance with the cost allocation results.
8
However, it should be noted that while short-term PTP rates tend to track long-
9
term PTP rates192, the FERC pro-forma tariff permits discounting for such rates
10
and, as a result, the currently proposed short-term rates could be retained even if
11
long-term PTP rates were adjusted upwards.
12
13
5.8
Ancillary Service Rates
14
15
For 2005, HQT proposes to continue to offer the six existing Ancillary Services
16
and to introduce a new Ancillary Service – Energy Receipt Imbalance service
17
which would be applicable to point to point transactions where the point of receipt
18
is located within HQT’s control area193. Since the costs of the System Control
19
service are embedded in the rates for Native Load/Network Integration and PTP
20
service, a separate charge is not required. For the remaining Ancillary Services,
21
HQT determines the rates using the same methodology as approved by the
22
Régie194 for the 2001 rates. However, the costs of generation have been
23
updated by HQP to 7.5 cents/kWh195 in order to reflect the cost of new supply as
24
per the April 2004 call for tender. In the case of the new Energy Receipt
25
Imbalance service, the methodology used mirrors that used to set the rates for
26
the already existing Energy Delivery Imbalance service196.
191
HQT-4, Document 1, page 14
HQT-6, Document 9, page 80, Question 57.1
193
HQT-4, Document 1, page 33
194
D-2002-95, page 285
195
HQT-4, Document 1, pages 28-29
196
HQT-4, Document 1, page 33
192
63
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
Finally, under HQT’s proposal the rates for Frequency Control, Spinning Reserve
3
and Non-Spinning Reserve would apply, for the first time, to PTP service where
4
the point of receipt is within HQT’s control area197.
5
6
Comments
7
8
In developing the existing Ancillary Service rates, HQT used the cost of Heritage
9
Pool energy (2.79 cents/kWh) to price the facilities supporting Voltage Control,
10
Frequency Control, Spinning Reserve and Non-Spinning Reserve services198. In
11
the current Application, HQP has used a value of 7.5 cents / kWh to set these
12
rates199. The 7.5 cents per kWh is reasonable value as it corresponds to the cost
13
of new supply for 2005 as used by HQD in its latest rate Application200.
14
15
In adjusting the Ancillary Service rates to reflect the increase in cost of supply
16
from 2.79 to 7.5 cents per kWh, it was also necessary for HQT to account for the
17
fact that the 2.79 cents is based on the point of delivery to customers whereas
18
the 7.5 cents is based on the point of delivery to the transmission system. While
19
loss factors have improved since the development of the initial Ancillary Service
20
rates, it was necessary for HQT to retain in the calculation the original loss
21
factor201 (8.74%) in order to properly adjust to the new cost of supply.
22
23
It is not clear why the original calculation202 of the rate for Frequency Control did
24
not include a loss factor adjustment. However, since the proposed rate is based
25
on a ratio of the current 7.5 cents/kWh cost and the 2.79 cents/kWh used in the
26
original calculation203, the resulting rate is correct.
197
HQT-6, Document 1, page 7, Question 4.2
HQT-6, Document 7, Question 65 a)
199
HQT-4, Document 1, pages 28-29
200
R-3541-2004, HQD-8, Document 2, pages 5-6. Note: The reported 8.06 cents/kWh must be adjusted
for losses of 7.5% to yield the cost of energy delivered to the transmission system.
201
R-3401-98, HQT-10, Document 1, page 51
202
R-3401-98, HQT-10, Document 1, page 53
203
HQT-4, Document 1, Table 9 – see footnote
198
64
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
2
In the case of the Energy Imbalance service rates, the current Energy Imbalance
3
Delivery rates apply to PTP transactions where the point of delivery is within
4
HQT’s control area. Where the quantity of energy consumed (i.e., taken at the
5
delivery point) is greater than scheduled, the cost of the imbalance (i.e., the
6
additional energy delivered) is priced at the cost of generation plus 50%. When
7
the quantity of energy consumed at the delivery point is less than scheduled, a
8
credit is granted based on 50% of the cost of Heritage Pool energy.
