BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Promote Policy
and Program Coordination and Integration in
Electric Utility Resource Planning.
Order Instituting Rulemaking to Promote
Consistency in Methodology and Input
Assumptions in Commission Applications of
Short-run and Long-run Avoided Costs,
Including Pricing for Qualifying Facilities.
Rulemaking 04-04-003
(Filed April 1, 2004)
Rulemaking 04-04-025
(Filed April 22, 2004)
JOINT PRE WORKSHOP COMMENTS OF PACIFIC GAS & ELECTRIC
COMPANY (U 39-E) SAN DIEGO GAS & ELECTRIC COMPANY (902-E) AND
SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E)
WILLIAM V. MANHEIM
EDWARD V. KURZ
MARY A. GANDESBERY
Law Department
Pacific Gas and Electric Company
Post Office Box 7442
San Francisco, CA 94120
Telephone: (415) 973-6669
Fax: (415) 973-5520
E-mail: [email protected]
Attorneys for
PACIFIC GAS AND ELECTRIC
COMPANY
GEORGETTA J. BAKER
San Diego Gas & Electric Company
101 Ash Street
San Diego, CA 92101
Telephone: (619) 699-5064
Facsimile: (619) 699-5027
E-mail: [email protected]
Attorney for
SAN DIEGO GAS & ELECTRIC COMPANY
BERJ K. PARSEGHIAN
Southern California Edison Company
2244 Walnut Grove Ave.
Rosemead, CA 91770
Telephone: (626) 302-3102
Fax: (626) 302-1904
E-mail: [email protected]
Attorney for
SOUTHERN CALIFORNIA EDISON
COMPANY
October 22, 2007
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Promote Policy
and Program Coordination and Integration in
Electric Utility Resource Planning.
Order Instituting Rulemaking to Promote
Consistency in Methodology and Input
Assumptions in Commission Applications of
Short-run and Long-run Avoided Costs,
Including Pricing for Qualifying Facilities.
Rulemaking 04-04-003
(Filed April 1, 2004)
Rulemaking 04-04-025
(Filed April 22, 2004)
JOINT PRE WORKSHOP COMMENTS OF PACIFIC GAS & ELECTRIC COMPANY
(U 39 E) SAN DIEGO GAS & ELECTRIC COMPANY (902-E) AND SOUTHERN
CALIFORNIA EDISON COMPANY (U 338-E)
I.
INTRODUCTION
In accordance with D.07-09-040 (the “Decision”), Pacific Gas & Electric Company
(“PG&E”), San Diego Gas & Electric Company (“SDG&E”), Southern California Edison
Company (“SCE”), TURN and the Division of Ratepayer Advocates (“DRA”), collectively
referred to as the “Joint Parties,” submit the following Pre-Worskhop Comments
(“Comments”).1 As directed in the Decision, these Comments address issues regarding the
implementation of the short-run avoided cost (“SRAC” methodology adopted in the Decision.
These Comments do not address issues concerning the implementation of standard offer
contracts, which the Joint Parties recognize will also be a subject encompassed within the scope
1
The Joint Parties, collectively and individually, reserve all rights and recourses with respect to the Decision,
including the right to seek rehearing, modification, and review of the Decision. These Comments are offered by the
Joint Parties for purposes of implementing the Decision as issued, and should not be considered or deemed and
admission or waiver in any respect.
of the workshop.2 The Joint Parties intend to submit, whether separately or jointly, comments on
the proposed form of contract submitted by the Cogeneration Association of California and the
Energy Producers and Users Association (“CAC/EPUC”), as well as proposed standard offer
contracts for consideration by staff and other stakeholders at the workshop in advance of the
workshop.
With respect to the implementation of the Decision’s adopted SRAC methodology, the
Joint Parties note that the Decision requests pre-workshop comments concerning both the
methodology to be used prior to the operation of MRTU and thereafter. While the Joint Parties
acknowledge the importance of both efforts, the Joint Parties note that the post-MRTU
methodology will not go into effect until October, 2008 at the earliest, and, therefore, that the
need to discuss and finalize the methodology is far less pressing than the need to implement a
methodology for calculating SRAC in the near term. The Joint Parties suggest that the
Commission should defer consideration of the post MRTU SRAC methodology for consideration
at later, separate workshop, both in order to allow staff and parties to focus on near-term
implementation issues and to avoid confusion.
In accordance with the directive in the Decision that the three respondent investor-owned
utilities, PG&E, SDG&E and SCE, file a joint advice letter subsequent to the workshop for
purposes of updating the current SRAC methodology, the Joint Parties have met and conferred
on several occasions with a view towards proposing a uniform approach to all of the input
variables for the updated SRAC methodology. Although the Joint Parties have reached the
consensus reflected in these Comments on many issues, some areas remain open for discussion
at the workshop, particularly with respect to the calculation of the Market Heat Rate (“MHR”) in
the updated methodology. In those instances in which the Joint Parties have not reached a
consensus view, alternative approaches to the input data sets and/or calculation of the variable
are noted and the identity of the sponsoring party for the particular proposal noted.
