TO:
Chuck Goldman/LBL
FROM:
Grayson Heffner
DATE:
November 3, 2000
SUBJECT:
Draft Task 1 Report for LBNL Subcontract # 6505348, ‘Review & Analysis
of Load Management/Demand Responsiveness Programs”
Please find attached a draft memo report entitled Review of California’s Non-Firm
Commercial/Industrial Load-Management Programs.
The report consists of a narrative, several tables (which I have previously sent you), and a
number of hard copy attachments.
I am sending you via e-mail the parts of the report that I have in electronic format and will
send a complete hard copy version by overnight mail.
I hope this draft meets your requirements and satisfies the deliverable requirements of Task
1. Please let me know what you would like added, subtracted, or modified.
15525 AMBIANCE DRIVE • NORTH POTOMAC, MD • 20878
TEL: (301) 330-0947 • FAX: (301) 330-0141
–2–
March 8, 2016
Review of California’s Non-Firm Commercial/Industrial Load-Management Programs
California’s three investor-owned Local Distribution Companies (LDCs), Pacific Gas and Electric
Company (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E), operate
several load management programs that taken together represent almost 2,800 MW of dispatchable peak
demand.
This brief review examines the performance of these load management programs in operation under the
direction of the California Independent System Operator (Cal ISO) during the last three peak demand seasons
(1998, 1999, and 2000) in California.
This review relies almost exclusively on secondary sources of information and data available through the
utilities themselves as well as the California Public Utilities Commission (CPUC), intervenor groups such as
TURN and CLECA, and of course the Cal ISO. Brief interviews were also conducted with utility personnel
charged with management of the several load management programs reviewed.
This memo report is organized into six sections as follows:
1

