Alberta Electric System Operator (AESO) 2005/2006 General Tariff Application August 28, 2005

Decision 2005-096
Alberta Electric System Operator (AESO)
2005/2006 General Tariff Application
August 28, 2005
ALBERTA ENERGY AND UTILITIES BOARD
Decision 2005-096: Alberta Electric System Operator (AESO)
2005/2006 General Tariff Application
Application No. 1363012
August 28, 2005
Published by
Alberta Energy and Utilities Board
640 – 5 Avenue SW
Calgary, Alberta
T2P 3G4
Telephone: (403) 297-8311
Fax: (403) 297-7040
Web site: www.eub.gov.ab.ca
Contents
1
INTRODUCTION................................................................................................................. 1
2
2005 OWN COST OUTSTANDING MATTERS .............................................................. 2
2.1 Incentive Compensation Program Parameters ............................................................... 2
2.2 Disallowance of Costs .................................................................................................... 3
3
2005 PHASE I REVENUE REQUIREMENT ................................................................... 4
3.1 2005 Revenue Requirement and Deferral Account Treatment ...................................... 4
4
2006 PHASE I REVENUE REQUIREMENT ................................................................... 5
4.1 2006 Own Costs Process ................................................................................................ 5
4.2 Forecast Methodology.................................................................................................... 6
4.2.1 Key Forecast Inputs .......................................................................................... 6
4.3 TFO Wires Related Costs............................................................................................... 8
4.4 Non-Wires Costs ............................................................................................................ 9
4.5 Ancillary Services Forecast.......................................................................................... 12
4.6 Transmission Losses .................................................................................................... 13
5
RATE DESIGN ................................................................................................................... 13
5.1 Legislative Requirements ............................................................................................. 13
5.2 Rate Design Principles ................................................................................................. 15
5.3 Transmission Wires Cost Causation Study (TCCS) .................................................... 17
5.3.1 Functionalization of Costs .............................................................................. 19
5.3.2 Classification of Costs .................................................................................... 21
5.4 Ancillary Services Cost of Service Study .................................................................... 24
5.4.1 Classification of Ancillary Services................................................................ 25
5.5 Demand Transmission Service Rate Design ................................................................ 25
5.5.1 Unbundling ..................................................................................................... 25
5.5.2 Classification of Costs .................................................................................... 26
5.5.3 Ratchet ............................................................................................................ 29
5.5.4 Standby Tariffs................................................................................................ 30
5.6 Supply Transmission Service Rate (STS) .................................................................... 30
5.7 Fort Nelson BC Rate .................................................................................................... 30
5.8 Export Rates ................................................................................................................. 33
5.8.1 Firm Export/Import Rates ............................................................................... 33
5.8.2 Generator Remedial Action Scheme (GRAS) ................................................ 36
5.8.3 Opportunity Import and Export Rates............................................................. 37
5.9 Primary Service Credit and Finalization of COS Credits ............................................ 38
5.10 Opportunity Service Rates ........................................................................................... 40
5.11 Rate Riders ................................................................................................................... 41
5.11.1 Rider B .......................................................................................................... 41
5.11.2 Rider C .......................................................................................................... 41
5.11.3 Rider E .......................................................................................................... 41
6
TERMS AND CONDITIONS – CONTRIBUTION POLICY........................................ 42
6.1 Customer Contribution Policy ..................................................................................... 42
6.1.1 High Level Policy Principles .......................................................................... 42
6.1.2 Designation of System-Related Costs ............................................................. 47
EUB Decision 2005-096 (August 28, 2005) • i
6.1.3 “Standard” and “Optional” Interconnection Facilities .................................... 49
6.1.3.1
AESO Standard Service Definition ................................................................ 49
6.1.4 Maximum Investment Formula....................................................................... 55
6.1.5 Contribution Waivers for Expansion at Multiple Customer PODs ................ 58
6.1.6 Other Contribution Policy Issues .................................................................... 60
6.1.6.1
Application of Contribution Policy to Dual-Use Sites ................................... 60
6.1.6.2
Staged Load .................................................................................................... 62
6.1.6.3
Distribution vs Transmission Interconnections .............................................. 62
6.1.6.4
Discount Rates ................................................................................................ 63
6.1.6.5
Common Facilities .......................................................................................... 63
6.1.6.6
Conditions for Customer Contribution Adjustments ...................................... 66
6.1.6.7
Pre-Paid Operations and Maintenance Charge ............................................... 66
6.2 Generator System Contribution ................................................................................... 69
6.3 Contribution Policy Next Steps.................................................................................... 73