2
Ordering Paragraph 2 in D.07-09-040 indicates that the IOUs “shall comment on the EPUC/CAC draft contract
and present at th[e] workshop their draft standard offer contracts.” The IOUs do not interpret this paragraph to
require them to comment on the EPUC/CAC document or to submit their own proposed standard offer contracts as
part of today’s submission. Concurrently with these Comments, PG&E has submitted comments preliminarily
addressing some of the issues addressed in the EPUC/CAC proposal. SDG&E and SCE join these comments. All
of the IOUs reserve the right to supplement PG&E’s comments and/or to file separate supplemental comments prior
to the workshop.
2
These Comments are organized into three sections. The first attempts to provide a set of
principles that the Joint Parties believe are appropriate for guiding discussion at the workshop.
Although the Joint Parties are hopeful that the workshop will produce a consensus on all issues,
the Joint Parties are also aware that there are likely to be divergent views regarding the
implementation of some aspects of the updated SRAC methodology and that full stakeholder
consensus may not be reached. Therefore, a commonly understood set of principles may be
useful not only in guiding discussions at the workshop but also in assisting staff and others in
resolving issues that remain open going forward. The second section in these Comments
addresses the near term (i.e., pre-MRTU) SRAC formula, and is organized by variables in the
formula itself. Each variable in the formula is identified and discussed separately. Finally, the
Joint Parties discuss the post-MRTU SRAC methodology, with a view towards identifying in
general terms some of the issues that must be addressed and resolved in order to implement the
methodology.
II.
GUIDING PRINCIPLES FOR IMPLEMENTING UPDATED SRAC METHODOLOGY
The Joint Parties offer the following principles to guide discussion of the workshop with
respect to the implementation of the updated SRAC Methodology:
1.
The implementation methodology should be consistent with the Decision.
2.
In the event that the Decision requires clarification, the clarification should be consistent
with avoided cost principles, i.e., PURPA and FERC's implementing regulations
3.
The implementation methodology should be accurate and produce results that are easily
verifiable (duplicated) by posting IOUs and CPUC personnel.
4.
The implementation methodology should be entirely objective, with no subjective
judgment by posting IOUs.
5.
The CPUC and staff should strive for ease of administration for both posting entities and
the CPUC.
6.
To the extent practicable and appropriate, the implementation methodology should rely
on input data sources that are already recognized and approved by the CPUC for other
uses (i.e., electricity and gas forwards already in use in connection with the approval of
3
the LTPP or IOU hedging activities); CPUC should strive to achieve consistency across
all procurement and planning activities
7.
The implementation methodology should include a mechanism for mitigating or rejecting
anomalous input values.
8.
To the extent practicable, the implementation methodology (as opposed to input values
for variables), should be the same for all three IOUs.
9.
In order to avoid confusion or disputes, the implementation methodology should be
approved in a CPUC resolution on the filed joint Tier 3 implementation filing.
III.
IMPLEMENTATION OF THE MARKET INDEX FORMULA
Algebraically, the updated SRAC methodology, referred to in the Decision as the Market
Index Formula (“MIF”) can be expressed as follows:
Pn = [IER x (GPn + GTn) / 10,000] + O&M
Where:
Pn = calculated SRAC energy price, cents/kWh
IER = Incremental Energy Rate (.5 x MHR + .5 x AHR)
GPn = gas price, $/MMBtu
GTn = intrastate transportation costs, $/MMBtu
MHR = Market Heat Rate Btu/kWh
AHR = Administrative Heat Rate (PG&E = 9,794 Btu/kWh, SCE = 9,705 Btu/kWh, SDG&E =
9,603 Btu/kWh
O&M = operations and maintenance costs, cents/kWh
10,000 = [$1/100 cents] x [1,000,000 Btu / MMBtu]
TOD Factors = Time of Delivery Factors
Each of these variables is discussed below.
A.
Incremental Energy Rate (IER)
This calculation is straightforward as 0.5 x MHR + 0.5 x AHR, and there do not appear to
be any implementation issues. The value will be expressed in Btu/kWh. As discussed below,
however, calculation of the values for both the MHR and the Administrative Heat Rate (“AHR”)
requires clarification.
4
B.
Gas Price (GPn)
There do not appear to be any significant issues with respect to this input variable either.
In accordance with the Decision consistent with the Decision at page 72, SCE and SDG&E will
be required to use bidweek values for natural gas at the Southern California delivery point at
Topock in lieu of Malin. The value, expressed in $/MMBtu, will be derived, as is currently the
case, by taking the simple average of natural gas market price bidweek indices for the Southern
California border spot price. The publications SCE and SDG&E currently use are Natural Gas
Week, Natural Gas Intelligence, and BTU Daily Gas Wire. PG&E will continue to derive this
value in a similar manner using natural gas market price bidweek indices for the Northern and
Southern California border prices for Malin and Topock. For each border point, PG&E intends to
use the average bidweek gas price indices from the same publications it has used since the CPUC
issued D.96-12-028: Gas Daily, Natural Gas Intelligence and Natural Gas Week.
