Alberta Electric System Operator AUC Decision 2013-135 Direction No. 3 Annual Report

Alberta Electric System Operator
AUC Decision 2013-135
Direction No. 3 Annual Report
Date:
June 16, 2014
Prepared by:
Alberta Electric System Operator
Prepared for: Alberta Utilities Commission
601331 v2
Contents
1
2
Background ........................................................................................................................................... 1
Costs of the TCM Rule ......................................................................................................................... 1
2.1
2.2
2.3
3
Constrained Down Generation ................................................................................................................... 1
Transmission Must Run……………………………………………………………………………………... ...... 3
Total 2013 TCM Rule Costs ....................................................................................................................... 3
Increased Use of Transmission Must Run/Dispatch Down Service ................................................ 4
1.
Background
1
In Decision 2013-135, the Alberta Utilities Commission (“AUC” or “Commission”) directed the Alberta
Electric System Operator (“AESO”) to monitor and report on the cost of using ISO Rule 302.1:
1
Transmission Constraint Management (the “TCM Rule”) on at least an annual basis. This report is
provided in compliance with that direction, and outlines both the methodologies employed by the AESO,
and the results obtained, in assessing and reporting on the cost of using the TCM Rule.
2
The AESO understands the cost of using the current TCM Rule to mean the pool price impact to
consumers that is caused by constraining down in-merit generation upstream of a constraint and
dispatching the next generation in the merit order downstream of the constraint (referred to herein as
Constrained Down Generation “CDG”) and the costs incurred in respect of Transmission Must Run
(“TMR”) service.
3
TMR is an ancillary service under the AESO tariff. TMR costs are reported annually and charged to load
customers through the AESO tariff. The historical costs of TMR are provided in the TMR section below.
2
Additionally, in response to the further guidance provided by the Commission in Decision 2014-067, the
AESO has provided a discussion of increased use of conscripted TMR to manage constraints.
4
While gathering the costs of TMR for past periods is straightforward, determining the pool price impact to
consumers caused by CDG is challenging given the sources of information available. The AESO IT tools
currently in place were designed for the operation of the current TCM Rule and were not designed with
the intent of measuring constrained down volumes or reporting the price impact from CDG. Accordingly,
at this time, any calculation of the costs of CDG, including the calculation in this first annual report, is an
estimate and should not be construed as actual costs.
2.
Costs of the TCM Rule
2.1
Constrained Down Generation
5
In the past, the AESO has released information relating to CDG volume and price impacts. As the
Commission is aware, the AESO reported an estimate of the cost of CDG to consumers in the AESO
3
Long-term Transmission Plan (LTP) filed in June 2012. The AESO has also periodically reported
4
volumes (GWh) of CDG in the AESO’s 24-Month Reliability Outlooks.
6
All previous reports of CDG volume have been based on the transmission limits put in place during
transmission constraint events, rather than on actual in-merit energy that is constrained down during an
event. Simply put, when an AESO System Controller (SC) identifies a constraint, a transmission limit is
put in place for reliability purposes to prevent generation dispatches above a determined energy level for
a region. For the duration of the constraint event, this level has been used as a proxy for constrained
5
down generation. For purposes of this report, the AESO will refer to this CDG proxy value as “Nominal
CDG”. It should be noted, however, that it is possible that actual in-merit generation varies during the
constraint event and, although a constraint may exist for a period of time, the constrained volume may be
below the initial reported limit. When the in-merit generation is below a system limit no generation is
constrained down. To account for the variance between the use of event limits and in-merit generation,
1
Decision 2013-135, Complaints by ATCO Power Ltd. and ENMAX Energy Corporation regarding ISO rule 302.1: Real Time Transmission Constraint Management (April 5,
2013) at p. 37.
2
Decision 2014-067, ATCO Power Letter Regarding Commission Directions to the AESO in Decisions 2013-135 (March 20, 2014) at para. 77, the Commission stated that it
“expects an analysis of the increased use of TMR/DDS to be included as part of that report as that analysis is part of the cost of the TCM Rule.
3
AESO Long-term Transmission Plan, June 2012, page 24.
4
24-Month Reliability Outlook, (2013-2014), page 6, table 3.
5
For example, if generation output in an area is currently 400MW and a transmission event takes place that requires the SC to ensure that generation output does not exceed
350MW in the area, a limiter is put in place to ensure that energy output in the area does not exceed 350MW. The energy reduction required (CDG) in this example is 50 MW
and that CDG value is entered by AESO system controllers for use in the IT systems. As long as the limiter for this energy reduction level is deemed to be required to ensure
reliable system operation, there will be a 50MW record of CDG in the AESO IT systems. The 50MW that is referenced in this example is what the AESO has used to report CDG
in the past.