6.3.1 Contribution Policy Implementation Timing .................................................. 73
6.3.2 Disco/AESO Contribution Policy Harmonization .......................................... 73
6.4 TransCanada Standard Interconnection Facilities Complaint ...................................... 73
7
TERMS AND CONDITIONS – OTHER ......................................................................... 74
7.1 System Access Applications ........................................................................................ 74
7.2 Right of “Set-Off” ........................................................................................................ 75
7.3 TFO Investment in Optional Facilities Constructed for Distribution Facility Owners
(Discos) ................................................................................................................................. 76
7.4 Merchant Transmission Interconnections .................................................................... 78
7.5 Contract Term, Reductions, and Termination .............................................................. 80
7.6 Letters of Credit Security in Respect of Construction Projects ................................... 83
7.7 Consistency, Business Practice Documents and Other T&C Issues ............................ 84
8
OTHER MATTERS ........................................................................................................... 88
8.1 Disposition of Outstanding Board Directions .............................................................. 88
9
REFILING OF APPLICATION ....................................................................................... 91
10 ORDER ................................................................................................................................ 91
APPENDIX A – RATE DESIGN SPREADSHEET ................................................................ 92
APPENDIX 1 – HEARING PARTICIPANTS ......................................................................... 93
APPENDIX 2 – SUMMARY OF BOARD DIRECTIONS ..................................................... 95
APPENDIX 4 – ABBREVIATIONS ....................................................................................... 101
ii • EUB Decision 2005-096 (August 28, 2005)
2005/2006 General Tariff Application
Alberta Electric System Operator
To conclude, with regard to the rate design principles discussed above, the Board considers that
cost causation must be afforded the most weight in attempting to balance these sometimes
competing principles when evaluating a proposed rate design. That is, in reviewing a proposed
rate design, the Board finds that it is critical that the rate design proposed ensures that a customer
that causes a cost must be prepared to pay that cost. The principle of rate shock, which can
conflict with this cost causation principle, must take a secondary consideration to cost causation
in arriving at an appropriate rate design. The balance of the criteria can usually be seen as
complimentary to cost causation. On balance, if rates reflect causation, barring unusual
regulatory events such as regulatory lag or a dramatic change in cost structure, there should be
little need to be concerned about the principles of rate shock and gradualism.
The Board has considered all of these factors in arriving at its preferred classification of costs
and rate design, as contained in sections 5.3, 5.4 and 5.5 of this Decision.
5.3
Transmission Wires Cost Causation Study (TCCS)
The AESO filed a cost of service study in response to Direction 21 contained in Decision 200132. The TCCS covered the wires portion of transmission costs only and a summary of the study
results was produced at pages 4-6 of Section 4 of the Application.
The TCCS investigated transmission wires costs and included an analysis of net book value data
by transmission facility from the four major transmission facility owners in Alberta, namely,
AltaLink, ATCO Electric, Enmax, and EPCOR. The study assessed, or “sub-functionalized”,
transmission wires costs to bulk system, local system, and POD (including radial lines
exclusively used by a single POD) functions based on three approaches: voltage level,
economics, and volume-distance. The study’s final recommendation was functionalization based
on the average of the three methods, these being voltage level, economics and MW-kM. The
three methods are described in detail in the Application.27
The TCCS also classified costs as demand-related, usage-related, or customer-related, based on
zero intercept and minimum system approaches to determine the principal drivers of costs within
each function. The TCCS results were summarized in Tables 4.2.1 and 4.2.228 of the Application
and are reproduced below:
Table 4.2.1
Function
Bulk System
Local System
POD
Total
Note:
Functionalized and Classified Transmission Wires Costs, $ 000 000
Classification
Total
Demand
Usage
Customer
$144.6
$117.9
$ 26.7
$ 60.2
49.7
10.5
147.8
63.7
1.0
83.1
$352.6
$231.2
$ 38.3
$ 83.1
Totals may not add due to rounding
For rate design purposes, the functionalized and classified wires costs are generally converted to
percentages of total costs, as provided in Table 4.2.2.
27
28
Appendix B, pages 13-32 of the Wires Cost of Service Study or TCCS
Section 4, P. 5 of the Application
EUB Decision 2005-096 (August 28, 2005) • 17
2005/2006 General Tariff Application
Table 4.2.2
Function
Bulk System
Local System
POD
Total
Note:
Alberta Electric System Operator
Functionalized and Classified Transmission Wires Costs (“Pure”), % of Total
Classification
Total
Demand
Usage
Customer
41.0%
33.4%
7.6%
17.1%
14.1%
3.0%
41.9%
18.1%
0.3%
23.6%
100.0%
65.6%
10.9%
23.6%
Totals may not add due to rounding
For comparison, the AESO noted the current AESO DTS rate was based on transmission wires
costs classified 60% as demand-related, 40% as usage-related, and 0% as customer-related.
Dr. Rosenberg, in evidence filed on behalf of the ADC, was generally supportive of the TCCS
but expressed reservations regarding the minimum system analysis that PSTI used to support its
recommended classification of transmission wires costs into demand and energy components.
Specifically, Dr. Rosenberg stated the minimum system approach led to an overstatement of the
energy portion of the wires costs. Apart from this concern, Dr. Rosenberg indicated that other
aspects of the PSTI study reasonably adhered to the tenets of cost causation. Therefore, while not
endorsing the minimum system component of PSTI’s analysis, Dr. Rosenberg considered it was
reasonable to accept the results of the study for the purpose of designing DTS rates in this case.
IPCAA submitted evidence prepared by Drazen Consulting. IPCAA noted that the TCCS had not
attempted to allocate the costs among various classes of service and stated that the purpose of
defining rate classes was to recognize differences in costs that should be appropriately
recognized between groups of customers. Absent this consideration, IPCAA considered the
usefulness of the TCCS to be limited. IPCAA suggested some insight into differences in
behaviour that give rise to cost incurrence may have been useful to examine the possible need to
distinguish cost responsibility among sub-groups of AESO customers.
