Application: 18-02- U-39E Exhibit No.: Date: February 28, 2018 Witness(es): Various PACIFIC GAS AND ELECTRIC COMPANY APPLICATION FOR COMPLIANCE REVIEW OF: UTILITY-OWNED GENERATION OPERATIONS; ELECTRIC ENERGY RESOURCE RECOVERY ACCOUNT ENTRIES; CONTRACT ADMINISTRATION; ECONOMIC DISPATCH OF ELECTRIC RESOURCES; UTILITY-RETAINED GENERATION FUEL PROCUREMENT; AND OTHER ACTIVITIES FOR THE PERIOD JANUARY 1 THROUGH DECEMBER 31, 2017 PREPARED TESTIMONY PUBLIC VERSION
331
Embed
PACIFIC GAS AND ELECTRIC COMPANY APPLICATION FOR ...
This document is posted to help you gain knowledge. Please leave a comment to let me know what you think about it! Share it to your friends and learn new things together.
Transcript
Application: 18-02- U-39E Exhibit No.: Date: February 28, 2018 Witness(es): Various
PACIFIC GAS AND ELECTRIC COMPANY
APPLICATION FOR COMPLIANCE REVIEW OF: UTILITY-OWNED GENERATION OPERATIONS;
ELECTRIC ENERGY RESOURCE RECOVERY ACCOUNT ENTRIES; CONTRACT ADMINISTRATION; ECONOMIC DISPATCH OF ELECTRIC
RESOURCES; UTILITY-RETAINED GENERATION FUEL PROCUREMENT; AND OTHER ACTIVITIES
FOR THE PERIOD JANUARY 1 THROUGH DECEMBER 31, 2017
PREPARED TESTIMONY
PUBLIC VERSION
-i-
APPLICATION FOR COMPLIANCE REVIEW OF UTILITY OWNED GENERATION OPERATIONS, ELECTRIC ENERGY RESOURCE RECOVERY ACCOUNT ENTRIES,
CONTRACT ADMINISTRATION, ECONOMIC DISPATCH OF ELECTRIC RESOURCES, UTILITY RETAINED GENERATION FUEL PROCUREMENT,
AND OTHER ACTIVITIES FOR THE PERIOD JANUARY 1 THROUGH DECEMBER 31, 2017
TABLE OF CONTENTS
Chapter Title Witness
1 LEAST-COST DISPATCH AND ECONOMICALLY-TRIGGERED DEMAND RESPONSE
Alva J. Svoboda Franklin Fuchs
Attachment A SUMMARY OF TRIGGERED DISPATCH
FROM DEMAND RESPONSE PROGRAMS Franklin Fuchs
Attachment B SUMMARY OF 2017 CAPACITY BIDDING
PROGRAM EVENTS Franklin Fuchs
Attachment C SUMMARY OF TOTAL ENERGY
DISPATCHED FROM DEMAND RESPONSE PROGRAMS
Franklin Fuchs
2 UTILITY-OWNED GENERATION:
HYDROELECTRIC Alvin L. Thoma
Attachment A PG&E POWERHOUSES AND GENERATING
UNITS Alvin L. Thoma
3 UTILITY-OWNED GENERATION: FOSSIL
AND OTHER GENERATION Steve Royall
4 UTILITY-OWNED GENERATION: NUCLEAR Cary D. Harbor
5 COSTS INCURRED AND RECORDED IN THE
DIABLO CANYON SEISMIC STUDIES BALANCING ACCOUNT
Stuart P. Nishenko
APPLICATION FOR COMPLIANCE REVIEW OF UTILITY OWNED GENERATION OPERATIONS, ELECTRIC ENERGY RESOURCE RECOVERY ACCOUNT ENTRIES,
CONTRACT ADMINISTRATION, ECONOMIC DISPATCH OF ELECTRIC RESOURCES, UTILITY RETAINED GENERATION FUEL PROCUREMENT,
AND OTHER ACTIVITIES FOR THE PERIOD JANUARY 1 THROUGH DECEMBER 31, 2017
TABLE OF CONTENTS
(CONTINUED)
-ii-
Chapter Title Witness
6 GENERATION FUEL COSTS AND ELECTRIC PORTFOLIO HEDGING
Felipe Ibarra Michael Kowalewski Mark Mayer Yanee Pongsupapipat Alvin L. Thoma
Attachment A LETTER FROM RUBY PIPELINE OFFICER
CERTIFYING PG&E’S “MOST FAVORED NATIONS” (LOWEST RATE) STATUS
Felipe Ibarra
Attachment B GENERATION FUEL COSTS Felipe Ibarra
Michael Kowalewski Mark Mayer
Attachment C ANNUAL REPORT OF UTILITY ON THE
ACTIVITIES OF STARS ALLIANCE, LLC; UTILITY SAVINGS/AVOIDED COSTS BY STARS TEAM/PROJECT
Yanee Pongsupapipat
7 GREENHOUSE GAS COMPLIANCE
INSTRUMENT PROCUREMENT Vincent Loh
8 CONTRACT ADMINISTRATION Candice K. Chan
9 CAISO SETTLEMENTS AND MONITORING Candice K. Chan
APPLICATION FOR COMPLIANCE REVIEW OF UTILITY OWNED GENERATION OPERATIONS, ELECTRIC ENERGY RESOURCE RECOVERY ACCOUNT ENTRIES,
CONTRACT ADMINISTRATION, ECONOMIC DISPATCH OF ELECTRIC RESOURCES, UTILITY RETAINED GENERATION FUEL PROCUREMENT,
AND OTHER ACTIVITIES FOR THE PERIOD JANUARY 1 THROUGH DECEMBER 31, 2017
TABLE OF CONTENTS
(CONTINUED)
-iii-
Chapter Title Witness
10 REVIEW ENTRIES RECORDED IN THE GREEN TARIFF SHARED RENEWABLES MEMORANDUM ACCOUNT AND THE GREEN TARIFF SHARED RENEWABLES BALANCING ACCOUNT
Donna L. Barry Molly Hoyt
11 SUMMARY OF ENERGY RESOURCE
RECOVERY ACCOUNT ENTRIES FOR THE RECORD PERIOD
Lucy Fukui Armando Duran
Attachment A FINAL JOINT PROPOSAL ON POTENTIAL
VERIFICATION METHOD FOR PG&E’S GREENHOUSE GAS EMISSIONS AND WEIGHTED AVERAGE COSTS (WAC) FOR FUTURE ERRA COMPLIANCE FILING
Armando Duran
12 MAXIMUM POTENTIAL DISALLOWANCE Kelly A. Everidge
13 COST RECOVERY AND REVENUE
REQUIREMENT Lucy Fukui
Appendix A STATEMENTS OF QUALIFICATIONS Donna L. Barry
Candice K. Chan Armando Duran Kelly A. Everidge Franklin Fuchs Lucy Fukui Cary D. Harbor Molly Hoyt Felipe Ibarra Michael Kowalewski Vincent Loh Mark Mayer Stuart P. Nishenko Yanee Pongsupapipat Steve Royall Alva J. Svoboda Alvin L. Thoma
B.5 Least Cost Dispatch Bidding and Scheduling Cost Impacts
B.6 Background Summary Table
B.7 2017 Market and Business Process Changes
B.8 LCD Summary
PG&E is also providing detailed workpapers that are formatted 3
consistent with, and provide the information required by, the LCD Decisions.4
2. Overview of Least-Cost Dispatch in the CAISO Markets5
During the record period, PG&E managed its portfolio of contracted and 6
utility-owned resources consistent with SOC4, relevant Commission 7
decisions, and its 2014 BPP.8
SOC4 was initially adopted by the Commission in 2002, at a time when 9
all CAISO generation resource schedules were either directly matched by 10
the utilities to their customer loads, or procured and matched to forecast 11
customer loads via bilateral trades. However, as the Commission explained 12
in D.11-10-002 Finding of Fact (FOF) 1, “[o]n April 1, 2009, the CAISO 13
began implementation of [MRTU], which substantially changed the 14
least-cost dispatch processes of SCE and other utilities.” As the 15
Commission has noted, since 2009, “[t]he regulated energy utility is 16
responsible for scheduling and bidding its generation to the CAISO, but 17
once that is done, it is the CAISO’s responsibility to dispatch the 18
generation.”2 Thus, an overview of the CAISO markets is essential to LCD. 19
Since April 1, 2009, the CAISO operated day-ahead and real-time 20
markets, enabling market participants to offer or procure energy and 21
Ancillary Services (A/S) in the CAISO control area. The CAISO markets 22
2 D.14-05-023, FOF 15.
1-4
perform optimization (i.e., LCD) for all resources bid or self-scheduled3 into 1
the markets based on information provided by market participants, CAISO 2
transmission information, and information regarding system conditions that 3
is not available to market participants. The Full Network Model (FNM) used 4
in the CAISO markets contains approximately 10,000 pricing nodes. The 5
FNM is used to identify potential local area reliability concerns and resolve 6
them day-ahead in the Integrated Forward Market (IFM) and Residual Unit 7
Commitment (RUC) processes (further detail below), as well as in the 8
real-time markets.9
The CAISO’s optimization of each of its markets results in supply 10
clearing against demand at least cost. The results are based on the 11
submitted hourly bids and the costs of getting energy from supply nodes to 12
demand nodes in the CAISO grid. In addition to energy bids, the CAISO 13
provides for the submission of start-up and minimum load costs. Market 14
prices at each node are determined on a day-ahead basis for each hour of 15
the day, and in real-time for each fifteen- and five-minute interval, and 16
indicate the incremental cost of an additional unit of energy at each location 17
in the CAISO grid (Locational Marginal Price or “LMP”).418
The structure and design of each of the CAISO markets, day-ahead and 19
real-time, are described in more detail below.20
a. Day-Ahead Markets21
The CAISO day-ahead market process, the IFM, provides market 22
participants with the opportunity to buy and sell energy for the following 23
day. In the IFM, the CAISO clears the offers to buy and sell energy 24
based on the physical characteristics and locations of available 25
resources and bid-in demand, for each of the 24 hours of the following 26
3 Self-schedules are interpreted by the CAISO markets as price-taking supply or demand. Price-taking supply is supply that is willing to accept any price to inject energy into the grid. Price-taking demand self-schedules, which can only be submitted by Load Serving Entities (LSE) in the day-ahead market, indicate a willingness to pay any price to clear demand in that market.
4 The LMP is the marginal cost of supplying, at least cost, the next increment of electric demand at a specific node on the electric power network. This takes into account supply (generation/import) bids, demand (load/export) offers and the physical network of the transmission system.
1-5
day, and establishes LMPs for each of the approximately 10,000 nodes 1
within the CAISO system. The CAISO also uses the IFM to procure A/S 2
(regulation up, regulation down, spinning reserve and non-spinning 3
reserve) to ensure system reliability for the next day. Energy market 4
and A/S procurement are performed simultaneously using the CAISO’s 5
Security Constrained Unit Commitment algorithm, which minimizes total 6
costs based on submitted bids, the CAISO’s A/S requirements, and the 7
constraints on power flows imposed by the control area’s large and 8
complex transmission network.9
The CAISO’s market model recognizes load pockets that may be 10
exposed to local market power. The CAISO performs a Local Market 11
Power Mitigation (LMPM) process that identifies suppliers with local 12
market power and mitigates their supply bids to competitive default 13
bid levels.14
Because not all forecast load bid into the IFM will necessarily clear 15
in the market, the CAISO performs a second phase of the day-ahead 16
market process, the RUC, after the IFM to ensure that sufficient capacity 17
has an obligation to bid into real time to meet the CAISO’s own forecast 18
of control area load.19
LCD requires PG&E to bid or schedule its generation portfolio such 20
that it is generally dispatched to serve PG&E customer load if the 21
variable operating costs of the resources are lower than the alternative 22
CAISO market cost of energy. PG&E meets this requirement by offering 23
PG&E owned and contracted resources into the day-ahead market at 24
incremental cost,5 with the resulting awards of schedules determined by 25
the CAISO without regard to whether the scheduled resources are 26
PG&E controlled or from the other market participants.27
The CAISO should dispatch resources such that those with lowest 28
incremental costs are scheduled to meet PG&E customer loads at least 29
cost. In general, day-ahead prices have been more predictable and less 30
volatile than real-time prices. Thus, procuring the majority of energy to 31
5 Incremental cost refers to the variable costs of providing energy and does not include fixed costs that do not vary with output.
1-6
serve PG&E’s customer load in the day-ahead market enables LCD 1
while avoiding the volatility associated with real-time prices.62
b. Real-Time Markets3
The Real-Time Market is comprised of several overlapping market 4
processes, producing financially and/or physically binding awards and 5
prices that are used for energy and A/S settlements. 6
The Hour-Ahead Scheduling Process is an hour-ahead, non-binding 7
process run that runs every hour to yield feasible block schedules for8
imports and exports (permitting “tagging,” i.e., scheduling of supporting 9
transmission capacity across multiple balancing authorities) and 10
advisory (non-binding) price and internal schedule results.11
The Fifteen-Minute Market (FMM) process was introduced with 12
Federal Energy Regulatory Commission (FERC) Order 76413
implementation in 2014. The FMM process runs for successive 14
fifteen-minute intervals with updated CAISO forecasts of intermittent 15
resources and loads, and yields import/export schedules and financially 16
binding prices for all resources (imports, exports, and convergence bids 17
as well as CAISO balancing area resources). As in the day-ahead 18
markets, the LMPM process is run prior to each FMM run. Differences 19
between the day-ahead awards and FMM awards are settled at the 20
FMM prices. 21
Finally, the five-minute RTD process runs with updated CAISO 22
five-minute load and intermittent resource forecasts, to yield five-minute 23
prices, and physically binding dispatches for all internal resources. 24
Differences between the FMM awards and Real-Time Dispatch (RTD) 25
awards are settled at the RTD prices. Imbalances between RTD awards 26
and actual deliveries are priced at the RTD prices in each five-minute 27
interval. 28
6 The CAISO ultimately clears all control area demand physically in the real-time markets: this is fundamental to its mandate to serve California’s electricity needs reliably.
1-7
3. PG&E’s Bidding and Scheduling Processes1
a. Least-Cost Dispatch Guidelines and Principles2
1) Least-Cost Dispatch Principles3
As explained in the Commission-approved 2014 BPP that was 4
in effect during the record period, PG&E has adopted the following 5
seven principles to guide its procurement and LCD activities:76
PG&E aims to minimize the total cost of energy required to meet 7
load and A/S requirements, subject to regulatory, legal, 8
operational, contractual, and financial requirements.9
PG&E’s scheduling and bidding process considers all 10
regulatory, legal, safety, operational, contractual and 11
financial requirements. Subject to these requirements, the 12
scheduling and bidding process aims to provide the CAISO 13
flexibility in dispatching the resources across the day-ahead and 14
real-time markets.15
PG&E supports LCD by explicitly considering the incremental 16
costs of all resources available to it in scheduling or bidding 17
decisions.18
PG&E integrates any local area reliability requirements, 19
day-ahead scheduling requirements, and deliverability 20
requirements into its scheduling or bidding decisions.21
The CAISO markets perform LCD for all resources 22
bid/scheduled into the markets based on information provided 23
by all market participants, transmission information that is solely 24
available to the CAISO, and information regarding system 25
conditions that are solely available to the CAISO.26
The parameters and forecasts that PG&E has ability to control 27
with regard to LCD are the following: PG&E load forecast; 28
market price forecast; incremental heat rate; and Master File 29
submission. These parameters and forecasts are used in the 30
calculation of submitted bids and/or schedules.31
7 See also 2014 BPP, Appendix K.
1-8
LCD activities are subject to forecast and market uncertainties, 1
including those associated with actual customer loads, behavior 2
of other market participants, actual energy deliveries from 3
Qualifying Facilities (QF) and intermittent resources, non-public 4
transmission constraints, and CAISO reliability-based 5
discretionary decisions.6
PG&E followed the principles described above during the record 7
period. The principles described above remain essential for 8
achieving LCD and meeting all safety, regulatory, legal, operational 9
and financial requirements associated with PG&E’s portfolio. 10
For resources with bidding rights, PG&E bids these resources 11
into the CAISO markets based on their incremental costs or 12
opportunity costs.8 By bidding its resources into the CAISO 13
markets at their incremental or opportunity costs, PG&E enables 14
total procurement to meet customer demand in the CAISO markets 15
to be at the least cost. Resources with contractual or physical 16
constraints that limit their ability to be bid are self-scheduled into the 17
CAISO markets. 18
2) Incremental Costs19
With resources that have flexibility to be dispatched, PG&E 20
schedules9 or bids resources into the CAISO markets at the 21
incremental cost of providing energy, considering the variable 22
operating cost of its resources and the market price forecast. 23
Resource costs that increase or decrease depending on how the 24
resource runs are properly treated as incremental costs. Fixed 25
costs that are not affected by how resources are dispatched, such 26
as capital investment costs or contract capacity payments, are 27
treated as sunk costs and therefore not incorporated into energy 28
bids. For resources with energy or starts constraints, incremental 29
8 For those resources with energy, curtailment, or starts limitations, the opportunity cost reflects the value of not being able to use the resource’s flexibility in a future time period.
9 Schedules commonly refer to self-schedules whereas bids refer to price-quantity offers to sell or buy in the CAISO markets.
1-9
costs may also include the opportunity cost of not using the 1
resource in the future.2
Incremental costs are categorized as: (1) start-up costs; 3
(2) minimum load costs; and (3) incremental energy costs. Start-up 4
costs are the costs to start up a resource and bring it to its minimum 5
operating level; for Multi-Stage Generation (MSG)10 resources, 6
“state transition costs” representing the start-up of resource subunits 7
are similar to startup costs. An additional opportunity cost 8
component may be added to start-up costs when a limit on cycling is 9
expected to be binding over a period of months or years.10
Minimum load costs are the costs to operate a resource at its 11
minimum operating level for one hour.12
Minimum load, start-up, and transition costs may include fuel 13
costs and Greenhouse Gas (GHG) costs as well as variable 14
Operations and Maintenance (O&M) costs, and documented Major 15
Maintenance Adder costs of inspections and overhauls that are 16
incurred, under warranty or other contract provisions, based on run 17
hours or cycles. 18
Incremental energy bid costs include those incremental or 19
opportunity costs that vary directly with the generation of each 20
additional megawatt-hour (MWh) above the minimum operating 21
point. For example, fuel costs and variable O&M costs vary directly 22
with energy output.23
Resources with no explicit fuel cost, such as hydroelectric 24
plants, are bid/scheduled based on their opportunity costs, which 25
are equivalent to fuel costs in their effect on bids. Hydroelectric 26
watersheds operate subject to complex constraints on minimum and 27
maximum canal flows, minimum and maximum reservoir storages, 28
and restrictions on changes in flow and storage, which may depend 29
on season. These constraints include FERC powerhouse license 30
requirements, safety, maintenance, and environmental constraints, 31
10 MSG resources are described in further detail in the “Thermal Resource Bidding and Scheduling” section of this chapter.
1-10
constraints due to emergency drought declaration, and limits due to 1
uncontrollable inflows into the watershed from natural sources or 2
other water entities. For hydro resources, the opportunity cost is the 3
future value of water. It may be more prudent and lower cost in the 4
long run to defer hydro generation to higher value future periods 5
rather than using it in the current day to receive a price below its 6
opportunity cost.7
In addition to its large (in number, total capacity, and total 8
energy) portfolio of utility-owned thermal, hydro, and solar 9
resources, PG&E also bids and schedules contracts under tolling 10
agreements, and intermittent and other renewables resources. 11
Incremental costs of tolling agreements are based on contract 12
terms, reflecting the actual costs of dispatch paid by PG&E’s 13
customers.14
Renewable resources for which PG&E has contractual bidding 15
and scheduling rights are bid pursuant to Appendix K of the 16
2014 BPP.17
3) Self-Scheduling18
A portion of PG&E’s supply portfolio is must-take11 or 19
must-run,12 due to safety, environmental and license constraints, 20
regulatory requirements, contract terms (e.g., certain renewable 21
11 Regulatory Must-Take Generation is defined as generation from the following resources that the relevant Scheduling Coordinator (SC) schedules directly with the CAISO as Regulatory Must-Take Generation: (1) Generation from Generating Units subject to (a) an Existing QF Contract or an Amended QF Contract, or (b) a QF Power Purchase Agreement (PPA) for a QF 20 megawatts (MW) or smaller pursuant to a mandatory purchase obligation as defined by federal law; (2) Generation delivered from a Combined Heat and Power (CHP) Resource needed to serve its host thermal requirements up to RMTMax in any hour; and (3) Generation from nuclear units. SeeCAISO Conformed Tariff, November 30, 2016.
12 Regulatory Must-Run Generation is defined as Generation Hydro Spill Generation and Generation which is required to run by applicable federal or California laws, regulations, or other governing jurisdictional authority. See CAISO Conformed Tariff, November 30, 2016. Such requirements include, but are not limited to, hydrological flow requirements, environmental requirements, such as minimum fish releases, fish pulse releases and water quality requirements, irrigation and water supply requirements, or the requirements of solid waste Generation, or other Generation contracts specified or designated by the jurisdictional regulatory authority as it existed on December 20, 1995, or as revised by federal or California law or Local Regulatory Authority.