C.
Intrastate Transportation Costs (GTn)
An intrastate transportation cost must be added to the border price for natural gas in order
to reflect the avoided cost of natural gas at the burnertip. In the current SCE methodology for
SRAC, this calculation is derived with reference to tariffed transportation rates for Southern
California Gas Company, and is expressed as follows:
(GT-F5) + (ITCS) + (G-MSUR)
Where:
GT-F5 = Firm Intrastate Transmission Service, for electric generation, for customers using 3
million therms or more per year. See Schedule No. GT-F.
ITCS = Interstate Transition Cost Surcharge. See Schedule No. GT-F.
G-MSUR = Surcharge % outside the city of Los Angeles x (G-CPA) x Imputed Franchise Fee
Factor
G-MSUR = Transported Gas Municipal Surcharge. See Schedule No. G-MSUR.
G-CPA = The rate used for purposes of calculating the municipal surcharge as defined in
Schedule No. G-MSUR. See Schedule No. G-CP, G-CPA
SCE does not propose to change this calculation.
5
SDG&E is not currently calculating an intrastate transportation rate (GTn) in its monthly
SRAC posting based on the current formulation of the transition formula with a fixed factor.
SDG&E proposes to use the rate from its tariff schedule EG, “Natural Gas Intrastate
Transportation Service for Electric Generating Customers.” The specific volumetric rate to be
used would be the currently in effect value “for customers using 3 million therms or more per
year.”
PG&E is not currently calculating an intrastate transportation rate (GTn) in its monthly
SRAC posting based on the transition formula. However, for PG&E, intrastate transportation
GTn can be expressed as the sum of:
(Backbone Transmission ) + (Local Transmission) + G-SUR
Where:
Backbone Transmission = Average (Redwood transmission rate, Baja transmission rate)
consistent with the 50/50 weighting of the Malin and Topock border gas indices. For
backbone rates, PG&E intends to use firm Redwood - On-System and Baja On-System
rates at the full contract rate, plus applicable shrinkage for the relevant delivery path. See
PG&E G-AFT and Gas Rule 21.
Local Transmission = Applicable variable transportation charge for electric generator
service under the G-EG tariff.
G-SUR = Gas Franchise Fee Surcharge, in effect on the first day of the pertinent SRAC
posting month.
The Joint Parties note that at page 72, the Decision states “We will allow SDG&E and the
other utilities to annually update the intrastate transportation rate to the most recent value in their
gas tariffs, as necessary.” The Decision is unclear on this point. Although it appears to indicate
that the intrastate transportation component can be updated only once in any given 12-month
period, it does not indicate what 12 month period should be used. In the event that the tariffed
rate for intrastate transportation were to change, failing to reflect the change immediately in the
6
GTn portion of the MIF would necessarily result in a rate that does not accurately reflect avoided
cost of natural gas at the burnertip. The Joint Parties suggest that any change in tariffed rates
should be reflected immediately in the monthly SRAC posting. However, given the language of
the Decision, this leaves open the question of whether the GTn component could be updated
again if the tariffed rate changes again within the following 12 month period. Ideally, the word
“annually” should be stricken from the Decision; the Joint Parties recognize, however, that such
a revision would appropriately be the subject of a petition to modify the Decision.
The Joint Parties also note that intrastate transportation costs for natural gas will
necessarily play a role in the denominator of the formula (however it is ultimately derived) used
to calculate MHR. That is, it is reasonable to assume that the implied forward market heat rate
for the purpose of determining avoided cost should calculate the heat rate at the burner tip.
Because the MIF discussed in the Decision proposes to derive the MHR based on an average of
forward heat rates, this necessarily implies a requirement of deriving a forward calculation of the
intrastate transportation cost for natural gas. The Joint Parties note that using one value for GTn
and a different value in the denominator of the MHR calculation would be inappropriate, and that
any change in the value of GTn should also be reflected with a commensurate adjustment in the
value assigned to intrastate transportation costs in calculating MHR. The Joint Parties therefore
propose that if GTn is adjusted to account for a change in tariffed transportation rates that the
adjusted value should be used for the calculation of MHR.
D.
Market Heat Rate (MHR)
This value, which should be expressed in Btu/kWh, may prove to be the most difficult to
reach consensus on at the workshop. The Decision provides very little guidance as to how the
value should be calculated in practice. Specifically, the Decision states: “In calculating the
market heat rate using NP15/SP15 indices, rather than using historical prices, we will use a 12month rolling average of the weighted average price of the forward market prices for NP15 (for
PG&E) or SP15 (for SCE and SDG&E).” Decision, at 67. Further, the Decision directs that
variable O&M should be deducted in this calculation. Decision, at 66. Beyond this scant
discussion, the Decision provides no guidance as to how the MHR component of the IER
variable should be implemented.