IPCAA also noted that the study claimed that maximum stress upon the system did not coincide
with system peak. IPCAA disagreed with this finding on the basis that this claim was based upon
an examination of very few of the bulk lines in the Province.
Both IPCAA and EnCana claimed that POD costs may have been overstated in the
functionalization step due to the use of Net Book Value (NBV) in the analysis. They maintained
that, as POD costs were of a more recent vintage and as no major new bulk lines had been
constructed for several years, the use of NBV would tend to distort the results of the study,
causing POD costs to be more heavily weighted. FIRM concurred with this latter claim and
suggested that replacement costs new (RCN) be used rather than NBV.
EnCana also claimed that functionalization of wires costs on the basis of voltage was flawed as it
was inconsistent with the AESO’s approach to planning and that some of the lower voltage lines
still in use may have originally been built to serve the bulk function. EnCana suggested the
findings of the study should be rejected and that the Board should instead rely on the
functionalization proposed by the AESO in the Application.
In addition to its comments respecting the use of RCN, FIRM also suggested that high side
switches and bus work be functionalized as local costs rather than POD related costs, noting the
18 • EUB Decision 2005-096 (August 28, 2005)
2005/2006 General Tariff Application
Alberta Electric System Operator
testimony of Mr. Reimer to that effect.29 The Board notes, however, Mr. Reimer stated that the
cost information received from the utilities did not contain sufficient detail to allow for the
detailed breakdown suggested by FIRM.
TCE expressed concern over the amount AESO proposed to use as the Regulated Generation
Unit Connection Costs (RGUCC).
The Board acknowledges the above suggestions and concerns of the parties and will address
them in more detail below. The Board notes, however, that the TCCS was the only cost of
service study filed in this process. Furthermore, the Board notes that no party, with the exception
of EnCana, has questioned that the study is directionally incorrect or suggested that it be ignored
by the Board. Indeed, both IPCAA and ADC have used the study as evidence to bolster their
arguments for a higher demand related component in the final rate design.
The Board considers the TCCS to be an excellent first step and commends the AESO and
Mr. Reimer for their initiative and effort in this regard. The Board will rely upon the results of
the study in the development of its approved rate design.
5.3.1
Functionalization of Costs
As noted above, the study assessed, or “sub-functionalized”, transmission wires costs to bulk
system, local system, and POD (including radial lines exclusively used by a single POD)
functions based on three approaches: voltage level, economics, and volume-distance. The study’s
final recommendation was functionalization based on the average of the three methods.
The parties raised some concerns with the functionalization of costs but, in the Board’s view,
appeared to accept the study as reasonable.
In the evidence of Dr. Rosenberg,30 the ADC stated the following:
PSTI considered three different approaches to determine the transmission wires
functional categories: 1) voltage level, 2) economics and 3) MW-km. The three methods
provide results that are somewhat similar, particularly for the voltage level and MW-km
approaches. The POD function is the same in all three approaches. The variation occurs
between bulk and local system. According to PSTI, all three methods have strengths and
weakness. Since this type of study is relatively new, PSTI recommended that
functionalization be based on the average results of the three methods. The resulting
functionalization is 45.7% bulk system, 15.7% local system and 38.6% point of delivery.
I support the proposed functionalization of the transmission system as reasonable.
IPCAA noted that the TCCS used depreciated historical book costs and stated the relative
weighting of the cost of various functions will differ whether they are based on current costs or
depreciated original cost. IPCAA stated that no major transmission has been built in Alberta in
many years. This, combined with the addition of PODs as load has continued to grow, means
that POD costs were likely more heavily weighted in the present analysis than would be the case
if all assets were of similar vintage. Both EnCana and FIRM supported IPCAA’s claim.
In its reply, the AESO stated:
29
30
T241, L. 2
Rosenberg Evidence, page 21
EUB Decision 2005-096 (August 28, 2005) • 19
2005/2006 General Tariff Application
Alberta Electric System Operator
Examining the depreciation evidence filed in AltaLink’s 2004-2007 GTA as referenced
by EnCana, one finds the following information for AltaLink’s two largest asset
accounts:
Substation Facilities: Transformers and Regulators
Average Service Life (Survivor Curve) 38 years
Composite Remaining Life 24.2 years
Transmission Plant (Lines): Transmission Facilities
Average Service Life (Survivor Curve) 42 years
Composite Remaining Life 23.0 years
The AESO submits that these two accounts demonstrate that both substation and line
facilities have similar lives and are of comparable vintage, and any resulting variance of
the approximately 50% of TFO costs represented by depreciation and operating and
maintenance expense would not be substantive enough to lead to rejection of the
Transmission Cost Causation Study as recommended by EnCana.31
The Board notes that, while the amount of dollars related to the bulk system may increase in the
future, and therefore the percentage of costs allocated to bulk system costs will increase, this will
not, however, decrease the absolute dollars allocated to POD costs. Moreover, it is NBV which
drives the return, tax and depreciation calculations of the TFO revenue requirements. As these
items comprise the bulk of the revenue requirement of the TFOs, the Board considers NBV to be
an appropriate basis upon which to base the functionalization of costs. For all of the above
reasons, the Board does not share the concern of IPCAA and EnCana.