1-11
resources and QF resources) or because it is inherently non-1
dispatchable (e.g., run-of-river hydro with no reservoir controls). 2
Because such generation is inflexible, PG&E self-schedules 3
must-take supply in the day-ahead market and then modifies these 4
self-schedules in real-time if the forecast of generation has changed.5
A relatively small number of PG&E’s contracts, tolling 6
agreements, and the Puget Exchange have dispatch flexibility on an 7
earlier contractual timeline from the CAISO markets, and hence 8
must be self-scheduled by PG&E and cannot be bid into the market. 9
The best price forecast available at the time of the scheduling 10
decision is used in PG&E optimization program runs to determine 11
the best self-schedules of these resources.12
In addition to must-take and must-run resources and bilateral 13
contracts which are purely self-scheduled, other resources are 14
periodically or partially self-scheduled for particular purposes. 15
Self-schedules may be used when testing is to be performed on 16
resources, or when resources such as hydro plants need to be run 17
above their minimum operating limits in order to ensure that water is 18
not spilled or is used according to operating constraints. Resources 19
may also be “self-committed,” which refers to instances in which a 20
resource is self-scheduled at minimum, and its remaining available 21
capacity is bid into the markets.22
4) Constraints23
a) Operational Constraints24
In addition to meeting load obligations at minimum cost, 25
PG&E also incorporates safety, operational, physical, legal, 26
regulatory, and environmental constraints into bidding and 27
scheduling decisions.28
One example of operational constraints are those imposed 29
by FERC licenses on the operations of PG&E’s hydroelectric 30
system. For example, FERC licenses may include 31
requirements for fish and wildlife maintenance (e.g., flows for 32
fish and water quality that bypass generators and thus produce 33
1-12
no electricity), recreation (e.g., seasonal minimum reservoir 1
water levels), and safety (e.g., constraints on reservoir 2
drawdowns). Such considerations may not be readily apparent 3
in a cost-only analysis of PG&E’s bidding and scheduling 4
decisions.5
b) Local Area Reliability and Delivery Constraints6
D.04-07-028 mandated that utilities consider local area 7
reliability and “deliverability” of energy to serve load in its 8
bidding and scheduling decisions, in addition to minimizing 9
costs. PG&E complied with D.04-07-028 through bidding and 10
scheduling its resources into the CAISO markets. The CAISO 11
considers local area reliability and deliverability in its dispatch 12
decisions.13
b. 2017 Least-Cost Dispatch Business Process Overview14
PG&E’s daily LCD business processes encompass the forecasting 15
of loads and prices, the bidding of customer demand and PG&E-16
scheduled supply, and the validation and analysis of market results. 17
Each of these processes is described in the following sections.18
1) Load and Price Forecasts19
a) Load Forecast Process20
PG&E’s LCD processes use a vendor-supplied short-term 21
area load forecast. The inputs to the short-term load forecast 22
are actual historical loads for the PG&E system based on 23
Supervisory Control and Data Acquisition (SCADA), provided at 24
an hourly granularity; and actual and forecast temperatures for 25
six representative weather stations in the PG&E service 26
territory, provided by external weather forecast vendors. 27
Under special circumstances either the inputs to the vendor 28
model, or the model outputs, may be modified by PG&E in order 29
to correct for failures in data communications or special 30
circumstances (i.e., holiday periods) that are not captured 31
adequately by the forecast model.32
1-13
The outputs of the short-term load forecast are an hourly 1
forecast of load for the PG&E area for the current day and out to 2
six days in the future; and as a check on the inputs, an hourly 3
forecast of composite area temperatures used to develop the 4
load forecast.5
The “seven-day” hourly-load forecast provided by the 6
vendor is adjusted to produce a forecast of PG&E’s bundled 7
customer load. The PG&E area load forecast is adjusted by 8
subtracting estimates of transmission losses, municipal loads in 9
the area, and forecasts of Direct Access and Community Choice 10
Aggregation loads in the PG&E area. PG&E uses this 11
seven-day short-term forecast of bundled customer load in 12
creating load bids for each of the next six days. 13
b) Evaluation of Load Forecast Accuracy14
In this section PG&E provides an evaluation of the accuracy 15
of its day-ahead load forecast during the record period.16
The most common metric used to evaluate the relative 17
quality of load forecasts in the utility industry is Mean Absolute 18
Percentage Error (MAPE). This metric measures both the 19
magnitude and frequency of errors, and is similar to the Root 20
Mean Square Error (RMSE) metric except that it puts a higher 21
weight on larger errors relative to RMSE. The metric is 22
expressed as a percentage of some value. In the case of load 23
forecasts, MAPE is expressed as a percentage of actual hourly 24
load.25
Average MAPE of the short-term load forecast was slightly 26
above 2 percent during the record period. Unusually high 27
deviations (e.g., above 5 percent), which occurred on 6 days 28
(most associated with holidays and weekends) were reviewed 29
and discussed with the vendor to determine the source of 30
errors, and depending on that analysis resulted in adjustments 31
to the forecast model itself by the vendor.32
1-14
c) Price Forecast Process1
PG&E uses its price forecast for the following purposes. An 2
hourly next-day price forecast is used to determine self-3
schedules in the day-ahead market for those resources where 4
Self-Scheduling is required by contract terms or operational 5
requirements (as in the case of hydro resources subject to flow 6
constraints). A longer-term price forecast, ranging from several 7
days up to two years, is used for resources with opportunity 8
costs. The longer-term price forecast is needed to estimate the 9
relative value of dispatching the resources next day versus at 10
later points in time.11
In previous years, PG&E’s short-term price forecast was 12
based on a regression of recent loads and gas prices against 13
hourly electric prices. The coefficients of the regression were 14
recalculated (or “recalibrated”) frequently to use the most recent 15
data on actual loads and prices. 16
Beginning in 2016, PG&E evaluated an alternative approach 17
to price forecasting. PG&E evaluated using a vendor of a 18
neural network forecast to 19
provide an independently produced forecast on demand. Over 20
six months, PG&E measured the accuracy of the vendor 21
forecast versus its own and determined that the vendor forecast 22
(i) was measurably, and consistently, more accurate on average 23
than PG&E’s internal forecast; (ii) responded more quickly to 24
changes in the “shape” of prices (for example, which hours were 25
highest or lowest); and (iii) required less manual intervention by 26
analysts than PG&E’s own forecast.27
Accordingly, during 2017, PG&E transitioned from its own 28
regression-based forecast model to the vendor neural-network 29
based forecast model, completing the transition mid-year. The 30
transition, in addition to improving the accuracy of the short-term 31
price forecast, streamlined business processes and reduced the 32
need for manual intervention. During the record period PG&E 33
1-15
continued to review the reasonableness of the daily forecasts 1
produced by the vendor.2
d) Evaluation of Price Forecast Accuracy3
In this section, PG&E provides an evaluation of the 4
accuracy of its day-ahead price forecast during the record 5
period using the metric of mean average percentage error, or 6
MAPE.13 Taken together this section and Workpaper 6 offer 7
PG&E’s evaluation of its day-ahead price forecast accuracy as 8
requested by ORA in the 2014 ERRA Settlement.9
As described above, PG&E switched to using a vendor price 10
forecast in 2017.11
The MAPE on average before the model switch was 12
18.6 percent and the average after the switch was 10.4 percent. 13
2) Load Bidding14
The CAISO day-ahead markets offer LSEs, such as PG&E, the 15
capability to bid some or all of their forecast loads into a day-ahead16
market, to try to reduce the total cost of serving these loads.17
PG&E evaluates the relative costs of serving customer loads in 18
the day-ahead versus real-time markets, based on actual past 19
market outcomes that provide insights into future outcomes. 20
21
22
3) Thermal Resource Bidding and Scheduling23
PG&E’s portfolio of dispatchable thermal power plants (all using 24
natural gas as their primary, if not exclusive, fuel) are either owned 25
by PG&E or contracted from counterparties through tolling 26
agreements.27
D.02-12-069 provides that, “prohibited utility conduct under this 28
standard includes any action that results in preference to 29
utility-retained generation resources or the utility’s own negotiated 30
13 Daily MAPE = | | .
1-16
contracts.”14 PG&E makes no distinction between its own 1
resources and contracted resources in its bidding practices: All 2
resources are bid or self-scheduled into the CAISO markets based 3
on their incremental costs, recognizing safety, regulatory, legal, 4
operational, and financial requirements. 5
PG&E-owned plants and tolling agreement plants that can be 6
bid into the CAISO markets are bid at incremental cost consistent 7
with operational and contract constraints, as described in 8
Section 3.a.2. The incremental cost of energy consists of 9
incremental fuel costs and any other costs that vary between the 10
minimum and maximum points of a plant’s operating range.11
The incremental cost of minimum load is similarly estimated as 12
the minimum load fuel cost and any other costs that are incurred in 13
every hour that the plant runs (for example, hourly operating 14
charges included or imputed in plant long-term service agreements). 15
The incremental cost of starting a plant (or in the case of a multi-unit 16
plant, starting a unit at the plant) is estimated as the fuel and other 17
inputs required for a start along with other costs incurred for every 18
start (such as start charges included or imputed in plant long-term 19
service agreements).20
In its portfolio, PG&E has a number of MSG resources, which 21
are resources that have multiple operating configurations that can 22
be characterized as having distinct operating parameters. Often 23
these resources require time and/or incur costs to move from 24
one configuration operating range to another. For example, 25
combined cycle gas turbine (CCGT) plants consist of a steam 26
turbine (ST) and multiple gas turbines (GT) run in combination so 27
that GT waste heat can be used to power the ST. Dispatch of 28
CCGT plants therefore requires consideration of the cycling (startup 29
and shutdown) of individual turbines. In order to better represent 30
this consideration in the CAISO markets, to help combined cycle 31
plants better comply with CAISO dispatch instructions, and to better 32
14 D.02-12-069 at pp. 62-63.
1-17
represent multiple GTs at a single location (which would otherwise 1
be treated as a single resource with a continuous dispatch range) 2
the CAISO developed the MSG resource model. The MSG model 3
was used by PG&E during the record period to model PG&E’s 4
portfolio of fossil generation CCGT plants.5
4) Description of Proxy/Registered Cost Determination for 6
Thermal Resources7
The section describes PG&E’s procedures for evaluating proxy 8
versus registered cost determination for the small set of resources 9
allowed to make such a determination, so that taken together this 10
section and the workpapers offer complete documentation of the 11
proxy/registered cost determination for thermal resources as 12
requested by ORA in the 2014 ERRA Settlement. 13
In addition to energy bids, the CAISO provides for the 14
submission of start-up and minimum load costs. The CAISO 15
enables certain gas fired resources to submit minimum load and 16
start-up cost parameters either as “proxy” costs or “registered” 17
costs. Proxy costs are calculated by the CAISO as the product of a 18
fuel use times a fuel cost index plus other costs. Registered costs 19
are required to be a single dollar value for no less than 30 days at a 20
time, and can reflect both fuel and a facility’s specific non-fuel costs 21
including longer-term maintenance costs that vary with number of 22
starts or number of hours running at minimum load. Registered 23
costs are capped at 1.5 times a CAISO calculation of proxy fuel 24
costs, performed when cost changes are submitted to the CAISO 25
Master File.26
CAISO changes made in 2015 eliminated the registered cost 27
option for all but use-limited gas-fired resources, where use limits 28
had to be documented and accepted by CAISO for each such 29
resource. An example of a use limit is a limit on the emissions from 30
a power plant, expressed as a limit on the number of “cycles” 31
(startups and shutdowns of turbines) at the plant over a rolling 32
1-year period. 33
1-18
In the portfolio of thermal resources or tolling agreements with 1
PG&E as SC, five were qualified as use-limited in 2017. These 2
resources have constraints on starts or run hours.3
During the last week of each month, the five qualified 4
use-limited resources are evaluated to determine the cost basis 5
election of either proxy or registered. The proxy cost option is the 6
default choice given that the commitment costs can be updated 7
daily, but the projected CAISO proxy costs are compared to the 8
projected forecast costs to check if the proxy costs are sufficient. 9
The projected CAISO proxy costs are calculated based on the 10
CAISO proxy gas prices, GHG prices, gas transport adders, and 11
default Variable Operating and Maintenance (VOM) adders for the 12
operating month. The projected forecast costs are based on the 13
latest gas forward prices, GHG forward prices, gas transport adders, 14
and PPA VOM adders. If the projected proxy costs are so low that 15
the projected forecast costs are higher by , then the 16
registered cost basis will be chosen instead.17
During 2017, for every month PG&E used the proxy cost option 18
to determine the commitment cost basis for each of the five use-19
limited thermal resources.20
5) Hydro Resource Bidding and Scheduling21
Hydro generation is energy-limited due to the limited and 22
uncertain availability of water. Water in reservoirs from natural 23
inflows may be considered a limited zero-cost fuel, except in the 24
case of pumped storage hydro (where pumping water uphill to serve 25
as future fuel requires the purchase of electricity from the CAISO 26
markets, but effectively makes the fuel limited only by the cycling 27
capability and reservoir capacities of the plant).28
To the extent that the availability of water can be controlled, it is 29
prudent to store water so as to generate when the power is most 30
valuable, ultimately those times with the highest hourly prices in the 31
CAISO’s day-ahead and real-time markets. Thus, least-cost 32
hydroelectric dispatch is achieved in the CAISO markets by 33
bidding/scheduling hydro resources based on their estimated 34
1-19
opportunity costs (which reflect their energy limitations and forecasts 1
of the future value of water not used in the current scheduling 2
period). CAISO also allows hydro resources to bid limits on total 3
energy dispatched in a single day. If bid, hydro resources should be 4
dispatched only when energy is available and the LMP meets or 5
exceeds the estimated opportunity costs. Depending on operating 6
constraints (such as safety, FERC license requirements, 7
recreational use requirements, or environmental restrictions), some 8
hydro generation is self-scheduled or bid at a price close to zero, to 9
indicate that some flow through the watersheds is not controllable, 10
except possibly by diverting it from particular plants (“spilling” the 11
water) and thus losing any opportunity to generate with it at 12
these plants.13
Hydro resources have their highest value to customers when 14
they either realize high market prices, offsetting customer costs in 15
high-price periods, or when they have the effect of avoiding high 16
prices. Avoided costs are evaluated based on comparison to 17
historical periods or forecasts of future periods to estimate the risk of 18
high-market prices or capacity shortage. In addition, the energy and 19
capacity markets provide short-term price signals, in the form of 20
high A/S or capacity prices, that also help identify high-risk, 21
high-value periods.22
LCD of PG&E’s hydroelectric resources requires that 23
uncertainties in future hydrological system conditions (stream flows, 24
precipitation, temperatures, etc.) and uncertainties in the future 25
value of energy and A/S be incorporated into planning models over 26
future seasons. PG&E’s operation of energy-limited resources, 27
such as hydro, involves decisions that may span multiple months 28
and years. Hydro conditions, end-of-year reservoir target levels, 29
market conditions, and scheduled plant outages affect the 30
optimization of hydro operations in the “short term,” meaning 31
two years or less. Sufficient storage is required to allow for dry year 32
(drought) conditions for the year after the current year. The 33
two-year cycle is used because using either too much or too little 34
1-20
water from the large reservoirs in PG&E’s hydro system may leave 1
the system vulnerable to either drought or storm conditions in the 2
following year.3
a) Modeling Inputs4
The inputs to PG&E’s mid-term hydro planning models are: 5
– Static characteristics of generators, reservoirs and canals 6
and the network configurations of the watersheds;7
– Energy and A/S price forecasts;8
– Reservoir storage inflow forecasts;9
– Outage schedules of generators (and at Helms pumped 10
storage plant, the pumps);11
– Reservoir storage initial volumes;12
– Other reservoir operational constraints; and13
– Canal/waterway flow constraints.14
b) Modeling Outputs15
Outputs of the mid-term hydro planning model consist of: 16
– Hourly MW schedules for all represented plants; 17
– Hourly A/S schedules for A/S capable plants; 18
– Forecast energy and A/S revenues; 19
– Forecast water releases from reservoirs and resulting 20
storage levels; 21
– Flows on all canals/waterways; and22
– Forecasted water values.23
c) Implementation and Use of Modeling Results24
Mid-term hydro planning models generate forecasts of 25
optimal water plans for each of PG&E’s watersheds using 26
assumptions about forward prices, considering safety, physical, 27
operational, and license constraints. The models produce 28
decisions on target reservoir storages, and end-of-month water 29
values, over the entire water planning horizon, as well as 30
nominal hydro generation schedules at each PG&E 31
powerhouse. The most recently generated water plans 32
provide guidance in planning the storage and drafting of 33
1-21
reservoirs, maintenance of hydro powerhouses, and 1
assumptions about availability of hydro generation and A/S 2
over the model’s horizon.3
The nearest term outputs of the mid-term hydro planning 4
models are their end-of-month target reservoir storage levels 5
and marginal water values for the current and following months 6
of the model’s optimization horizon. These targets and water 7
values are used as starting points in shorter-term hydro 8
optimization. PG&E uses a combination of network optimization 9
models and water balance spreadsheet models to forecast 10
week-ahead powerhouse operations at each dispatchable 11
powerhouse. Thus, the network optimization and water balance 12
models forecast bids or schedules of hydro resources based on 13
the most current information on end-of-month reservoir targets, 14
water values, actual hydro conditions, and CAISO market 15
energy and A/S prices.16
Multi-day hydro operations forecasts, based on forecasts of 17
prices and hydro inputs such as inflows, are translated into 18
next-day preferred operating schedules for each powerhouse. 19
The opportunity costs associated with departing from these 20
preferred schedules depend on the nature of the constraints on 21
operations, if any. These opportunity costs, along with the 22
end-of-month water values associated with reservoir planning 23
targets, are used to calculate bids to adjust up or down from the 24
preferred schedule levels (in case of no flexibility, the preferred 25
schedules become self-schedules). Bids and schedules are 26
submitted to the CAISO.27
6) Hydro Self-Scheduling Decisions28
In this section, PG&E includes a description of the rationales for 29
hydro self-schedules during the record period in order to provide 30
additional information on the operational constraints in the hydro 31
LCD process as requested by ORA in the ERRA 2014 Settlement. 32
Each self-schedule is done for one of the following three reasons:33
1-22
a) Self-Scheduling Required During and After Storms1
Under certain storm conditions, much or all of PG&E’s 2
hydroelectric system can become effectively “run of river” hydro, 3
meaning that it cannot be controlled by dispatch decisions. 4
Under such conditions, PG&E’s hydro is represented in the 5
market systems by self-scheduled forecast hourly generation in 6
the markets.7
b) Self-Scheduling in Other Conditions With Limited Operating 8
Flexibility9
Constraints on the hydroelectric system for irrigation, 10
recreation, environmental, or safety reasons may be expressed 11
in terms of minimum flows or minimum releases from reservoirs; 12
such constraints may in general require flows through 13
powerhouses that exceed the rated minimum flows, thus 14
requiring self-schedules at levels above minimum generating 15
level for specific hydro resources. Additionally, limited 16
capacities of small forebay reservoirs may require minimum 17
guaranteed powerhouse flows, implemented as self-schedules, 18
to ensure the safe operation of those small reservoirs.19
c) Self-Commitment to Indicate Preferred Ancillary Service 20
Providing Resources21
Hydroelectric resources supply a significant amount of 22
PG&E’s supply of A/S, including regulation and spinning 23
reserves. In cases where experience shows that price signals 24
alone may result in excessive cycling of resources to provide 25
A/S, PG&E may elect to self-schedule particular hydro 26
resources to ensure that A/S are provided in the most efficient 27
and effective way.28
7) Helms Pumped Storage Plant Bidding and Scheduling29
The Helms Pumped Storage Plant (Helms) is a located on the 30
Kings River watershed, situated between an upper reservoir, 31
Courtright Lake, and lower reservoir, Lake Wishon. It has three 32
generators that can be reversed to act as pumps, and has an 33
1-23
installed generation capacity of 1,212 MW and a pump capacity of 1
930 MW. Helms has the capability of increasing its Courtright 2
forebay (Courtright) reservoir storage by pumping water from the 3
Lake Wishon uphill to Courtright. Helms is subject to physical 4
hydrological operating constraints and hydro uncertainties like any 5
other of PG&E’s hydro resources.156
LCD of Helms requires evaluation of the opportunity cost of 7
stored water and, in addition, requires that pumping be evaluated 8
based on the benefits of incremental generation. LCD of Helms also 9
requires evaluation of how best to use the generating capacity of the 10
plant, which can provide reserves and regulation as well as energy. 11
Because reserves generally have highest value in the same periods 12
that energy has highest value, total costs to customers are 13
minimized when the Helms schedule has maximum value 14
considering both energy and reserves. The plant may therefore not 15
be dispatched to its maximum generation output in the market, so 16
that its undispatched capacity may provide high value A/S.17
The mid-term hydro planning optimization model is used to 18
determine reservoir storage targets and water values for Courtright 19
(forebay) and Wishon (afterbay) reservoirs on a monthly basis 20
through the end of the year following the current year. Reservoir 21
planning for Helms differs from that on other watersheds in that 22
inflows to the afterbay can be pumped to the forebay for later use; 23
and mid-term planning model outputs therefore include a pumping 24
plan over the horizon of the model.25
Short-term hydro planning for Helms is based on the mid-term 26
month-end reservoir targets and water values, as it is for other 27
watersheds. Adjustments within the month are made based on 28
realized inflows as well as short-term price forecasting. The 29
resulting preferred operating schedules for Helms may include some 30
pumping and some generation and A/S. Additional pumping may be 31
15 For more information on Helms in the context of PG&E’s Hydroelectric System and PG&E’s Portfolio Management, see “Chapter 2: Utility-Owned Generation: Hydroelectric.”
1-24
economic in the short term if additional generation and A/S (above 1
the forecast/preferred schedule) is valuable enough; likewise, 2
additional generation and/or A/S may be economic in the short term 3
if additional pumping is at low enough cost (the LMP paid for 4
pumping energy). This incremental ability to pump and generate or 5
provide A/S is included in the bids submitted for Helms to the 6
CAISO markets.7
8) Battery Storage Bidding and Scheduling8
During the record period, PG&E continued to bid its 9
dispatchable storage batteries to test CAISO software capabilities 10
and limitations and to identify feasible charge/discharge cycles. 11
PG&E’s two owned battery resources participated in the CAISO 12
markets and were used to evaluate several potential models of 13
market revenue maximization. 14
Two market models were available in the CAISO markets during 15
the record period. The Non-Generator Resource (NGR) market 16
model allows a combination of energy bids and A/S bids to receive 17
CAISO market awards. The NGR model constrains charge and 18
discharge to keep the battery between minimum and maximum 19
State of Charge (SOC) limits. 20
The Regulation Energy Management (REM) market model 21
allows batteries to bid only to provide regulation up and down in the 22
CAISO markets. Under this model, a battery can bid regulation up 23
and down in one or more hours, but it cannot bid or self-schedule 24
energy. The CAISO is responsible for maintaining the SOC of a 25
REM battery at approximately 50 percent to the extent feasible. If 26
the resource’s SOC makes it impossible to regulate, the resource 27
will still receive its regulation capacity payments, even though it is 28
unable to physically regulate until its SOC makes regulation 29
possible again.30
The incremental cost of battery discharge is based on the 31
battery’s cycling efficiency and cost of charging. After testing, 32
PG&E determined that the advantages of having the CAISO 33
manage the SOC in the REM model did not outweigh the benefits of 34
1-25
energy arbitrage value possible under the NGR model. Accordingly, 1
both batteries were bid using the NGR market model for the majority 2
of the year.3
Overall, the purpose of operating the batteries in the market 4
combined the objectives of maximizing revenues from the resources 5
under a known strategy (e.g., bidding the resources into the 6
regulation markets) and testing new approaches that might yield 7
new sources of value or have application to future operations of 8
batteries in the CAISO markets (e.g., representing customer-side 9
uses of the batteries or distribution-level operating restrictions). 10
11
12
13
14
15
16
9) Resource Bid Non-Submission17
In this section, PG&E provides a description of the rationales for 18
thermal resource bid non-submission during the record period. 19
“Thermal resource bid non-submission” here means non-submission 20
of bids in periods when a resource is not on outage, i.e., not 21
explicitly limited by a clearance in the CAISO’s Outage Management 22
System (OMS). Resources on outage are not included here, 23
because they may or may not have bids created for them, 24
depending on whether bids are created as a backup to address 25
unexpected early returns from outage. Workpaper 2 provides 26
additional detailed explanations for instances in which bids were not 27
submitted for thermal resources. Taken together, this section and 28
the workpapers offer complete documentation of thermal bid 29
non-submission decisions as requested by ORA in the 2014 ERRA 30
Settlement.31
Gas-fired and other fossil fuel thermal plants are in general 32
subject to limits (e.g., emissions limits) that translate into limits on 33
startups and shutdowns over each year and over subperiods, 34
1-26
potentially even daily subperiods, of the year. To stay within the 1
limits and to guarantee the availability of some thermal resources to 2
serve customers in the periods of the year with expected highest 3
need, PG&E reserves the right not to bid some or all of the resource 4
capacity in other periods of the year, subject to meeting all 5
Resource Adequacy (RA) and other contractual or reliability 6
constraints on the resource.7
10) Market Transactions8
Bilateral transactions in the CAISO day-ahead markets take 9
two forms: (1) financial transactions, known as “inter-SC trades” or 10
“bilateral swaps,” which trade the difference between a fixed price 11
and the CAISO’s day-ahead IFM prices at a given location without 12
involving any delivery of energy to the grid; and (2) physical 13
transactions at the intertie points (also known as scheduling points), 14
which require physical scheduling of an import or export and are 15
settled in the CAISO day-ahead market just as other supplies or 16
demands are settled.17
Day-ahead financial bilateral transactions (i.e., within the CAISO 18
balancing area) and bilateral physical transactions (i.e., at CAISO 19
interties) were used to settle existing energy procurement contracts. 20
During the record period, PG&E continued to close its financial and 21
physical positions by transacting in the CAISO markets, with the 22
important exceptions of imports from, and exports to, outside of the 23
CAISO control area.24
Imports and exports require physical scheduling into the CAISO 25
markets, “tagging” to match schedules across balancing authority 26
control areas, and a separate bilateral financial settlement with 27
counterparties outside of the CAISO control area. PG&E imports 28
included energy associated with renewable contracts, 29
energy required to meet RA targets, and the long-term Puget 30
Exchange contract.31
1-27
11) Must-Take Resources and Contracts1
Must-take resources, unlike dispatchable resources, have no 2
flexibility in the delivery of energy; whatever energy they produce 3
must be taken by the transmission grid. The exception for 4
must-take resources is when transmission constraints make it 5
physically impossible for the power to flow. Must-take 6
resources include:7
i) Existing Qualifying Facilities: PG&E’s existing QF PPAs allow 8
QFs to decide what level of generation to provide. Existing QF 9
PPAs are considered must-take resources;10
ii) Combined Heat and Power: Contracts allow certain CHP 11
resources to determine the level of supply they will provide;12
iii) Renewable energy contracts and resources without bidding 13
rights for economic dispatch;14
iv) Diablo Canyon Power Plant (DCPP);15
v) Existing/Legacy Contracts: PG&E had obligations to purchase 16
or exchange power under existing contracts which were settled 17
as financial inter-SC trades; and18
vi) Must-Run Hydro Generation: Certain power plants have 19
environmental, licensing or physical requirements that require 20
continuous operations.21
During the record period, there were 22
. These are discussed in 23
Section 5.24
12) Economic Bidding of Renewable Resources25
During the record period, PG&E’s portfolio included utility 26
owned and contracted renewable resources with economic 27
bidding capabilities and rights described in PG&E’s 2014 BPP. 28
Economic bidding of these resources captures the opportunity 29
costs associated with the contractual and the operational 30
constraints of these resources.31
In all cases of economic bidding of renewable resources, 32
33
34
1-28
1
2
3
4
5
6
7
8
Economic curtailment of renewables occurs when market 9
prices fall to, or below, 10
. Thus, the market, not 11
PG&E, ultimately determines when these resources are 12
economically curtailed.13
Some renewable resources have economic dispatch rights 14
for only a limited number of hours per contract year, for example 15
100 hours. 16
17
18
19
20
21
22
23
24
25
26
13) Bid/Award Validation27
PG&E reviews the results of each day’s CAISO day-ahead 28
market. Market results in the form of resource schedules are 29
examined to verify that day-ahead schedules are feasible, to 30
determine the additional operational flexibility that can be offered in 31
the real-time markets, to verify that the schedules are consistent 32
with market prices (or at a minimum, with the CAISO tariffs), and to33
1-29
check the accuracy of PG&E’s forecast of generation and costs prior 1
to the market against the actual results of the market.2
Forecasts inherently do not perfectly match actual results. 3
PG&E continually assesses the accuracy of its forecasts to improve 4
the quality of forecast results.5
If day-ahead schedules are not physically deliverable, PG&E 6
adjusts them in real-time and performs an analysis to determine the 7
reason for any infeasibility. In addition to correcting infeasible 8
schedules (i.e., re-scheduling or rebidding in the real-time markets), 9
corrective action is taken when possible with respect to future days’ 10
bidding and scheduling.11
When total market revenues earned over the course of a day 12
based on the awards by the CAISO do not cover the generating 13
unit’s bids, units are eligible to receive Bid Cost Recovery (BCR) 14
payments. PG&E validates that expected BCR is received in these 15
cases, or if not, that PG&E has communicated its concerns and/or 16
disputes of BCR calculations to CAISO.17
When issues with market results are identified, whether 18
immediately after publication of day-ahead market results or at any 19
later point in time, management is informed and, when appropriate, 20
a ticket is registered with the CAISO’s Issues Management System 21
(also known as Customer Inquiry, Dispute and Information (CIDI)) 22
for resolution. Persistent issues not remedied through normal CIDI 23
ticket resolution or settlement dispute resolution may be identified 24
for resolution either by changes in bidding and scheduling strategy 25
or through CAISO market design or regulatory channels.26
(a) CBP program dispatch is limited to 30 hours per month for the 6-month program period.(b) CBP program dispatch is limited to five events per month for the 6-month program period.