The generic equation for MHR can be expressed easily enough as:
([SP15 or NP15] forward – O&M) / Burnertip Gas Forward
7
However, the Decision is susceptible to numerous interpretations as to how the data inputs and
calculation should be performed in practice. Among other things, it is unclear what 12-month
period is to be used for calculating the MHR; what indices are to be used for SP-15 and NP-15
forward energy prices; what indices are to be used for forward natural gas prices; when and how
often these indices are to be polled for purposes of determining a 12-month rolling average (i.e.,
should the indices be polled one time in the prompt month? 5 times? 20 times?); how a burnertip
gas price is to be derived based on forward data when elements of the intrastate transportation
rate cannot be forecast; whether a series of implied heat rates are to be derived, then averaged or
whether an average forward electricity price and an average forward gas price are to be derived
and then averaged. Simply stated, there are many, many possible variations on the methodology
adopted by the Decision.
The Joint Parties have not reached a consensus on this particular component of the MIF,
and therefore offer two possible interpretations. The Joint Parties anticipate that there may be
others offered at the workshop and therefore, reserve the right to either revise the proposals made
below or to adopt other proposals.
1.
General Description of alternative approaches to derivation of MHR
Generally, SCE and PG&E propose to develop a 12-month rolling average of forward
heat rates by polling the forward markets on a defined number of days in the prompt month for
the SRAC posting. For example, in December 2007, the methodology would require polling the
forward markets for natural gas and electricity in the next succeeding 12 months, i.e., January
2008 through December 2008 on several days, deriving the heat rates for each of those twelve
months for each of the days on which the forward markets are polled and then averaging those
heat rates to derive MHR for the next posting month. SCE and PG&E have not yet reached a
consensus on how many days the forward markets should be polled in the prompt period.
As an alternative approach, SDG&E proposes a methodology for deriving MHR that
would look at historical forward prices. In addition to polling the forward market in the prompt
month, this proposal would derive the MHR for the prompt month by looking at 12 months of
forward prices, “a 12-month rolling average of forward prices.” For example, for the posting
month of January, 2008, this methodology would look at the 12 months of forward electricity
and natural gas prices for the preceding 12 months. Thus, it would look at 12 months of forward
8
prices as of January 2007, 12 months of forward prices for February 2007, 12 months of forward
prices for March 2007 and so on, and the resulting series of heat rates would then be averaged to
calculate MHR. This average would have 12 separate projections of the January, 2008 electric
prices.
The Joint Parties also have not yet reached a consensus with respect to the appropriate
publications to be used to determine a forward electricity price. A number of publications and
sources are available, including all agree that Platt’s Megawatt Daily Intercontinental Exchange
(“ICE”), Tullet Prebon, Amerex and TFS. The Decision at page 6 and 7 seems to restrict the use
to Megawatt Daily and ICE. Ideally, the word “such as” should be added to the Decision to
expand the range of publications that could be used; the Joint Parties recognize, however, that
such a revision would appropriately be the subject of a petition to modify the Decision.
SDG&E plans to use only Megawatt Daily since the ICE data is not transparent. Where
there are no monthly values, the quarterly data value will be entered for each month in the
quarter.
For purposes of deriving a forward gas price, the Joint Parties agree that the calculation
should use the NYMEX Henry Hub futures contract for the Henry Hub Price,
and the NYMEX Clearport price for the SoCal or Malin basis differentials.
2.
Detailed Description of SCE/PG&E Proposal
The discrete components and input data sources needed to calculate the MHR can be
described as follows:
a. Method for Deriving Electricity Forward
i.
ii.
iii.
iv.
v.
Components for Electricity Forward (SP15 or Np15 – 12 month forward)
Electricity Publications (ICE & Platt’s MWD, not yet decided)
Number of Trade Days (3 to 40 days, not yet decided)
Which Trade Days (last trade days prior to posting month)
On/Off peak weighting – Use actual hours to determine weighting or
Decision directed 57%/43%. (57%/43%)
b. Method for Deriving Gas Forward
i.
ii.
iii.
iv.
Components for Gas Forward (Henry Hub, SoCal Basis)
Gas Publications (NYMEX HH contract, NYMEX Clearport)
Number of Trade Days (3 to 40 days, not yet decided)
Which Trade Days (last trade days prior to posting month)
9
v. Trade Days for Gas (consistent with Electricity Forwards)
c. Method for Deriving GTn Forecast
i. Components for GTn (same as GTn in SRAC posting)
ii. O&M (use escalating O&M as directed by Decision)
iii. Averaging Method – Average prices first, then calculate heat rates. Or, calculate
each individual heat rate first, then average the heat rates. (calculate each
individual heat rate first, then average the heat rates)
These components can then be used to calculate the MHR using the following formula:
Monthly Heat Rate Month 1 = ([SP15 or NP15] forward Month 1 - O&M Month 1) / Burnertip Gas Forward Month 1
Trading Date Heat Rate Day 1 = Average (Monthly Heat Rate Month 1 … Monthly Heat Rate Month 12)
Market Heat Rate = Average (Trading Date Heat Rate Day 1 …Trading Date Heat Rate Day n)
Burnertip Gas Forward = NYMEX HH + SoCal Basis + GTn Forecast
GTn Forecast – Partially relying on NYMEX HH, SoCal Basis sources, and existing SoCalGas
tariffs
3.