FIRM and EnCana submitted that the use of voltage level to differentiate between bulk and local
wires may not be accurate since older, low voltage lines may have originally been constructed to
serve as bulk lines but would now be classified as local lines. This, they argued, could distort the
amounts allocated to each function, lowering bulk costs and raising local related wires costs.
EnCana stated that this approach was not consistent with the AESO’s planning, noting that
138kv and 240kv lines were often substitute technical options for the same transmission need.
The Board notes that three different approaches were used to functionalize costs and Mr. Reimer
described the three approaches in detail at pages 20 to 33 of the TCCS. In the Board’s view, Mr.
Reimer was very direct and candid in describing the strengths and weaknesses of the approaches.
In particular, Mr. Reimer stated the following:
The three options provide different views of how transmission property can be
functionalized in an objective way. Subjective functionalization was rejected because the
results were not repeatable, and there was no assurance that a reasonable group of experts
could come to an agreement with respect to functionalization of transmission property.
The three methods provide results that are somewhat similar. The POD definition does
not change and the functionalization of POD property remains stable. The variation
occurs as to the distinction between Bulk System and Local System.
All three methods have strengths and weaknesses. We consider that the MW-kM method
is the strongest because it most closely aligns the purpose of transmission facilities to
31
AESO Reply Argument page 12.
20 • EUB Decision 2005-096 (August 28, 2005)
2005/2006 General Tariff Application
Alberta Electric System Operator
their functional category. Since this type of study is relatively new, we recommend that
the functionalization be based on the average results of the three methods.32
The Board considers that the averaging of the three different approaches provides sufficient
balance to the findings of the TCCS.
Finally, the Board notes that TCE expressed concern with the amount the AESO proposed to
allocate to RGUCC claiming it was too high and was just a placeholder as per Decision U97065.
In reply, the AESO acknowledged that although the RGUCC costs were established as a
placeholder in Decision U97065, additional evidence was submitted during EAL’s (ESBI
Alberta Ltd.)1999-2000 GTA proceeding, resulting in the following conclusion in
Decision 2000-1 (p. 119):
Although Mr. Crowe noted the shortcomings and possible inaccuracies of his study, the
Board accepts his results as confirming the reasonableness of the $43.9 million deemed
by the Board to be generation connection costs for existing generators.
The AESO submitted that the EUB’s acceptance removed the “placeholder” nature of the
RGUCC and provided a basis for continuing it as determined in Decision 2000-1. The Board
agrees.
The Board, having addressed the concerns of the parties with respect to the functionalization
proposed in the TCCS, accepts the findings of the TCCS as reasonable and will rely upon them
in its final approved rate design.
5.3.2
Classification of Costs
The TCCS used a minimum system approach to classify bulk and local wires costs and a zero
intercept approach to classify POD related costs. The TCCS also noted that a complicating factor
in classifying the costs of the bulk system was the fact that the time of maximum stress on the
bulk system did not coincide with peak load conditions. The TCCS proposal for the classification
of costs is detailed at pages 34-45 of the TCCS.
ADC was critical of the use of the minimum system approach for bulk and local wires costs.
ADC claimed that such an approach was unorthodox and was generally used to classify
distribution costs between demand and customer-related components. ADC noted that system
investment was lumpy and the lead time for transmission projects was frequently much longer
than for generation projects. ADC maintained that the fact that the transmission grid may be
configured to exceed the system’s minimum requirements does not imply that the excess
transmission investment was constructed to minimize energy costs.
IPCAA was also critical of the TCCS use of a minimum system analysis. IPCAA claimed that
there was no evidence that past practice was to increase conductor size to reduce line losses, that
conductor optimization or size could not be generalized and that it was difficult to generalize
about loss savings given that losses varied with the load on a line.
32
TCCS, page 33
EUB Decision 2005-096 (August 28, 2005) • 21
2005/2006 General Tariff Application
Alberta Electric System Operator
IPCAA was also critical of the TCCS for attempting to define demand in terms of coincident
load at maximum system stress (CLMS), noting that the TCCS only reviewed two bulk lines and
that CLMS included significant opportunity transactions.33 IPCAA noted that Mr. Reimer
himself stated:
A. MR. REIMER: No. I think generally I would expect peak stress on the Bulk System to
be more coincident to the system peak load than what was found, in this case, on the
north-south corridor:34
IPCAA appeared to agree with the TCCS that a portion of POD costs could be classified as
customer-related and in their rate design proposal have advocated the implementation of a
customer charge.
EnCana supported IPCAA’s criticism of the TCCS, stating that there was no evidence that the
minimum system approach had been used in any other jurisdiction. Specifically EnCana
submitted that PSTI's use of the minimum system approach was inappropriate because it did not
attempt to identify the causes behind transmission expansion. Instead, it only reflected the
capacity-optimization decisions once a primary ‘need’ exists. In EnCana’s view, the driver of the
primary ‘need’ is the central question that must be addressed in any sound cost causation study.
The Board agrees that the use of a minimum system analysis may be somewhat unorthodox, as
described by ADC. However, the Board notes the following passages from the TCCS:35
The nature of cost causation for transmission service is an evolving science. The cost of
transmission service within the context of the vertically integrated structure was small in
comparison to total cost and therefore transmission costs were not normally the focus of
attention.