Summary

History and Load Management Program Background

Program Structure and Operations

Performance Results for 1998-2000

Issues for the Future of Non-Firm Load Management Programs

Contact Points
S U M M A RY
On at least five separate occasions during this past summer, the dispatchable load management programs
operated by the five major California utilities were instrumental in avoiding disruptive Stage 1 electric power
emergencies across the state. Taken together these programs were able to reliably deliver as much as 2200 MW
on demand by the California ISO. The load reductions were dispatchable on as little as 30 minutes notice and
were sustained for durations up eight hours. The programs were also durable in that they were called upon as
many as 12 times in a summer without significant deterioration in performance. Table 1 summarizes the
frequency of operation over a three-year period for the three largest programs.
Number of Nonfirm Program
Operations Each Year by Utility
1998
1999
2000
PG&E
5
2
13
SCE
3
1
12
SDG&E
2
1
8
Table 1: Frequency of Operation of Nonfirm Programs: 1998-2000
A specific example helps describe the critical role that the dispatchable load management played in
mitigating the summer 2000 electric emergencies in California. Wednesday, August 2, 2000, was the eighth Stage
–3–
March 8, 2016
Two emergency declared by the California ISO during the Summer 2000 peak demand season. It was also the
second of what would be four consecutive Stage-Two Emergencies called that week. Due to a weeklong heat
wave affecting the entire West Coast, forecast demand for August 2 was 45,723 MW – only 150 MW short of
the all-time record demand for the State.
A Stage One emergency under the ISO’s Electric Emergency Plan was declared at 11 am, and an appeal
was made urging Californians to conserve as much energy as possible. At 1 pm the state-wide spinning reserve
fell below 5%, and the electric emergency entered Stage Two. With the Stage Two declaration came an order
from the ISO to the LDCs to implement all non-firm and load management programs. Altogether the three
utilities and five different programs reduced peak demand by an estimated 2,190 MW. The California system
demand peaked at 42,879 and the spinning reserve held steady at 1.5% - just enough to avoid a Stage Three
Emergency, when rolling black-outs become a part of the ISO’s Electric Emergency plan.
One August 2 the 2,190 MW of non-firm load represented almost four times the spinning reserve of 450
MW available to the ISO. It is thus highly likely that on this and at least four other instances (July 31, August 1,
August 16, and Sept. 18) the performance of the non-firm programs kept the spinning reserve above 1.5% and
allowed the ISO to avoid declaring a Stage Three Emergency.
The non-firm load programs have provided an important hedge against resource uncertainty during peak
demand conditions for as long as the California ISO has been responsible for the power grid. There were
seventeen Stage Two Emergencies declared during Summer 2000. There was one Stage Two Emergency only
during Summer 1999 but five Stage Two Emergencies during Summer 1998. In addition to these summer
system emergency operations, the individual programs were also called upon four times to alleviate local
transmission emergencies or regional transmission constraints and in one case (December 1998) because of a
cold weather induced natural gas shortage to power plants.
These significant contributions come at a time when the non-firm programs are in the midst of major
change. The three large customer non-firm programs described here involve tariffed rates and grand-fathered
eligibility requirements that are due to expire March 31, 2002. More immediately, one of the provisions in the
current tariffs (I-6 for SCE, E-19/E-20 for PG&E, and I-3 for SDG&E) calls for a one-month exit window in
the month of November each year, during which customers who want to revise their conditions for
participating or exit the non-firm program altogether can do so without penalty or permission. The California
Public Utilities Commission (CPUC) recently issued an Order Instituting Rulemaking into the Operation of
Interruptible Rate Programs (OIR-00-10-002). The stated objectives of this proceeding are to: “(1) examine
the role of customers on a utility’s interruptible tariffs to ensure reliable and reasonably-priced electric
service…for the Summer of 2001; and (2) coordinate the variety of interruptible, curtailable, and demand
responsiveness programs being offering and proposed.”1 However, the first official rulings of the Commission
in this proceeding were to temporarily suspend the opt-out provision and to defer until April 2001 the question
of whether or not these non-firm program participants will be allowed to exit at all.
A key issue implicit in the Commission’s proposed rulemaking is whether California’ ratepayers have gotten
their money’s worth out of these programs. Ratepayers of all classes taking firm service pay over $220 million
per year – over $6,000 per kw per year of curtailable load – to the non-firm participants. Cumulative payments
over the past ten years – over a period when these programs were operated very infrequently if at all – totaled
close to $2 billion. In return for these generous payments, California ratepayers were expected to have a
curtailable load resource signed up for 3-5 year contracts as a hedge against resource uncertainty and system
emergencies. Some regulators and energy policymakers feel that these non-firm customers should not be
allowed to opt out of these programs on short notice just when the capacity shortages and system emergencies
have resulted in much more frequent emergency curtailments.
“Order Instituting Rulemaking into the Operation of Interruptible Load Programs”, R-00-10-002, issued Oct.
6, 2000.
1
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March 8, 2016
Further complicating the policy and economic issues is the anecdotal evidence that some, if not many,
non-firm customers have been buying through the curtailments by paying the penalties on excess energy use.
The scale and causes of non-firm customer noncompliance during Summer 2000 has not yet been determined
but is certainly under study by all sides.
Finally, there are many new ideas or initiatives under development that build on the basic notion that enduse customers can be encouraged to significantly reduce their demands during periods of high wholesale prices