Detailed Description of SDG&E Proposal
The Decision states at page 66 that to calculate the Market Heat Rate “we will use a 12month rolling average of the weighted average price of forward market prices for NP15 (PG&E)
and SP15 (for SCE and SDG&E).” Further explanation is provided at page 66, “This is based on
SCE’s proposed methodology in Exhibit 1, but deducts the variable O&M from prices as
proposed by SDG&E. We note that by using a 12-month rolling average of forward prices, there
is little, if any, difference between a collared and an uncollared heat rate. Thus, SCE’s rationale
for utilizing a collar around the IER does not appear to be present, as a rolling average of
forward prices serves to mitigate excessive price volatility.”
In these two passages, the Decision appears to suggest a rolling average similar to that
proposed by SCE should be used and would mitigate volatility that would exist if the weighted
average of long-term forward prices for the next 12-month period were replaced in their entirety
each month. The fact that 11 months stay the same provides the stability the Commission
determined will avoid excessive volatility.
SDG&E proposes to collect data on one day per month to reduce the burden of data
collection and verification. The 12 months of long-term electric and gas forward prices would be
10
collected on the third business day before the end of the month to coincide with the bidweek
period for gas prices (the last five business days of the month). During this period there is likely
more liquidity in the market for long-term forward electric and natural gas products.
The following tables provide an illustration of the calculations. Tables 1 and 2 show the
calculation of the weighted average electric 12-month forward price.
Table 1
12-Month Average Forward On-Peak And Off-Peak Electric Prices For July, 2007
[Illustrative Data]
Flow Date
07/01/2007
08/01/2007
09/01/2007
10/01/2007
11/01/2007
12/01/2007
01/01/2008
02/01/2008
03/01/2008
04/01/2008
05/01/2008
06/01/2008
12-month Average
11
On-peak Off-peak
89.50
55.50
92.75
58.50
88.10
57.50
77.50
61.00
77.50
61.00
77.50
61.00
82.75
66.00
82.75
66.00
82.75
66.00
77.50
51.50
77.50
51.50
77.50
51.50
81.97
58.92
Table 2
Weighted Average Of On-Peak And Off-Peak Electric Prices
[Illustrative Data]
Month/Year
Jul-06
Aug-06
Sep-06
Oct-06
Nov-06
Dec-06
Jan-07
Feb-07
Mar-07
Apr-07
May-07
Jun-07
Jul-07
ON PK
OFF PK
72.22
75.71
81.38
68.56
72.67
78.25
73.78
69.35
76.30
75.75
83.31
85.24
81.97
53.43
56.92
59.83
50.96
51.06
53.31
51.55
48.21
55.90
43.54
60.02
59.25
58.92
ON PK
Hrs %
57%
57%
57%
57%
57%
57%
57%
57%
57%
57%
57%
57%
57%
OFF PK
Hrs %
43%
43%
43%
43%
43%
43%
43%
43%
43%
43%
43%
43%
43%
Weighted
Avg Price
64.14
67.63
72.11
60.99
63.38
67.53
64.22
60.26
67.52
61.90
73.29
74.07
72.06
Table 3 below shows a similar calculation of the SoCalGas border price based on the
Henry Hub price and the SoCal border price basis compared to Henry Hub.
12
Table 3
Natural Gas Price Calculation for July, 2007
[Illustrative Data]
July-07
August-07
September-07
October-07
November-07
December-07
January-08
February-08
March-08
April-08
May-08
June-08
Average
SoCal Border
Forward Price
6.59
6.42
6.27
6.15
6.72
7.77
8.09
8.09
8.01
7.23
7.28
7.39
7.170
Month/Year
Jul-06
Aug-06
Sep-06
Oct-06
Nov-06
Dec-06
Jan-07
Feb-07
Mar-07
Apr-07
May-07
Jun-07
Jul-07
(Average)
7.231
8.099
7.754
6.282
6.927
7.673
6.432
7.628
7.721
7.783
8.075
8.019
7.170
SDG&E proposes to set up the calculation in the same manner as shown in Table 3 of the
Decision. The first column of Table 4 shows the weighted average of 12-month forward electric
prices from Table 2. The second column shows the variable O&M. The third column is the 12month forward SoCalGas border prices from Table 3. Fourth column is the current gas intrastate
transportation rate. The remainder of the columns are calculations of the market IER calculation;
the calculation of the MHR, the rolling average of the market IERs; and finally, the IER, and
average of the SDG&E AHR, 9,603, and the MHR.
13
Table 4
Calculation of IER
[Illustrative data]
Weighted
Avg SP-15
SoCal
Electric
Border
Price
Var O&M Gas Price
Month/Year
Jul-06
Aug-06
Sep-06
Oct-06
Nov-06
Dec-06
Jan-07
Feb-07
Mar-07
Apr-07
May-07
Jun-07
Jul-07
64.14
67.63
72.11
60.99
63.38
67.53
64.22
60.26
67.52
61.90
73.29
74.07
72.06
2.60
2.60
2.60
2.60
2.60
2.60
2.65
2.65
2.65
2.65
2.65
2.65
2.65
7.231
8.099
7.754
6.282
6.927
7.673
6.432
7.628
7.721
7.783
8.075
8.019
7.170
Gas
Trans.