…
Performing a Cost of Service Study on transmission alone is not a common practice and
therefore, there is no one common or standardized method for conducting such a study.
The Board notes that the contentious point of the minimum system analysis is that it maintains
embedded costs are incurred to optimize losses. In its reply argument the AESO stated the
following:36
ADC stated (ADC Argument, p. 19) that “the only contentious part of the study was the
use of the minimum size method to determine that 11 percent of the costs were energy
related.” IPCAA argued (IPCAA Argument, p. 8-9) that the Transmission Cost Causation
Study did not provide any evidence that embedded costs were incurred to optimize losses.
In fact, the Study contained the following information:
Since electric transmission system costs are capital intensive, decisions made at the
planning stage drive costs over the life of the transmission facilities. Therefore,
understanding the transmission planning process is crucial to understanding cost
causation for a transmission system. (p. 8)
33
34
35
36
IPCAA argument, page 13
Transcript Volume 1, page 223 lines 10 to 14.
TCCS. page 3
AESO reply, page 15
22 • EUB Decision 2005-096 (August 28, 2005)
2005/2006 General Tariff Application
Alberta Electric System Operator
The nature of a transmission facility is such that the facility is sized to meet the forecast
demand, and a conductor optimization study is typically performed to determine the
optimum conductor size to optimize losses. (p. 36)
The cost of a substation was assessed with a normal efficiency transformer, and a high
efficiency transformer that may be suitable for a high load factor customer. (p. 43)
These excerpts indicate that planners do study the efficient expansion of the transmission
system, and that there are capital costs associated with energy efficiency in both
conductors and transformers. However, Mr. Reimer described (T0834) the difficulty in
recreating history to determine precisely what embedded costs would have been
associated with energy efficiency. Given these challenges, a simplified approach was
taken in the Transmission Cost Causation Study to assess costs associated with energy
efficiency. The AESO submits that costs are incurred to optimize losses on the
transmission system…
Parties also questioned the use of CLMS to moderate the demand charge otherwise called for.
With respect to this matter, the Board notes that the TCCS appears to have studied only two of
many bulk lines in its analysis. IPCAA has argued that one of the two lines studied, the
Edmonton-Calgary line, had significant loading caused by opportunity service at the time of
CLMS. Indeed, the Board observes that Mr. Reimer, as referenced above, has acknowledged that
CLMS may be expected to be more coincident with system peak. As such, the discount that
Mr. Reimer proposes in demand related charges may not be fully justified. The Board expects
that, in future studies, the AESO will conduct a more thorough review of all those lines
comprising the bulk system. This should give a more accurate indication as to the exact portion
of costs that are energy related.
However, the Board also considers that a reasonable portion of TFO costs are related to O&M
and that a material percentage of these may be energy related. Unfortunately, the impact of this
factor does not appear to have been researched in this current study and therefore the Board
cannot draw a firm conclusion respecting its impacts on the demand charge. Nonetheless, based
upon the percentage that O&M expenses comprise of a TFO’s revenue requirement,37 the Board
considers that such an analysis would support a reasonable classification of costs as energy
related. The Board expects the AESO to address these issues in future cost of service studies.
The Board also notes the following from the TCCS:38
While transmission planning models consider one point in time, transmission planning
criteria are based on experience and judgment to ensure reliable operations year round,
and planners will optimize conductor size in order to minimize the total cost of wires and
losses. The transmission planning process is often used as justification for classification
of all wires costs by demand, because transmission planners consider demand under
various scenarios. In the event that transmission planning criteria are violated, the
transmission system is upgraded to accommodate the forecast demand. However,
transmission planning criteria are based on experience and judgment, and therefore, it is
too simplistic to classify transmission costs as completely demand related.
37
38
AltaLink 2004-2007 GTA Application
TCCS, page 34
EUB Decision 2005-096 (August 28, 2005) • 23
2005/2006 General Tariff Application
Alberta Electric System Operator
Given the above, the Board is prepared to accept that some portion of embedded wires costs are
energy related. The Board also notes that preparing a cost of service study for transmission on a
stand alone basis is a relatively new and unique process. The Board acknowledges the difficulties
faced by Mr. Reimer in preparing his analysis and in the circumstances the Board considers the
TCCS to be a good first step and is willing to accept its recommendations in the Board’s
approved rate design.
5.4
Ancillary Services Cost of Service Study
In response to Directions 10 and 11 of Decision 2001-32, the AESO filed an Ancillary Services
Cost of Service Study. The study was prepared by Mr. Randy Stubbings of Envision Consulting
and was summarized at pages 11-15, Section 4 of the Application.
The AESO’s proposed classification was summarized in Table 4.3.1 of the Application and is
reproduced below.
The AESO explained the results of the study and their proposal as follows:39
Ancillary services costs to the AESO can also be viewed as a function of payments to
ancillary service providers, and can be classified for rate design purposes as demandrelated or usage-related. The costs could then be recovered through tariffs as fixed or
variable charges, in accordance with the classification of the ancillary service payments.