9
10
In its current proposal, HQT has updated the cost of generation used to value
11
deliveries greater than scheduled from the 6.94 cents/kWh underpinning the
12
existing rates204. However, HQT has failed to update the cost of Heritage Pool
13
energy (at the point of delivery to the transmission system). In the original
14
calculation the cost of Heritage Pool energy was adjusted for losses of 8.64% to
15
yield a price of 2.57 cents per kWh – prior to the 50% reduction. Current losses
16
on the transmission and distribution systems are estimated at 7.5%205. As a
17
result, the current proposal should have reflected this new information, which
18
would have yielded a credit for delivery of less than the scheduled amount of
19
$1.30 per kWh206.
20
21
HQT’s current and proposed practice of charging different rates when the
22
deliveries are greater than scheduled versus when they are less than scheduled
23
is consistent with the practices of other Canadian utilities with OATT-style
24
tariffs207. The objectives in offering the different rates are to encourage users to
25
properly schedule their usage of the transmission system and to prevent users
26
from arbitraging (where possible) between the price for energy imbalance
27
services and the price such energy can command elsewhere208.
28
204
R-3401-98, HQT-10, Document 1, page 55
R-3541-2004, HQT-8, Document 2, page 5
206
Calculated as (2.79/1.075) * 50%
207
For example, Nova Scotia, New Brunswick, Saskatchewan, Manitoba and British Columbia
208
HQT-6, Document 1, pages 49-50, Questions 20.1 and 20.2
205
65
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
HQT’s proposal includes the same rates for its new Energy Imbalance Receipt
2
Service as for its Energy Imbalance Delivery service209. As a result, the
3
comments from the earlier paragraph regarding the need to update the loss
4
factor used in the calculation also apply to the proposed credit to be paid to
5
customers when the quantities received are greater than the quantity scheduled.
6
7
The requirement that users pay for imbalances between the energy scheduled
8
and the actual energy received by the transmission provider is a departure from
9
“Energy Imbalance Service” as set out in the FERC’s pro-forma tariff which just
10
deals with delivery imbalances. However, when parties raised with the FERC the
11
fact that energy imbalance could exist at the point of generation (i.e., receipt) as
12
well as delivery FERC’s response210 was:
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
Although we agree that the second type of mismatch can occur, we
will not designate as Energy Imbalance Service a mismatch between
energy scheduled and energy generated. Energy Imbalance Service
in this Rule applies only to the obligation of the transmission
provider to correct the first type of energy mismatch, one caused
by load variations. In general, the amount of energy taken by
load in an hour is variable and not subject to the control of
either a wholesale seller or a wholesale requirements buyer. The
Energy Imbalance Service that we require as our ancillary service
has a bandwidth appropriate for load variations and should have a
price for exceeding the bandwidth that is appropriate for
excessive load variations. Although NIMO states correctly that,
where two control areas are involved, there can also be a
mismatch between energy scheduled and energy generated, NIMO has
not explained why this mismatch should have the same bandwidth
and price as our Energy Imbalance Service. Indeed, we believe it
should not.
A generator should be able to deliver its scheduled hourly energy
with precision. If we were to allow the generator to deviate
from its schedule by 1.5 percent without penalty, as long as it
returned the energy in kind at another time, this would
discourage good generator operating practice. A generation
supplier could intentionally generate less power when its
generating cost is high and make it up when its cost is lower if
the second type of mismatch is included in our Energy Imbalance
Service. Instead, a generator will have an interconnection
agreement with its transmission provider or control area
operator, and we expect that this agreement will specify the
requirements for the generator to meet its schedule, and for any
209
210
HQT-4, Document 1, page 33
FERC Order 888-A, page 164
66
Evidence of
William Harper
1
2
3
4
5
6
7
8
9
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
consequence for persistent failure to meet its schedule. This
agreement will be tailored to the parties' specific standards and
circumstances, and, although such arrangements must not be unduly
preferential or discriminatory (e.g., must be comparable for all
wholesale sellers, including the transmission provider's own
wholesale sales), we prefer not to set these standards
generically for all parties.
As a result, implementing an Energy Receipt Imbalance service that sets out the
10
consequences of a generator not meeting its schedule is compatible with the
11
FERC pro-forma tariff. However, HQT should monitor the use of service and
12
report back to the Régie during its next Rate Application, as to whether use of a
13
common deviation band for Energy Delivery and Energy Receipt services is
14
appropriate.