Rate
0.4350
0.4350
0.4350
0.4350
0.4350
0.4350
0.3859
0.3859
0.3859
0.3859
0.3859
0.3859
0.3859
Implicit
Heat Rate
(net of
VOM)
8,027
7,619
8,488
8,694
8,256
8,007
9,031
7,188
8,002
7,253
8,349
8,497
9,186
MHR
8,118
8,214
IER
8,860
8,909
The rolling average recommended in the Decision and shown in the next to last last
column reduces the volatility of the MHR, so that a collar is not required.
E.
Administrative Heat Rate (AHR)
The Decision provides specific values for the AHR for each of the three IOUs. None of
the IOUs have been able to replicate the determination of these values from 1994 and 1995 data,
and all three IOUs believe that the values calculated are incorrect. The correct AHR values for
SCE, PG&E and SDG&E should be 9,140 Btu/kWh; 9,464 Btu/kWh and 9,339 Btu/kWh
respectively. However, given that the Decision does not indicate how the values were derived
and instead hardwires the values, there may be little left to interpretation at the workshop.
F.
Operations and Maintenance (O&M)
The Joint Parties agree that the O&M component of the MIF should begin with 0.250
cents/kWh in 2004 and be escalated by 2% per year thereafter. The VOM should be escalated at
2% per year unrounded, but paid at a rounded four significant digits in cents/kWh. The
escalation should occur each January. These values are calculated in the following table.
14
Table 5
Calculation of O&M Adder
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
G.
Payment
Unrounded
rounded
cents/kWh cents/kWh
0.250000
0.255000
0.260100
0.265302
0.270608
0.2706
0.276020
0.2760
0.281541
0.2815
0.287171
0.2872
0.292915
0.2929
0.298773
0.2988
0.304749
0.3047
0.310844
0.3108
Energy Time of Use (TOU) Factors
The Decision provides that the IOUs are to use energy TOU factors that are consistent
with the adopted TOU factors for the Market Price Referent (“MPR”), stating “Nevertheless, we
believe that updating the IOUs’ TOU/TOD factors and periods to too flat to adequately reflect
the differential in prices in peak and off-peak be consistent with the TOU factors adopted in
other procurement proceedings is reasonable and as pointed out by CCC, the TOD factors are
periods.[?Is quote correct] In light of this, we believe it is appropriate to adopt TOU factors that
are consistent with the adopted TOU factors for the Market Price Referent (MPR).” [Emphasis
added]
The two issues in developing SRAC TOU factors consistent with the MPR factors are 1)
the separation of capacity and energy components of the MPR factors and 2) the alignment of the
SRAC and MPR TOU periods. SCE has the first issue, SDG&E has the second issue, and PG&E
has both issues.
15
1.
SCE SRAC TOU factors
The SCE TOU factors for the MPR are as follows:
Summer On
Summer Mid
Summer Off
Winter Mid
Winter Off
Winter Super
3.28
1.28
0.67
1.02
0.82
0.65
The MPR is an “all in” price, which includes both energy and capacity. Consequently,
the TOU factors developed for the MPR are intended to reflect the value of both energy and
capacity during various periods of time. In contrast, energy and capacity payments made to QFs
are differentiated, and separate and distinct TOU factors have historically been applied to energy
payments and capacity payments made to QFs. Applying the MPR TOU factors to SRAC will
thus result in an overpayment for capacity to QFs that already receive time-differentiated
capacity payments to reflect the increased value of capacity during various periods.
The Joint Parties therefore interpret the Decision as requiring the “energy component” of
the TOU factors applied to the MPR to be determined in order to avoid a payment in excess of
avoided cost for capacity. [Here is an idea – SCE proposes to keep its existing SRAC energy
factors, which no party took issue with in the proceeding, and allocate capacity such that for firm
capacity the sum of the SRAC energy and capacity equals the MPR factors. ] The Joint Parties
do not have a specific proposal at this time for developing an energy only TOU factor from the
TOU factors adopted to adjust the all-in MPR price.
2.
SDG&E TOU Factors
SDG&E’s MPR TOD factors are appropriate for an energy market application since they
do not include an additional capacity cost component as explained on the California Energy
Commission Report, CEC-300-2006-015, “A Summary and Comparison of the Time of Delivery
Factors Developed by the California Investor-Owned Utilities for Use in Renewable Portfolio
Standard Solicitations.”
However, the hourly time periods and the months included in summer and winter are
different between the SDG&E MPR TOD factors and the SRAC TOU factors as shown below.
The SRAC summer period is five months, not four and includes May – September, not July October. Further, the hourly time period definitions differ, especially the winter on-peak period,
16
which is three hours in length for the SRAC TOU periods (5-8 pm), but 8 hours long for the
MPR TOD periods (1-9 pm).