or scarce generation resources. The Cal ISO has several experimental price-responsive pilots underway and all
three LDCs have already proposed new demand management programs, such as PG&E’s E-Bid Program.
Other structural issues, such as whether price-responsive demand management should be bid into an ancillary
services market or kept within the purview of load-serving entities or local distribution companies or energy
service providers, will also likely be taken up in this proceeding.
To sum up, it appears that the next six-nine months will see extensive debate and policy development
regarding the role of non-firm rate programs and in fact load management programs in general in California.
The debate will be all the more interesting and certainly more urgent as it will take place with a backdrop of
frantic short-term preparations by the ISO and others for a potentially even more costly and embarrassing
summer peak season in 2001.
2
H I S T O RY A N D L OA D M A N AG E M E N T P RO G R A M B AC KG RO U N D
California began implementing load management programs in the late 1970’s and early 1980’s in response
to a capacity-short situation and the delays in bringing new capacity, such as the Helms pumped storage project
and the Diablo Canyon nuclear generating station, on line. Among the dispatchable load management programs
developed were residential air conditioner and water heater load control, agricultural pumping load control,
small commercial interruptible programs, and commercial/industrial interruptible/curtailable programs. By the
mid-1980s there were over 200,000 residential customers with load control devices representing almost 300
MW of load control. 2,3
The large customer non-firm rate programs were established in the mid-1980s. In 1985 PG&E and SCE
each had about 30 large customers on interruptible/curtailable rates. Under these programs, customers receive
a discount off of their electric rates in exchange for the ability of the utility to curtail them for a certain
number of hours per year.
The customers were subject to fairly frequent operations up until about 1988, when there was sufficient
generation capacity on line. From 1988 until 1995 there were very few if any operations.
In April of 1998 the California Independent System Operator (CAISO) assumed responsibility for control
of generation scheduling and grid operations in California. Along with this responsibility the CAISO also
assumed control over the energy curtailment programs of the three LDCs whenever system-wide or local
operating conditions called for their operation. Each of the LDCs modified their individual non-firm tariffs to
establish consistent operating parameters across the entire state. The operational details of the non-firm
program are discussed in Section 3 below.
3.1
PACIFIC GAS AND ELECTRIC COMPANY (PG&E)
PG&E currently has about 200 customers representing 500 MW of curtailable load on its E-19 and E-20
rates. The program has been stable since the late 1980s, when the current level of rate discount for non-firm
service was established. In rate proceedings the California Large Energy Consumers Association (CLECA)
“Residential Air Conditioner Cycling: A Case Study”, G. F. Strickler, et al, v. 3, #1, IEEE Transactions on
Power Systems, February 1988.
3 “1984-1985 Progress Report to the California Energy Commission on PG&E’s Summertime Break Program”,
PG&E Load Management Group, Rates Department, November 1985.
2
–5–
March 8, 2016
represents these customers. The current program was closed to new participants in 1993 and is scheduled to
expire on March 31, 2002. The minimum eligibility requirement for the non-firm rates has historically been set
at a minimum of 500 kW of average load during the summer on-peak period. As a practical matter, this has
largely limited the non-firm rates to PG&E’s existing Schedule E-20 customers, who have at least 1,000 kW of
billed monthly maximum demand. Typically, the customer will designate a “Firm Service Level (FSL)” when
they join the program. Upon notification of an emergency curtailment the customer has one hour to bring their
demand down to or below the FSL. The current tariff allows PG&E’s non-firm customers to be curtailed up to
30 times per year, no more than 6 hours per curtailment, and for no more than 100 hours per year. The
customer must reduce their load within 1 hour of notification by the utility or face penalties of $8.40 per kWh
of excess energy used. PG&E has detailed operational records going back to 1981 that show the number of
occasions it has requested emergency curtailments from its non-firm customers. Table 2 shows this history of
curtailments for the period 1981-1997.
‘81
‘82
‘83
‘84
‘85
‘86
‘87
‘88
‘89
‘90
‘91
‘92
‘93
‘94
‘95
‘96
‘97
3
1
10
7
1
0
1
0
0
0
0
1
0
0
1
4
1
Table 2: PG&E Non-Firm Rate Program Emergency Curtailments: 1981-19974
As of mid-Summer 2000, there were 215 customers on PG&E’s non-firm tariffs. These customers
received an annual discount from firm service rates of about $45.1 million – about a 15% discount on average
from firm service rates. PG&E reported in a TURN data request that in 1998 and 1999 the average load in
excess of contract FSL was about 20 MW (out of 500 MW, or less than 5%). The corresponding penalties paid
for this excess energy was about $250,000 per curtailment.
Several pdf.adobe files are available with additional details on the administration of PG&E’s non-firm rates
program. Table 3 (NFSequence.pdf) shows the seven regional groupings that PG&E has established. These
groups correspond to transmission planning areas (TPAs) that PG&E has established. The groups – named ZP
26, Fresno, SF Local, Humboldt Local, Sacramento, Outer Bay Area, NO Path 15, and Bay Area - are of
unequal size. However, an attempt is made to operate them sequentially in such a way as to equalize the
number of curtailment hours for each customer over the course of an operating season. Figure 1
(NFGroupsMap.pdf) shows the boundaries of each transmission planning area and Regional Non-firm Load
Group. Figure 2 (nfflowchts.pdf) shows a communications single-line diagram for the dispatch of PG&E’s nonfirm customers.
Finally, conversations with PG&E program personnel as well as a review of billing records reveals that
most of PG&E’s non-firm customers fall into the following two-digit SIC classifications:5
4
5