15
16
Finally, HQT proposes that the rates for Frequency Control, Spinning Reserve
17
and Non-Spinning Reserve be applicable to all point to point services (not just
18
those where the delivery point is located in the Quebec control zone). This
19
proposal would substantially increase the revenue accruing to HQP211 for
20
Ancillary Services. However, the bulk of the revenue will be generated by HQP,
21
who, in turn, is the service provider to whom the revenues are to be remitted.
22
The net increase in revenue (due to use of point to point services by 3rd parties)
23
appears to be in the order of $300,000.
24
25
HQT’s rationale is that transmission customers, using its system to deliver power
26
to other inter-connected networks not in its control area, also benefit from these
27
services and should pay for them. Again, this proposal differs from the FERC
28
pro-forma tariff wherein such services are only invoiced when the load is in the
29
Transmitter’s control area. However, there is a rationale for charging both types
30
of transactions, since proper frequency must be maintained for all electricity
31
carried by the transmitter and the spinning reserves are to ensure the integrity of
32
the transmission system for all users.
211
HQT-6, Document 1, page 7, Question 4.2, Table R.4.2
67
Evidence of
William Harper
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
1
6
CONCLUSIONS
2
A summary of the key comments and conclusions is set out below.
3
4
6.1
HQT’s Cost Allocation Methodology
5
6
Definition of Functions and Sub-Functions
7
8
•
statutory definition of transmission, which includes generation-related
9
transmission assets.
10
11
The cost allocation functions proposed by HQT are reasonable given the
•
The assignment of the Churchill Falls connection to the Interconnections
12
function, as opposed to the Generation Connection function, is questionable
13
but manageable provided the costs continue to be tracked in a separate
14
sub-function.
15
•
The assignment of transmission assets that carry electricity from generation
16
zones to the Network function is also questionable. However, reassigning
17
the assets to the Generation Connection function will not impact on the
18
results unless the Régie determines that Generation Connection facilities
19
should be allocated to services based on demand and energy
20
considerations.
21
•
transformer stations serving HQD.
22
23
Customer Connections should also include radial lines that connect to HV
•
The Control Centre function should be considered a “main function” and the
24
costs allocated through to services (as opposed to being pro-rated over the
25
other main functions).
68
Evidence of
William Harper
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Assignment of Costs to Functions
2
3
•
HQT’s proposals regarding the assignment of rate base to functions are
4
reasonable except for the treatment of Working Capital, where the component
5
parts can easily be assigned using more precise factors. In particular, fixed
6
and intangible assets should be used to assign the working cash requirement
7
to functions.
8
•
HQT’s proposals regarding the assignment of cost of service to functions are
reasonable except for the treatment of the amortization of other expenses
9
10
where (again) the component parts can easily be assigned using more
11
precise factors. Specifically, the assignment of the component parts of the
12
annual amortization could readily be done in the same manner as the
13
assignment of the remaining unamortized balances was accomplished for the
14
rate base.
15
•
Finally, there is a need to clarify the process used for assigning External
Billings associated with Facilities Operations.
16
17
18
Classification of Cost Functions
19
20
•
HQT’s proposal to classify transmission costs as demand-related is generally
21
reasonable. One could question the treatment of Generation Connection
22
costs as 100% demand-related. However, the impact on the overall
23
allocation results would be minor and there is no generally accepted way to
24
classify generation connection costs (or indeed generation costs overall) as
25
demand and energy-related.
26
•
The only exception to the 100% demand classification is the Control Centre
27
function. Classification of this function’s costs as energy-related would better
28
reflect the role of the associated activities.
69
Evidence of
William Harper
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
Allocation of Costs to Services
2
3
•
The allocation methodology needs to specifically (and separately) recognize
4
short-term PTP service so as to properly manage any costs associated with it
5
and properly allocate the benefits (i.e., the net revenues) from short-term PTP
6
service.
7
•
purposes of allocating demand-related costs to services.
8
9
The use of 3-CP (December, January and February) is preferable to 1-CP for
•
The costs in the Generation Connection and Network functions should each
10
be allocated to Native Load and long-term PTP service based on the total 3-
11
CP loads for each – where long-term PTP loads are determined based on
12
reservations.