Basing rate design for ancillary services solely on alignment with payments to ancillary
services providers may not always accord with the cost classification set out in the AS
Cost Study, as cost causation is only one of several rate design criteria. In particular, the
AESO is proposing ancillary services rates that also consider rate stability, simplicity of
understanding, and economy of billing.
In Decision 2001-32, the EUB also noted “that the first step to self-provision [of ancillary
services] is to unbundle the various system support services in the TA’s tariff” (p. 41) and
provided Direction 11 to “include rate proposals for unbundling SSS and proposals for
customer self-supply of SSS” (p. 59). Based on the AS Cost Study and rate design
considerations, the AESO proposes to unbundle certain ancillary services. The AESO
recognizes that each of the many individual ancillary services (as detailed in the AS Cost
Study) could be identified separately in the rate schedule, but considers such detailed
unbundling would be premature and would unnecessarily complicate billing during the
time that the market for such services is developing. For example, the AS Cost Study
concludes that the cost of regulating reserves should be classified in accordance with
customers’ ranges of demand over a given period. Rates designed on this basis would
degrade rate stability on an individual customer basis, and would also increase billing
costs as extensive information system changes to the billing and metering systems would
be required to support the resulting tariffs.
Accordingly, the AESO has unbundled ancillary services into three separate and distinct
tariff charges categorized by separate cost recovery approaches:
a) operating reserves charge, structured as a usage charge which varies as a
percentage of pool price, averaged over all hours;
b) voltage control charge, structured as a flat (non-varying) usage charge; and
c) other system support services charge, structured as a demand charge.
39
Application, Section 4, pages 11-12
24 • EUB Decision 2005-096 (August 28, 2005)
2005/2006 General Tariff Application
Alberta Electric System Operator
Table 4.3.1
Proposed Ancillary Services Charges and Classification
Ancillary Service
Current Classification
Proposed Classification
Component
MW
MWh
% of PP
MW
MWh
% of PP
Operating Reserves Charge
Operating Reserves
Generator RAS
Black Start
-
-
100%
100%
100%
-
-
100%
100%
100%
Voltage Control Charge
Transmission Must Run
-
-
100%
-
100%
-
40%
100%
-
53.4%
-
Other System Support Services Charge
Under Frequency Mitigation
Poplar Hill
100%
ILRAS (see note)
60%
Notes:
5.4.1
100%
100%
46.6%
MW indicates classification as demand
MWh indicates classification as flat (non-varying) usage
% of PP indicates classification as usage varying as percentage of pool price
Changes in classification are indicated in bold in the table
Classification of ILRAS changes to reflect the change in classification of wires costs
The MWh component of ILRAS is recovered in the DTS rate schedule as part of the DTS Interconnection Charge, to
avoid a small $/MWh component in the OSS Services Charge
ILRAS Interruptible Load Remedial Action Scheme
Classification of Ancillary Services
The only party to submit any comments with respect to the AESO’s proposal was FIRM. FIRM
maintained that TMR costs should be allocated on a basis more reflective of cost causation and
recommended that the AESO rate design for the TMR component of voltage control reflect the
1:2 ratio of TMR costs for DTS-MWH on-peak and off-peak charges. FIRM acknowledged such
a muted price signal would not significantly affect customer consumption behavior but claimed it
would better reflect cost causation.
In reply the AESO submitted that if a price signal is so muted that it will not affect customer
behaviour, then there is little point in providing such a signal. If such a unique bill charge will
vary by so little compared to an all-hours average charge and will seem illogical to many
customers (as explained by Mr. Martin at T0657-58), then the AESO submitted there was no
justification to warrant its implementation.
The Board agrees with the AESO and approves the recovery of TMR costs on a flat usage basis.
Consistent with the Board’s determinations with respect to classification of wires costs, the costs
for ILRAS should be classified as 80% demand and 20% energy. The demand portion should be
allocated on the same basis as the bulk wires.
5.5
Demand Transmission Service Rate Design
5.5.1
Unbundling
The AESO has stated that it considers the level of unbundling proposed in the Application to be
adequate and any further steps in this regard should be deferred until the 2007 tariff. The AESO
stated that it did not consider a bill containing seven to nine distinct charges to be simple.
EUB Decision 2005-096 (August 28, 2005) • 25
2005/2006 General Tariff Application
Alberta Electric System Operator
Both IPCAA and ADC supported unbundling. IPCAA maintained that unbundling would result
in a tariff where charges are better aligned with the various cost components and cost drivers.
Both IPCAA and ADC pointed out that unbundling would allow for different billing
determinants.
The Board does not agree with the AESO. The Board considers that unbundling, as
recommended in the TCCS report, would allow for rates that are more reflective of cost
causation, more visible and capable of sending more appropriate price signals to customers.
With respect to the concern raised by the AESO that such a bill would be too complex for its
customers, the Board considers the customers of the AESO to be few in number, sophisticated in
nature, and well able to understand and respond to such a bill.
The Board therefore directs the AESO, in its refiling, to unbundle the wires portion of the DTS
rate into bulk, local and POD segments. The Board notes this is necessary to facilitate the cost
allocation decided upon below.
5.5.2
Classification of Costs
The AESO’s proposal for classification of wires costs was originally presented in the
Application.40 The AESO submission proposed three adjustments to the cost results of the TCCS.