10 (Primary Metals Extraction)

13 (Oil & Gas)

20 (Food Processing)

24 (Lumber & Wood)

26 (Pulp & Paper)

28 (Organic Chemicals)
“Nonfirm Program History of Operations”, PG&E Tariff Services, last updated 6/29/00.
10/20/00 conversation with Andrew Bell, PG&E Rates Department.
–6–
3.2

32 (Glass, Clay, & Ceramics)

35 (Manufacturing)
March 8, 2016
SOUTHERN CALIFORNIA EDISON (SCE)
SCE currently operates three sizeable load management programs –the Air Conditioner Cycling Program,
and the Agricultural & Pumping Interruptible Program, and of course the I-6 Interruptible Services Program.
The Air Conditioner Cycling Program has been around for many years, and there are still over 200,000
customers – almost all residential – participating. The tariff designations are D-APS and GS-APS. According to
SCE’s response to a TURN data request, this program delivered over 200 MW of instantaneous peak load
reduction on seven separate occasions between July 1998 and July 20006. This was the first time that this
program had been operated in several years, and there is some anecdotal evidence that some customers were
not aware they were on the program and in fact called the HVAC repairman when their air conditioner did not
appear to be operating correctly. SCE has recently filed to modify tariffs D-APS and GS-APS to allow
customers to be cycled more than the 15 times per summer now allowed and outside the normal five-month
summer window (June 1 to September 30) and instead allow the program to be operated whenever the ISO
determines that a Stage III Emergency is imminent.7
The Agricultural and Pumping Interruption Program is tariffed as TOU-PA-SOP-I, or Time-of-Use,
Agricultural and Pumping – Super Off-Peak – Interruptible. This program is only for large (greater than 50
kW) customers who can interrupt their loads on very short notice (30 minutes) upon notification from the
Company. Interruptions are limited to 25 times per calendar year and 150 hours per year, with a maximum
duration per day of six hours. Customers must have interval meters and must pay a penalty of $5.70 per kWh
for any usage after the 30 minutes notice period and over the duration of the interruption. In Summer 2000
this program consistently delivered 45 MW of demand reduction on seven separate occasions over the period
July 1998 to July 2000.
The I-6 and TOU-8-SOP-I Interruptible Services Program (ISP) is the flagship of the Edison non-firm
rates. A large percentage of Edison’s largest customers participate in this program – over 1300 out of a total
large customer population of 4500. As with the PG&E program, customers must have a summertime
maximum demand of at least 500 kW to be eligible to participate. Taken together the participating customers
have a theoretical maximum (non-coincident maximum demand less firm service level) demand reduction
potential of around 3,000 MW. However, as a practical matter, the amount actually available during coincident
peak periods is about 2000 MW. These customers receive rate discounts totaling about $180 million in exchange
for their participation. Interruptions are limited to 25 times per year, six hours per interruption, and 150
cumulative hours per calendar year. Table 4 shows the number of times that the ISP has been operated between
1994 and 1999.
Year
1999
1998
1997
1996
1995
1995
# of I-6 Interruptions
1
3
0
1
0
0
Table 4: SCE I-6 ISP Emergency Curtailments: 1995-1999
Edison has organized its interruptible load into blocks. Currently there are nine blocks – Z, Y, H, G, F, E,
D, C, and B. Each block has approximately 200 MW. When an interruption is called, the blocks are dispatched
in reverse alphabetical order until the ISO’s requested load reductions are satisfied. The next interruption then
SCE Company Advice 1465-E, “Emergency Modification to SCE’s Commercial & Industrial Interruptible
Program to Assist in Alleviating the Shortage of Generating Capacity in the State of California, Data Request
# 1 (TURN), 7/18/00.
7SCE Advice Letter # 1479-E, August 18, 2000.
6
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March 8, 2016
begins with the customers in the load block immediately following the last interrupted load block, again in
reverse alphabetical sequence. Table 5 (separate page) shows the actual operations by day and by load block for
Summer 2000. Note that all nine blocks representing the entire ISP population were dispatched on only five
occasions – July 31, August 1, August 2, August 16, and September 18.
According to SCE’s response to a TURN data request, the ISP delivered 425 MW of interruptible load on
seven separate occasions between July 1998 and July 2000. According to Edison sources, the program delivered
between 900 and 1100 MW of load reduction on the five instances between July and September 2000 when the
entire population was activated.8
3.3
SAN DIEGO GAS AND ELECTRIC COMPANY (SDG&E)
SDG&E operates a small industrial interruptible program, with approximately 40 participants, served on
Rate Schedule AV-1. It has consistently contributed approximately 40 MW of load on at least eight occasions
between June 1998 and September 2000. SDG&E non-firm customers receive the same level of discount as
PG&E and SCE customers – about 15% - and are subject to similar tariff provisions regarding frequency and
duration of curtailments and penalty provisions.
3
C U R R E N T P RO G R A M S T RU C T U R E A N D O P E R AT I O N S
Before 1998 each individual LDC operated their own generation and transmission assets, closely
coordinating with neighboring utilities. The tariff provisions for emergency curtailment operations reflected the
emergency procedures developed by each utility individually. Starting in 1998 the CAISO was placed in charge
of dispatching and coordinating all generation and grid assets in California.
3.4
CAL ISO ELECTRIC EMERGENCY PLAN (EEP)
The Cal ISO has put in place a complicated system of alerts, warnings, and emergency notifications as part
of its institutional role as operator of California’s electric system. Alerts, Warnings, and Emergencies may be
declared by the ISO when a shortfall of Operating Reserve 9 or some other marginal operational condition is
forecast to occur. The timing and severity of the forecasted shortfall determines whether an Alert, Warning or
Emergency is declared. An Alert may be declared at any time there is a forecasted shortfall of operating
reserve. A Warning may be declared a day ahead or more of the time that there is a forecasted shortfall in
operating reserve. Both the Alert and Warning declarations are sent to market participants – producers,
transmission owners, local distribution companies – in an effort to stimulate the market to provide more
resources or warn the participants of potentially inadequate operating reserves.
Emergencies may be declared for more severe circumstances and are communicated to the general public. A
Stage 1 Emergency may be declared anytime that an Operating Reserve shortfall (less than 7%) is unavoidable
or is forecast to occur in the next two hours. A Stage 1 Emergency declaration includes a request to
customers to voluntarily reduce their consumption of electric energy in order to avoid more severe conditions
including involuntary curtailments. There were seven Stage 1 Emergencies in 1998, four in 1999, and 32 in
2000. A Stage 2 Emergency may be declared any time it is clear that an operating reserve shortfall of less than