13
•
Service, as proposed by HQT.
14
15
•
•
The costs in the Support function should be pro-rated over the other five
functions – prior to the costs in each of the five being allocated to services.
18
19
The costs in the Control Centre function should be allocated to Native Load,
long-term PTP and short-term PTP services based on energy.
16
17
Customer Connection costs should be directly assigned to Native Load
•
The net revenues attributable to short-term PTP service (i.e., revenues less
20
allocated costs) should be pro-rated over the other two services based on the
21
total costs allocated to each.
70
Evidence of
William Harper
6.2
1
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
HQT’s Derivation of Transmission Service Rates
2
3
Allocation of Revenue Requirement Between Native Service and Long-Term PTP
4
Service
5
6
•
both Native Load and long-term PTP service is appropriate.
7
8
HQT’s use of revenue from short-term PTP service to reduce the rates for
•
The use of 3-CP (December, January and February) is preferable to 1-CP for
purposes of allocating the net revenue requirement between Native Load and
9
long-term PTP service.
10
11
12
Long-Term PTP Service Rates
13
14
•
As per HQT’s proposal, the long-term PTP service rate should reflect the
15
annual rate derived from the foregoing allocation of the revenue requirement
16
between services.
17
18
Native Load/Network Integration Service Rates
19
20
•
potential Network Integration customers based on 1-CP or 1-NCP.
21
22
There is a need to clarify whether HQT’s proposal allocates costs between
•
It would be preferable to allocate the transmission costs between Native Load
and Network Integration customers based on 12-NCP (or failing this 12-CP).
23
24
25
Consistency with Cost Allocation Methodology
26
27
28
29
30
•
A comparison of the revenues derived from rates based on FERC’s pro-forma
OATT and the results of the cost allocation methodology indicates that:
o Native Load Service revenues are only slightly above allocated costs,
but
71
Evidence of
William Harper
o Long-term PTP revenues are significantly below allocated costs.
1
2
Hydro-Québec TransÉnergie
R-3549-2004 Phase 2
•
This result is considerably different from that presented in HQT’s evidence
3
primarily due to the treatment of revenues from short-term PTP service which
4
HQT combined with long-term PTP service for purposes of comparing costs
5
and revenues by service. In the case of HQT’s proposal, this treatment of
6
short-term PTP revenues offsets the higher cost allocated to long-term PTP
7
service, by virtue of the unique allocation treatment of Churchill Falls and the
8
interconnections.
9
10
Short-Term PTP Rates
11
12
•
HQT’s proposed short-term PTP rates are reasonable.
13
14
Ancillary Service Rates
15
16
•
HQT’s proposed Ancillary Service rates are reasonable with the following
17
exception of the proposed Energy Receipt and Energy Delivery Imbalance
18
rates where the rate derived from the cost of the Heritage Pool needs to be
19
updated for the most recent loss estimates. This would impact the Energy
20
Receipt Imbalance rate when more energy is received by the transmission
21
system than scheduled and the Energy Delivery Imbalance rate when less
22
energy is taken from the transmission system than scheduled.
72
APPENDIX A
CV FOR ECS CONSULTANT
73
ECONALYSIS CONSULTING SERVICES
William O. Harper
Mr. Harper has over 20 year experience in the design of rates and the regulation of electricity
utilities. He has testified as an expert witness on rates before the Ontario Energy Board from
1988 to 1995, and before the Ontario Environmental Assessment Board. He was responsible for
the regulatory policy framework for Ontario municipal electric utilities and for the regulatory
review of utility submissions from1989 to 1995. Mr. Harper coordinated the participation of
Ontario Hydro (and its successor company Ontario Hydro Services Company) in major public
reviews involving Committees of the Ontario Legislature, the Ontario Energy Board and the
Macdonald Committee. He has served as a speaker on rate and regulatory issues for seminars
sponsored by the APPA, MEA, EPRI, CEA, AMPCO and the Society of Management
Accountants of Ontario. Since joining ECS, Mr. Harper has provided consulting support for
client interventions on energy and telecommunications issues before the Ontario Energy Board,
Manitoba Public Utilities Board, Québec’s Régie de l’énergie, British Columbia Utilities
Commission, and CRTC. He has also appeared before the Manitoba’s Public Utilities Board, the
Manitoba Clean Environment Commission and Quebec’s Régie de l’énergie. Bill is currently a
member of the Ontario Independent Electricity Market Operator’s Technical Panel.