Attachment 1B provides monthly tables showing the number of 1
hours when PG&E forecasted that trigger criteria would be reached, 2
hours in which trigger conditions were reached in the same 3
time period, actual hours dispatched, and the number of events 4
dispatched.5
3) Non-Dispatch Occurrences6
a) Summary7
Despite the closure of the AMP program and trigger 8
conditions being met less often, PG&E dispatched 9
approximately the same number of events and event hours in 10
2017 as in 2016. While each SubLAP experienced 11
approximately 25 hours during the 2017 CBP season when 12
triggers were met but resources were not dispatched (see 13
Table 1-10 below), there were on average 10 percent fewer 14
hours of non-dispatch across all SubLAPs compared to 2016. 15
Additional information about the reasons for non-dispatch is 16
provided further below.17
1-43
TABLE 1-10CAPACITY BIDDING PROGRAM HOURS IN WHICH TRIGGER MET
Attachment 1C provides a detailed summary of total energy 1
actually dispatched as a proportion of maximum available 2
energy for each DR program. This comparison provides both 3
percentage and nominal MWh terms.4
b) Explanation of the Basis for a Decision Not to Dispatch5
As discussed above, PG&E’s tariffs allow for, but do not 6
require, dispatch when triggers are reached. While PG&E 7
increased the utilization of its DR resources in 2017, there were 8
instances in which PG&E did not dispatch CBP resources when 9
triggers were met.10
During the record period, there were two general reasons 11
that PG&E did not dispatch CBP when the program triggers 12
were met. First, operational constraints embedded in the tariff 13
can impact dispatch. Second, because DR resources are 14
customer-impacting and use-limited, PG&E may choose to not 15
dispatch so that the resource may be used at a different and 16
more highly valued time. This latter reason is referred to as 17
“opportunity cost” and captures the “customer fatigue” issues 18
discussed in Section C.2.b.3)b)ii below.19
1-44
In the 2014 ERRA Settlement, PG&E agreed to provide 1
definitions of “operational constraints” and “opportunity cost” as 2
reasons for not dispatching DR programs when economic 3
triggers are met.18 These definitions are provided in 4
Sections C.2.b.3)b)i and C.2.b.3)b)ii below, respectively. 5
PG&E also agreed to provide guidelines for situations in 6
which “customer fatigue” may occur. This is included in 7
Section C.2.b.3)b)ii.8
i) Operational Constraints Related to DR Dispatch9
PG&E defines a DR “operational constraint” as a 10
constraint based on limitations included in the DR tariff(s). 11
The primary operational constraints for CBP are the total12
hour limitation and number of events on monthly basis, and 13
also the hour limitation on a per-call basis. For example, 14
the CBP program is limited to 30 hours per month and 15
five events per month.1916
In 2017, had heat rate triggers been the sole 17
determinant of when dispatch conditions were met, then 18
there would have been more instances of meeting dispatch 19
conditions.20 Adding the price trigger requirement 20
($70/MWh) to the heat rate requirement resulted in fewer 21
instances of dispatch conditions being met, but also 22
significantly reduced the number of dispatch exceptions, 23
and resulted in a greater number of events and event hours 24
than occurred in 2016. 25
While maximum available tariff hours provide the 26
primary operational constraint on dispatch, tariff design also27
may create additional operational constraints. One example 28
18 2014 ERRA Settlement, ¶¶ 3.2, 3.6.19 The CBP tariff specifies that the program is only available during the summer
(May-October) DR season. This also would be considered an operational constraint when compared to year-round DR programs.
20 The 15,000 Btu/kWh heat rate resulted in a strike price ranging from $46.05-51.92/MWh in 2017, significantly less than the $70/MWh price trigger.
1-45
of this type of constraint is the customer notification 1
requirements included in each tariff. Under the CBP tariff in 2
effect during the record period, PG&E had to notify its 3
day-ahead CBP participants by 3 p.m. on the day before it 4
planned to dispatch the program.21 However, on five days 5
of the record period, the CAISO did not send its day-ahead 6
forecast information to PG&E in time to make these 7
dispatch decisions. The notification requirements in the 8
CBP tariff therefore acted as an operational constraint on 9
those days. PG&E still awaits approval from the 10
Commission to extend this notification time until 4 p.m. to 11
alleviate much of this constraint.12
ii) Opportunity Costs as Related to DR Dispatch13
Generally, “opportunity cost” is the potential lost future 14
value associated with calling a DR program at a certain 15
point in time and, therefore, eliminating the option to use it 16
at a future time. Opportunity costs arise from two issues. 17
First, there are maximum hour limits on the number of 18
times a DR resource may be called in the DR program 19
season, so dispatching a resource today may result in the 20
resource not being available during a future time of need. 21
Decisions to dispatch or not to dispatch DR programs are 22
made in PG&E’s DR Tailboard. In these meetings, heat 23
rate and price levels in relation to their respective triggers 24
are considered along with an assessment of opportunity 25
costs that are estimated by taking into account market price 26
forecasts, weather forecasts, and historical experience with 27
system conditions. If the opportunity cost suggests that 28
there could be greater value in dispatching the resource at a 29
21 “PG&E will notify the affected Aggregators by 3:00 p.m. on a day-ahead basis of a CBP Event for the following business day. Notices will be issued by 3:00 p.m. on the business day immediately prior to a NERC holiday or weekend if a CBP Event is planned for the first business day following the NERC holiday or weekend.”
1-46
later date, then the resource may not be dispatched even if 1
the heat rate and price triggers have been met.2
The second issue that creates opportunity cost is 3
“customer fatigue,” which occurs at the individual customer 4
level rather than at the program level. Participation in DR 5
events can cause a participating customer to make 6
significant changes to energy use, such as shutting down a 7
manufacturing line that in turn may result in sending home 8
employees. There are a limited number of times within a 9
demand response season that customers are willing to 10
make such sacrifices for the current level of compensation. 11
If customers are dispatched too frequently or for too long of 12
periods, then it could result in “customer fatigue,” which is a 13
reduction in participation rates due to the customer 14
perceiving the costs of participating exceeding the benefits15
of participating. 16
Some of PG&E’s largest DR customers have provided 17
consistent feedback to PG&E that dispatch frequency has 18
seriously impacted their business operations and requested 19
that dispatch only occur if necessary. As a result, PG&E 20
generally does not dispatch DR events for more than 21
three days in a row, which was agreed to in the 2014 22
ERRA Settlement.23
4) Dispatch Day Selection24
For the record period, PG&E’s DR event dispatch helped to 25
minimize its overall portfolio costs. As demonstrated in 26
Table 1-10 below, PG&E employed its DR resources during highly 27
valuable hours.28
1-47
TABLE 1-11AVERAGE DLAP PRICE FOR FORECASTED TRIGGER EVENT DAYS
AND ACTUAL DISPATCH DAYS
Line No.
Average Hourly DLAP Price During
Actual Dispatch Events
($/MWh)
Average Hourly Potential DLAP Price From All Times When
Trigger Conditions Were Forecasted (Dispatched or Not)
($/MWh) $ (A) – (B) (A)/(B) (%)(A) (B)
1
As indicated in Table 1-11, the average hourly Default Load 1
Aggregation Point (DLAP) price for events actually dispatched in the 2
2017 record period was /MWh, whereas the average hourly 3
potential DLAP price from all time periods when DR program 4
triggers were forecasted to be met by PG&E was /MWh. 5
This further underscores that PG&E optimized its dispatch of DR 6
resources to deliver load reductions during the most valuable hours 7
of the 2017 DR Season. Where triggers were met and PG&E opted 8
not to dispatch, such opportunity cost decisions were made in order 9
to utilize the resources at times of higher prices and greater need.10
3. SmartAC11
PG&E’s SmartAC Program is a voluntary DR program in which PG&E 12
installs a device to temporarily cycle a customer’s AC compressor. 13
SmartAC can be dispatched by order of the CAISO during emergency or 14
near-emergency situations, when the CAISO day-ahead price for the PG&E 15
DLAP exceeds $1,000 per MWh, or during program testing. 16
There were no instances in which the SmartAC price trigger was 17
forecasted to be reached during the record period. PG&E did test SmartAC 18
16 times during the record period, for 57 hours of dispatch. Additionally, 19
SmartAC customers dually enrolled in PG&E’s SmartRate™ Program were 20
dispatched for the 14 SmartRate events, to help reduce load. Since these 21
were not economic dispatches, however, SmartAC is not discussed further 22
in this chapter. 23
4. Aggregator Managed Portfolio24
PG&E’s AMP closed on December 31, 2016. Therefore, it will no longer 25
2) Forced Outages Unrelated to the January-February Winter Storms......................................................................................... 2-45
E. Conclusion...................................................................................................... 2-53
2-1
PACIFIC GAS AND ELECTRIC COMPANY1
CHAPTER 22
UTILITY-OWNED GENERATION: HYDROELECTRIC3
A. Introduction4
In compliance with Decision (D.) 14-01-011, this chapter addresses the 5
operation of Pacific Gas and Electric Company’s (PG&E) utility-owned 6
hydroelectric facilities, and outages that occurred at these facilities during the 7
2017 record year.8
PG&E’s utility-owned hydroelectric portfolio was operated in a reasonable 9
manner during the record period. PG&E’s hydro-generating portfolio consists of 10
66 powerhouses with 106 generating units. The system operates under 11
25 Federal Energy Regulatory Commission (FERC) licenses, which govern the 12
operation of 102 of the generating units at 64 powerhouses. Four generating 13
units are at two non-FERC jurisdictional powerhouses. PG&E’s 14
hydro-generating portfolio has an aggregate nameplate capacity of 15
3,892.2 megawatts (MW) and produces an average of about 11 terawatt-hours 16
of energy in a normal precipitation year.17
PG&E’s 66 hydro powerhouses are located on 15 rivers and four tributaries 18
of the Sierra Nevada, Cascade and Coastal mountain ranges. This is a unique 19
set of facilities that was built between 1898 and 1986. Most of the dams and 20
powerhouses have been in service for well over 50 years, and some of the water 21
collection and transport systems were used for gold mining and consumptive 22
water prior to the development of these hydro-generating facilities.23
The system collectively includes the following ancillary support facilities: 24
98 reservoirs, 73 diversions, 170 dams, 173 miles of canals, 43 miles of flumes, 25
132 miles of tunnels, 65 miles of pipe (penstocks, siphons, and low head pipes), 26
four miles of natural waterways, and approximately 140,000 acres of fee-owned 27
land. It also includes switchyards, switching centers that remotely control 28
generation facilities, administrative buildings, fleet, multiple modes of 29
communication, materials and supplies inventories, office equipment, and other 30
miscellaneous instrumentation and monitoring equipment. PG&E’s authority to 31
divert and store water for power generation is based on 89 water right licenses 32
or interim permits, and 160 Statements of Water Diversion and Use.33
2-2
PG&E’s hydro plants produce low cost and clean energy, high value 1
ancillary services and peaking capacity to meet customers’ needs. PG&E has 2
demonstrated its ability to optimize these generation facilities through efficient 3
use of water resources and continuing environmental stewardship.4
PG&E’s system of dams, reservoirs, and water collection facilities enables 5
PG&E to store runoff and aquifer flows and then subsequently use the water to 6
generate power when customers need it most. This “shaping” of the available7
generation is performed both seasonally (for example, by storing more water in 8
the spring and releasing water from the reservoirs during high value hot summer 9
days) and day to day (for example, generating more during hours of peak 10
system demand—typically weekday late-afternoons and evenings—and less at 11
night and on weekends). In general, the highest value of PG&E-owned 12
generation is likely to be when PG&E’s demand is greatest and intermittent 13
renewables are not available, and hydro generation can contribute significantly 14
toward reducing the amount of power that has to be purchased during these 15
higher priced hours.16
Hydroelectric generating units typically start up quickly, have fast ramp 17
rates, and can easily, quickly, and economically vary output in response to 18
changing customer loads and system conditions. In addition, hydro-generating 19
units can operate at no load or low load with much higher efficiency than the 20
alternative fossil fueled peaking plants. Finally, because a large portion of 21
California's non fossil-fueled electricity resources consist of non-dispatchable 22
energy sources such as wind, solar, nuclear and regulatory “must-take” 23
generation, the California Independent System Operator (CAISO) relies on 24
PG&E’s hydro resources to satisfy a large portion of its operating reserve 25
requirements.26
B. Overview of PG&E’s Hydroelectric System27
1. Hydro System Characteristics28
Hydroelectric generation converts the potential energy contained in 29
falling water to electricity. In general, water from precipitation runoff and30
aquifer flows is collected at a high elevation and through various water 31
collection, storage and conveyance systems is delivered to the powerhouse 32
penstock where it drops to the powerhouse elevation. The water, under 33
2-3
pressure from the elevation drop, is directed through or against the turbine 1
runner causing the turbine and coupled generator to rotate and produce 2
electricity. The major system components consist of:3
Water Collection Facilities – Reservoirs and dams including stream 4
diversions;5
Water Conveyance Facilities – Tunnels, canals, flumes, natural 6
waterways, conduits and penstocks utilized to direct the water from 7
collection points to the powerhouse;8
Powerhouses – Structures containing the turbines, generators and 9
associated equipment used to produce electricity; and10
Auxiliary Equipment – Transmission lines and associated switchyard 11
equipment to transmit the electricity to the grid.12
PG&E’s hydro-generation portfolio can be segregated into 13
three categories based on the characteristics of the water supply to the 14
powerhouse:15
Run-of-the-River Powerhouses – These powerhouses generally have 16
little or no water storage facilities and rely on stream/river diversions, 17
with small impoundments, to direct the water into the water conveyance 18
system. The powerhouse is operated based on the flow available to be 19
diverted from the river. Once diverted, the water travels through various 20
water conveyance facilities, such as canals, flumes, tunnels, natural 21
waterways, and conduits to the penstock.22
Reservoir Storage Powerhouses – Powerhouses that have significant 23
water storage facilities are not limited to run based on the available river 24
flow, but can store runoff and aquifer flows and then subsequently use 25
the water to generate power when customers need it most. Generally, 26
these powerhouses have less water conveyance assets either because 27
they are located close to the dams or have a single large tunnel 28
delivering water to the penstock(s). Because of their large 29
impoundments and hydro’s ability to quickly come online and ramp up to 30
full capacity, these powerhouses can be used for peaking during high 31
demand power periods.32
Pumped Storage Powerhouse – PG&E has one pumped storage 33
powerhouse, Helms Pumped Storage Facility (Helms). Helms is a 34
2-4
reservoir storage powerhouse, situated between an upper reservoir, 1
Courtright Lake, and a lower reservoir, Lake Wishon, with 2
three generators that can be reversed to act as pumps. During off-peak 3
hours, when energy prices are lower, the pumping mode is utilized to 4
pump water back up to Courtright Lake to be reused during the next 5
cycle. The ability to pump the water back up to the storage reservoir 6
allows the water resource to be reused during peak demand hours. 7
Helms also provides renewable integration benefits such as regulation 8
up and down, load following, operating reserves (backup), shaping, and 9
management of system over-generation conditions that result from 10
excess renewables generation during off-peak and partial-peak periods.11
2. Hydro Operations and Maintenance Organization12
PG&E’s Power Generation organization is responsible for managing the 13
hydro-generating portfolio. The Hydro Operations and Maintenance (O&M) 14
organization is responsible for facility O&M and works side by side with the 15
other Power Generation and PG&E Energy Supply support organizations to 16
provide safe, reliable, cost-effective and environmentally responsible 17
generation. Hydro O&M is organized geographically into five areas. These 18
areas consist of logical groupings of facilities that enable efficient oversight, 19
control and management of O&M. The powerhouses are operated from 20
seven switching centers located throughout the system. Six of the switching 21
centers are located at powerhouses and one is located in Fresno. A full 22
listing of powerhouses and individual units is included in Attachment 2A.23
The Hydro Areas (from North to South) and the Power Generation 24
support organizations are described below, and the information is then 25
summarized in Table 2-1.26
a. Shasta Area27
The Shasta Area manages 16 powerhouses with 28 generating 28
units and has an installed capacity of 809.9 MW. The powerhouses 29
have in-service dates spanning from 1903-1981. The facilities are 30
situated on six different watersheds in Shasta and Tehama counties. 31
There are two switching centers in Shasta, located at Pit 3 Powerhouse 32
2-5
and Pit 5 Powerhouse. The Shasta Area headquarters is located in 1
Burney with a satellite headquarters in Manton.2
b. DeSabla Area3
The DeSabla Area manages 15 powerhouses with 27 generating 4
units and has an installed capacity of 785.7 MW. The powerhouses 5
have in-service dates spanning from 1900-1985. The facilities are 6
situated on five different watersheds in Plumas and Butte counties, and 7
on one watershed located in Mendocino County. There is one switching 8
center in DeSabla located at Rock Creek Powerhouse. The 9
DeSabla Area headquarters is located at Rodgers Flat (near Oroville) 10
with satellite headquarters at Camp One (near Paradise) and 11
Potter Valley (near Ukiah).12
c. Central Area13
The Central Area manages 21 powerhouses with 28 generating14
units and has an installed capacity of 522.6 MW. The powerhouses 15
have in-service dates spanning from 1902-1986. The facilities are 16
situated on eight different watersheds in Nevada, Placer, El Dorado, 17
Amador, Tuolumne and Merced counties. There are three switching 18
centers in the Central Area located at Drum Powerhouse, Wise 19
Powerhouse and Tiger Creek Powerhouse. The Central Area 20
headquarters is located in Auburn with satellite headquarters at Alta, 21
Angels Camp, Tiger Creek (near Jackson) and Sonora.22
d. Kings-Crane Valley Area23
The Kings-Crane Valley Area manages 13 powerhouses with 24
20 generating units and has an installed capacity of 562 MW. The 25
powerhouses have in-service dates spanning from 1906-1983. The 26
facilities are situated on six different watersheds in Madera, Fresno, 27
Tulare and Kern counties. The Kings-Crane Valley switching center is 28
located at the Fresno Operating Center. The Kings-Crane Valley Area 29
headquarters is located in Auberry with a satellite headquarters at 30
Balch Camp (east of Clovis).31
2-6
e. Helms Pumped Storage Facility1
This Area consists of the Helms facility with three pump-generator 2
units and an installed capacity of 1,212 MW. Helms was placed in 3
service in 1984. Helms is operated from the powerhouse and is not 4
under the jurisdiction of a separate switching center. Helms is located in 5
Fresno County and has a headquarters facility at the project site.6
(4) an incident reporting process; (5) a Corrective Action Program (CAP); 17
(6) outage planning and scheduling processes; (7) a project management 18
process; and (8) a design change process. Each of these controls is 19
discussed below.20
a. Guidance Documents21
The guidance documents applicable to hydro operations include 22
PG&E Policy, PG&E Utility Standard Practices, PG&E Utility 23
Procedures, and Power Generation-specific guidance documents. 24
Power Generation-specific guidance documents include Standards, 25
Procedures and Bulletins. These guidance documents cover virtually all 26
aspects of safety, operations, maintenance, planning, environmental 27
compliance, regulatory compliance, emergency response, work 28
management, inspection, testing and other areas. Each guidance 29
document describes the purpose of the document, the details of the 30
actions and/or processes covered by the document, management’s 31
roles and responsibilities, and the date the document became effective.32
2-16
b. Operating Plans1
The hydro switching centers have operating plans to assure that the 2
powerhouses are operated in conformance with license conditions and 3
all other local, state and federal regulations. There are also specific 4
operating plans developed for operating the powerhouses in the 5
extreme conditions of summer and winter. The plans specify how 6
operation of the facilities is adjusted to take into account the impacts of 7
the seasons. For example, the summer plan addresses operational 8
issues related to excessive heat and increased public recreation in, 9
around and downstream of PG&E facilities. The winter plan addresses 10
operational issues related to heavy rainfall, increased river and stream 11
runoff and snow conditions.12
c. Operations Reviews13
Operations reviews are periodically performed at hydro 14
powerhouses and switching centers by the SQS organization. The 15
purpose of the operations reviews is to assure that PG&E’s generation 16
facilities are operated in a safe and efficient manner and that they are in 17
compliance with standard operating and clearance procedures.18
An operations review evaluates the overall operation of a 19
powerhouse against a variety of Power Generation’s guidance 20
documents to assure that standard operating practices are being 21
followed and the powerhouse is in full regulatory and environmental 22
compliance. The results of the review are shared with management and 23
any identified violations require an immediate response and correction.24
d. Incident Reporting Process25
The incident reporting process is intended to document problems, 26
activities and events that impact or could potentially impact the 27
performance of systems that assure: (1) public safety; (2) facility safety, 28
reliability, availability, and protection of property; and/or 29
(3) environmental or regulatory compliance. By thoroughly analyzing 30
significant problem events that occur in the operation and maintenance 31
of PG&E’s facilities, PG&E can report to various regulatory agencies as 32
required, identify possible precursors to repetitive or more serious 33
2-17
problems, understand root causes, and communicate and apply lessons 1
learned to other facilities and personnel.2
e. Corrective Action Program3
The CAP is designed to document and track corrective actions and 4
commitments. The CAP includes problem identification, cause 5
determination, reporting, development of corrective actions and 6
corrective action implementation tracking.7
PG&E’s Power Generation organization has implemented a CAP 8
that utilizes SAP notifications and orders to track and document the 9
following: actions that are necessary or have been taken as a result of 10
audit and/or inspection findings, deviations identified in incident reports, 11
regulatory non-compliance issues, engineering deviations and other 12
systemwide issues.13
f. Outage Planning and Scheduling Processes14
The hydro outage schedule is developed to communicate when 15
various powerhouse units will be unavailable due to maintenance or 16
project work. Shown on the schedule are annual maintenance outages, 17
project-specific outages and combination outages encompassing both 18
project and maintenance tasks. The hydro outage schedule for a given 19
outage year is developed through an iterative process, over several 20
years, as projects and maintenance tasks are identified by field 21
employees, management, project managers and others. Except for 22
outages with scopes of work demanding long durations or units that 23
have little or no water to run, no outages are planned during the peak 24
summer generation season. Also, every effort is made to limit the 25
number and duration of outages in the off-peak shoulder months.26
The yearly outage schedule is not a static document. The schedule 27
is fluid and adaptable to changing requirements for outages. PG&E’s 28
STES organization, the CAISO, and others utilize the schedule to make 29
plans regarding resource allocation, replacement power and restrictions 30
on the system. Therefore, changes in the schedule, particularly in the 31
short term, are discouraged. However, it is inevitable that due to the 32
dynamic nature of the hydro system, changes will be required. 33
2-18
Changes to the schedule may be required based on many factors, 1
including weather conditions, resource constraints, changes in project 2
scope or schedule, and/or emergent work. Depending on the proximity 3
to the outage start date, changes to the scope and schedule require 4
different levels of management review and approval. Before outage 5
changes are approved, consideration is given to the impacts of the 6
change on issues such as: effects on equipment reliability, replacement 7
power costs, water deliveries, possible by-pass spills, resources and 8
impacts to other scheduled outages.9
For an individual outage, an outage management plan is developed 10
prior to the start of the outage. Depending on the size and duration of 11
the outage, an outage management plan can be as simple as a list of 12
work orders extracted from the SAP Work Management (SAP WM) 13
system, or as complex as a critical path, resource-loaded work 14
execution plan detailing each task for a project as well as preventative 15
and corrective maintenance work orders. The development of an 16
outage management plan can be broken down into three distinct, but 17
interrelated, processes: (1) Planning and Scoping; (2) Scheduling; 18
and (3) Outage Execution.19
1) Planning and Scoping20
The planning and scoping process entails determining which 21
work is to be executed during the outage. This includes 22
preventative maintenance work orders, corrective work orders for 23
repairs on equipment and/or facilities and project-specific asset 24
replacements or major refurbishments. During this process, the 25
required resources to execute the work and the duration of all work 26
activities are identified.27
Power Generation utilizes SAP WM as the tool to manage 28
preventative and corrective work. Preventative maintenance work 29
orders, sometimes referred to as recurring work, encompass routine 30
maintenance work performed at established intervals. Corrective 31
work orders, sometimes referred to as trouble tags, refer to work 32
identified to correct an issue that is limiting the ability of the 33
equipment or facility to efficiently perform its design function. The 34
2-19
SAP WM system is the electronic repository where preventative and 1
corrective work is identified, tracked, organized and managed. The 2
system utilizes maintenance libraries to generate recurring work 3
orders against a piece of equipment at the appropriate frequency as 4
specified by PG&E. Corrective work orders are created in the 5
system by the crews or individuals identifying the problem.6
The planning and scoping process begins two to three years 7
prior to the outage and continues until outage execution.8
2) Scheduling9
The scheduling process includes determining the timing of the 10
start of the outage, as well as the appropriate duration. Outage 11
timing and durations are influenced by many factors, including but 12
not limited to: capital and maintenance work to be performed, 13
system operation constraints, powerhouse elevation, time of year, 14
weather conditions, water storage requirements, downstream water 15
user requirements, size of unit, labor resources available to perform 16
work, configuration of hydro system (close coupled to dam or long 17
water delivery system), effects on other powerhouses, CAISO 18
constraints, transmission system issues, distribution system issues 19
and FERC license conditions.20
Table 2-2 below provides the timeline for the outage scheduling 21
process.22
2-20
TABLE 2-2OUTAGE SCHEDULING PROCESS
Steps Timing Process Description
1. 2 to 3 Years Prior to Outage Year
A preliminary annual outage schedule for the outage year isprepared 2 to 3 years in advance. This preliminary schedule is created using historical outage durations and timing data for each watershed, powerhouse and unit. There is no formal approval of this preliminary schedule. The local O&M supervisors review the preliminary schedule and recommend changes.