First, the AESO reduced the demand weighting to reflect billing demand non-coincidence with
the point of system maximum stress. Second, the AESO eliminated the customer charge amount
and added it back to demand. Third, and most significantly, the AESO deducted the current STS
wires revenue from demand and re-classified it as energy related.
The AESO acknowledged that its proposal did not meet the goal of cost causation but stated that
it planned further consultation in 2007 and other rate design considerations may affect the rate
design ultimately developed in 2007.41 The AESO also maintained that phasing in the STS wires
revenues into the DTS rate on an energy basis would maintain customer neutrality and would
avoid undue rate shock to low load, low load factor customers.
The AESO was largely supported in its proposed rate design by FIRM and EnCana. EnCana
supported the unbundling proposed in the TCCS but also supported the classification of the STS
wires costs as energy related. The resultant demand/energy split is approximately the same.
Proponents of the AESO proposal appear to support it for three main reasons:
1. Gradualism or rate shock – The parties state that low load, low load factor customers will
see huge rate increases and maintain that these should be tempered. All agree this can be
accomplished by classifying the STS wires amount as energy related. This would also
achieve customer neutrality to the phase out of the STS charge.
2. Transmission Regulation – Parties assert that the regulation requires classification of STS
charges as energy related, as a means to ensure revenue neutrality.
3. Decision 2000-1 – Parties submit that the Board’s determination in Decision 2000-1 to
classify all STS wires charges as energy was based upon cost causation.
40
41
Application, Section 4, pages 7-9
Application, Section 4, page 9
26 • EUB Decision 2005-096 (August 28, 2005)
2005/2006 General Tariff Application
Alberta Electric System Operator
The Board has noted in the previous section on rate design principles that it considers cost
causation to be the most important principle and the Board is in agreement with ADC and
IPCAA that rates should reflect this principle to the greatest extent possible.
With respect to gradualism or rate shock concerns, the Board notes that the AESO has stated that
DTS rates will rise by 66% in total, largely due to the legislative requirement that load pay for all
wires costs. Regardless of the rate design chosen, DTS customers will see significant increases in
their AESO billings. The Board points out, however, that this relates to AESO billings only. In
the past when the Board has considered rate shock, the Board has considered the effect an
increase will have on a customer’s total bill. The Board continues to believe that this is the most
appropriate manner in which to assess rate design proposals. Only this approach allows the
Board to keep bill impact in true perspective.
The Board notes that, in information response ADC-AESO-012(c), the AESO provided the
impact upon a customer’s total bill as a result of their proposed rate design. In response to an
undertaking requested by the Board42, the AESO provided the effect upon a customer’s bill when
demand factors of 60, 70 and 80% were used. Exhibit 030-126 revealed that a demand factor of
80% resulted in an 8% increase in costs, when commodity charges were included. The Board
does not consider this to be unreasonable. The Board did not request the AESO to factor in the
effect of allocating some of the demand charge to a customer charge. The Board has prepared
such a spreadsheet and it is attached as Appendix A.43 As can be seen in Appendix A, when
considering the effect upon a low load factor customer of the increase in DTS rates only, the
addition of a customer charge, including commodity charges, results in an increase of
approximately 47%. This could be considered significant.
As noted above, the Board considers that it must evaluate the effect that a change in rate design
will have upon a customer’s total bill. The Board notes that, in response to an undertaking
requested by the Cities, Exhibit 030-022, the AESO acknowledged that all 17 of the low load
factor customers identified in response to IR IPCAA-AESO-23(a) are generators. The Board
considers it appropriate to account for the drop in the STS portion of their AESO billings that
these customers will receive as a result of the shift in costs to load. The Board has prepared such
an analysis and it is also attached as part of Appendix A.44 The result clearly indicates that, when
the drop in STS billings is factored in, these low load factor customers actually experience a
decrease in total billings.
In the end, therefore, when considering the total effect upon low load factor customers of an
increase in DTS rates and decreases in STS rates, it is clear to the Board from the evidence that
the rate shock referenced is simply not significant. It does not justify a failure to move to more
cost based rates. Indeed, when the reduction of STS charges is considered, customers may
actually see decreases in their total AESO billings.
With respect to the requirements of the Transmission Regulation, the Board has examined
Section 30 of the regulation and concludes that there is no requirement for the Board to pass
through STS costs on an energy basis. Section 30 simply requires that costs be just and
reasonable. Associated with this issue is the notion of revenue neutrality. The Board notes the
42
43
44
Exhibit 030-126
Appendix A, sheet titled “DTS only increase”
Appendix A, sheets titled “Rate Shock Analysis” and “Rate Shock no STS losses”
EUB Decision 2005-096 (August 28, 2005) • 27
2005/2006 General Tariff Application
Alberta Electric System Operator
evidence Mr. Sullivan presented on behalf of the ADC. This evidence clearly indicates that the
energy market may not be as efficient as postulated by the AESO. In the Board’s view there is no
evidence to conclude that STS charges in total will be recouped by load, let alone that they can
be recouped evenly across all hours.