5% is unavoidable or forecast to occur in the next two hours. A Stage 2 Emergency declaration signals that
significant intervention by the ISO is required to manage inadequate Operating Reserves, including orders to
LDCs to interrupt service to nonfirm customers. As in Stage 1 Emergency, all customers are again requested
to voluntarily reduce their consumption. There were five Stage 2 Emergencies in 1998, one in 1999, and 17 in
2000. A Stage 3 Emergency may be declared at any time it is clear that a severe Operating Reserve shortfall
(less than 1.5%) is unavoidable or forecast in the next two hours. Stage 3 is the most severe condition and
Conversation with Jose Espinosa of SCE, November 6, 2000
Operating Reserve is the margin of generating resource above that required to meet consumer demand. This
margin is necessarhy to maintain reliability and as protection against the sudden loss of a generation resource.
The minimum requirement for Operating Reserve approximates seven percent of the consumer demand
(Source: CAL ISO web page, Summary of Alerts, Warnings, and Emergencies, July 1998).
8
9
–8–
March 8, 2016
indicates that without immediate and significant ISO intervention, the electric system is in danger of imminent
collapse. Involuntary curtailments (i.e., rolling blackouts) are required during a Stage 3 Emergency.
3.5
CAL ISO-LDC COORDINATION
The California ISO located in Folsom (outside Sacramento) is in constant communication with the
Transmission Operations (formerly the Energy Control Centers) of PG&E, Southern California Edison, and
SDG&E. The ISO will typically forecast a day ahead whether they expect the EEP to be in effect. As the day
progresses they will issue Alerts, Warnings, and if necessary a Stage 1 Emergency and then a Stage 2
Emergency. As part of a Stage 2 Emergency, and in accordance with the provisions of the non-firm tariffs
E-19 and E-20 (PG&E) and I-6 (SCE), the ISO will direct the LDCs to schedule curtailments and request a
specific load reduction amount from each LDC.
When the Transmission Operator at each LDC receives the curtailment request they proceed to
implement it according to the specific procedures they have in place. As described above, both PG&E and SCE
have a load blocking scheme which allows them to allocate curtailment requests evenly among all the
participants.
Edison has 9 non-geographic load blocks of approx. 200 MW each, for a total of 1800 MW. They also
operate two other load management programs – a Residential Air Conditioner (RAC) control program and an
agricultural interruptible pumping program. The RAC program is capable of controlling 250 MW of load and
the interruptible pumps program can control another 45 MW. According to SCE reports they operate the
residential air conditioning and small agricultural interruptible programs first, and then operate only enough I-6
customers necessary to meet the ISO request.
Edison has Remote Terminal Units (RTUs) installed in each I-6 customer premises. The Edison
Transmission Operator activates the notification system to the load blocks next in order as needed to satisfy the
ISO load reduction request. Each customer RTU has its own unlisted, dedicated phone line, with a back-up
dedicated incoming-calls-only phone line. The RTU has several functions: (1) instantaneous read-out of the
customer’s KW demand during both interruptions and normal operation; (2) Visual and audio alarms that alert
the nonfirm customer of an impending operation; (3) a relay that can be connected to one or more internal
automatic load-shedding device; (4) an acknowledgement button that communicates with Edison and silences
the alarm; (5) back-up batteries that ensure the unit will function even during an AC power outage. If the
customer does not acknowledge the alarm, then an Edison rep will make a manual notification phone call via
the back-up phone line. Once the customer receives the notification, they must curtail below their Firm Service
Level within 30 minutes or face substantial penalities. The RTU is the official time-stamped SCE nonfirm
notification vehicle.10
PG&E uses geographical load blocks corresponding to their Transmission Planning Areas (TPAs). This
allows them important flexibility, provided for in the non-firm tariffs, to curtail customers in response to local
transmission emergencies as well as state-wide electric emergencies. This has happened several times in
different TPAs since 1998. Because the load blocks are geographical they are not of uniform size. SF Local and
Humboldt Local are the smallest, with only 5 and 12 MW, respectively. The other areas, named for major
transmission corridors such as ZP26 and NO Path 15 vary in size from 40 to over 100 MW.
Interruptible Service Program Remote Terminal Unit (RTU) Operation & Customer Installation
Requirements, SCE ISP Program, October 1998. Available for downloading from: www.scebiz.com.
10
–9–
March 8, 2016
Table 5
SCE Interruptible Service Program
BLOCKING HISTORY CHART
Date
ZYHGFEDCB
09-18-2000
09-18-2000
09-13-2000
08-16-2000
08-16-2000
08-15-2000
08-14-2000
08-02-2000
08-02-2000
08-01-2000
08-01-2000
07-31-2000
07-31-2000
07-19-2000
06-28-2000
06-27-2000
05-22-2000
05-22-2000
09-30-1999
09-01-1998
08-31-1998
07-27-1998
Comments
THE "BLOCKING" SYSTEM FOR
INTERRUPTING ELECTRIC LOAD
In order to drop electric load in an organized fashion, Edison has
divided customers on its Interruptible Program into blocks. A
block is assigned at the time a Remote Terminal Unit (RTU)
installation is completed and electronically connected.
Customers with the Type A RTU's are placed in Blocks "Y" and
"Z". Customers with the RELM Type B RTU's are placed in
Blocks B, C, D, E, F, G and H.
If an interruption is called by the ISO, the blocks will be rotated in
reverse alphabetical order until the requested load is satisfied.
Subsequent interruptions begin with the next block in
alphabetical sequence. After all blocks are interrupted, the
process is repeated.
.
– 10 –
March 8, 2016
PG&E’s notification system is not as high-tech as Edison’s. The ISO notifies PG&E’s ETPO (Electric
Transmission Planning and Operations) of a Stage Two emergency and further specifies when and how much
load reduction they require from PG&E. If there is no need for transmission area specificity, PG&E then
apportions the load relief amongst the non-firm groups to roughly even out the number of curtailments and
number of curtailment half-hours (Note: these are two very different things. Customers are sensitive to both
the total number of curtailments and the total cumulative time of curtailment, for different reasons). Once the
order of dispatch is determined, the Demand Control Center activates the Non-firm Notification System,
which is basically a programmable automatic faxing system. A FAX to a dedicated FAX machine on a dedicated
phone line at the customer premise is the official time-stamped PG&E non-firm notification vehicle. The
Tariffs and Marketing Departments at the HQ and regional level are also notified as to which customers have
been asked to curtail. They then activate their own parallel courtesy notification schemes, which can include emails, e-paging, and phone calls to key contacts.
4
P E R F O R M A N C E R E S U LT S F O R 1998-2000
Tables 5, 6, and 7 show the detailed performance results for the summers of 1998, 1999, and 2000,
respectively. Highlights and issues emerging from the detailed performance analysis include the following:
4.1
4.2
HIGHLIGHTS