2. 1 to 2 Years Prior to Outage Year
Each annual outage on the schedule is adjusted/revised over the next 1 to 2 years as more information becomes available about routine maintenance tasks, non-routine maintenance requirements, and/or project work that must be performed during the outage. During this preliminary phase, requested changes are made to the schedule and reviewed by PG&E Generation Supervisors for powerhouses under their control.
3. 3 Months Prior to the Start of the Outage Year
On a quarterly basis, PG&E submits to the CAISO a planned outage schedule that details the outages planned for the following 15 months. In October of the year prior to the outage year, the planned outage schedule is submitted to the CAISO to set the base outage schedule. After this submission, any requests for changes to individual outages are submitted to the responsible Area Manager and/or Hydro O&M Director for approval. The level of management approval is dictated by the proximity of the request to the outage start date. These internal approvals are required before the changes are submitted to the CAISO.
4. Changes During an Outage
Changes to the duration of an outage can occur during an outage due to emerging work, unforeseen problems or other issues. Requests for outage extensions require the approval of the Hydro O&M Director.
3) Outage Execution1
The outage execution process encompasses not only 2
performing the work planned for the outage, but also complying with 3
the many sub-processes for notifications and approvals between the 4
outage stakeholders and lessons learned. These include:5
Notifications to and approvals from the CAISO to separate the 6
unit(s) from the grid;7
Clearance procedures covering the steps required to 8
electrically, hydraulically and mechanically clear the units and 9
facilities (i.e., put them in a safe condition) for the outage work 10
to proceed;11
Notifications and approvals for any changes in the outage due 12
to emerging work or changed conditions;13
2-21
Restoration procedures to restore the unit to service when the 1
outage work is completed. This includes complying with the 2
steps in the switch log and any start-up procedure for new or 3
refurbished equipment;4
Notifications to and approvals from the CAISO to restore the 5
unit to service and connect to the grid at the completion of 6
the outage; and7
Collection of lessons learned at the completion of the outage for 8
incorporation into processes and procedures.9
Table 2-3 provides the timeline for the outage execution 10
process.11
2-22
TABLE 2-3OUTAGE EXECUTION PROCESS
Steps Timing Process Description
1. Prior to Outage Start Date
An Application for Work (AFW) covering the planned outage is submitted to the STES organization’s Outage Coordinator. Once the AFW has been reviewed and approved internally, it is submitted to the CAISO through the Scheduling and Logging ISO California (SLIC) system for preliminary approval.Switching Center Operators write detailed step-by-step switching logs for clearing the units. These logs detail all the clearance points for the outage and the tasks that need to be performed, and the order in which they must be performed, to make the unit or facility safe for outage work to begin.
2. Outage Start Date The STES organization’s Real-Time Desk, working off the list of preliminary approved outages, contacts the CAISO for final approval that the unit can be separated from the grid and communicates that approval to the Switching Center Operators.Once approval has been obtained, an operator, working in concert with the Switching Center, executes the steps in the Switching Log to clear the unit or facility.
3. During the Outage PG&E employees and/or contractor resources are utilized to execute the prioritized maintenance work and any project work in accordance with the outage plan and in compliance with PG&E standards.Emerging work that is identified during the outage is evaluated and prioritized against other ongoing work. If it is determined that the emerging work must be completed during the current outage, the work is added to the outage plan. Adding emergent work to the outage plan is often necessary to prevent a future forced outage. If emerging work requires an outage extension, approval of the Hydro O&M Director is required. Notification of an outage extension is communicated to the CAISO through the SLIC system.Both the Switching Log for restoring the unit and a start-upprocedure, covering all the requirements for testing newly installed equipment, are written.
4. Return to Service Date
When all outage work has been completed, the process of restoring the unit to service begins. This entails a series of standard unit tests that must be performed before the unit can be released for service and a start-up procedure if there is newly installed equipment. Once complete, an operator, working in concert with the Switching Center, executes the steps in the Switching Log to restore the unit to service.
The Switching Center Operators contact the Real-Time Desk when the unit has been restored and the Real-Time Desk notifies the CAISO through the SLIC system that the unit has been restored to service.At the completion of the outage, the information gathered while performing the maintenance work during the outage is utilized to update maintenance libraries in SAP WM and refine the details and timing of future maintenance tasks.
2-23
The three processes detailed above are highly interrelated. 1
Outage scheduling is dependent on planning and scoping. As the 2
defined outage scope changes, the outage schedule is continuously 3
reviewed and updated based on that changed scope. Conversely, if 4
outside influences require the outage timing or duration to change, 5
the scope of work is reviewed and adjusted to fit the revised 6
timeframe. During outage execution, emerging work may require an 7
outage extension, which could, in turn, impact the planning and 8
scheduling of outages on other units or facilities.9
g. Project Management Process10
Project work is controlled through the project management process. 11
Each project has an assigned Project Manager who has responsibility 12
for the project scope, cost and schedule, and who coordinates and 13
manages the project from inception to closeout. Project management 14
procedures and tools are in place to provide Power Generation project 15
managers and job leaders guidelines for successfully achieving the 16
project objective of each project they manage. These procedures are 17
intended to be applicable to all types, sizes and phases of Power 18
Generation projects, and are anticipated to improve the consistency and 19
quality of project management throughout Power Generation. Project 20
Managers are responsible for regular project reporting to management.21
h. Design Change Process22
Design changes are controlled through the design change process. 23
The design change process is the process for proposing, evaluating, 24
and implementing changes to the design of structures, systems, and 25
equipment at PG&E’s hydro-generating facilities. It includes the process 26
for requesting design changes; reviewing and approving design change27
requests; implementing design changes; closing out design changes; 28
and revising design change notices.29
D. Operational Results30
PG&E operates its diverse hydro system as a portfolio. The following 31
section discusses the operational results for the hydro portfolio. The operational 32
2-24
results achieved by PG&E’s hydro portfolio demonstrate that PG&E’s hydro 1
resources were operated in a reasonable manner during the record period.2
1. Energy Production3
The energy production at hydro generation facilities is dependent on the4
available water supplies in any given year. Just as natural gas is fuel for a 5
fossil fuel generating station, water from precipitation, snowmelt, and aquifer 6
outflows is the fuel for hydro-generating facilities. The hydro fuel supply in 7
any given year is dependent on several factors including meteorological 8
conditions in the current year, snowpack, aquifer outflows during the year, 9
the amount of water storage carryover in reservoirs from the previous year 10
and FERC license conditions. The changing meteorological conditions each 11
year and the ongoing changes in aquifer outflows result in a yearly variation 12
in the fuel supply that directly impacts the energy output each year.13
As FERC-jurisdictional hydro projects, many of PG&E’s projects have 14
recently completed relicensing efforts, where the operation of the project 15
must adhere to increasingly strict and complex license requirements that 16
seek to balance the many beneficial uses of the water resource. To respond 17
to these mandated demands on the water resources (such as stream flows 18
for fish, frogs and other species, recreation (including white water rafting), 19
consumptive water uses, and other purposes), some of the hydro fuel 20
bypasses the generating assets and is lost for the production of energy.21
PG&E’s hydro generating assets produced significant amounts of 22
electricity during the 2017 record period. The total generation for the 23
portfolio for the 2017 record year was 10,578 gigawatt-hours (GWh) of 24
energy, which is a 32 percent increase to the 2016 production of 8,016 GWh25
of energy. The main drivers for the energy increase include an increase in 26
statewide April 1 snowpack to 163 percent of average (in terms of water 27
content), from 86 percent of average in 2016,2 and an increase in 28
2 April 1 has historically been considered the time of peak snow accumulation in the season. Percentages are based on snow sensor data, with 94 stations reporting statewide.
2-25
precipitation to 187 percent of the 30-year average precipitation, from 1
114 percent in the 2016 water year.32
The generation production results for 2017 underscore the fact that data 3
for any single year should not be viewed alone, but rather should be 4
considered in light of the hydro-meteorological conditions during the year. 5
The biggest driver of generation in any given year is directly related to the 6
quality of the water year as well as the snowpack.7
2. Outages8
Consistent with previous Energy Resource Recovery Account 9
compliance proceedings, PG&E is providing general information regarding 10
scheduled outages that were 24 hours or more in duration, and specific 11
information regarding each forced outage that was longer than 24 hours in 12
duration, for facilities that are 25 MW or greater in size. PG&E has provided 13
additional, detailed information concerning the outages that occurred during 14
the record period to the Office of Ratepayer Advocates (ORA) in response to 15
ORA’s Master Data Request.16
One of the key industry metrics used to gauge the operating 17
performance of generating units is the Forced Outage Factor (FOF). FOF is 18
a ratio of the hours a unit is forced out of operation to the total hours in the 19
operation period (i.e., month, year). The high number of storm-related 20
forced outages related to extreme precipitation events in January and 21
February of 2017 raised the hydro portfolio 2017 FOF to 6.90 percent, worse 22
than the industry benchmark of 3.08 percent.4 Table 2-4 includes the hydro 23
portfolio FOF for the past five years compared to the latest industry 24
benchmark.5 Excluding storm-related outages, the hydro portfolio 25
2017 FOF was 1.86 percent, significantly better than the benchmark.26
3 Percentages are based on PG&E’s 15-station precipitation year index. A water year is designated by the calendar year in which it ends. The 2017 water year ran from July 1, 2016 to June 30, 2017. Previous years follow the same logic.
4 The industry benchmark is the 2012-2016 NERC GADS Generating Unit Statistical Brochure 4. The brochure and derivation of the forced outage benchmark is included in PG&E’s workpapers.
5 The combined hydro and fossil portfolio 2017 FOF was 5.38 percent, worse than the combined hydro and fossil industry benchmark of 2.77 percent. Excluding storm-related outages, the combined portfolio 2017 FOF was 1.55 percent, better than the industry benchmark.
The winter of 2016-17 was one of the wettest on record in 15
Northern California. As of March 2, 2017, the precipitation gauges16
located throughout PG&E-managed hydro territories averaged 17
221.3 percent of normal for that date. Snowpack, based on 18
98 reporting automated snow sensors, had water equivalent/content 19
readings of 183 percent of normal Statewide, 157 percent of normal 20
for the north Sierra, 190 percent of normal for the central Sierra, and 21
200 percent of normal for the southern Sierra.22
There were two periods during the winter when precipitation 23
intensities brought excessive amounts over short periods of time. 24
These included:25
1) January 4, 2017 – January 11, 2017: 24 inches compared to 26
the 4 inches precipitation historical average during the same 27
8-day period (PG&E hydro weighted precipitation at 28
15 representative stations).29
2) February 1, 2017 – February 10, 2017: 28 inches compared to 30
the 5 inches precipitation historical average during the same 31
10-day period (PG&E hydro weighted precipitation at 32
15 representative stations).33
2-28
The extreme precipitation events in the winter of 2016-2017 led 1
to high water flows, debris flows, and turbidity on a number of 2
PG&E’s river systems, resulting in numerous landslides, road 3
failures, and 58 forced outages with durations longer than 24 hours 4
at powerhouses with a capacity of 25 MW or greater. A detailed 5
description of these storm-related forced outages is included in 6
powerhouse alphabetical order below.7
a) Bucks Creek Powerhouse8
On January 9, 2017, at 9:10 a.m., Unit 2 was forced out of 9
service due to low bearing cooling water flows. Unit 1 was 10
forced out of service for the same reason at 10:22 a.m. The 11
bearing cooling water intake is covered by a screen to prevent 12
large material from being pumped into the system. Inside the 13
powerhouse, a strainer system removes any smaller material. 14
The strainer system is manually cleaned by PG&E operators. 15
This cooling water system was overwhelmed by the high 16
turbidity levels of the Feather River, resulting in debris building 17
up at the strainer faster than the operator could remove it. High 18
runoff from early January storms caused numerous upstream 19
landslides, significantly raising the turbidity level of the water. 20
PG&E cleaned the intake screen and strainers and returned 21
Unit 2 to service on January 10, 2017, at 3:33 p.m. Unit 1 was 22
returned to service at 8:56 p.m. on January 10, 2017.23
On January 10, 2017, at 8:59 p.m., Unit 2 was again forced 24
out of service due to low bearing cooling water flows. A PG&E 25
operator manually cleaned the cooling water strainers but the 26
strainers clogged again right away when the cooling water 27
system was restarted. Once the river flows receded around 28
January 15, the cooling water pit was exposed and PG&E 29
discovered that the cooling water pit was filled with sediment. 30
On January 17, a PG&E crew was onsite to remove sediment 31
from the cooling water pit and trough, clean sediment from the 32
cooling water pressure regulating valve, and flush the unit 33
2-29
bearing cooling water piping. PG&E completed these activities 1
on January 18, 2017, returning the unit to service at 4:52 p.m.2
On January 17, 2017, at 11:38 a.m., Unit 1 was forced out3
of service to clean the bearing cooling water system. A PG&E 4
crew was onsite to remove sediment from the cooling water pit 5
and trough, clean sediment from the cooling water pressure 6
regulating valve, and flush the unit bearing cooling water piping. 7
PG&E completed the activities on January 18, 2017, returning 8
the unit to service at 4:49 p.m.9
On February 7, 2017, at 10:46 a.m., Unit 1 was removed 10
from service due to low bearing cooling water flows caused by 11
the February storm event. Unit 2 was removed from service at 12
10:47 a.m. for the same reason. High flows in the North Fork 13
Feather River deposited significant sediment in the powerhouse 14
cooling water pit and trough. The sediment in the trough was 15
clogging the unit cooling water system. On February 12, the 16
river flows had receded and the pit and trough located in the 17
tailrace of the powerhouse became accessible. A PG&E crew 18
was onsite to remove sediment from the cooling water pit and 19
trough, clean sediment from the cooling water pressure 20
regulating valve, and flush the unit bearing cooling water piping. 21
PG&E completed these activities on February 15, 2017, 22
returning Unit 1 to service at 2:58 p.m. and Unit 2 to service 23
at 3:01 p.m.24
On February 17, 2017, at 1:01 a.m., Unit 2 tripped offline 25
due to an alarm at the penstock shutoff valve (PSV) that 26
indicated it was drifting to a closed position. The roving 27
operator reported the issue that day, but crews were not 28
dispatched to the valve house until the weather permitted on 29
February 22. Under normal conditions, this outage would be 30
expected to be resolved by the end of the working day. As a 31
result, PG&E separated the cause of the outage into two parts, 32
the first being due to the penstock shutoff valve and the second 33
due to storm conditions. The storm condition portion of the 34
2-30
outage is marked as having begun on February 17, 2017, at 1
5:30 p.m., at the end of the crew shift. PG&E was able to reach 2
the valve house on February 22, replace the PSV position 3
switches, and return the unit to service at 7:02 p.m.4
On February 20, 2017, at 7:14 a.m., Unit 1 tripped offline 5
due to an alarm at the PSV that indicated it was drifting to a 6
closed position. The roving operator reported the issue that 7
day, but crews were not dispatched to the valve house until the 8
weather permitted on February 22. Under normal conditions, 9
this outage would be expected to be resolved by the end of the 10
working day. As a result, PG&E separated the cause of the 11
outage into two parts, the first being due to the penstock shutoff 12
valve and the second due to storm conditions. The storm 13
condition portion of the outage is marked as having begun on 14
February 20, 2017, at 5:30 p.m., at the end of the crew shift. 15
PG&E was able to reach the valve house on February 22, 16
replace the PSV position switches, and return the unit to service 17
at 7:01 p.m.18
b) Butt Valley Powerhouse19
On January 8, 2017, at 12:43 p.m., the Butt Valley unit was 20
forced offline due to a fault on the 115 kV Caribou/Palermo 21
transmission line. Storm conditions had caused trees to make 22
contact with the line. The trees were cleared and the line was 23
restored to service. PG&E tested and returned the unit to 24
service on January 14, 2017 at 5:14 p.m.25
c) Caribou 1 Powerhouse 26
On January 8, 2017, at 5:15 p.m., Units 1 through 3 were 27
unavailable due to a trip in the 115 kV Caribou/Palermo 28
transmission line. Storm conditions had caused trees to make 29
contact with the line. The trees were cleared and the line was 30
restored to service. The units were all returned to service on 31
January 9, 2017 at 5:36 p.m.32
2-31
d) Caribou 2 Powerhouse 1
On January 8, 2017, at 5:15 p.m., Units 4 and 5 were 2
unavailable due to a trip in the 230 kV Caribou/Table Mountain 3
transmission line. Storm conditions had caused trees to make 4
contact with the line. The trees were cleared and the line was 5
restored to service. Unit 4 was returned to service on 6
January 13, 2017 at 7:02 a.m. and Unit 5 was returned to 7
service on January 13, 2017 at 9:04 a.m.8
e) Cresta Powerhouse9
On January 8, 2017, at 2:13 p.m., Units 1 and 2 were forced 10
out of service due to high flows caused by early January storms. 11
At the time, North Fork Feather River flows exceeded 12
30,000 cubic feet per second (cfs), as measured downstream of 13
Cresta Dam at NF-56. The units and dam were removed from 14
service to prevent damage to the facilities during high river 15
flows, consistent with the DeSabla Hydro Winter Storm16
procedure.7 The procedure requires that the powerhouse 17
facility be shut down if flows exceed 30,000 cfs at NF-56. 18
Following the receding of river flows, Unit 1 was returned to 19
service on January 13, 2017 at 11:05 a.m. and Unit 2 was 20
returned to service at 11:12 a.m. 21
On February 7, 2017, at 7:52 a.m., Units 1 and 2 were 22
removed from service due to high flows caused by early 23
February storms. At the time, North Fork Feather River flows 24
exceeded 30,000 cfs, as measured downstream of Cresta Dam 25
at NF-56. The units and dam were removed from service to 26
prevent damage to the facilities during high river flows, 27
consistent with the DeSabla Hydro Winter Storm procedure. 28
The procedure requires that the powerhouse facility be shut 29
down if flows exceed 30,000 cfs at NF-56. Following the 30
receding of river flows, Unit 1 was returned to service on 31
7 DeSabla Hydro Winter Storm Procedures 2016-2017 is provided in PG&E’s workpapers.
2-32
February 13, 2017 at 1:52 p.m. and Unit 2 was returned to 1
service at 1:54 p.m.2
f) Electra Powerhouse3
On January 8, 2017, at 7:21 p.m., Unit 1 was removed from 4
service due to high flows caused by early January storms. 5
Units 2 and 3 were removed from service at 7:25 p.m. for the 6
same reason. The units were shut down when the river 7
elevation exceeded the tailrace wall elevation to prevent high 8
river water levels from flooding the galleries. Following the 9
receding of the water, PG&E found the tailrace was filled with 10
sediment that needed to be removed prior to return to service.11
PG&E removed the sediment and returned Unit 1 to service on 12
January 23, 2017 at 4:18 p.m., returned Unit 2 to service at 13
4:27 p.m., and returned Unit 3 to service at 4:35 p.m.14
g) James B. Black Powerhouse15
On February 6, 2017, at 6:10 p.m., Unit 1 tripped offline due 16
to a transmission line outage. At 6:17 p.m., the transmission 17
line was restored to service, but the unit remained offline. High 18
runoff from the early February storms caused landslides on both 19
of the access roads to the powerhouse, preventing PG&E 20
operators from accessing the powerhouse and returning the unit 21
to service. The landslides prevented access to the powerhouse 22
until February 10. PG&E operators returned the unit to service 23
on February 10, 2017 at 10:36 a.m.24
h) Kerckhoff 1 Powerhouse25
On February 7, 2017, at 5:24 p.m., Units 1 and 3 were 26
removed from service due to high flows caused by early 27
February storms. The units were removed from service to 28
prevent damage to the facilities during high river flows, 29
consistent with the San Joaquin Watershed Common Operating 30
2-33
Guideline.8 Following the receding of river flows, the units were 1
brought online on February 13, 2017 at 12 p.m.2
On February 19, 2017, at 6:36 p.m., Units 1 and 3 were 3
removed from service due to low bearing cooling water flows. 4
Cooling water provided via the penstock contained significant 5
amounts of debris due to the February storms, which constantly 6
clogged the cooling water strainer. As a result, PG&E operators 7
were not able to keep up with cleaning the strainers. Following 8
abatement of storm conditions, Unit 1 was returned to service 9
on February 24, 2017 at 12:15 p.m. and Unit 3 was returned to 10
service at 12:33 p.m.11
i) Kerckhoff 2 Powerhouse12
On January 10, 2017, at 3:56 p.m., Unit 1 was removed 13
from service due to low bearing cooling water flows. Cooling14
water provided via the penstock contained significant amounts 15
of debris due to the January storms, which constantly clogged 16
the cooling water strainer. As a result, PG&E operators were 17
not able to keep up with cleaning the strainers. Following 18
abatement of storm conditions, the units were brought online the 19
next day at 4:08 p.m.20
On February 7, 2017, at 4:13 p.m., Unit 1 was removed 21
from service due to high flows caused by the early February 22
storms. The unit was removed from service to prevent damage 23
to the facilities during high river flows, consistent with the San 24
Joaquin Watershed Common Operating Guideline. Following 25
the receding of river flows, the unit was brought online on 26
February 13, 2017 at 1:08 p.m.27
j) Pit 5 Powerhouse28
The early January and February weather events caused 29
extremely high water in the Pit River watershed that resulted in 30
numerous landslides, road failures, and inundation of the Pit 531
8 San Joaquin Watershed Common Operating Guideline is provided in PG&E’s workpapers.
2-34
Powerhouse. These conditions caused a number of forced 1
outages on the powerhouses located in the Pit River, which are 2
described below.3
On January 18, 2017, at 7:09 p.m., Units 3 and 4 were 4
forced out of service due to an elevated reading on the neutral 5
overvoltage relay. The neutral overvoltage relay detects a 6
ground fault on a generator and is part of the stator ground fault 7
protection scheme. Upon detection of a ground fault, the relay 8
activates the 86E lockout relay, tripping the units to prevent any 9
electrical damage. 10
An ice dam had formed on the roof of the powerhouse due 11
to heavy snow. During the early January storms, high runoff led 12
to high water levels which overtopped the roof, causing water to 13
leak into the common bus duct works and eventually trip the 14
units offline. PG&E removed the ice dam and replaced the 15
cracked insulators on the copper bus penetration through the 16
wall. Unit 3 was returned to service on January 28, 2017 at 17
7:14 p.m. Unit 4 was returned to service on January 30, 2017 at 18
5:24 p.m.19
On February 4, 2017, Pit 5 Powerhouse was ordered to be 20
evacuated due to numerous landslides both above and below 21
the access road, caused by high runoff from early February 22
storms. The Pit 5 operators were relocated to the Pit 323
Switching Center, where a backup operating system had been 24
installed to allow remote control and monitoring of the various 25
powerhouses and facilities under the Pit 5 Switching Center’s26
jurisdiction. The Pit 5 access road became impassable on 27
February 5 due to multiple landslides. The four units at Pit 528
Powerhouse remained operational at the time of the evacuation.29
On February 6, 2017, at 7:34 p.m., Unit 1 was forced out of 30
service due to low bearing cooling water flows. The bearing 31
cooling water intake is located in the tailrace sump for the unit. 32
A screen around the pump intake prevents large material from 33
being pumped into the system. Inside the powerhouse, a 34
2-35
strainer system removes any smaller material. This cooling 1
water system was overwhelmed by the high turbidity levels of 2
the Pit River. High runoff from the February storms caused 3
numerous upstream landslides, raising the turbidity level of the 4
water. The unit was out of service when the Pit 5 powerhouse 5
flooded on February 9, as described below.6
On February 9, 2017 at 12:19 p.m., 12:29 p.m., and 7
12:34 p.m. respectively, Units 2, 3 and 4 were forced out of 8
service due to powerhouse flooding. Unit 1 was already out of 9
service, as explained above. The flooding occurred due to 10
record-setting precipitation.11
At its peak on February 9, the atmospheric river event912
reached 5.19 inches of precipitation in 24 hours. River flows 13
exceeded 36,000 cfs, as measured at gauging station PH-27, 14
causing significant accumulation of gravel debris at and 15
downstream of the powerhouse and resulting in increased river 16
elevations at the powerhouse. The river elevation at Pit 517
Powerhouse is estimated to have reached an all-time high 18
elevation of 1457.3 feet, reaching to near the ceiling level of the 19
basement. For reference, the historical maximum recorded 20
flood elevation at the powerhouse had been 1442 feet.21
PG&E completed an Apparent Cause Evaluation (ACE) of 22
the Pit 5 powerhouse flooding in October 2017.10 Per the 23
powerhouse engineering design drawing,11 flows were 24
expected to have to reach about 75,000 cfs for the tailrace 25
9 Per the National Oceanic and Atmospheric Administration (NOAA), “atmospheric rivers are relatively long, narrow regions in the atmosphere—like rivers in the sky—that transport most of the water vapor outside of the tropics. When atmospheric rivers make landfall, they often release this water vapor in the form of rain or snow. Those that contain the largest amounts of water vapor and the strongest winds can create extremerainfall and floods, often by stalling over watersheds vulnerable to flooding. On average, about 30-50% of annual precipitation in the west coast states occurs in just a few atmospheric river events.” (http://www.noaa.gov/stories/what-are-atmospheric-rivers).