AUC Decision 2013-135
Direction No. 3 Annual Report
Page 1
Confidentiality: Public
June 16, 2014
and provide the most accurate representation of CDG experienced as a result of the TCM Rule, in this
report the AESO undertook further analysis of the information available to it to estimate in-merit CDG
(“Estimated CDG”). The results presented below use volumes of both Nominal CDG and Estimated CDG.
7
Notwithstanding the AESO’s additional analysis, the cost of CDG to consumers provided in this report
remains an estimate. There is a variety of methodologies available to develop the estimate, all of which
require simplifying assumptions and must recognize existing data limitations. For this first annual report,
the AESO employed three methodologies described in further detail below. The first (“Method 1”) is the
methodology that was used in the LTP filed in 2012 and is based on Nominal CDG. The second
methodology (“Method 2”) is an ex post calculation based on event merit orders and Nominal CDG. The
third methodology (Method 3) is the same as the second methodology but is based on Estimated CDG.
As current tools do not allow the AESO to quantify import curtailments due to the use of the TCM rule,
these volumes have not been included in the CDG cost calculations under any of the three
methodologies.
1. LTP Theoretical (Method 1): This methodology consists of simulating the cost of “Nominal CDG”
to consumers based on a distribution of price impacts derived from a variety of dispatch levels in
random merit orders.
2. Ex Post based on “Nominal CDG” (Method 2): This methodology identifies 5 minute Energy
Market Merit Order (EMMO) snapshots for each minute with “Nominal CDG” and estimates an
unconstrained SMP had “Nominal CDG” not been in place. Then it calculates a “new” Pool Price for
each hour where there was CDG based on the new calculated SMPs. The pool price differential is
multiplied by the AIES demand for that hour to estimate the cost of CDG to Alberta consumers.
3. Ex Post based on Estimated CDG (Method 3): This methodology is the same as Method 2,
however, a further step is added in order to refine the estimate of the amount of CDG. Rather than
using the Nominal CDG value, this method looks at the merit order snapshot and estimates the
6
amount of in-merit CDG of assets in the area where the CDG took place.
8
While the AESO has provided costs based on all three methodologies for this first annual report, unless
the Commission otherwise directs, the AESO intends to report solely based on the Ex Post Estimated
CDG (Method 3) in future annual reports as it is most representative of market outcomes. It also aligns
with future AESO IT tools and the direction the AESO is taking for managing transmission constraints in
accordance with Decision 2013-135.
9
In order to provide the Commission additional context for the cost estimates the AESO has prepared for
this report, in Table 1 below the AESO has included the estimated costs of CDG for 2008, 2009, and
2010 as presented in the LTP alongside estimates for 2011, 2012, and 2013 using all three
methodologies. The AESO is not able to provide estimates under Methods 2 and 3 for the years 2008,
2009 and 2010 due to data limitations.
6
Given the methodology for estimating in-merit CDG, constrained down wind generation is not included in the Estimated CDG.
AUC Decision 2013-135
Direction No. 3 Annual Report
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Confidentiality: Public
June 16, 2014
Table 1: CDG Volume and Cost Estimate
CDG Volume (GWh)
Cost (Million Dollars)
Year
Nominal
Estimated**
Method 1
Method 2
Method 3
2008
295
NA
827
NA
NA
2009
55
NA
76
NA
NA
2010
700
NA
691
NA
NA
2011
142
108
264
171
111
2012
164
84
238
200
105
2013
126
103
199
305
264
**Estimated CDG is only available for 2011 onwards due to data availability
10
The estimates presented in Table 1 illustrate that under Method 1 calculations, when 2008 to 2010 is
compared to 2011 to 2013, the cost of CDG is considerably lower. The key reason for the decrease is
that 2008 and 2010 had, what appear to be, abnormally high volumes of CDG for reasons including storm
events in the southeastern part of the province and construction in the Keephills, Ellerslie, Genesee area
of the province. For 2011 to 2013, a comparison across the three methodologies illustrates the impact of
using a distribution of price impacts as opposed to price impacts consistent with the market outcomes
during the constraint events.
11
In 2013, the estimated volume of CDG was 103 GWh, which represents 0.13% of total Alberta internal
load in the province for that year. The cost of CDG under Method 3, through pool price increases to
consumers estimated with an ex post calculation was $264 million, which represents 4.4% of the value of
7
System Demand in 2013.
2.2
12
Transmission Must Run
An additional component of the cost of the TCM Rule is the cost of TMR. Under the ISO tariff TMR can be
procured on a contracted basis or, if required, TMR can be conscripted. Transmission reinforcements
have led to dramatically lower TMR costs in the last few years. The total estimated cost of TMR in 2013,
including conscripted and contracted TMR, was $10.7 million.