In 1998 there were two occasions when most of the non-firm participants were dispatched –
Monday, July 27, and Monday, August 31. The demand reductions reported by the ISO were 1940
and 1337 MW, respectively, and spinning reserve was stabilized at just below 5 %.

In 1999 there was only one Stage 2 Emergency, on Thursday, September 30. The demand
reduction reported by the ISO was 1155 MW, and spinning reserve was stabilized at 3.5%.

In 2000 there were 17 days when a Stage 2 Emergency was declared. The non-firm programs
were used on 14 of these days. Demand reduction reported by the ISO ranged from a low of 300
MW to a high of 2190 MW on Wednesday, August 2. All nine SCE non-firm load blocks and all
seven PG&E regional load blocks were dispatched on five separate occasions, as follows:
Monday, July 31: 1995 MW reported by the ISO, spinning reserve at 5.4%
o
Tuesday, August 1: 1778 MW reported by the ISO, spinning reserve at 1.5%
o
Wednesday, August 2: 2190 MW reported by the ISO, spinning reserve at 1.5%
o
Wednesday, August 16: 1710 MW reported by the ISO, spinning reserve at 3.9%
o
Monday, September 18: 1697 MW reported by the ISO, spinning reserve at 5.0%
ISSUES

11
o
Table 8 contains a number of N/A (Not Available) entries. This was because the secondary
sources used for this review did not cover the operations in the latter half of Summer 2000. In
particular, the TURN data request responses to PG&E and SCE did not include the month of
August and September, when the most critical emergency curtailments took place. According to
TURN, they will be resubmitting their data request as part of R. 00-10-002.11
Conversation with Bob Finkelstein of TURN, 11/2/00.
– 11 –
5
March 8, 2016

Information on customer compliance and penalties was available for PG&E but not for SCE.
Again, this information is likely to emerge from the discovery process in the interruptible
rulemaking proceeding.

In several cases the numbers provided by secondary sources were in conflict. In particular, the
non-firm demand reduction reported by CAISO differed from the numbers provided by the
individual utilities. This was especially pronounced on July 27, 1998; August 4, 1998; August 31,
1998; September 1, 1998; September 30, 1999; May 22, 2000; and June 28, 2000. For dates after
June 28, 2000 only the ISO reported demand reduction figures were available.
I S S U E S F O R T H E F U T U R E O F N O N -F I R M L OA D M A N AG E M E N T P RO G R A M S
The CPUC’s ongoing Order Instituting Rulemaking into the Operation of Interruptible Load Programs
(R. 00-10-002) lists many of the key issues that will affect the future of non-firm load management in
California and elsewhere. Informal interviews with utility staff, regulators, and intervenors identified additional
issues and concerns. The list below is partial but illustrative.
5.1
STRUCTURAL ISSUES
The current non-firm rates all expire on March 31, 2002. The expectation back in 1997 was that these large
end-users who can accommodate non-firm service would start bidding into the ancillary services market and
receive payments directly from the ISO or PX for shedding their loads on demand. Another possibility is that
they can join one of the price-responsive demand bidding programs the ISO is developing. Given the
demonstrated importance of the non-firm resource, creating a place where these customers can migrate to is a
key issue. The question of whether the ISO can effectively administer relations with these large end-users – or
whether the LDC is needed as an intermediary – must also be addressed.
5.2
PERFORMANCE
The CPUC is concerned that the “stated ability” of these programs – 2,800 MW – is much higher than the
actual delivered load relief when an emergency curtailment is called.12 This discrepancy can be a result of
coincident load factor, availability of specific customers, and some customers opting to incur penalties rather
than curtail their loads. The CPUC uses Edison’s estimates that although 3,000 MW of industrial load is signed
up on the ISP, they expect to only obtain 1,900 MW of actual demand reduction whenever they operate the
program. This performance gap – and its causes – will be a very hot issue in R. 00-10-002.
5.3
CUSTOMER AFFINITY FOR NON-FIRM SERVICE
The performance of the PG&E non-firm customers appears to be more reliable than that of the SCE
non-firm customers. PG&E non-firm customers incurred far fewer penalties over Summer 2000 for excess
energy use. Generally speaking, the PG&E non-firm population is larger and more industrial than the
corresponding SCE population. Size is important because the costs of set-up and participation in the program
can be significant. Larger customers can amortize these costs over the larger dollar savings that accrue to large
users. The participating customers also tend to be those where energy constitutes a significant portion of total
costs associated with the business. This suggests that choosing the type of end-user is a key factor to the ability
of the customer to reliably perform during curtailments.
An analysis of non-firm customer performance by two-digit SIC code and development of guidelines for
marketing the non-firm rate programs are likely to be among the issues surfaced in R. 00-10-002
12
CPUC R. 00-10-002, p. 4
– 12 –
5.4
March 8, 2016
NATURE OF THE DISCOUNT
The discount scheme for PG&E, SCE, and SDG&E customers consists of reduced energy and demand
rates – about 15% overall – over the entire year. Non-firm customers receive the same discount regardless of
the number of curtailments. There is a fixed dollars-per-kWh penalty for non-performance, but no inducement
to provide extra load relief or reflection of actual market prices on a given system emergency day.
The level of the discount is another issue. Many observers feel that $6,000 per kW of non-firm load per
year is too high, especially if the customer is not bound by a multi-year contract requiring significant advance
notice before departing the program.
One of the issues in R. 00-10-002 will be how to develop price-responsive incentive schemes that can
encourage improved performance on occasions when wholesale prices are particularly high or spinning reserves
are particularly low.
5.5
BARRIERS TO PARTICIPATION
One of the issues that R. 00-10-002 is set to consider are the conditions necessary to obtain load relief
from smaller customers. In this regard PG&E program managers have noted the following marketing and
logistics issues:13