10 Pit 5 Storm Damage ACE is provided in PG&E’s workpapers.11 Attachment 8 to the Pit 5 Storm Damage ACE contains an image of the original drawing
print of the powerhouse cross section featuring elevations and design water levels.
2-36
water level to rise to 1457.3 feet. However, the massive volume 1
of debris carried by the river accumulated in the tailrace section, 2
which significantly raised tailrace water levels above the design 3
levels for a given flow rate.12 The powerhouse has multiple 4
potential sources of water intrusion at elevation 1453.4 feet, via 5
multiple basement floor penetrations that are open and vent to 6
the atmosphere, as well as the #3 ejector piping discharge line. 7
When the river level exceeded this elevation on its way to a 8
maximum elevation of 1457.3 feet, the powerhouse began 9
flooding.10
The corrective actions detailed in the Pit 5 Storm Damage 11
ACE include:12
Complete dredging project to mitigate debris accumulation 13
at Pit 5 powerhouse.14
Evaluate other hydro facilities to identify where a similar 15
event could occur.16
Complete repairs to Pit 5 access roads to include larger 17
diameter culverts.18
Perform an engineering evaluation on the building 19
penetration leakage and structure seepage. This should 20
include an evaluation of the basement floor penetrations 21
and their intended purpose and if the current elevation of 22
the piping is appropriate for expected external water levels. 23
This should also include an evaluation of the leakage 24
around the penstock and other bulkhead penetrations.25
Perform an engineering evaluation on ejector system design 26
criteria and whether this system should have additional 27
engineering controls such as a check valve to mitigate 28
backflow potential.29
Evaluate hydro facilities with similar system configurations 30
with piping open to the tailrace and no backflow restriction, 31
12 Attachment 3 to the Pit 5 Storm Damage ACE contains a photograph showing the large volume of material deposited in the tailrace area.
2-37
and whether the systems should have additional 1
engineering controls such as a check valve to mitigate 2
backflow potential.3
Restoration of the powerhouse required major efforts in 4
road clearing and rebuilding, tailrace dredging and clearing out 5
the mud and debris that accumulated inside the flooded 6
powerhouse.7
The geology above the powerhouse and along the 8
seven miles of access road from Big Bend Road to the 9
powerhouse has historically been susceptible to landslides due 10
to the colluvium makeup. Snow accumulation from 11
January 2017 storms combined with historic rainfall caused 12
accelerated snow melt and led to multiple landslides as well as 13
road washouts on the Pit 5 Powerhouse and Pit 5 Valve House 14
Roads. Several locations along the roads failed, preventing 15
access to the Pit 5 Powerhouse, Pit 5 Valve House and 16
James B. Black Powerhouse. As a first step, PG&E removed 17
debris, and cleared and reestablished ditches and drainage 18
improvements to allow construction crews to safely access the 19
road sites and begin road reconstruction work. Road 20
reconstruction included construction of slope stability 21
improvements such as rock slope protection, mechanically 22
stabilized earth, and concrete or soldier pile walls depending on 23
location. PG&E replaced washed out culvert crossings for 24
drainages and creek crossings, and restored a section of slope 25
that had failed between the surge chamber access road and 26
valve house access road.27
In addition to the material deposited in the tailrace by the 28
storm, the extended powerhouse outage also led to additional 29
material build-up throughout the spring as higher flows 30
continued to deposit material that would normally be transported 31
downriver if the powerhouse units were online. PG&E 32
estimated that over 100,000 cubic yards of material needed to 33
be dredged, starting from the tailrace, and extending 34
2-38
approximately 1,000 feet downstream of the powerhouse. The 1
additional material needed to be dredged to allow for unit 2
operation. Material also needed to be removed from the stoplog 3
gates and draft tubes before unit operation could be restored.4
PG&E initiated powerhouse restoration efforts by pumping 5
out the water in the powerhouse, cleaning the station and 6
disposing of all contaminated material. About 800 gallons of oil 7
was stored at or below the flooded sub-basement and basement 8
levels of the powerhouse. The flooding damaged the turbine 9
shut-off valve control panels, cooling water control panels, 10
elevated neutral transformers, and station distribution and 11
lighting. PG&E replaced all of that equipment and refurbished 12
the turbine pit mechanical assemblies. In the turbine pit are all 13
the wicket gate assemblies, the top of the head cover and the 14
turbine guide bearing. The turbine guide bearing and lubrication 15
systems were dismantled, purged, flushed and inspected. All of 16
the mechanical assemblies that operate the wicket gates were 17
dismantled to allow the upper wicket bushings to be removed, 18
cleaned, inspected, and re-installed. Various bolts, studs and 19
nuts on the gate assemblies, head covers, draft tubes and gland 20
rings were all cleaned and greased to mitigate corrosion. Any 21
packing exposed to flood waters and contaminated sediment 22
was replaced to mitigate scoring of any rotating or sliding shafts.23
Unit 1 was returned to service on October 5, 2017 at 24
9:41 p.m. Unit 2 was returned to service on November 4, 2017 25
at 2:49 p.m. Unit 3 was returned to service on December 13, 26
2017 at 5:27 p.m. Unit 4 remained on forced outage at the end 27
of the Reporting Period and was returned to service on 28
January 5, 2018 at 4:25 p.m.29
On November 10, 2017, at 8:31 a.m., Unit 2 was forced out 30
of service as part of flood restoration efforts to restore damage 31
caused by the January and February 2017 storms. The unit 32
was forced out of service to allow divers to enter the tailrace to 33
clear debris and seal stop log gates in the Unit 3 draft tube. 34
2-39
Following completion of this activity, Unit 2 was returned to 1
service on November 12, 2017 at 4:40 p.m.2
k) Pit 6 Powerhouse3
On February 10, 2017, at 10:36 a.m., Units 1 and 2 were 4
forced out of service due to concerns about excessive5
storm-related woody debris accumulating at the powerhouse. 6
On January 8, the Pit 6 access road was heavily damaged 7
by a landslide. Access to the facility was limited to foot access 8
around the slide area. During the January and February storms, 9
the powerhouse had to be manned 24/7 to keep the bearing 10
cooling water intake screens clean. During the early February 11
storms, numerous landslides occurred on the Pit River upstream 12
of Pit 6 Powerhouse. These landslides caused numerous whole 13
trees to enter the river and collect at the log boom at the Pit 614
forebay. The log boom eventually failed on February 9 due to 15
the pressure applied by the trees. PG&E evacuated the 16
operator from Pit 6, forced the units out of service, and fully 17
opened the spillway gates to pass the trees downstream without 18
clogging the spillway. 19
Following water level abatement, Unit 2 was returned to 20
service on February 25, 2017 at 4:52 a.m. While attempting to 21
return Unit 1 to service in late February, PG&E discovered a 22
broken shear pin on one of the wicket gates. The wicket gates 23
control the flow of water to the turbine. Each wicket gate is 24
hinged using a shear pin that is designed to shear or break to 25
prevent damage if there is woody debris caught in the wicket 26
gate while it is closed. PG&E replaced the shear pin and 27
returned Unit 1 to service on March 2, 2017 at 6:14 p.m.28
On February 25, 2017, at 11:55 a.m., following an outage 29
on the 12-kV overhead line leading to transformer bank 3, Unit 230
was separated from the grid. The line outage was caused by a 31
tree falling on the line due to storm conditions. Unit 2 is set to 32
automatically black start and auto-parallel to the system if the 33
12-kV line fails. After the 12-kV line failed and Unit 2 started, it 34
2-40
was separated from the 230-kV transmission line to provide 1
power in-house until the 12-kV overhead line was returned to 2
service. PG&E’s electrical operations returned the overhead 3
line to service and Unit 2 was returned to service on February 4
27, 2017 at 10:50 a.m.5
l) Pit 7 Powerhouse6
On February 10, 2017, at 11:06 a.m., Unit 1 was forced out 7
of service due to concerns about excessive storm-related woody 8
debris accumulating at the powerhouse. Unit 2 was forced out 9
at 11:09 a.m. for the same reason. Similar to Pit 6, numerous 10
landslides occurred on the Pit River upstream of the Pit 711
Powerhouse during the early February storm. These landslides 12
caused numerous whole trees to enter the river and collect at 13
the log boom at the Pit 6 forebay. As described above, the Pit 614
log boom eventually failed on February 9 due to the pressure 15
applied by the trees. The Pit 7 log boom also failed due to the 16
pressure applied by the trees. PG&E forced the Pit 7 units out 17
of service, and fully opened the spillway gates to pass the trees 18
downstream without clogging the spillway. Following water level 19
abatement, Unit 2 was returned to service on February 28, 2017 20
at 11:40 a.m. Unit 1 was returned to service on March 1, 2017 21
at 6:05 p.m.22
m) Poe Powerhouse23
On January 8, 2017, at 3:50 p.m., Unit 1 was removed from 24
service due to high flows caused by the early January storms. 25
Unit 2 was removed from service at 3:52 p.m. for the same 26
reason. At the time, North Fork Feather River flows exceeded 27
45,000 cfs, as measured downstream of Poe Dam at NF-23. 28
The units and dam were removed from service to prevent 29
damage to the facilities during high river flows, consistent with 30
the DeSabla Hydro Winter Storm procedure. The procedure 31
requires that the powerhouse facility be shut down if flows 32
exceed 45,000 cfs at NF-23. Following the receding of river 33
2-41
flows, Unit 1 was returned to service on January 15, 2017 at 1
9:48 a.m. and Unit 2 was returned to service at 9:53 a.m.2
On February 7, 2017, at 7:40 a.m., Unit 1 was removed 3
from service due to high flows caused by the early February 4
storms. Unit 2 was removed from service at 7:42 a.m. for the 5
same reason. At the time, North Fork Feather River flows 6
exceeded 45,000 cfs, as measured downstream of Poe Dam at 7
NF-23. The units and dam were removed from service to 8
prevent damage to the facilities during high river flows, 9
consistent with the DeSabla Hydro Winter Storm procedure.10
The procedure requires that the powerhouse facility be shut 11
down if flows exceed 45,000 cfs at NF-23. Following the 12
receding of river flows, Unit 1 was returned to service on 13
February 18, 2017 at 8:40 a.m. and Unit 2 was returned to 14
service at 8:44 a.m.15
On February 21, 2017, at 12:33 a.m., Unit 2 was removed 16
from service due to low bearing cooling water flows. Unit 1 was 17
removed from service at 12:36 a.m. for the same reason. The 18
bearing cooling water intake is covered by a screen to prevent 19
large material from being pumped into the system. Inside the 20
powerhouse, a strainer system removes any smaller material. 21
For Poe, the strainer system includes both auto strainer and 22
manual strainer lines. The auto strainers feature backflush 23
valves designed to keep the line from plugging with debris.24
Both lines were overwhelmed by the high turbidity levels of the 25
Feather River, resulting in debris building up at the strainer 26
faster than the system could remove it. On February 24, the 27
flows had receded in the river and the debris in the water had 28
reduced to the point where the cooling water strainers could 29
reliably clean the water for the bearing cooling system. Unit 130
was returned to service on February 24, 2017 at 10:27 a.m. and 31
Unit 2 was returned to service at 10:31 a.m.32
2-42
n) Rock Creek Powerhouse1
On January 8, 2017, at 5:55 p.m., Unit 1 was removed from 2
service due to high flows caused by early January storms. 3
Unit 2 was removed from service at 5:58 p.m. for the same 4
reason. At the time, North Fork Feather River flows exceeded 5
30,000 cfs, as measured downstream of Rock Creek Dam at 6
NF-57. The units and dam were removed from service to 7
prevent damage to the facilities during high river flows, 8
consistent with the DeSabla Hydro Winter Storm procedure.9
The procedure requires that the powerhouse facility be shut 10
down if flows exceed 30,000 cfs at NF-57. Following the 11
receding of river flows, Unit 1 was returned to service on 12
January 12, 2017 at 6:59 p.m. and Unit 2 was returned to 13
service at 7:19 p.m.14
On February 7, 2017, at 9:02 a.m., Unit 1 was removed 15
from service due to high flows caused by early February storms. 16
Unit 2 was removed from service at 9:04 p.m. for the same 17
reason. At the time, North Fork Feather River flows exceeded 18
30,000 cfs, as measured downstream of Rock Creek Dam at 19
NF-57. The units and dam were removed from service to 20
prevent damage to the facilities during high river flows, 21
consistent with the DeSabla Hydro Winter Storm procedure. 22
The procedure requires that the powerhouse facility be shut 23
down if flows exceed 30,000 cfs at NF-57. Following the 24
receding of river flows, Unit 1 was returned to service on25
February 13, 2017 at 11:29 a.m. and Unit 2 was returned to 26
service at 7:02 p.m.27
o) Salt Springs Powerhouse28
On February 8, 2017, at 6:29 p.m., Units 1 and 2 were 29
removed from service at the request of PG&E’s transmission 30
line of business. A transmission tower on the 115-kV line 31
slipped on its foundation due to a mudslide related to the 32
February storm events. PG&E repaired the tower and Unit 133
2-43
was returned to service on February 11, 2017 at 3:37 p.m. 1
Unit 2 was returned to service at 3:40 p.m. the same day.2
p) Stanislaus Powerhouse3
On January 5, 2017, at 6:00 a.m., Unit 1 was removed from 4
service due to low bearing cooling water flows. The bearing 5
cooling water intake is covered by a screen to prevent large 6
material from being pumped into the system. Inside the 7
powerhouse, a strainer system removes any smaller material. 8
The strainer system is manually cleaned by PG&E operators. 9
This cooling water system was overwhelmed by the high 10
turbidity levels of the Stanislaus River, resulting in debris 11
building up at the strainer faster than the operator could remove 12
it. High runoff from early January storms caused numerous 13
upstream landslides, raising the turbidity level of the water. 14
PG&E cleaned the intake screen and strainers and returned the 15
unit to service on January 9, 2017 at 10:34 a.m.16
On January 9, 2017, at 3:11 p.m., Unit 1 was removed from 17
service due to low bearing cooling water flows. High runoff from 18
early January storms caused numerous upstream landslides, 19
raising the turbidity level of the water. PG&E cleaned the intake 20
screen and strainers and returned the unit to service on 21
January 13, 2017 at 9:56 a.m.22
On February 20, 2017, at 9:44 a.m., Unit 1 was removed 23
from service due to low bearing cooling water flows. High runoff 24
from February storms caused numerous upstream landslides, 25
raising the turbidity level of the water. PG&E cleaned the intake 26
screen and strainers and returned the unit to service on 27
February 22, 2017 at 1:48 p.m.28
On February 23, 2017, at 10:04 a.m., Unit 1 was removed 29
from service due to low bearing cooling water flows. High runoff 30
from February storms caused numerous upstream landslides, 31
raising the turbidity level of the water. PG&E cleaned the intake 32
screen and strainers and returned the unit to service on 33
February 27, 2017 at 10:47 a.m.34
2-44
q) Tiger Creek Powerhouse1
On February 7, 2017, at 10:39 a.m., Unit 2 was removed 2
from service due to a large mudslide occurring in the forebay 3
canal during the early February storms. Access to the 4
powerhouse was restricted because the powerhouse and5
afterbay dam access roads were damaged by landslides and 6
overflows of the drainage facilities during the same February 7
storms. The storms also damaged 300 feet of canal foundation. 8
Both road repair work and canal repair work were required in 9
order to return the unit to service. 10
Road repair work included upper slope excavation (move 11
roadway inward), lower slope excavation (remove and replace 12
saturated road subbase), installation of rock rip-rap revetment 13
on the shoulder of the road, and installation of gabion walls 14
where more suitable. Various sites required removal and 15
replacement of asphalt concrete (pavement) surface. Canal 16
repair work included removal of mudslide debris, drainage 17
improvements, installation of a reinforced concrete retaining wall 18
and slope erosion control measures including rock revetments. 19
The unit was returned to service on April 10, 2017 at 9:25 a.m.20
On February 13, 2017, at 9:40 a.m., Unit 1 was removed 21
from service to allow repair of the forebay canal. Between 22
February 7, when Unit 2 was removed from service, and 23
February 13, partial canal flow was available and deemed 24
necessary to allow debris to be transported downstream. The 25
flow was routed through Unit 1 during this time period. 26
Following partial repair of the canal, Unit 2 was returned to 27
operation, again utilizing partial canal flow. Unit 1 remained out 28
of service for the duration of the canal repair work because the 29
canal could not support the flow required to operate both units. 30
When the canal restoration work was completed, Unit 1 was 31
returned to service on June 1, 2017 at 9:25 a.m.32
2-45
2) Forced Outages Unrelated to the January-February Winter 1
Storms2
A detailed description of the 27 forced outages not related to the 3
January and February winter storms is included in powerhouse 4
alphabetical order below.5
a) Balch 1 Powerhouse6
On March 14, 2017, at 4 p.m., Unit 1 was removed from 7
service following a routine generator brush rigging cleaning, 8
where PG&E discovered one of the bearing slinger rings was 9
wedged and could not be rotated before unit startup. Further 10
investigation revealed a damaged slinger ring. The slinger ring 11
is used to provide bearing lubrication by rotating freely on the 12
shaft to “sling” oil to the top of a horizontal bearing in a 13
non-pressurized oil system. The damaged ring was removed 14
from service and an on-hand spare was installed. The unit was 15
returned to service the next day at 8:38 p.m.16
b) Butt Valley Powerhouse17
On July 15, 2017, at 7:56 p.m., the Butt Valley unit went 18
from 36 MW load to 0 MW load without a corresponding 19
command to change load. PG&E placed the unit under manual 20
control and attempted to raise and lower the load, but the unit 21
was unresponsive. The unit tripped offline at 8:23 p.m. due to 22
an elevated reading on the neutral over/under voltage relay. 23
PG&E investigated and found a burned coil at the governor 24
complete shutdown solenoid, which helps control wicket gate 25
operation. PG&E replaced the coil and associated wiring, and 26
tested the solenoid, wicket gate operations and SCADA 27
commands. The unit was returned to service on July 19, 2017 28
at 7:53 p.m.29
On August 7, 2017, at 7:28 a.m., the Butt Valley unit tripped 30
offline. PG&E investigated and found a damaged oil spill 31
prevention (OSP) pump gear box. While the unit was tripping 32
offline, the exciter breaker also malfunctioned, remaining in a 33
2-46
partial closed/open position. PG&E replaced the OSP pump 1
gear box, cleaned the exciter breaker linkage, and tested and 2
returned the unit to service on August 9, 2017 at 1:02 a.m.3
c) Caribou 1 Powerhouse 4
On January 10, 2017, at 9:59 a.m., Unit 2 was forced out of 5
service due to the needle “A” deflector being in-stream at full 6
load. PG&E found that the needle "A" deflector position DigiPID7
control module in the governor had failed. The DigiPID is a 8
digital proportional integral derivative controller utilized to control 9
the position of the deflector. PG&E repaired the DigiPID control 10
module, and tested and returned the unit to service on 11
January 13, 2017 at 12:28 p.m.12
On July 27, 2017, at 9:40 a.m., Unit 1 experienced governor 13
issues and was forced out of service. The governor oil pumps 14
were cycling on and off with high oil pressure spikes due to low 15
nitrogen levels. PG&E added nitrogen to the pumps to stabilize 16
the pressure. PG&E tested and returned the unit to service the 17
next day at 3:36 p.m.18
On July 30, 2017, at 6:04 p.m., Unit 3 was forced out of 19
service due to the needle “B” deflector not responding. PG&E 20
found that the needle "B" deflector position DigiPID control 21
module in the governor had failed. PG&E repaired the DigiPID 22
control module, and tested and returned the unit to service the 23
next day at 6:35 p.m.24
On October 11, 2017, at 4:10 a.m., Unit 1 tripped offline due 25
to low cooling water pressure. A PG&E investigation revealed 26
broken nitrogen lines in the cooling water pressure regulator. 27
PG&E replaced the lines and returned the unit to service on 28
October 16, 2017 at 2 p.m.29
On November 5, 2017, at 10:33 p.m., Unit 2 tripped offline 30
due to transmission issues on the 500-kV line. The unit was 31
returned to service the next day at 10:34 p.m.32
2-47
d) Drum 1 Powerhouse1
On January 19, 2017, at 3:24 p.m., Unit 3 was removed 2
from service due to governor trouble. While attempting to adjust 3
load on the unit, the DC control breaker to the governor needles 4
control tripped open and no load control to the unit was 5
available. PG&E inspected the governor and found that the 6
upstream needle control motor had failed. PG&E removed, 7
re-wound, replaced and tested the motor. The unit was 8
returned to service on January 22, 2017 at 10:51 a.m. 9
On May 4, 2017 at 2:00 p.m., Units 3 and 4 were removed 10
from service following the discovery of several leaks on the 11
common #2 penstock during a routine inspection. The leaks 12
were located on a dead-end section of penstock that formerly 13
connected common penstocks #1 and #2 in an old 14
configuration. The “new” configuration dates back to around 15
1927. The dead-ends are capped with steel spherical heads. 16
These heads corroded over time, eventually leaking where 17
sufficient deterioration had occurred. The penstock was drained 18
and cleared for further inspection and repair. The preparation 19
for repair included installing temporary access into the building 20
housing the dead-end sections, pumping down some standing 21
water, and cleaning the outside surface of the spherical heads. 22
The repair included welding metal plates into place over the 23
leaks. Following repair, the penstock was filled and Drum 124
Units 3 and 4 were returned to service on May 25, 2017 at 25
3:04 p.m.26
On May 6, 2017 at 2:30 p.m., Units 1 and 2 were removed 27
from service as a precautionary measure following the discovery 28
of leaks on the common #2 penstock servicing Drum Units 329
and 4. PG&E expanded the scope of inspection to include the 30
common #1 penstock. Leaks similar to those discovered in the31
common #2 penstock were also found in the common #1 32
penstock, which were again due to deterioration in the steel 33
spherical heads. The penstock was drained, cleared, inspected 34
2-48
and repaired. Following repair, the penstock was filled and 1
Drum 1 Units 1 and 2 were returned to service on May 26, 2017 2
at 6:49 p.m.3
On May 28, 2017 at 8:44 a.m., Unit 1 tripped offline due to a 4
blown leather packing seal on the downstream needle valve. 5
The leather seal allows the ball joint to articulate during 6
movement of the needle valve. PG&E replaced the blown 7
leather seal and the Unit was returned to service on May 31, 8
2017 at 2:29 p.m.9
On September 8, 2017, at 9:28 p.m., Unit 3 tripped offline 10
due to high exciter temperature readings. PG&E investigated 11
and discovered that the cooling fan inside the exciter cabinet 12
had failed. PG&E replaced the fan and returned the unit to 13
service on September 11, 2017 at 11:43 a.m.14
e) Electra Powerhouse15
On August 8, 2017, at 11:47 p.m., Unit 3 was forced offline 16
because of governor trouble. PG&E operators were unable to 17
control the load output of the unit and took the unit offline to 18
investigate. A detailed inspection revealed that the pistons that 19
port oil to the governor were clogged. PG&E cleaned the 20
pistons and returned the unit to service on August 10, 2017 at 21
1:01 p.m.22
f) Haas Powerhouse23
On September 7, 2017, at 10:49 a.m., Unit 1 experienced 24
an out of sync event and tripped offline. The unit was 25
scheduled for an annual exercise with PG&E electric operations, 26
whereby the unit is separated from the grid and switched to 27
carry local load for the 70kV Woodchuck line. This is done 28
annually to test circuit breaker 212, the high voltage breaker for 29
the powerhouse. During the exercise, the circuit breaker was 30
closed but the unit was out of phase, or sync, with the local area 31
system and tripped offline to protect the generator. 32
2-49
Upon investigation, PG&E determined that the unit was out 1
of phase with the substation due to incorrect wiring. During a 2
previous planned outage, PG&E had installed new 3
auto-synchroscope devices, which help PG&E monitor the 4
degree to which the unit generator and the power system are 5
synchronized with each other. The wiring at the unit was 6
updated based on substation drawings that were later found to 7
be incorrect. The auto-synchroscope devices were 8
disconnected from the generator. Rewiring of the devices is 9
scheduled to be completed and tested during the next 10
planned outage.11
The remainder of the outage consisted of testing the unit to 12
ensure proper functionality when it was returned to service. 13
PG&E completed this testing and returned the unit to service the 14
next day at 7:36 p.m.15
g) Helms Powerhouse16
On March 21, 2017, at 11:15 p.m., Helms Unit 1 was 17
removed from service. PG&E inspectors found a leak in the 18
Unit 1 west side six-inch equalizing line. The equalizing line is 19
located inside the headcover, which is a confined space 20
requiring a permit for entry. PG&E had spare parts onsite and 21
completed repair welding of the pipe. The unit was returned to 22
service on March 24, 2017 at 1:35 a.m. PG&E completed an 23
ACE Report of the equalizing line failure.1324
h) Kerckhoff 1 Powerhouse 25
On May 7, 2017, at 1:27 p.m., Units 1 and 3 were forced out 26
of service. The station service switchgear tripped in the open 27
position and could not be reliably reset by the operator. PG&E 28
cleaned and repaired the breaker. Unit 3 was returned to 29
service the next day at 3:49 p.m. and Unit 1 was returned to 30
service at 3:55 p.m.31
13 2017 Helms Unit 1 Equalizing Line Failure ACE is provided in the PG&E workpapers.