EXPERIENCE
Econalysis Consulting Services- Senior Consultant
2000 to present
•
Responsible for supporting client interventions in regulatory proceedings, including
issues analyses & strategic direction, preparation of interrogatories, participation in
settlement conferences, preparation of evidence and appearance as expert witness (where
indicated by an asterix).
•
Electricity
o IMO 2000 Fees (OEB)
o Hydro One Remote Communities Rate Application 2002-2004
o OEB - Transmission System Code Review (2003)
o OEB - Distribution Service Area Amendments (2003)
o OEB – Regulated Asset Recovery (2004)
o OEB – 2006 Electricity Rate Handbook Proceeding*
o BC Hydro IPP By-Pass Rates
o WKP Generation Asset Sale
o BC Hydro Heritage Contract Proposals
o BC Hydro’s 2004/05 and 2005/06 Revenue Requirement Application
o BC Transmission Corporation – Open Access Transmission Tariff Application 2004
o BCTC’s 2005/06 Revenue Requirement Application
o BC Hydro’s CFT for Vancouver Island Generation – 2004
74
o
o
o
o
o
o
o
o
o
o
o
BC Hydro’s 2005 Resource Expenditure and Acquisition Plan
Fortis BC’s 2005 Revenue Requirement Application
Hydro Québec-Distribution’s 2002-2011 Supply Plan*
Hydro Quebec-Distribution’s 2002-2003 Cost of Service and Cost Allocation
Methodology*
Hydro Québec-Distribution’s 2004-2005 Tariffs*
Hydro Québec – Distribution’s 2005/2006 Tariff Application*
Hydro Québec – Distribution’s 2005-2014 Supply Plan*
Manitoba Hydro’s Status Update Re: Acquisition of Centra Gas Manitoba Inc.*
Manitoba Hydro’s Diesel 2003/04 Rate Application*
Manitoba Hydro’s 2004/05 and 2005/06 Rate Application*
Manitoba Hydro/NCN NFAAT Submission re: Wuskwatim*
•
Natural Gas Distribution
o Enbridge Consumers Gas 2001 Rates
o BC Centra Gas Rate Design and Proposed 2003-2005 Revenue Requirement
o Rate of Return on Common Equity (BCUC)
o Terasen Gas (Vancouver Island) LNG Storage Project (2004)
•
Telecommunications Sector
o Access to In-Building Wire (CRTC)
o Extended Area Service (CRTC)
o Regulatory Framework for Small Telecos (CRTC)
•
Other
o Acted as Case Manager in the preparation of Hydro One Networks’ 2001-2003
o Distribution Rate Applications
§ Supported the preparation of Distribution Rate Applications for various
Ontario municipal electric utilities.
o Supported the implementation of OPG’s Transition Rate Option program prior to
Open Access in Ontario
o Prepared Client Studies on various issues including:
§ The implications of the 2000/2001 natural gas price changes on natural
gas use forecasting methodologies.
§ The separation of electricity transmission and distribution businesses in
Ontario.
§ The business requirements for Ontario transmission owners/operators.
§ Various issues associated with electricity supply/distribution in remote
communities
o Member of the OEB’s 2004 Regulated Price Plan Working Group
75
Hydro One Networks
Manager - Regulatory Integration, Regulatory and Stakeholder Affairs
(April 1999 to June 2000)
• Supervised professional and administrative staff with responsibility for:
o providing regulatory research and advice in support of regulatory applications and
business initiatives;
o monitoring and intervening in other regulatory proceedings;
o ensuring regulatory requirements and strategies are integrated into business
planning and other Corporate processes;
o providing case management services in support of specific regulatory
applications.
• Acting Manager, Distribution Regulation since September 1999 with responsibility for:
o coordinating the preparation of applications for OEB approval of changes to
existing rate orders; sales of assets and the acquisition of other distribution
utilities;
o providing input to the Ontario Energy Board’s emerging proposals with respect to
the licences, codes and rate setting practices setting the regulatory framework for
Ontario’s electricity distribution utilities;
o acting as liaison with Board staff on regulatory issues and provide regulatory
input on business decisions affecting Hydro One Networks’ distribution business.