Customer apprehension regarding non-firm service

Costs associated with interval metering

Curtailment training and procedures

Internal communications plans

Program and equipment maintenance

Utility staff requirements for program administration and operations
Taken from: “Report to the Commission in Compliance with Resolution E-3696 – Feasibility and CostEffectiveness of Developing Interruptible Rate Programs for Smaller Customers”, PG&E Rates Department,
9/15/00.
13
– 13 –
6
March 8, 2016
C O N TAC T P O I N T S
Name
Organization
Phone
E-Mail Address or Web Site
Don Fuller
Cal ISO
(916) 608-7055
dfuller@caiso.com
Don Shultz
CPUC
Office
Ratepayer Advocates
(916) 327-2409
dks@cpuc.ca.gov
Barbara Barkovich
CLECA
(415) 457-5537
brbarkovich@earthlink.net
Mark Wallenrod
SCE
(626) 301-8331
wallenmh@sce.com
J.C. Martin
SDG&E
(858) 654-1743
Jmartin@sdge.com
Steve DeBacker
PG&E
(415) 973-1982
Sjd5@pge.com
Bob Finkelstein
TURN
(415) 929-8876
rfinkelstein@turn.org
.
of
Table 6: California Non-Firm Programs 1998 Operational Performance14
Day and
Date
EEP
Stage
Proximate
Cause
Mon., July
27
Stage
Two
2000 MW of
generation lost
State-wide Peak
Demand (MW)
Spinning Reserve
Nonfirm
Programs
Activated
Estimated
Advance
Notice to
Customers
Less than 30
min.
Approximate
Duration of
Curtailment
41,776 Forecast
PG&E
16:00-17:00
43,382* Actual
SCE
Less than 5%
Tues., Aug.
Stage
Very high
45,532 Forecast
PG&E
Two hours
13:00-19:00
4
Two
temperatures
44,707 Actual
Less than 5%
Mon., Aug.
Stage
Very high
44,836 Forecast
PG&E
Less than 30
16:00-17:15
31
Two
temperatures
45,676* Actual
SCE
min.
Less than 5%
Tues., Sept.
Stage
Very high
44,810 Forecast
PG&E
Less than 30
13:00-16:45
1
Two
temperatures
44,726* Actual
SCE
min.
Less than 5%
Mon., Dec.
Stage
Cold weather32,684 Forecast
PG&E
Less than 30
08:30-10:20
21
Two
induced natural
33,664* Actual
min.
gas shortage
Less than 5%
*Actual Peak Demand includes the Interruptible Load
**SCE figures Include approx. 225 MW of Residential Air Con Cycling and 45 MW of Ag Pumping Interruption
N/A=Not Available
Nonfirm Load Relief Requested by Cal ISO &
Reported Results by the LDCs and the ISO (MW)
ISO Request
Reported by the Utility Reported
by the ISO
500
541
1940
1270
695**
500
521
0
500
936
522
524**
1337
500
730
554
320**
320
500
393
400
Key sources for this and the subsequent tables not already listed include CAISO News Releases; PG&E, SCE, and SDG&E News Releases; CAISO listing of
Declared Stages Emergencies through September 2000; PG&E’s Data Request Response to Advice Letter 2020-E, regarding Revisions to Electric Schedules E-19 and
E-20;
14
– 15 –
March 8, 2016
Table 7: California’s Non-Firm Programs 1999 Operational Performance
Day and
Date
EEP
Stage
Proximate
Cause
Thursday,
Sept. 30
Stage Two
Loss of
generation
Thursday,
Oct. 21
State-wide Peak
Demand (MW)
Spinning
Reserve
37,662 Forecast
41,227* Actual
Less than 3.5%
34,403 Actual
N/A
Nonfirm
Programs
Activated
PG&E
SCE
Estimated
Advance
Notice to
Customers
Less than 30
min.
Approximate
Duration of
Curtailment
17:00-17:30
Nonfirm Load Relief Requested by Cal ISO &
Reported Results by the LDCs and the ISO (MW)
ISO Request
Reported by the Utility Reported
by the ISO
500
114***
1155
710
425**
Localized
Loss of
PG&E
N/A
13:00-19:00
116
66
N/A
Non-Firm
generation in SF
Emergency
Bay Area
*Actual Peak Demand includes the Interruptible Load
**SCE figures Include approx. 225 MW of Residential Air Con Cycling and 45 MW of Ag Pumping Interruption
***The curtailment was requested very late in the day, with little notice, and then terminated early. Because of the short notice time and short duration, no penalties
were assessed.
N/A=Not Available
– 16 –
March 8, 2016
Table 8: California’s Non-Firm Programs 2000 Operational Performance