2-50
On December 4, 2017, at 9:48 a.m., Unit 3 was forced out 1
of service due to a water leak in the cooling water supply line. 2
The line failed due to corrosion. PG&E replaced the failed 3
section of pipe and returned the unit to service the next day at 4
10:03 a.m.5
i) Pit 1 Powerhouse 6
On March 23, 2017, at 7 p.m., Unit 2 was unable to return to 7
service following a scheduled generator and turbine inspection 8
due to erratic vibration measurements. Starting in January, 9
PG&E had observed erratic vibrations and monitored the unit 10
until a scheduled shutdown on March 10. At that time, PG&E 11
determined that the vibrations were electrically influenced; when 12
a field was applied the vibration increased and when it was 13
removed the vibration significantly decreased. PG&E scheduled 14
another outage for March 23, with a visual inspection of the 15
stator core leading to the decision to keep the unit out of service 16
until approved for operation. PG&E brought in Applied 17
Technology Services (ATS) and an outside contractor to inspect 18
the unit and monitor it with precision equipment. The unit was 19
inspected and placed back into service for ATS to record certain 20
operating parameters. The vibration was not as erratic and the 21
unit was released back to service with all monitoring equipment 22
still in place. The unit returned to service on March 31, 2017 at 23
11:45 a.m. A planned outage was scheduled for October 2017 24
and was still in progress at the end of the 2017 record period. 25
The stator core will be rewound and repaired, resolving the 26
vibration issue.27
j) Pit 4 Powerhouse28
On May 19, 2017, at 3:37 p.m., Unit 2 was unable to return 29
to service during initial testing following conclusion of a turbine 30
overhaul project. During testing, the lower guide bearing 31
temperature was observed to be rising faster than the other 32
bearings. Once the predetermined temperature limit was 33
2-51
reached, the unit was shut down. PG&E examined the lower 1
guide bearing and discovered that it had failed, or “wiped,” 2
coming into direct contact with the shaft journal. PG&E 3
investigated and determined that the bearing wipe was caused 4
by a shift in the turbine headcover extension, and thus, the 5
turbine shaft alignment with the lower guide bearing, due to 6
insufficient constraint by headcover extension bolts. The bolts 7
were replaced with fit bolts. The new bolts provide additional 8
constraint due to their interference fit with the headcover and 9
headcover extension. Also, the headcover extension was put 10
back into alignment and the lower guide bearing was replaced.11
Additional issues with the turbine shutoff valve closure caused12
by a faulty pressure switch; turbine guide bearing work due to 13
anticipated heat issues; and a faulty mercury switch, delayed 14
the unit’s return to service until September 7, 2017, at 15
11:25 a.m. An independent root cause evaluation is being 16
performed by ABS Consulting for the outage. It is unavailable at 17
the time of this testimony submittal but is expected to be 18
complete shortly thereafter.19
On November 8, 2017, at 7 p.m., Unit 1 was unable to 20
return to service following maintenance work on the governor 21
pilot valve due to a collapsed governor accumulator float. When 22
attempting to return the unit to service PG&E discovered that 23
the governor oil pump clapper valve was not operating correctly. 24
The governor accumulator was then drained and PG&E 25
discovered that the clapper valve oil level accumulator float had 26
collapsed. PG&E replaced the governor accumulator float and 27
returned the unit to service the next day at 7:01 p.m.28
k) Pit 6 Powerhouse 29
On August 21, 2017, at 10:09 p.m., Unit 1 tripped offline due 30
to a fault at the main transformer. Upon inspection, PG&E 31
determined that the transformer had failed beyond repair. 32
PG&E ordered a temporary replacement transformer to allow 33
the plant to continue operating while a permanent transformer 34
2-52
was designed, fabricated, delivered and installed, a process that 1
takes approximately two years. PG&E installed the replacement 2
transformer and returned the unit to service on November 8, 3
2017 at 8:15 p.m. PG&E initiated a failure inspection of the 4
transformer. The contractor’s report is included in PG&E’s 5
workpapers.14 The contractor’s report states that the failure 6
was most likely due to the advanced age of the transformer.7
l) Poe Powerhouse 8
On May 17, 2017, at 8:10 p.m., Unit 2 was forced out of 9
service due to a catastrophic failure of a rotor fan blade. The 10
rotor fan blades are required to provide cooling to the generator 11
and auxiliary parts. The rivets that join fan blade number 21 to 12
the mounting bracket failed while in service. Failure of the rivets 13
on the fan blade resulted in significant damage to the generator 14
stator and field windings. The fault currents caused by the 15
failure also caused damage to the bearing babbitt material. 16
PG&E completed an ACE report of the outage.15 The 17
evaluation revealed that the cause of the failure was vibration 18
induced by air vortices bouncing between the top plate of the 19
fan shroud and the fan blades. The air vortices were introduced 20
from air passing across the 3/4 inch abandoned CO2 piping 21
located inside the fan shroud. More details on the air vortices 22
are provided in the ACE. Recommendations listed in the ACE 23
will extend to units with fan blades that are the same design as 24
those used at Poe Powerhouse Unit 2.25
Due to the findings of the ACE, the fan shroud was returned 26
to its original state. All piping and mounting brackets were 27
removed and all windows that were cut into the shroud were 28
welded shut. The top fan blades were replaced, the bearings 29
were replaced, two field poles were refurbished, six stator coils 30
14 Field Service Report – Pit 6 Powerhouse Unit 1 Failure Inspection is provided in PG&E’s workpapers.
15 Poe Powerhouse Fan Blade Failure ACE is provided in PG&E’s workpapers.
2-53
were beyond repair and removed from the circuit. Following 1
completion of testing, the unit was returned to service on 2
August 10, 2017 at 11:25 p.m.3
m) Salt Springs Powerhouse4
On June 9, 2017, at 2:38 p.m., Unit 2 was removed from 5
service due to arcing generator brushes found during a routine 6
inspection. A PG&E brush rigging specialist was contacted to 7
investigate the cause. On June 14, the brush rigging specialist 8
examined the unit, replacing and adjusting the brushes as 9
needed. The unit was returned to service on June 14, 2017 at 10
11:46 a.m.11
E. Conclusion12
In compliance with D.14-01-011, this chapter addresses the operation of 13
PG&E’s utility-owned hydroelectric facilities, and outages that occurred at these 14
facilities during the 2017 record year. It demonstrates that PG&E's utility-owned 15
hydroelectric portfolio was operated in a reasonable manner during the 16
record period.17
PG&E has a comprehensive management structure, with numerous internal 18
controls, to prudently oversee the operation of a large, geographically dispersed, 19
and complex hydro system. Scheduled outages were planned sufficiently in 20
advance to allow adequate preparation time and were efficiently executed to 21
assure prompt return to service.22
PG&E’s hydro resources were operated in a reasonable manner as 23
demonstrated by the 2017 record year FOF results being better than the industry 24
average when excluding the January and February storm-related outages.25
PG&E acted reasonably in resolving forced outages in a timely manner.26
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 2
ATTACHMENT A
PG&E POWERHOUSES AND GENERATING UNITS
PACIFIC GAS AND ELECTRIC COMPANYCHAPTER 2
UTILITY OWNED GENERATION: HYDROELECTRICAttachment A Table of Hydro Generating Units at 2017 End of Year
LineNo. Powerhouse Name and Unit Basic type and /
or configuration Management Area Specific physical location Capacity Date in
service1 ALTA POWERHOUSE UNIT #1 Conv Hydro Central Alta, CA 1.0 11/7/19022 BALCH PH 1 UNIT 1 Conv Hydro Kings Crane Valley Balch Camp, CA 34.0 2/20/19273 BALCH PH 2 UNIT 2 Conv Hydro Kings Crane Valley Balch Camp, CA 52.5 11/26/19584 BALCH PH 2 UNIT 3 Conv Hydro Kings Crane Valley Balch Camp, CA 52.5 11/26/19585 BELDEN POWERHOUSE Conv Hydro DeSabla Belden, CA 125.0 9/14/19696 BUCKS CREEK PH UNIT #1 Conv Hydro DeSabla Storrie, CA 33.0 3/4/19287 BUCKS CREEK PH UNIT #2 Conv Hydro DeSabla Storrie, CA 32.0 3/4/19288 BUTT VALLEY POWERHOUSE Conv Hydro DeSabla Belden, CA 41.0 12/31/19589 CARIBOU #1 POWERHOUSE UNIT #1 Conv Hydro DeSabla Belden, CA 25.0 5/6/1921
10 CARIBOU #1 POWERHOUSE UNIT #2 Conv Hydro DeSabla Belden, CA 25.0 5/6/192111 CARIBOU #1 POWERHOUSE UNIT #3 Conv Hydro DeSabla Belden, CA 25.0 5/6/192112 CARIBOU #2 POWERHOUSE UNIT #4 Conv Hydro DeSabla Belden, CA 60.0 11/9/195813 CARIBOU #2 POWERHOUSE UNIT #5 Conv Hydro DeSabla Belden, CA 60.0 11/9/195814 CENTERVILLE PH UNIT NO.1 Conv Hydro DeSabla Chico, CA 5.5 5/1/190015 CENTERVILLE PH UNIT NO.2 Conv Hydro DeSabla Chico, CA 0.9 5/1/190016 CHILI BAR POWERHOUSE UNIT #1 Conv Hydro Central Placerville, CA 7.0 3/22/196517 COLEMAN PH UNIT NO.1 Conv Hydro Shasta Anderson, CA 13.0 6/19/197918 COW CREEK PH UNIT NO.1 Conv Hydro Shasta Millville, CA 0.9 1/1/190719 COW CREEK PH UNIT NO.2 Conv Hydro Shasta Millville, CA 0.9 1/1/190720 CRANE VALLEY PH UNIT 1 Conv Hydro Kings Crane Valley North Fork, CA 0.9 7/4/191921 CRESTA POWERHOUSE UNIT #1 Conv Hydro DeSabla Storrie, CA 35.0 11/23/194922 CRESTA POWERHOUSE UNIT #2 Conv Hydro DeSabla Storrie, CA 35.0 1/15/195023 DE SABLA PH UNIT NO.1 Conv Hydro DeSabla Magalia, CA 18.5 2/28/196324 DEER CREEK PH UNIT #1 Conv Hydro Central Nevada City, CA 5.7 5/6/190825 DRUM POWERHOUSE #1, UNIT #1 Conv Hydro Central Alta, CA 13.2 11/26/191326 DRUM POWERHOUSE #1, UNIT #2 Conv Hydro Central Alta, CA 13.2 11/26/191327 DRUM POWERHOUSE #1, UNIT #3 Conv Hydro Central Alta, CA 13.1 11/26/191328 DRUM POWERHOUSE #1, UNIT #4 Conv Hydro Central Alta, CA 14.5 11/26/191329 DRUM POWERHOUSE #2, UNIT #5 Conv Hydro Central Alta, CA 49.5 12/18/196530 DUTCH FLAT POWERHOUSE UNIT #1 Conv Hydro Central Alta, CA 22.0 3/29/194331 ELECTRA POWERHOUSE UNIT #1 Conv Hydro Central Jackson, CA 31.0 6/29/194832 ELECTRA POWERHOUSE UNIT #2 Conv Hydro Central Jackson, CA 31.0 6/29/194833 ELECTRA POWERHOUSE UNIT #3 Conv Hydro Central Jackson, CA 36.0 6/29/194834 HAAS PH UNIT 1 Conv Hydro Kings Crane Valley Balch Camp, CA 72.0 12/23/195835 HAAS PH UNIT 2 Conv Hydro Kings Crane Valley Balch Camp, CA 72.0 12/23/195836 HALSEY POWERHOUSE UNIT #1 Conv Hydro Central Auburn, CA 11.0 12/6/191637 HAMILTON BRANCH PH UNIT #1 Conv Hydro DeSabla Penninsula Village, CA 2.4 1/1/192138 HAMILTON BRANCH PH UNIT #2 Conv Hydro DeSabla Penninsula Village, CA 2.4 1/2/192139 HAT CREEK PH 1 UNIT 1 Conv Hydro Shasta Burney, CA 8.5 8/22/192140 HAT CREEK PH 2 UNIT 1 Conv Hydro Shasta Burney, CA 8.5 9/28/192141 HELMS POWERHOUSE UNIT 1 Pumped Storage Helms Shaver Lake, CA 404.0 6/30/198442 HELMS POWERHOUSE UNIT 2 Pumped Storage Helms Shaver Lake, CA 404.0 6/30/198443 HELMS POWERHOUSE UNIT 3 Pumped Storage Helms Shaver Lake, CA 404.0 6/30/198444 INSKIP PH UNIT NO.1 Conv Hydro Shasta Manton, CA 8.0 10/9/197945 JAMES B. BLACK PH UNIT #1 Conv Hydro Shasta Big Bend, CA 86.0 2/17/196646 JAMES B. BLACK PH UNIT #2 Conv Hydro Shasta Big Bend, CA 86.0 12/17/196547 KERCKHOFF PH 1 UNIT 1 Conv Hydro Kings Crane Valley Auberry, CA 12.6 8/6/192048 KERCKHOFF PH 1 UNIT 3 Conv Hydro Kings Crane Valley Auberry, CA 12.8 8/6/192049 KERCKHOFF PH 2 UNIT 1 Conv Hydro Kings Crane Valley Auberry, CA 155.0 5/6/198350 KERN CANYON PH UNIT 1 Conv Hydro Kings Crane Valley Bakersfield, CA 11.5 8/8/192151 KILARC PH UNIT NO.1 Conv Hydro Shasta Whitmore, CA 1.6 10/1/190352 KILARC PH UNIT NO.2 Conv Hydro Shasta Whitmore, CA 1.6 5/2/190453 KINGS RIVER PH UNIT 1 Conv Hydro Kings Crane Valley Balch Camp, CA 52.0 3/7/1962
2-AtchA-1
PACIFIC GAS AND ELECTRIC COMPANYCHAPTER 2
UTILITY OWNED GENERATION: HYDROELECTRICAttachment A Table of Hydro Generating Units at 2017 End of Year
LineNo. Powerhouse Name and Unit Basic type and /
or configuration Management Area Specific physical location Capacity Date in
service54 LIME SADDLE PH UNIT NO.1 Conv Hydro DeSabla Oroville, CA 1.0 8/1/190655 LIME SADDLE PH UNIT NO.2 Conv Hydro DeSabla Oroville, CA 1.0 8/1/190656 NARROWS POWERHOUSE #1 UNIT #1 Conv Hydro Central Grass Valley, CA 12.0 12/29/194257 NEWCASTLE POWERHOUSE UNIT #1 Conv Hydro Central Auburn, CA 11.5 10/28/198658 OAK FLAT POWERHOUSE UNIT #1 Conv Hydro DeSabla Belden, CA 1.3 11/2/198559 PHOENIX POWERHOUSE UNIT #1 Conv Hydro Central Sonora, CA 2.0 2/20/194060 PIT PH 1 UNIT 1 Conv Hydro Shasta Burney, CA 30.5 2/28/192261 PIT PH 1 UNIT 2 Conv Hydro Shasta Burney, CA 30.5 2/28/192262 PIT PH 3 UNIT 1 Conv Hydro Shasta Burney, CA 23.3 7/15/192563 PIT PH 3 UNIT 2 Conv Hydro Shasta Burney, CA 23.3 7/15/192564 PIT PH 3 UNIT 3 Conv Hydro Shasta Burney, CA 23.4 7/15/192565 PIT PH 4 UNIT 1 Conv Hydro Shasta Big Bend, CA 47.5 10/1/195566 PIT PH 4 UNIT 2 Conv Hydro Shasta Big Bend, CA 47.5 10/1/195567 PIT PH 5 UNIT 1 Conv Hydro Shasta Big Bend, CA 40.0 4/29/194468 PIT PH 5 UNIT 2 Conv Hydro Shasta Big Bend, CA 40.0 4/29/194469 PIT PH 5 UNIT 3 Conv Hydro Shasta Big Bend, CA 40.0 4/29/194470 PIT PH 5 UNIT 4 Conv Hydro Shasta Big Bend, CA 40.0 4/29/194471 PIT PH 6 UNIT 1 Conv Hydro Shasta Montgomery Creek, CA 40.0 8/14/196572 PIT PH 6 UNIT 2 Conv Hydro Shasta Montgomery Creek, CA 40.0 8/14/196573 PIT PH 7 UNIT 1 Conv Hydro Shasta Montgomery Creek, CA 56.0 9/10/196574 PIT PH 7 UNIT 2 Conv Hydro Shasta Montgomery Creek, CA 56.0 9/10/196575 POE POWERHOUSE UNIT #1 Conv Hydro DeSabla Storrie, CA 60.0 10/26/195876 POE POWERHOUSE UNIT #2 Conv Hydro DeSabla Storrie, CA 60.0 10/26/195877 POTTER VALLEY UNIT 1 Conv Hydro DeSabla Potter Valley, CA 4.5 4/1/190878 POTTER VALLEY UNIT 3 Conv Hydro DeSabla Potter Valley, CA 2.0 4/1/190879 POTTER VALLEY UNIT 4 Conv Hydro DeSabla Potter Valley, CA 2.7 4/1/190880 ROCK CREEK POWERHOUSE UNIT #1 Conv Hydro DeSabla Storrie, CA 63.0 3/1/195081 ROCK CREEK POWERHOUSE UNIT #2 Conv Hydro DeSabla Storrie, CA 63.0 3/16/195082 SALT SPRINGS PH UNIT #1 Conv Hydro Central Pioneer, CA 11.0 6/15/193183 SALT SPRINGS PH UNIT #2 Conv Hydro Central Pioneer, CA 33.0 4/24/195384 SAN JOAQUIN 1A PH UNIT 1 Conv Hydro Kings Crane Valley North Fork, CA 0.4 3/12/191985 SAN JOAQUIN 2 PH UNIT 1 Conv Hydro Kings Crane Valley North Fork, CA 3.2 9/29/191786 SAN JOAQUIN 3 PH UNIT 1 Conv Hydro Kings Crane Valley North Fork, CA 4.2 8/17/192387 SOUTH PH UNIT NO.1 Conv Hydro Shasta Manton, CA 7.0 12/8/197988 SPAULDING PH #1, UNIT #1 Conv Hydro Central Emigrant Gap, CA 7.0 5/8/192889 SPAULDING PH #2, UNIT #1 Conv Hydro Central Emigrant Gap, CA 4.4 7/16/192890 SPAULDING PH #3, UNIT #1 Conv Hydro Central Emigrant Gap, CA 5.8 2/21/192991 SPRING GAP POWERHOUSE UNIT #1 Conv Hydro Central Long Barn, CA 7.0 9/16/192192 STANISLAUS POWERHOUSE UNIT #1 Conv Hydro Central Vallecito, CA 91.0 3/11/196393 TIGER CREEK PH UNIT #1 Conv Hydro Central Pioneer, CA 29.0 8/1/193194 TIGER CREEK PH UNIT #2 Conv Hydro Central Pioneer, CA 29.0 8/1/193195 TOADTOWN PH UNIT NO.1 Conv Hydro DeSabla Mogalia, CA 1.5 4/22/198696 TULE RIVER PH UNIT 1 Conv Hydro Kings Crane Valley Springville, CA 3.2 1/21/191497 TULE RIVER PH UNIT 2 Conv Hydro Kings Crane Valley Springville, CA 3.2 1/21/191498 VOLTA 1 PH UNIT NO.1 Conv Hydro Shasta Manton, CA 9.0 4/4/198099 VOLTA 2 PH UNIT NO.2 Conv Hydro Shasta Manton, CA 0.9 10/30/1981
100 WEST POINT PH UNIT #1 Conv Hydro Central Pioneer, CA 14.5 11/21/1948101 WISE POWERHOUSE #1, UNIT #1 Conv Hydro Central Auburn, CA 14.0 3/4/1917102 WISE POWERHOUSE #2, UNIT #1 Conv Hydro Central Auburn, CA 3.2 12/12/1986103 WISHON PH 1 UNIT 1 Conv Hydro Kings Crane Valley North Fork, CA 5.0 9/20/1910104 WISHON PH 1 UNIT 2 Conv Hydro Kings Crane Valley North Fork, CA 5.0 9/20/1910105 WISHON PH 1 UNIT 3 Conv Hydro Kings Crane Valley North Fork, CA 5.0 9/20/1910106 WISHON PH 1 UNIT 4 Conv Hydro Kings Crane Valley North Fork, CA 5.0 9/20/1910
3,892.2
2-AtchA-2
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 3
UTILITY-OWNED GENERATION: FOSSIL AND OTHER
GENERATION
3-i
PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 3
UTILITY-OWNED GENERATION: FOSSIL AND OTHER GENERATION
TABLE OF CONTENTS
A. Introduction ....................................................................................................... 3-1
DCPP is consistently operated at 100 percent (or full) power level. 28
Regular cycling of DCPP is not performed. This is consistent with the 29
operation of most nuclear power plants in the United States, which are 30
operated as baseload units. When a plant is taken off-line for any reason, 31
regulatory-required testing must be performed before the plant can be 32
4-6
returned to service, which extends the time period to return to service 1
beyond the time required to conduct repairs.2
There are a number of factors that can affect the megawatt-hour (MWh) 3
output of a nuclear facility, such as scheduled refueling outages, routine 4
turbine generator valve testing, ocean cooling water temperature, ocean 5
cooling water system tunnel cleaning, curtailments, and forced outages. 6
The capacity factor3 and net generation4 for the record period for DCPP 7
Units 1 and 2 are shown below in Table 4-1.8
TABLE 4-1NUCLEAR GENERATION 2017 ENERGY PRODUCTION
Line No. DCPP Unit Capacity Factor
Net Generation(MWh)(a)
1 1 83% 8,198,2842 2 100% 9,728,167
_______________
(a) The net generation values reflect preliminary CAISO data. Final 2017 generation values will be available in April 2018.