Table 6
MPR TOD Periods
SUMMER
JULY 1 - OCTOBER 31
TIME PERIODS
WINTER
NOVEMBER 1 - JUNE 30
ON-PEAK
11:00 a.m. - 7:00 p.m.
Weekdays
1:00 p.m. - 9:00 p.m.
SEMI-PEAK
6:00 a.m. - 11:00 a.m.
Weekdays
6:00 a.m. - 1:00 p.m.
Weekdays
7:00 p.m. - 10:00 p.m.
Weekdays
9:00 p.m. - 10:00 p.m.
Weekdays
10:00p.m. - 12:00 mid.
5:00 a.m. - 6:00 a.m.
5:00 a.m. - 12:00 mid.
5:00 a.m. - 12:00 mid.
Weekdays
Weekdays
Weekends
Holidays
10:00 p.m. - 12:00 mid.
5:00 a.m. - 6:00 a.m.
5:00 a.m. - 12:00 mid.
5:00 a.m. - 12:00 mid.
Weekdays
Weekdays
Weekends
Holidays
12:00 mid. - 5:00 a.m.
All Days
12:00 mid. - 5:00 a.m.
All Days
OFF-PEAK
Weekdays
Time periods are currently defined in accordance with the above table. All time periods listed are clock time. The time period
Table 7
SRAC TOU Periods
TIME PERIODS
SUMMER
MAY 1 - SEPTEMBER 30
WINTER
OCTOBER 1 - APRIL 30
11:00 a.m. - 6:00 p.m.
Weekdays
5:00 p.m. - 8:00 p.m.
6:00 a.m. - 11:00 a.m.
Weekdays
6:00 a.m. - 5:00 p.m.
Weekdays
OFF-PEAK
6:00 p.m. - 10:00 p.m.
10:00p.m. - 12:00 mid.
5:00 a.m. - 6:00 a.m.
5:00 a.m. - 12:00 mid.
5:00 a.m. - 12:00 mid.
Weekdays
Weekdays
Weekdays
Weekends
Holidays
8:00 p.m. - 10:00 p.m.
10:00 p.m. - 12:00 mid.
5:00 a.m. - 6:00 a.m.
5:00 a.m. - 12:00 mid.
5:00 a.m. - 12:00 mid.
Weekdays
Weekdays
Weekdays
Weekends
Holidays
SUPER OFF-PEAK
12:00 mid. - 5:00 a.m.
All Days
12:00 mid. - 5:00 a.m.
All Days
ON-PEAK
SEMI-PEAK
Weekdays
Time periods are currently defined in accordance with the above table. All time periods listed are clock time. The time period definitions may be revised to
comply with CPUC orders regarding billing hours. The Holidays specified are: New Year's Day, President's Day, Memorial Day, Independence Day, Labor
Day, Veteran's Day, Thanksgiving Day, and Christmas Day as designated by California's Law.
To develop SRAC TOU factors that are consistent with the MPR TOD factors, SDG&E
is proposing to use the exact same hourly price data used to originally calculate the MPR TOD
factors, except to change the time periods to match the time periods of the SRAC TOU periods
rather than the time periods of the MPR TOD factors. This process will provide SRAC TOU
factors that are consistent with the MPR, but that account for the differences in time period
definitions.
17
Table 8
Summer
Winter
On-Peak
1.4980
1.3439
Semi-Peak
0.9861
1.1612
Off-Peak
0.8727
0.9875
Super Off-Peak
0.5739
0.6935
For comparison purposes, the MPR TOD factors are shown in the table below.
Table 9
Summer
Winter
On-Peak
1.641
1.192
Semi-Peak
1.040
1.079
Off-Peak
0.883
0.793
Super Off-Peak
0.883
0.793
H. Capacity Time of Use Factors (Capacity TOU Factors)
The Decision does not address TOU factors for capacity payments. No change is
required if an appropriate methodology for determining an energy-only factor from the all-in
factors used to adjust the MPR is developed.
I.
Line Loss Factors
At Page 75, the Decision states that “Since the MIF we adopt today is based on the
Transition Formula, we decline to modify the GMM calculation at this time.” No adjustments
are required at this time. [Consider moving this next discussion to MRTU section] However,
further consideration will need to be given to this issue once MRTU becomes operational,
regardless of whether MRTU pricing is used to derive the MHR. The Joint parties understand
that once nodal pricing is adopted as the basis for settlements, the CAISO will no longer adjust
settlements using GMMs to account for losses, and that the relative value of energy delivered at
different geographic locations will be reflected and incorporated in the nodal price, although not
necessarily as a discretely calculated element of the price. Thus, although it may be premature
18
(and, the Joint Parties suggest, counterproductive) at this juncture to consider how the
operationalization of MRTU will affect the calculation of the MHR, more urgent consideration
should be given to the effect MRTU will have on the calculation of line loss factors.
IV.
IMPLEMENTATION OF THE MIF POST-MRTU
As noted above, the Joint Parties strongly urge the Commission to defer consideration of
post MRTU implementation of SRAC to a later date, except insofar as the inception of nodal
pricing may require a more urgent updating of the line loss factors applicable to SRAC energy
pricing. There are three reasons to defer this discussion, which lead the Joint Parties not to make
a specific proposal at this time.