• Supported the preparation and review before the OEB of Hydro One Networks’
Application for 1999-2000 transmission and distribution rates.
Ontario Hydro
Team Leader, Public Hearings, Executive Services (APR. 1995 TO APR. 1999)
• Supervised professional and admin staff responsible for managing Ontario Hydro’s
participation in specific public hearings and review processes.
• Directly involved in the coordination of Ontario Hydro’s rate submissions to the Ontario
Energy Board in 1995 and 1996, as well as Ontario Hydro’s input to the Macdonald
Committee on Electric Industry Restructuring and the Corporation’s appearance before
Committees of the Ontario Legislature dealing with Industry Restructuring and Nuclear
Performance.
Manager – Rates, Energy Services and Environment (June 1993 to Apr. 95)
Manager – Rate Structures Department, Programs and Support Division
(February 1989 to June 1993)
• Supervised a professional staff with responsibility for:
o Developing Corporate rate setting policies;
o Designing rates structures for application by retail customers of Ontario Hydro
and the municipal utilities;
o Developing rates for distributors and for the sale of power to Hydro’s direct
industrial customers and supporting their review before the Ontario Energy
Board;
o Maintaining a policy framework for the execution of Hydro’s regulation of
municipal electric utilities;
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o Reviewing and recommending for approval, as appropriate, municipal electric
utility submissions regarding rates and other financial matters;
o Collecting and reporting on the annual financial and operating results of
municipal electric utilities.
Responsible for the development and implementation of Surplus Power, Real Time
Pricing, and Back Up Power pricing options for large industrial customers.
Appeared as an expert witness on rates before the Ontario Energy Board and other
regulatory tribunals.
Participated in a tariff study for the Ghana Power Sector, which involved the
development of long run marginal cost-based tariffs, together with an implementation
plan.
Section Head – Rate Structures, Rates Department
November 1987 to February 1989
• With a professional staff of eight responsibilities included:
o Developing rate setting policies and designing rate structures for application to
retail customers of municipal electric utilities and Ontario Hydro;
o Designing rates for municipal utilities and direct industrial customers and
supporting their review before the Ontario Energy Board.
• Participated in the implementation of time of use rates, including the development of
retail rate setting guidelines for utilities; training sessions for Hydro staff and customers
presentations.
• Testified before the OEB on rate-related matters.
Superintendent – Rate Economics, Rates and Strategic Conservation Department
February 1986 to November 1987
• Supervised a Section of professional staff with responsibility for:
o Developing rate concepts for application to Ontario Hydro’s customers, including
incentive and time of use rates;
o Maintaining the Branch’s Net Revenue analysis capability then used for screening
marketing initiatives;
o Providing support and guidance in the application of Hydro’s existing rate
structures and supporting Hydro’s annual rate hearing.
Power Costing/Senior Power Costing Analyst, Financial Policy Department
April 1980 to February 1986
• ?Duties included:
o Conducting studies on various cost allocation issues and preparing
recommendations on revisions to cost of power policies and procedures;
o Providing advice and guidance to Ontario Hydro personnel and external groups
on the interpretation and application of cost of power policies;
o Preparing reports for senior management and presentation to the Ontario Energy
Board.
• Participated in the development of a new costing and pricing system for Ontario Hydro.
Main area of work included policies for the time differentiation of rates.
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Ontario Ministry of Energy
Economist, Strategic Planning and Analysis Group
April 1975 to April 1980
• ?Participated in the development of energy demand forecasting models for the province of
Ontario, particularly industrial energy demand and Ontario Hydro’s demand for primary
fuels.
• Assisted in the preparation of Ministry publications and presentations on Ontario’s
energy supply/demand outlook.
• Acted as an economic and financial advisor in support of Ministry programs, particularly
those concerning Ontario Hydro.
EDUCATION
Master of Applied Science – Management Science
• University of Waterloo, 1975
• Major in Applied Economics with a minor in Operations Research
• Ontario Graduate Scholarship, 1974
Honours Bachelor of Science
• University of Toronto, 1973
• Major in Mathematics and Economics
• Alumni Scholarship in Economics, 1972
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