Electric power industry generation unit performance calculations are9
based on “Maximum Dependable Capacity” (MDC). This value is 10
determined for each generating unit based on extensive unit operational 11
testing and engineering analysis by the plant staff. MDC is the maximum 12
amount of power a unit can produce during average worst case natural13
operating conditions.514
The MDC values for DCPP Units 1 and 2 are 1,122 MW and 1,118 MW, 15
respectively. As shown in Table 4-1 above, the 2017 capacity factors for 16
Unit 1 and Unit 2 were 83 percent and 100 percent, respectively. In 2017, 17
Unit 1 had a planned Baffle Bolt Replacement Refueling Outage (1R20), 18
3 Capacity factor is a measure of actual generation compared to potential generation (based on operating a unit 24 hours a day every day of the reporting period, and established Net Maximum Dependable Capacity values of 1,122 MW for Unit 1and 1,118 MW for Unit 2).
4 Net generation (MWh) is equal to gross generation minus the amount of energy consumed by the plant, as reported by PG&E to the California Independent System Operator (CAISO).
5 The NRC’s definition of MDC can be found at: https://www.nrc.gov/reading-rm/basic-ref/glossary/maximum-dependable-capacity-gross.html.
4-7
resulting in a lower capacity factor for Unit 1 than for Unit 2. DCPP Units 11
and 2 did not experience any unplanned shutdowns or forced losses of a 2
duration greater than 24 hours throughout the entire 2017 record period.3
Combined, DCPP Units 1 and 2 generated 17,926,451 MWh of energy 4
with an average capacity factor of 91.5 percent (for the record period) 5
against a planned target of 87.7 percent.6 The 2016 industry average 6
capacity factor was 92.3 percent.7 DCPP’s exceptional performance was 7
the result of no forced outages during the record period, and completion of 8
the planned Unit 1 1R20 Baffle Bolt Replacement Refueling Outage 14 days9
ahead of the planned schedule. As explained in Section D.2.a. below, the 10
Unit 1 1R20 Baffle Bolt Replacement Refueling Outage was 16 days shorter 11
than the 2017 industry average for this type of outage. 12
As demonstrated above, DCPP’s performance resulted in safe and 13
reliable generation for PG&E’s customers, with high levels of availability and 14
zero forced outages longer than 24 hours in duration. In addition, 15
completion of the Unit 1 1R20 Baffle Bolt Replacement Refueling Outage 16
ahead of schedule allowed for 14 days of additional DCPP generation to 17
PG&E’s customers.18
2. Outages19
Nuclear generating facilities can experience generation losses due to: 20
outages; and (4) curtailments. Refueling outages and maintenance outages 22
are both classified as scheduled outages. Each of these types of outages is 23
discussed below.24
Nuclear generating units are unique in that they must be shut down 25
periodically to be refueled. The consumption of this set amount of fuel is 26
what establishes the operating duration of a fuel cycle and scheduling of a 27
refueling outage. Nuclear units schedule necessary maintenance and 28
6 The 88 percent planned target capacity factor accounted for the scheduled Unit 1 1R20Baffle Bolt Replacement Refueling Outage that is discussed in Section D.2.a. below.
7 Industry capacity factors are available from the U.S. Energy Information Administration Electric Power Monthly report, Table 6.7.B. The November 2017 report identifies 2016 U.S. average capacity factor of 92.3 percent (https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_b).
4-8
projects within the refueling outages. After a nuclear unit is refueled it can 1
then be operated until the next refueling outage. The planned duration of a 2
refueling outage is established based on the duration required to refuel the 3
reactor, the scope of maintenance required for the specific outage, and the 4
scope of projects required to be implemented for regulatory or plant 5
improvement activities. 6
Maintenance outages are scheduled when needed throughout the year 7
to perform testing, routine maintenance, or non-emergency repairs when the 8
repairs can be deferred beyond the end of the next weekend, but require a 9
capacity reduction before the next scheduled refueling outage.10
Forced outages are generally the result of equipment malfunctions or 11
unexpected ocean conditions that restrict the plant’s ocean cooling water 12
intake system. When a forced outage occurs, the primary objective is to 13
repair the item that led to the outage or protect plant equipment from 14
damage resulting from restricted ocean cooling water flow. While 15
minimizing the outage period is important, a certain amount of work is 16
required for every forced shutdown. This includes surveillance testing as 17
well as complying with all regulatory requirements and emergent 18
maintenance requirements that cannot be deferred to a later period.19
A curtailment is when a unit is not operating at 100 percent capacity. A 20
curtailment could be the result of required surveillance testing that must be 21
performed at a power level less than 100 percent, routine maintenance that 22
requires a unit to be at less than 100 percent, such as cleaning of the ocean 23
cooling water system to remove biological growth, emergent maintenance 24
items that require the unit to be at a reduced power level, or an operational 25
decision to reduce power due to external influences such as significant 26
swells that could impact the ability of a unit to remain operational.27
Further detail concerning refueling outages, maintenance outages, and 28
forced outages that occurred during the record period for DCPP Units 129
and 2 is discussed below. Consistent with previous Energy Resource 30
Recovery Account compliance proceedings, PG&E is providing general 31
information regarding Scheduled Outages that were 24 hours or more in 32
duration, and specific information regarding each Forced Outage that was 33
longer than 24 hours in duration. PG&E has provided additional, detailed 34
4-9
information concerning the outages that occurred during the record period to 1
the Office of Ratepayer Advocates (ORA) in response to ORA’s Master Data 2
Request.3
a. Unit 14
During 2017, Unit 1 conducted a planned 1R20 Baffle Bolt 5
Replacement Refueling Outage from April 23, 2017 at 00:01 through 6
June 23, 2017 at 00:01. This outage was scheduled for a duration of 7
75 days. The actual Unit 1 1R20 outage duration was 61 days, 14 days 8
ahead of the planned schedule.9
A baffle bolt replacement refueling outage is an outage that includes 10
a major project of inspecting and replacing, as needed, the baffle bolts 11
that secure the reactor core plate that houses the nuclear fuel. The 12
activities required to perform this project are extensive, which makes the 13
refueling outage longer than usual. Baffle bolt inspection and 14
replacement is performed due to an industry and regulatory (NRC) 15
concern that nuclear plant operators ensure that the integrity of the core 16
plate remains within design requirements. 17
The industry average duration for a baffle bolt replacement refueling 18
outage through the end of 2017 was 77 days. As explained above, the19
DCPP Unit 1 1R20 Baffle Bolt Replacement Refueling Outage was 20
scheduled for 75 days and was completed in 61 days, which was shorter 21
than the industry average duration for this type of outage. Completing 22
the outage safely and ahead of schedule allowed PG&E’s customers to 23
benefit from Unit 1 generation 16 days sooner than if Unit 1’s refueling 24
outage had been of industry average duration.25
Unit 1 did not experience any forced outages that were longer than 26
24 hours in duration.27
b. Unit 228
Unit 2 experienced no scheduled or forced outages of a duration 29
greater than 24 hours during 2017.30
c. Outage-Related Violations From Nuclear Regulatory Commission31
There were no NRC violations issued to DCPP in 2017 affecting 32
outage durations. However, there were two Non-Cited Violations during 33
4-10
the Unit 1 1R20 Baffle Bolt Replacement Refueling Outage. Both 1
Non-Cited Violations were of very low safety significance. 2
The first Non-Cited Violation was for not properly obtaining Shift 3
Manager approval when starting work on a job activity during the 4
outage, which resulted in securing a redundant system from service 5
without Shift Manager approval per procedure. Corrective actions 6
included coaching involved personnel, reviewing a communication with 7
additional staff members, and enhancing procedures to provide greater 8
clarity on the standard and to strengthen control of valve position 9
through use of a physical barrier (seal).10
The second Non-Cited Violation was for not expanding the scope of 11
weld reviews for a flaw identified in the previous refueling outage. As an 12
immediate corrective action, PG&E identified and inspected four 13
additional welds assigned to the same degradation mechanism 14
identified in the prior refueling outage, as required by the risk-informed 15
in-service inspection program. This issue was also entered into the 16
DCPP CAP.17
E. Conclusion18
In compliance with D.14-01-011, this chapter addresses the operation of 19
PG&E’s utility-owned nuclear facility, and outages that occurred at this facility 20
during the 2017 record year. It demonstrates that DCPP was operated in a 21
reasonable manner during the record period.22
PG&E has a comprehensive management structure, with numerous internal 23
controls, to prudently oversee the operation of DCPP. The 2017 year-end24
DCPP total plant capacity factor was 91.5 percent, which exceeded the 2017 25
target of 87.7 percent and was slightly lower than the 2016 industry average 26
capacity factor of 92.3 percent. In addition, DCPP experienced no unplanned 27
shutdowns that were greater than 24 hours in duration. Finally, the Unit 128
planned 1R20 Baffle Bolt Replacement Refueling Outage was planned 29
sufficiently in advance to allow adequate preparation and was efficiently 30
executed to assure prompt return to service. This outage lasted 61 days 31
compared to the scheduled 75-day duration, and was completed 16 days sooner 32
than the nuclear industry average duration of 77 days for this type of outage. 33
4-11
This allowed PG&E to deliver 16 more days of generation from Unit 1 to its 1
customers during 2017 than it would have under the industry average.2
In sum, DCPP was operated in a reasonable manner in 2017 as 3
demonstrated by PG&E’s completion of the Unit 1 1R20 Baffle Bolt Replacement 4
Refueling Outage 16 days sooner than the industry average duration, and the 5
absence of forced outages on either Unit resulting from PG&E’s methodical 6
operational focus on maintenance. 7
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 5
COSTS INCURRED AND RECORDED IN THE DIABLO CANYON
SEISMIC STUDIES BALANCING ACCOUNT
5-i
PACIFIC GAS AND ELECTRIC COMPANYCHAPTER 5
COSTS INCURRED AND RECORDED IN THE DIABLO CANYON SEISMIC STUDIES BALANCING ACCOUNT
TABLE OF CONTENTS
A. Introduction....................................................................................................... 5-1
B. Description of Costs Incurred ........................................................................... 5-2
C. The Costs Recorded in the DCSSBA Are Reasonable and Consistent With D.12-09-008, D.14-08-032 and D.17-05-013............................................ 5-3
1. AB 1632 Seismic Studies........................................................................... 5-3
a. Ocean Bottom Seismometer................................................................ 5-4
b. AB 1632 Project Management............................................................. 5-4
2. Natural Gas Procurement .......................................................................... 6-2
a. PG&E Generation................................................................................ 6-2
b. PG&E Tolling Agreements................................................................... 6-2
c. PG&E’s Gas Supply Transactions Are Fully Compliant with Commission Guidance......................................................................... 6-5
1) PG&E Transacted Using Approved Products for Purchase or Sale........................................................................................... 6-5
2) PG&E Transacted Using Approved Procurement Processes........ 6-6
3) PG&E Transacted Within BPP Procurement Limits ...................... 6-6
4) PG&E Consulted With Its PRG as Required ................................. 6-6
d. Compliance with Ruby Pipeline Decision Requirements ..................... 6-7
C. Distillate Expenses ........................................................................................... 6-8
D. Water Purchased for Power ............................................................................. 6-8
E. Nuclear Fuel Expenses .................................................................................... 6-8
F. Nuclear Fuel Carrying Costs .......................................................................... 6-10
G. STARS Alliance.............................................................................................. 6-10
H. Electric Portfolio Hedging ............................................................................... 6-11
2. All Transactions Complied with Approved Products and Approved Transaction Processes............................................................................. 6-11
3. PG&E Consulted with the PRG as Required............................................ 6-11
PG&E engaged in fuel procurement activities in a manner consistent with:12
its California Public Utilities Commission (CPUC or Commission)-approved 13
procurement plans; Nuclear Fuel Procurement Plan; and Commission decisions 14
addressing procurement.15
In addition, consistent with Decision (D.) 12-05-010, Ordering Paragraph 16
(OP) 3, PG&E is also providing in this chapter a report concerning its activities 17
and operating costs associated with the STARS Alliance, LLC (STARS Alliance).18
Finally, this chapter reviews PG&E’s implementation of its 19
Commission-approved Electric Portfolio Hedging Plan (Hedging Plan) during the 20
record period from January 1 to December 31, 2017. Consistent with 21
D.11-07-039, OP 3, PG&E is also providing in this chapter a high-level 22
discussion of its internal procedures and controls for ensuring compliance with 23
its Hedging Plan.24
B. Gas Procurement25
1. Portfolio Overview26
PG&E manages natural gas procurement for its portfolio of gas-fired 27
generators, including power plants owned by PG&E and generators 28
contracted to PG&E under tolling agreements. PG&E describes its gas 29
procurement activities in the section below.30
6-2
2. Natural Gas Procurement1
a. PG&E Generation2
PG&E owned six natural gas-fired generating facilities in commercial 3
operation during the record period: Humboldt Bay Generating Station 4
(Humboldt), Gateway Generating Station (Gateway); Colusa Generating 5
Station (Colusa); and three utility-owned fuel cell generating units: 6
one at California State University, East Bay (CSUEB Fuel Cell) and 7
two at San Francisco State University (SFSU Fuel Cells). Humboldt 8
primarily burns natural gas1 and is capable of burning distillate fuel oil 9
during gas curtailments or emergencies. These facilities are listed in 10
Table 6-1 below.11
TABLE 6-1PG&E-OWNED GENERATION FACILITIES
Line No. Name Location
Capacity (megawatts
(MW)) Technology
Heat Rate(Millions of British
Thermal Units (MMBtu)/megawatt-hours(MWh))
1 Gateway Antioch, CA 530 Combined Cycle Gas Turbine
7.2
2 Colusa Maxwell, CA 530 Combined Cycle Gas Turbine
7.2
3 Humboldt Eureka, CA 163 Reciprocating Engines
9.1
4 CSUEB Fuel Cell Hayward, CA 1.4 Fuel Cell 8.0(a)5 SFSU Fuel Cells San Francisco, CA 0.2 Fuel Cell 6.6(a)6 SFSU Fuel Cells San Francisco, CA 1.4 Fuel Cell 8.0(a)
_______________
(a) Manufacturers estimated heat rate.
b. PG&E Tolling Agreements12
In addition to the gas-fired generating facilities it owns, PG&E’s 13
electric portfolio includes numerous tolling agreements for gas-fired 14
generators. A tolling agreement is an agreement for generating capacity 15
and electric energy where the buyer delivers fuel to the seller and the 16
1 When burning natural gas, the units at Humboldt require a small amount of distillate fuel for ignition.
6-3
seller delivers electric energy to the buyer.2 In this case, PG&E 1
(as buyer) delivers natural gas to the owner of the generating facility 2
(the seller) and in exchange receives energy and other services. 3
PG&E dispatches these tolled facilities according to least-cost dispatch 4
principles. These agreements are listed in Table 6-2.5
2 Tolling agreements are structured arrangements that can include a variety of services including capacity, energy, and ancillary services.
6-4
TABLE 6-2PG&E’S TOLLING AGREEMENTS IN 2017
Line No. Name Location Counterparty
Capacity(MW) Technology
Heat Rate (MMBtu/MWh)
1 Badger Creek Limited Bakersfield Badger Creek Limited 42 Simple Cycle Combustion Turbine (CT)
9.4 – 10.5
2 Bear Mountain Limited Bakersfield Bear Mountain Limited 42 Simple Cycle CT 9.4 – 10.53 Calpine Peakers Various Calpine Energy Services, L.P. 495 Simple Cycle CT 10.5 - 12.84 Chalk Cliff Limited Taft Chalk Cliff Limited 42 Simple Cycle CT 9.4 – 10.55 Double C Limited Bakersfield Double C Limited 47 Simple Cycle CT 10.36 GWF Energy Hanford Hanford GWF Energy LLC 96 Simple Cycle CT 10.1 – 12.97 GWF Energy Henrietta Henrietta GWF Energy LLC 96 Simple Cycle CT 10.1 – 12.98 GWF Tracy Tracy GWF Energy LLC 323 Combined Cycle 7.8 – 8.59 High Sierra Limited Bakersfield High Sierra Limited 47 Simple Cycle CT 10.310 Kern Front Limited Bakersfield Kern Front Limited 47 Simple Cycle CT 10.311 Live Oak Limited Bakersfield Live Oak Limited 42 Simple Cycle CT 9.4 – 10.512 Los Esteros Critical Energy Facility San Jose Los Esteros Critical Energy Facility, LLC 294 Combined Cycle 8.0-9.413 Mariposa Byron Mariposa Energy 194 Simple Cycle CT 9.9 – 11.714 Marsh Landing Generating Station Antioch NRG Marsh Landing, LLC 801 Simple Cycle CT 10.2 – 12.815 McKittrick Limited McKittrick McKittrick Limited 42 Simple Cycle CT 9.4 – 10.516 O.L.S. Energy-Agnews, Inc. San Jose O.L.S. Energy-Agnews 28 Combined Cycle 8.817 Oroville Cogen Oroville Oroville Cogeneration, L.P. 8 Reciprocating Engine 14.0 – 15.018 Panoche Energy Center Firebaugh Panoche Energy Center, LLC 399 Simple Cycle CT 9.3 – 13.819 Ripon Ripon AltaGas Ripon Energy Inc. 46 Simple Cycle CT 9.4 – 10.420 Russell City Energy Center Hayward Russell City Energy Company, LLC 601 Combined Cycle 7.2 – 8.021 Starwood Power Midway Firebaugh Starwood Power-Midway, LLC 118 Simple Cycle CT 10.7–12.0
6-5
c. PG&E’s Gas Supply Transactions Are Fully Compliant with 1
Commission Guidance2
PG&E’s [Bundled Procurement Plan (“BPP”)] establishes upfront 3achievable standards and criteria for PG&E’s procurement activities 4and the recovery of procurement costs.35
With respect to natural gas procurement activities, these standards 6
and criteria include approved products, approved procurement methods, 7
approved procurement limits, and specify when consultation with the 8
Procurement Review Group (PRG) is required.9
In 2017, PG&E’s gas procurement activities met these standards 10
and criteria. A high-level review of compliance is provided in this section 11
and a detailed demonstration is provided in each of PG&E’s 12
2017 Quarterly Compliance Reports (QCR), which are included in 13
PG&E’s workpapers to PG&E’s Prepared Testimony. The confidential 14
attachments to the QCRs detail all of PG&E’s transactions for physical 15
gas supply, including product type and method of transaction. 16
1) PG&E Transacted Using Approved Products for Purchase 17
or Sale18
All of PG&E’s electric portfolio transactions for natural gas in 19
2017 were for products approved in PG&E’s 2014 BPP.4 These 20
products are found in Table A-3, Sheet 43 of PG&E’s 2014 BPP. 21
PG&E utilized following products in 2017:22
Natural Gas Physical Supply (Spot and Term);23
Physical Options on Natural Gas Supply; and,24
Gas Storage, including parking and lending.25
Table 6B-1 in Attachment B details total costs allocated to and 26
volumes burned at each generator in PG&E’s portfolio. Attachments 27
to PG&E’s 2017 QCRs detail each transaction, including 28
product type.529
3 2014 BPP, Section I, Sheet 1.4 PG&E’s 2014 BPP, which was approved in D.15-10-031, is included as part of PG&E’s
Chapter 6 confidential workpapers.5 The 2017 QCRs are included as part of PG&E’s Chapter 6 confidential workpapers.
6-6
2) PG&E Transacted Using Approved Procurement Processes1
All of PG&E’s electric portfolio transactions for natural gas in 2
2017 used procurement processes and methods approved in 3
PG&E’s 2014 BPPs. These procurement processes are found in 4
Table B-1, Sheet 56 of PG&E’s 2014 BPP. All of the transaction 5
processes PG&E used in 2017 are listed below:6
Bilateral Transactions, short-term (three months or less);7
Transparent Exchanges, including brokers; and8
Electronic Solicitations.9
For day-ahead transactions—for gas deliveries the next 10
business day, or next few business days, in the event of a weekend 11
or holiday)—bilateral and transparent exchange transactions were 12
the most common procurement process used by PG&E. For 13
longer-term transactions, most were conducted via transparent 14
exchanges and electronic solicitations. The 2014 BPP defines an 15
electronic solicitation as any competitive process where products 16
are requested from the market6 including e-mail, instant message, 17
auction platforms, telephone survey and may also be informed by 18
market prices on transparent exchanges and from brokers. 19
Attachments to PG&E’s 2017 QCRs detail each physical gas 20
transaction, including its procurement method.21
3) PG&E Transacted Within BPP Procurement Limits22
PG&E’s compliance with the 2014 BPP Pipeline Capacity 23
Procurement Limits7 is demonstrated in Table 6B-2 and compliance 24
with the Natural Gas Storage Limits8 is demonstrated in Table 6B-3.25
4) PG&E Consulted With Its PRG as Required26
PG&E is required to consult its PRG for transactions with 27
delivery periods greater than three months. For certain 28
transactions, PG&E may preview the plan or strategy prior to 29
execution, and then share the transactions executed at the next 30
quarterly PRG meeting.9 PG&E made all required consultations 1
with its PRG as follows:2
PG&E reviewed with the PRG transactions with duration longer 3
than three months on:4
1) December 13, 2016, for the first quarter of 2017 5
(January 1-March 31, 2017);6
2) March 21, 2017, for the second quarter of 2017 7
(April 1-June 30, 2017);8
3) June 20, 2017 for the third quarter of 2017 9
(July 1-September 30, 2017); and10
4) September 19, 2017, for the fourth quarter of 2017 11
(October 1-December 31, 2017).12
In these quarterly consultations, PG&E also shared with the 13
PRG, as required by D.15-10-031, any transactions executed 14
according to the previously shared strategy or plan. A copy of each 15
PRG presentation is included in the confidential attachments to the 16
QCR, which are included as workpapers for PG&E’s Prepared 17
Testimony.18
d. Compliance with Ruby Pipeline Decision Requirements19
In its decision approving the Ruby Pipeline contract, the 20
Commission required that:21
[w]henever PG&E seeks Commission approval to recover Ruby 22Pipeline costs, PG&E shall certify that it is paying the lowest 23rate available under the Precedent Agreement. 24This certification may take the form of (a) a sworn declaration 25signed by an officer of PG&E or Ruby under penalty of perjury, 26or (b) any other form deemed acceptable by the Commission.1027
To comply with this requirement, PG&E is providing as 28
Attachment 6A to this chapter a letter from an officer of Ruby Pipeline 29
confirming that the “Most Favored Nations” provision in the PG&E 30
transportation contract with Ruby was not triggered with any other 31
shipper(s) in 2017, that is, PG&E received the lowest rate available to a 32
firm shipper with a term of one year or longer.33
9 D.15-10-031, OP 1h.10 D.08-11-032, OP 3.
6-8
C. Distillate Expenses1
In addition to natural gas, PG&E also purchases distillate as a pilot and 2
backup fuel at Humboldt. Humboldt consists of 10 reciprocating engines, 3
16.3 MW each, that burn a mix of natural gas as primary fuel and distillate as 4
pilot fuel. During times of limited natural gas delivery to the Humboldt area, the 5
units are able to burn 100 percent distillate. During the record period, PG&E 6
consumed distillate fuel for Humboldt at a total cost of $418,949. The 7
calculation is performed on industry acceptable practice of Last-In First Out 8
(LIFO) basis. The LIFO method was first approved by the Commission in Advice 9
Letter 1153-E associated with the Energy Cost Adjustment Clause (precursor to 10
Energy Resource Recovery Account (ERRA)) balancing account.11
D. Water Purchased for Power12
PG&E makes payments to various entities to obtain water for use in PG&E’s 13
hydro generation powerhouses, supplementing what is available from normal 14
inflows. These include water purchases and headwater payments. In addition, 15
PG&E pays water rights fees to the State Water Resources Control Board. 16
PG&E made water-for-power payments totaling $1,864,279 during the record 17
period. Generation benefits are not necessarily coincident within the time period 18
when the payments are made. For example, payment for a water diversion or 19
purchase may occur months after the water was obtained or used.20
E. Nuclear Fuel Expenses21
The framework for PG&E’s 2017 nuclear fuel procurement activity is 22
articulated in the Nuclear Fuel Procurement Plan included in PG&E’s 2014 BPP, 23
Appendix F. Nuclear fuel expenses are based on the amortization of the costs 24
of the in-core fuel, the actual cycle burn-up rate for the re-load, and the Diablo 25
Canyon Power Plant’s monthly generation. Each fuel re-load includes: the 26
costs of uranium; conversion services; enrichment services; fabrication; and 27
state and local use taxes, with the total costs dependent on the specific core 28
10 Calpine Wolfskill Peaker11 Calpine Lambie Energy Center12 Calpine King City Peaker13 Calpine Gilroy Energy Center14 Calpine Los Esteros15 GWF Tracy 16 Ripon Generation Station17 Panoche Energy Center18 Starwood Power Midway19 PG&E Fuel Cell - Hayward20 PG&E Fuel Cell - San Francisco21 Mariposa 22 NRG - Marsh Landing23 Calpine Russell City24 GWF Energy Hanford 25 GWF Energy Henrietta 26 Double C Limited 27 High Sierra Limited 28 Kern Front Limited 29 Badger Creek30 Bear Mountain31 Chalk Cliff32 Live-Oak33 McKittrick
34 Total
35 Total Unit Cost ($/MMBtu)_______________
(a) Some values for volume appear as zero due to rounding.(b) ERRA costs from Table 12-2.