First, as provided in the Decision, the use of MRTU pricing as an input value to the
formula parametrically adopted by the Decision will not occur until 6 months after MRTU
becomes operational at the earliest, meaning about 1 year from now.
Second, as all parties will acknowledge, MRTU will result in a significant change in the
way in which energy is valued and priced. In particular, MRTU will result in a shift from zonal
pricing to nodal pricing. Theoretically, and in practice, this will result in potentially hundreds of
“avoided costs” for each IOU reflecting the value of energy delivered at various nodes.
Historically, avoided cost has been thought of and calculated as a single value. While it may be
possible do continue this practice in a post-MRTU environment, careful consideration must be
given to whether or not it is either preferable or lawful to average nodal prices and whether it is
practicable or administratively desirable to use multiple pricing points for SRAC depending on
the location of the QF. Although it may be intellectually stimulating to discuss these issues at
the upcoming workshop, the issues which arise from such pricing regime deserve more
deliberate thought and attention than is possible at a two-day workshop dedicated to many other
issues and given the limited time to develop comments.
Finally, the Decision itself suggests a simple interpretation. At page 4, the Decision
states: “In addition, we anticipate that the Market Redesign and Technology Update (MRTU)
will be operational within the next 12 months and will provide a robustly traded day-ahead
market that establishes a market price that reflects the full avoided costs of the state’s utilities.”
[Emphasis supplied]. This statement expresses the view that the day-ahead price will in fact be
the avoided cost of energy at the time of delivery. In that event, the correct payment
19
methodology would be to simply pay the day-ahead price established in the MRTU market,
filtered through the transition formula.
At page 68 the Decision states: “Six months after the implementation of the CAISO’s
day-ahead market the MIF shall be revised to remove the administrative heat rate component
and base the IER exclusively on MRTU market prices.” [Emphasis supplied.] This indicates that
although day ahead prices “reflect full avoided cost,” the prices must be transmuted into an IER
value for purposes of making SRAC payments to QFs. Nodal hourly prices transformed into an
hourly IER is a reasonable interpretation of the Decision.
However, other parties may differ on how this calculation should be performed given the
other elements of the decision. For example, given the direction to use a twelve month rolling
average of forward prices to derive the MHR, it could arguably be done using forward markets
based on the MRTU day-ahead markets, if they exist; or a historical average of day-ahead prices.
All of the potential variants that might be proposed to imply a heat rate of IER value from dayahead prices seem circuitous given the recognition in the Decision that the day-ahead price will
ultimately fully reflect the utilities avoided cost.
Based on the foregoing, the Joint Parties urge the Commission to defer
consideration of post-MRTU pricing to a later date, and to focus the workshop effort
exclusively on near term implementation of the Decision’s directives for energy pricing.
Indeed, given the complexity of some the issues implicated in incorporating day-ahead
pricing into a heat rate formula approach to calculating SRAC, the Commission may
wish to consider convening hearings and developing an evidentiary record on this
point.
20
V.
CONCLUSION
The Joint Parties appreciate the opportunity to comment and look forward to participating
in the workshop.
Respectfully submitted,
WILLIAM V. MANHEIM
EDWARD V. KURZ
MARY A. GANDESBERY
Pacific Gas and Electric Company
Post Office Box 7442
San Francisco, CA 94120
Telephone: (415) 973-6669
Fax: (415) 973-5520
E-mail: [email protected]
By: s/_____________________________
EDWARD V. KURZ
GEORGETTA J. BAKER
San Diego Gas & Electric Company
101 Ash Street
San Diego, CA 92101
Telephone: (619)699-5027
Fax: (619) 699-5027
E-mail: [email protected]
By: s/_____________________________
GEORGETTA J. BAKER
BERJ K. PARSEGHIAN
Southern California Edison Company
2244 Walnut Grove Ave.
Rosemead, CA 91770
Telephone: (626) 302-1924
Fax: (626) 302-1904
E-mail: [email protected]
By: s/____________________________
BERJ K. PARSEGHIAN
October 22, 2007
21
CERTIFICATE OF SERVICE
I hereby certify that, pursuant to the Commission’s Rules of Practice and Procedure, I
have this day served a true copy of the “JOINT PRE WORKSHOP COMMENTS OF
PACIFIC GAS & ELECTRIC COMPANY (U 39-E) SAN DIEGO GAS &
ELECTRIC COMPANY (902-E) AND SOUTHERN CALIFORNIA EDISON
COMPANY (U 338-E)” on all parties identified on the attached service list(s). Service
was effected by one or more means indicated below:
Transmitting the copies via e-mail to all parties who have provided an e-mail
address. First class mail will be used if electronic service cannot be effectuated.
Executed this 22nd day of October, 2007, at Rosemead, California.
_/s/ _________________________________
RAQUEL IPPOLITI
Project Analyst
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue
Post Office Box 800
Rosemead, California 91770