Finally, the Board will address the suggestion that Decision 2000-1 classified STS charges as
energy related because it believed that this was in accordance with cost causation. The evidence
in that proceeding indicated that EAL (ESBI Alberta Ltd.) originally proposed to recover a
significant portion of the STS wires costs on a demand basis. The evidence of the Coalition in
that proceeding was that the imposition of a demand charge on generators could lead to an
inefficient energy market and have a detrimental effect upon the PPA (Power Purchase
Arrangements) auction, which was imminent at that time. Based upon the evidence before it in
that proceeding, the Board classified the STS portion of wires costs as energy. This
determination was not made on the basis of cost causation but rather as an exception to the
principle45. Reallocating all wires costs to load now allows the Board the opportunity to classify
such costs in a manner more in keeping with cost causation.
The Board concurs with ADC and IPCAA that rates should be more in keeping with cost
causation. The Board above has dismissed the parties’ concerns about rate shock or gradualism
and the potential complexity resulting from unbundling. The Board in the prior section on rate
design principles has determined that most other rate design principles are complimentary to cost
causation.
The Board considers that wires costs should be classified as 20% energy to be collected evenly
over all hours. There should be a full POD customer charge as determined in the TCCS. This
should amount to approximately 24% of total costs as per table 24 at page 47 of the TCCS. The
balance of wires costs should be collected through two demand charges – one related to the bulk
system and the second relating to local system and POD related costs. The Board, as stated
above, agrees with the AESO’s proposal and Mr. Reimer’s suggestion that a reduction be made
to the demand related portion of the bulk wires to account for the lack of coincidence of system
peak with point of maximum stress. The demand charge for local and POD costs should be
collected on the basis of non-coincident peak (NCP), including the use of a ratchet, as proposed
by the AESO.
With respect to the demand charge for bulk wires, the Board notes that ADC and IPCAA have
both proposed different alternatives. Both, however, would use some form of coincident peak to
allocate this demand charge. The parties advocate this approach on the basis that the bulk system
is largely constructed and sized, and costs incurred, to meet the peak load of the system. The
Board agrees. ADC has proposed a 12 CP approach that would use a 12 month average of the
system peaks and base a customer’s individual charge on their monthly coincidence with the
12 month average.46 IPCAA proposes to use an average of several peak hours to allocate the
demand charge.47
While the Board sees a certain degree of academic merit to the IPCAA approach it considers that
it may be more complex to administer. The Board considers that both approaches would provide
an appropriate price signal to customers.
45
46
47
Decision 2000-1, pages 121-123
Rosenberg Evidence, page 31
IPCAA Argument, page 20
28 • EUB Decision 2005-096 (August 28, 2005)
2005/2006 General Tariff Application
Alberta Electric System Operator
Therefore, the Board directs the AESO to use the 12 CP approach proposed by Dr. Rosenberg.
The average of 12 CP should address the seasonality concerns of IPCAA. As noted by IPCAA,
however, a reasonable degree of diversity exists on the bulk system and for this reason no ratchet
will apply to this demand charge.
As a summary of the above findings the AESO, in its refiling, is directed to amend its DTS rate
design as follows:




5.5.3
20% of all wires costs will be collected on an all hours energy basis
Levy a customer-related POD charge, as suggested in the TCCS
Levy a demand charge on bulk wires utilizing a 12 CP allocator
Levy a demand charge on local and POD related costs utilizing an NCP allocator.
Ratchet
The AESO introduced its proposal for a revised ratchet in the Application.48 The AESO proposed
to reduce the current 5 year declining ratchet to a 2 year, 90% ratchet. The AESO stated that it
was proposing the change in response to concerns expressed by customers. The AESO explained
that its proposal for a 90% ratchet could be achieved with only a 1% drop in interconnection
revenue and would therefore preserve revenue stability.
The AESO maintained that, in the absence of contract-based billing, ratchets are appropriate to
recover revenue from customers who may be leaving the system. The revenue is required to
balance the financial impacts for the remaining customers who would otherwise bear the full cost
of facilities which become under-utilized due to other customer’s actions. The ratchet provided a
balance between flexibility for customers and the need to recover any stranded system costs from
remaining customers.
Interveners made a number of comments with respect to the AESO proposal. TCE argued the
ratchet level should be reduced to 66% from the proposed 90% as this would be more in line
with Disco levels and it would be fairer. EnCana argued that the 5 year notice period for
reduction in service should be reduced to 2 years as well, to be consistent and fair. FIRM argued
the opposite view, maintaining that the ratchet should be maintained at the current 5 year level,
to be consistent with the 5 year notice period and protect customers from stranded costs.
In response to intervener comments, the AESO noted that TCE’s proposed ratchet level of 66%
would entail a 10% drop in interconnection revenue. In response to EnCana and FIRM, the
AESO noted EnCana stated that with respect to the ratchet provisions in Article 14.2 of the
proposed terms and conditions of service “…that two Customers who are similar in all respects
will be assessed different penalties based on whether or not notice of termination or reduction
has been provided.” The AESO explained if one customer has provided a notice of termination
while the other has not, those customers were not “similar in all respects.” As explained at
T0161-62, the specific provisions in Article 14.2 were designed to ensure the AESO gets as clear
an indication as possible of the customer’s intention with respect to demand on the transmission
system. The AESO submitted the ratchet provisions in Article 14.2 should be approved as filed.
48
Application, Section 4, pages 16-18
EUB Decision 2005-096 (August 28, 2005) • 29