Day and
Date
EEP
Stage
Proximate
Cause
Wed., Jan. 5
Localized
Non-Firm
Emergency
Stage Two
Loss of
generation in
Humboldt Region
Heat wave plus
6,000 MW
planned & unplanned outage
Continued hot
weather & plant
outages in Bay
Area
Plant outages in
Bay Area plus
Tracy 500/230
kV Transformer
Overloading
Pervasive heat
wave over much
of the West
Continued heat
wave, lack of
imported power
Mon., May
22
Wed., June
14
Stage One
Thurs., June
15
Localized
Non-Firm
Emergency
Tues., June
27
Stage Two
Wed., June
28
Stage Two
State-wide Peak
Demand (MW)
Spinning
Reserve
32,274 Actual
N/A
Nonfirm
Programs
Activated
Estimated
Advance
Notice to
Customers
One hour
Approximate
Duration of
Curtailment
39,000 Forecast
40,8628* Actual
2.7%
PG&E
SCE
One hour
14:30-16:37
495
348
481
368**
1054
45,329 Forecast
44,239* Actual
5.3%
PG&E
One hour
12:00-18:00
500
505
509
43,610 Actual
N/A
PG&E
One hour
12:00-18:00
340
Under Analysis
N/A
43,042 Forecast
43,793* Actual
5.3%
43,953 Forecast
43,911*Actual
5.3%
PG&E
SCE
30 minutes
13:30-19:44
500
754
504
485**
1000
PG&E
SCE
One hour
14:30-20:00
500
537
484
370**
1000
PG&E
17:30-19:30
Nonfirm Load Relief Requested by Cal ISO &
Reported Results by the LDCs and the ISO (MW)
ISO Request
Reported by the Utility Reported
by the ISO
13
10
N/A
– 17 –
Day and
Date
EEP
Stage
Proximate
Cause
Wed., July 19
Stage Two
Monday, July
31
Stage Two
Tues., Aug. 1
Stage Two
Wed., Aug. 2
Stage Two
Tues., Aug.
14
Stage Two
Tues., Aug.
15
Stage Two
Wed., Aug.
16
Stage Two
Hot weather plus
lack of available
generation or
imports from SW
& Path 26 (COT)
constraint
Pervasive heat
wave over much
of the West
Record-breaking
heat & forecast
record power
demands
Continuing heat
wave throughout
the West
Hot weather in
Southern
California
Continued hot
weather
stretching
throughout
California, Path
26 constraints
Continued heat
wave plus
generation
outages
March 8, 2016
State-wide Peak
Demand (MW)
Spinning
Reserve
39,753 Forecast
42,610* Actual
Below 5%
Nonfirm
Programs
Activated
Estimated
Advance
Notice to
Customers
One hour
Approximate
Duration of
Curtailment
45,391 Forecast
45,245* Actual
5.3%
46,245 Forecast
45,281* Actual
1.5%
PG&E
SCE
SDG&E
PG&E
SCE
SDG&E
One hour
14:30-19:30
One hour
13:30-19:30
45,723 Forecast
45,069* Actual
1.5%
42,635 Forecast
43,087* Actual
N/A
42,830 Forecast
42,927* Actual
5.1%
PG&E
SCE
SDG&E
SCE
SDG&E
One hour
13:30-19:30
One hour
15:00-17:30
PG&E
SCE
SDG&E
One hour
14:30-20:00
43,617 Forecast
45,494* Actual
3.9%
PG&E
SCE
SDG&E
One hour
14:30-19:00
SCE
SDG&E
14:47-1800
Nonfirm Load Relief Requested by Cal ISO &
Reported Results by the LDCs and the ISO (MW)
ISO Request
Reported by the Utility Reported
by the ISO
920
N/A
930
98
N/A
40
500
1236
40
97
N/A
N/A
Under analysis
N/A
N/A
1995
500
1650
40
700
40
500
2190
N/A
746
N/A
N/A
N/A
N/A
N/A
N/A
681
500
N/A
N/A
500
N/A
N/A
1710
1778
– 18 –
Day and
Date
EEP
Stage
Proximate
Cause
Wed., Sept.
13
Stage Two
Mon., Sept.
18
Stage Two
Heat wave plus
impaired
transmission
capability due to
wildfires
Severe heat
exacerbated by
shortage of
generation
March 8, 2016
State-wide Peak
Demand (MW)
Spinning
Reserve
39,750 Forecast
41,728* Actual
5.0%
Nonfirm
Programs
Activated
43,187 Forecast
43,740* Actual
5.0%
PG&E
SCE
PG&E
SCE
Estimated
Advance
Notice to
Customers
One hour
Approximate
Duration of
Curtailment
One hour
13:30-18:00
14:52-16:35
*Actual Peak Demand includes the Interruptible Load
**SCE figures include approx. 225 MW of Residential Air Con Cycling and 45 MW of Ag Pumping Interruption
N/A=Not Available
Nonfirm Load Relief Requested by Cal ISO &
Reported Results by the LDCs and the ISO (MW)
ISO Request
Reported by the Utility
Reported
by the ISO
100
96
1169
N/A
N/A
500
N/A
500
N/A
1697