Table 2: TMR Costs (Million Dollars)
Year
Contracted
TMR Costs
2011
2012
2013
27.1
3.7
2.6
2.3
Estimated
Conscripted
TMR Costs
6.4
24
8.1
8
Total TMR
Costs
33.5
27.7
10.7
Total 2013 TCM Rule Costs
13
To determine the total cost of using the TCM Rule under Method 3, one must sum the Ex Post cost of
Estimated CDG, Contracted TMR and Conscripted TMR. In 2013 the sum of these estimates leads to a
TCM Rule total cost estimate of approximately $275 million. The totals under Methods 1 and 2 are $210
Million and $316 Million, respectively.
14
As this is the AESO’s first report of TCM costs, the full range of results under different methodologies and
years has been provided. As above noted, unless the Commission otherwise directs, future annual
reports will use only the Ex Post Estimated CDG method (Method 3) to estimate the costs of CDG.
Additionally, for purposes of efficiency and completeness, the information will be reported through
7
The value of system demand is estimated as average annual pool price multiplied by annual system demand.
The total TMR costs for 2011, 2012, and 2013 are estimates as they are not yet settled. In addition, these TMR costs are based on production month (i.e. the month the event
took place) and are different from the values provided in the AESO Annual Reports, which are reported by the settlement month (i.e. when the costs were actually paid).
8
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Direction No. 3 Annual Report
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Confidentiality: Public
June 16, 2014
AESO’s standard annual reporting process, the Annual Market Statistics, until such time as the revised
TCM Rule is approved and implemented.
3.
Increased Use of Transmission Must Run/Dispatch
Down Service
15
In Decision 2013-135, the Commission directed the AESO to increase the use of TMR in conjunction with
DDS in an effort to minimize price distortion in the market, particularly to address foreseen occurrences of
9
congestion. In Decision 2014-067, the Commission provided further guidance outlining that “in addition
and in conjunction with direction (2) of Decision 2013-135, the Commission expects an analysis of the
increased use of TMR/DDS to be included as part of that report as that analysis is a part of the cost of the
10
TCM Rule.”
16
The AESO is taking a threefold approach to increasing the use of TMR. First, the AESO increased the
use of the synchronous condense mode (“SCM”) on the Poplar Hill unit, which alleviates a foreseen
output constraint on local area generation. Compensation for the SCM is already included in an existing
TMR contract such that no additional costs would be incurred for this approach. This option is not always
effective in relieving the constraint as the output of area units, which is dependent on market conditions,
may impact the effectiveness of the SCM in relieving the constraint, or even the availability of the SCM
itself. Nevertheless, under some circumstances, running the Poplar Hill generator in SCM will allow other
generators in the area to increase output.
17
The second action being undertaken by the AESO to increase the use of TMR to minimize price distortion
in accordance with the Commission’s direction involves using contracted TMR units in real time to replace
CDG rather than ascending the energy market merit order. This action is dependent on several
conditions, including:



contract conditions that may limit the reasons for dispatching the TMR unit;
whether or not the TMR unit is available or in-merit; and
the location of the constraint.
11
18
The third action to increase the use of TMR involves assessing the use of contracted TMR for planned
outages as part of the outage planning process. It is not anticipated that TMR would be conscripted to
fulfill this purpose. The compensation mechanism (section 11 of the ISO tariff) for conscripted TMR
contains a cost ratchet mechanism to discourage the use of conscripted TMR so its use in these
circumstances does not seem appropriate.
19
As above noted, there are no additional costs in respect of the first approach. As regards the second and
third approaches, the AESO is in the early stages of assessing the costs associated with such
approaches and how it may be able to report on such costs in the future. The assessment of, and
reporting on, such costs at this early stage is further complicated by the fact that the terms of TMR
contracts are confidential and much of the costs will depend on market conditions (i.e. offers, bids,
imports) at the time that the increased use of TMR is made. As such, the costs and the triggers for the
costs (i.e. the conditions of the market at the time of the use) will be highly variable. In particular, it will be
very difficult to differentiate and attribute the costs between typical TMR use and increased use for
purposes of minimizing price distortion arising from foreseen congestion. The AESO will address this
matter further at the time of filing its next annual report in response to Decision 2013-135, Direction No. 3.
9
AUC Decision 2013-135, at para. 197, direction 2.
AUC Decision 2013-067, at para. 77.
For example, limitations on the dispatch of the unit depending on which area the constraint is in,
10
11
AUC Decision 2013-135
Direction No. 3 Annual Report
Page 4
Confidentiality: Public
June 16, 2014