6-AtchB-2
TABLE 6B-2 2017 DEMONSTRATION OF COMPLIANCE WITH
2014 BPP PIPELINE CAPACITY PROCUREMENT LIMITS(a)
Line No. Year
Actual Capacity(MMBtu/day)
Limits(b)
(MMBtu/day)
1 20172 20183 20194 20205 20216 20227 20238 2024
_______________
(a) PG&E's actual pipeline capacity holdings were allless than the 2014 BPP limits therefore PG&E wascompliant with the Pipeline Capacity ProcurementLimits in 2017.
(b) 2014 BPP, Appendix C, Table C-10, Sheet 76.
TABLE 6B-32017 DEMONSTRATION OF COMPLIANCE WITH
2014 BPP STORAGE CAPACITY PROCUREMENT LIMITS(a)
Line No. Year
Actual Withdrawal Capacity
(MMBtu/day)
Withdrawal Capacity Limit(b)
(MMBtu/day)
Actual Injection Capacity
(MMBtu/day)
Injection Capacity Limit(b)
(MMBtu/day)
Actual Inventory (million MMBtu)
Inventory Limit(b)
(million MMBtu)
1 20172 20183 20194 20205 20216 20227 20238 2024
______________
(a) PG&E's actual Withdrawal, Injection, and Inventory capacity holdings were all less than the 2014 BPPlimits therefore PG&E was compliant with the Storage Capacity Procurement Limits in 2017.
On April 19, 2012, the Commission issued D.12-04-046, authorizing 4
PG&E to procure GHG compliance instruments and requiring PG&E to 5
update its 2010 BPP to incorporate the modifications made in that decision, 6
including annual procurement limits. Following that decision, PG&E 7
amended its 2010 BPP to include a GHG Procurement Plan approved by 8
the Commission in late 2012.5 PG&E’s GHG Procurement Plan was 9
subsequently modified in 2014 to reflect changes in regulatory and market 10
conditions.6 In October 2015, the Commission issued D.15-10-031, 11
approving PG&E’s 2014 BPP, which included an amended GHG 12
Procurement Plan and GHG Procurement Limits.13
PG&E’s 2014 BPP addresses the GHG-related procurement authority 14
necessary for PG&E to comply with the obligations associated with the 15
Cap-and-Trade Program. It establishes that PG&E has a need to procure 16
GHG compliance instruments to satisfy its compliance obligation as a 17
covered entity and to fulfill certain contractual requirements. PG&E’s 2014 18
BPP further addresses the means and strategies by which PG&E procures 19
GHG compliance instruments and the limits applicable to such procurement20
and those annual GHG Procurement Limits associated with GHG 21
compliance instrument procurement.22
C. PG&E’s GHG Procurement Activity During the Record Period23
Section B describes the regulatory authority and Commission proceedings 24
to review GHG compliance instrument procurement activities. Section C details 25
the resources in PG&E’s bundled electric portfolio which required PG&E to 26
engage in the GHG compliance instrument procurement activities reviewed in 27
5 In October 2012, the Commission issued Resolution E-4544, approving PG&E’s 2010 BPP, authorizing PG&E to procure allowances and offsets.
6 In December 2013, PG&E filed Advice Letter 4331-E concerning updates to its GHG Plan to reflect updated market and regulatory conditions. Resolution E-4660approved certain changes requested by Advice Letter 4331-E, and PG&E filed Advice Letter 4499-E to comply with the resolution. Advice Letter 4499-E was approved on October 15, 2014.
7-5
this proceeding. This section also details PG&E’s procurement activity in the 1
record period, and describes the actions PG&E took to comply with its 2014 BPP 2
during the course of that procurement.3
1. Facilities Comprising PG&E’s Direct GHG Costs4
PG&E may procure compliance instruments associated with qualifying 5
UOG, imported electricity, and certain tolling facilities where GHG 6
obligations associated with the contract are physically-settled with 7
compliance instruments.78
During the record period, PG&E procured compliance instruments for 9
anticipated GHG obligations related to imported electricity and three of its 10
UOG electric generation facilities: (1) Colusa Generating Station; (2) 11
Gateway Generation Station; and (3) Humboldt Bay Generation Station. 12
During the record period, PG&E did not procure GHG compliance 13
instruments to satisfy contractual obligations to its tolling counterparties 14
because PG&E did not have contractual obligations to physically procure 15
GHG compliance instruments for its tolling counterparties. 16
17
.818
2. PG&E’s GHG Procurement Activity19
Emissions allowances are issued by CARB, and CARB sells allowances 20
through quarterly auctions. CARB also issues offsets credits pursuant to 21
specific protocols set forth in the Cap-and-Trade Regulation. In addition, 22
compliance instruments are available for purchase bilaterally or through the 23
market. 24
25
26
7 Monthly invoices associated with these contracted facilities are available as part of Master Data Request 58 and provide detail concerning fuel quantities associated withPG&E’s physical settlement of GHG.
8
7-6
TABLE 7-1 TRANSACTIONS EXECUTED DURING RECORD PERIOD
TABLE 7-2 PG&E’S PROCURED GHG COMPLIANCE INSTRUMENTS IN THE 2017 RECORD PERIOD
Line No. Procured GHG Compliance Instruments
Quantity (MTCO2e) Cost ($)
Average Cost per Compliance
Instrument (Calculated)
1 Allowances Procured from CARB Auctions2 Allowances Procured from Third Parties
3 Allowances Total
4 Offsets Procured from Third-Parties5 Instruments with Future Vintages procured in the Record
Period (Do not qualify for the current Cap-and-Trade compliance period of 2015-2017)
6 Total Instruments Procured that qualify for the current Cap-and-Trade compliance period of 2015-2017
7 Total Instruments Procured in 2017
3. PG&E’s GHG CARB Auction Procurement Activity1
CARB holds quarterly auctions of current vintage and future vintage2
allowances. The current vintage auction may include allowances of any 3
vintage that can be used in the current year. During the record period,4
CARB made available current vintage allowances (i.e., 2017 vintage and 5
unsold earlier vintage allowances) and future vintage (i.e., 2020)6
allowances. Each quarterly auction has a published settlement price.7
Annually, CARB sets a floor price for its auctions. In 2017, the floor price 8
3. Project Development and Construction Monitoring Results ..................... 8-13
4. Contracts That Began Delivery ................................................................ 8-13
5. Contract Amendments, Consents to Assignment and Other Agreements.................................................................................... 8-14
PACIFIC GAS AND ELECTRIC COMPANYCHAPTER 8
CONTRACT ADMINISTRATION
TABLE OF CONTENTS(CONTINUED)
8-ii
6. Force Majeure Claims.............................................................................. 8-14
In addition to the matters described above, this section describes other 7
matters that occurred during the record period.8
1. Poco Power, LLC v. PG&E9
On December 12, 2016, Poco Power, LLC (Poco) applied for a ReMAT 10
PPA in the as-available non-peaking product type. However, since the 11
proposed project was a solar facility, PG&E determined that the project was 12
ineligible for the as-available non-peaking product type. Poco resubmitted 13
its application with a product type of as-available peaking, and is currently in 14
the queue for an as-available peaking ReMAT PPA. However, on May 1, 15
2017, Poco filed a complaint against PG&E with the CPUC, alleging that 16
PG&E had incorrectly determined that the project was ineligible for the 17
as-available non-peaking product type. On November 17, 2017, PG&E and 18
Poco resolved the complaint for a nominal amount. No costs associated 19
with this complaint were recorded in ERRA.20
8-17
2. Orion Solar I, LLC (PG&E Log No. 33R162)1
During a change of ownership of the project (Orion) during the record 2
period, PG&E identified that PG&E had inadvertently retained in 3
project development security and in excess daily delay 4
damages after the project achieved commercial operation on April 14, 2014.5
Under the PPA, these amounts should have been returned to Orion after the 6
project achieved commercial operation. On September 20, 2017, PG&E 7
returned the amounts owed plus interest to Orion. PG&E does not book the 8
collection or return of project development security to the ERRA balancing 9
account. PG&E books the collection of daily delay damages to ERRA, so 10
the return of the excess daily delay damages plus interest (which together 11
totaled ) was booked to the ERRA balancing account.12
3. Thermal Energy Development Corporation (PG&E Log No. 16P054)13
Thermal Energy's PPA requires the facility to meet its Firm Capacity 14
requirement. Thermal Energy failed to meet the minimum performance 15
requirement by September 1, 2014 and 16
17
18
19
PG&E and 20
Thermal Energy have been in discussions during the record period 21
. This issue has not yet been resolved.22
E. Request for Approval of Amendments23
PG&E requests that the Commission approve the following contract 24
amendments that were executed during the record period. PG&E is not 25
requesting express approval of each amendment entered into during the record 26
period. Many amendments are routine and/or administrative in nature and are 27
approved as a part of PG&E’s contract administration during the record period. 28
Other amendments have been submitted to the Commission for review and 29
approval in separate applications or advice letters. PG&E is requesting express 30
Commission approval of certain contract amendments that are not separately 31
approved through another Commission mechanism or process. Copies of the 32
amendments for which PG&E is seeking approval in this Application, described 33
8-18
in this Section E, are included in PG&E’s confidential workpapers for this 1
chapter. 2
1. Crockett Cogeneration Co (PG&E Log No. 01C045)3
PG&E is requesting Commission review and approval in this ERRA filing 4
of April 7, 2017, and April 28, 2017, letter agreements with Crockett 5
Cogeneration (Log No. 01C045).6
PG&E identified an immediate opportunity to decrease the cost of its 7
generation portfolio and provide customer savings 8
as the CAISO market 9
continued to sustain relatively low prices during the spring of 2017 due to 10
high levels of precipitation during the 2016–2017 winter. On April 7, 2017,11
PG&E and Crockett Cogeneration L.P., executed a “Letter Agreement 12
” whereby Crockett 13
. On April 28, 2017, PG&E and Crockett agreed 14
to .15
F. Conclusion16
The above testimony describes PG&E’s contract administration practices, 17
changes that occurred to the contracts administered, and the results achieved 18
with regard to contract administration during the record period, and 19
demonstrates that PG&E’s contract administration during the record period was 20
reasonable and in compliance with SOC4.2122
8-19
TAB
LE 8
-1
ENER
GY
PUR
CH
ASES
AN
DC
OST
SJA
NU
ARY
1, 2
017
THR
OU
GH
DEC
EMB
ER 3
1,20
17
Line
No
.De
scri
ptio
nJa
n-17
Feb-
17M
ar-1
7A
pr-1
7M
ay-1
7Ju
n-17
Jul-1
7A
ug-1
7Se
p-17
Oct
-17
Nov-
16De
c-17
Tota
l1 2
Tota
l Ene
rgy
(MW
h)16
,106
,656
3To
tal P
aym
ents
($)
$2,1
84,2
03,2
69
4Q
ualif
ying
Fac
ility
and
CHP
Gen
erat
ion
5To
tal E
nerg
y (M
Wh)
3,75
2,78
8
6To
tal P
aym
ents
($)
$290
,104
,651
7Co
nven
tiona
l Gen
erat
ion
8To
tal E
nerg
y (M
Wh)
6,94
0,56
8
9To
tal P
aym
ents
($)
$858
,668
,535
10O
ther
Mus
t-Tak
es
11To
tal E
nerg
y (M
Wh)
135,
571
12To
tal P
aym
ents
($)
2$1
2,07
0,20
5
13To
tal E
nerg
y (M
Wh)
26,9
35,5
83
14To
tal P
aym
ents
($)
$3,3
45,0
46,6
60
1A
djus
tmen
ts fo
r GTS
R co
sts
and
volu
mes
are
not
refle
cted
in th
is ta
ble
2Ne
gativ
e nu
mbe
r due
to re
vers
al o
f acc
rual
to a
ctua
l invo
ice
amou
nt p
aid
Rene
wab
le G
ener
atio
n 1
8-20
TABLE 8-2 CONTRACT ADMINISTRATION
CONTRACTS EXECUTED DURING RECORD PERIOD 2017
Line No. Date PG&E Log Number Project Name Capacity (MW) Contract Type1 1/9/2017 33R407RM Arbuckle Mountain Hydro 0.335 ReMAT2 1/31/2017 33R408RM Grasshopper Flat 1.1 ReMAT3 2/28/2017 04H061QPA4 Indian Valley Hydro 2.9 PURPA4 2/28/2017 13H001QPA El Dorado Hydro (Montgomery Creek) 2.8 PURPA5 3/8/2017 33R409RM Silver Springs 0.6 ReMAT6 4/28/2017 33R410 3 Phases Renewables Inc. 1 0 RPS7 4/28/2017 33R411 Direct Energy Business Marketing , LLC 1 0 RPS8 4/28/2017 33R412 EDF Trading North America, LLC 1 0 RPS9 4/28/2017 33R413 Exelon Generation Company, LLC 1 0 RPS10 4/28/2017 33R414 Peninsula Clean Energy Authority 1 0 RPS11 5/8/2017 33B232 Peninsula Clean Energy Authority N/A EEI Master12 5/18/2017 33R415RM Eagle Solar 3 ReMAT13 6/12/2017 33R416BIO San Luis Obispo AD 0.853 BioMAT14 6/21/2017 33R417RM Sutters Mill Hydroelectric Plant 0.13 ReMAT15 7/21/2017 33R418RM Angels Powerhouse 1 ReMAT16 7/24/2017 01C084QAA Berkeley Cogeneration 9.9 As Available17 9/22/2017 33R419 RE Gaskell West 3 20 RPS18 9/22/2017 33R420 RE Gaskell West 4 20 RPS19 9/22/2017 33R421 RE Gaskell West 5 20 RPS20 10/25/2017 33B230 Silicon Valley Clean Energy Authority N/A EEI Master21 10/25/2017 33B234 The Energy Authority (TEA) N/A EEI Master
22 10/25/2017 33B235 Marin Clean Energy, a California Joint Powers Authority N/A EEI Master
23 11/6/2017 33R422BIO ABEC #2 LLC 1 BioMAT24 11/6/2017 33R423BIO ABEC #3 LLC 1 BioMAT25 11/6/2017 33R424BIO ABEC #4 LLC 1 BioMAT26 11/8/2017 40S007 Calstor, LLC 10 Energy Storage27 11/8/2017 40S008 Sierra Energy Storage 10 Energy Storage28 11/8/2017 40S009 Cascade Energy Storage 25 Energy Storage29 11/8/2017 40S010 Kingston Energy Storage 50 Energy Storage30 11/8/2017 40S011 Diablo Energy Storage 50 Energy Storage31 11/30/2017 04H061QPA5 Indian Valley Hydro 2.9 PURPA
1 Sale of energy and renewable energy credits (RECs).
8-21
TABLE 8-3 CONTRACT ADMINISTRATION
RESOURCE ADEQUACY EXECUTED DURING RECORD PERIOD 2017
Line No. Date PG&E Log Number Project Name1 1/19/2017 33B022P02 Shell Energy North America (US), L.P.2 4/7/2017 33B231P01 Peninsula Clean Energy Authority3 4/12/2017 33B226P02 Sonoma Clean Power Authority4 4/14/2017 33B007P01 Exelon Generation Company, LLC5 4/26/2017 33B113P01 3 Phases Renewables Inc.6 5/10/2017 33B232P01 Peninsula Clean Energy Authority7 6/14/2017 33B022P03 Shell Energy North America (US), L.P.8 6/16/2017 33B022P04 Shell Energy North America (US), L.P.9 7/20/2017 33B113P02 3 Phases Renewables Inc.10 8/16/2017 33B233P01 Direct Energy Business Marketing, LLC11 9/18/2017 33B038P01 NRG Power Marketing LLC12 9/28/2017 33B022Q01 Shell Energy North America (US), L.P.13 10/26/2017 33B113Q01 3 Phases Renewables Inc.14 10/26/2017 33B200Q01 EDF Trading North America, LLC15 10/27/2017 33B021Q01 City of Santa Clara dba Silicon Valley Power16 10/27/2017 33B226Q01 Sonoma Clean Power Authority17 10/27/2017 33B230Q01 Silicon Valley Clean Energy Authority18 10/27/2017 33B233Q01 Direct Energy Business Marketing, LLC19 10/27/2017 33B234Q01 The Energy Authority, Inc.20 10/27/2017 33B235Q01 Marin Clean Energy21 10/31/2017 33B202Q01 Commercial Energy of Montana Inc.22 10/31/2017 33B232Q01 Peninsula Clean Energy Authority23 11/28/2017 33B005Q01 BP Energy Company24 11/30/2017 33B037P01 NextEra Energy Marketing, LLC25 12/12/2017 33B005Q02 BP Energy Company
8-22
TAB
LE 8
-4
CO
NTR
ACT
ADM
INIS
TRAT
ION
PER
MIT
TED
EXT
ENSI
ON
SD
UR
ING
REC
OR
D P
ERIO
D 2
017
Line
N
o.D
ate
of
Req
uest
PG&
E Lo
g N
umbe
rPr
ojec
t Nam
eC
ontr
act T
ype
Des
crip
tion
11/
17/2
017
33R
363
CED
Oro
Lom
a So
lar P
roje
ct A
RPS
GC
OD
* was
ext
ende
d fro
m 1
/20/
2017
to 2
/28/
2017
.2
1/17
/201
733
R36
5Av
enal
Sol
ar P
roje
ct A
RPS
GC
OD
was
ext
ende
d fro
m 1
/20/
2017
to 2
/28/
2017
.3
1/17
/201
733
R36
6C
ED O
ro L
oma
Sola
r Pro
ject
BR
PSG
CO
D w
as e
xten
ded
from
1/2
0/20
17 to
2/2
8/20
17.
41/
17/2
017
33R
368
Aven
al S
olar
Pro
ject
BR
PSG
CO
D w
as e
xten
ded
from
1/2
0/20
17 to
2/2
8/20
17.
53/
9/20
1733
R37
3RM
Roc
k C
reek
SB32
/ReM
ATG
CO
D w
as e
xten
ded
from
3/1
1/20
17 to
4/1
1/20
17.
63/
15/2
017
33R
376
Aspi
ratio
n So
lar G
RPS
GC
OD
was
ext
ende
d fro
m 5
/30/
17 to
7/3
0/17
.7
5/9/
2017
33R
376
Aspi
ratio
n So
lar G
RPS
GC
OD
was
ext
ende
d fro
m 7
/30/
17 to
11/
30/1
7.8
6/2/
2017
33R
387
San
Joaq
uin
1AR
PS9
7/13
/201
733
R38
6Sa
n Jo
aqui
n 1B
GTS
R -
PG&E
Sol
ar C
hoic
e (G
T)10
9/19
/201
733
R40
4Bu
rney
For
est P
rodu
cts
RPS
IED
D**
was
ext
ende
d fro
m 1
0/1/
17 to
10/
31/1
7.11
10/2
4/20
1733
R40
6W
heel
abra
tor S
hast
aR
PSIE
DD
was
ext
ende
d fro
m 1
2/1/
17 to
12/
31/1
7.
*Gua
rent
eed
Com
mer
ical
Ope
ratio
n D
ate
(GC
OD
)**
Initia
l Exp
ecte
d D
elive
ry D
ate
(IED
D)
8-23
TAB
LE 8
-5
CO
NTR
ACT
AD
MIN
ISTR
ATIO
NM
ISSE
D M
ILES
TON
ES D
UR
ING
REC
OR
D P
ERIO
D 2
017
Line
N
o.
Orig
inal
M
ilest
one
Dat
ePG
&E
Log
Num
ber
Proj
ect N
ame
Con
trac
t Ty
peM
ilest
one
Dat
e of
Eve
ntD
escr
iptio
n
13/
11/2
017
33R
370R
M22
45 G
entry
ReM
ATG
uara
ntee
d C
OD
3/20
/17
Term
inat
ed
24/
20/2
017
33R
360R
M22
75 H
atte
sen
ReM
ATG
uara
ntee
d C
OD
4/28
/17
Term
inat
ed
310
/31/
2017
33R
404
Burn
ey F
ores
t Pro
duct
s, A
Joi
nt V
entu
reR
PSIn
itial E
nerg
y D
elive
ry
Dat
e11
/1/2
017
Achi
eved
IE
DD
8-24
TABLE 8-6 CONTRACT ADMINISTRATION
CONTRACTS THAT BEGAN DELIVERING DURING RECORD PERIOD 2017
Line No. Date PG&E Log Number Project Name
Capacity (MW) Contract Type
1 2/24/2017 33R363 CED Oro Loma Solar Project A 10 RPS2 3/1/2017 13H001QPA El Dorado Hydro (Montgomery Creek) 2.8 PURPA3 3/10/2017 33R365 Avenal Solar Project A 7.9 RPS4 3/10/2017 33R368 Avenal Solar Project B 7.9 RPS5 3/10/2017 33R366 CED Oro Loma Solar Project B 10 RPS6 3/14/2017 33R407RM Arbuckle Mountain Hydro 0.335 ReMAT7 3/15/2017 04H061QPA4 Indian Valley Hydro 2.9 PURPA8 3/30/2017 33R373RM Rock Creek 2.796 ReMAT9 4/21/2017 33R362 Portal Ridge Solar C Project 11.4 RPS10 5/2/2017 33R375 Westside Solar 20 RPS11 5/15/2017 33R403RM Matthews Dam Hydro 1.35 ReMAT12 6/17/2017 33R410 3 Phases Renewables Inc. 1 0 RPS13 6/17/2017 33R411 Direct Energy Business Marketing , LLC 1 0 RPS14 6/17/2017 33R412 EDF Trading North America, LLC 1 0 RPS15 6/17/2017 33R413 Exelon Generation Company, LLC 1 0 RPS16 6/17/2017 33R414 Peninsula Clean Energy Authority 1 0 RPS17 8/1/2017 01C084QAA Berkeley Cogeneration 9.9 As Available18 8/15/2017 33R409RM Silver Springs 0.6 ReMAT19 8/22/2017 33R418RM Angels Powerhouse 1 ReMAT20 8/25/2017 33R364 Sunray 2 20 RPS21 10/17/2017 33R417RM Sutters Mill Hydroelectric Plant 0.13 ReMAT22 10/27/2017 33R376 Aspiration Solar G 9 RPS23 11/1/2017 33R404 Burney Forest Products 29 RPS24 12/1/2017 04H061QPA5 Indian Valley Hydro 2.9 PURPA25 12/2/2017 33R406 Wheelabrator Shasta 34 RPS26 12/20/2017 33R383 Bayshore Solar A 2 20 RPS27 12/20/2017 33R384 Bayshore Solar B 2 20 RPS28 12/20/2017 33R385 Bayshore Solar C 2 20 RPS29 12/26/2017 33R382 Bakersfield PV 1 2 5.25 GTSR - PG&E Solar Choice30 12/27/2017 33R388 Bakersfield Industrial 1 2 1 GTSR - PG&E Solar Choice31 12/27/2017 33R392 RE Tranquillity 8 Amarillo 2 20 GTSR - PG&E Solar Choice32 12/28/2017 33R389 Delano Land 1 2 1 GTSR - PG&E Solar Choice33 12/28/2017 33R390 Manteca Land 1 2 1 GTSR - PG&E Solar Choice
1 Sale of energy and renewable energy credits (RECs). 2 The project began deliveries during the record period, but will not start the delivery term until after the record period.
8-25
TABLE 8-7 CONTRACT ADMINISTRATION
CONTRACT AMENDMENTS AND CONSENTS TO ASSIGNMENT DURING RECORD PERIOD 2017
8-26
TABLE 8-7 CONTRACT ADMINISTRATION
CONTRACT AMENDMENTS AND CONSENTS TO ASSIGNMENT DURING RECORD PERIOD 2017(CONTINUED)
8-27
TABLE 8-8 CONTRACT ADMINISTRATION
FORCE MAJEURE CLAIMS DURING RECORD PERIOD 2017
Line No.
Date of Claim
PG&E Log Number Project Name
Contract Type Date Closed Description
1 9/1/2016 33R063 Ivanpah Unit 1 RPS 3/10/20172 9/1/2016 33R064 Ivanpah Unit 3 RPS 3/10/20173 9/1/2016 33R088 High Plains Ranch III RPS 5/30/2017
39 12/31/2017 33R410 3 Phases Renewables Inc. 1 RPS Expired
1 Sale of energy and renewable energy credits (RECs).2 Due to the dependency on a confirmed date for fulfillment of the contract energy quantity and associated RECs, this expiration was not captured in the Q3 QCR Attachment H table of Expirations and Terminations.
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 9
CAISO SETTLEMENTS AND MONITORING
9-i
PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 9
CAISO SETTLEMENTS AND MONITORING
TABLE OF CONTENTS
A. Introduction ....................................................................................................... 9-1
B. CAISO Market Costs ........................................................................................ 9-1
3. Balancing Account Entries for the Record Period .................................... 10-8
D. Conclusion ...................................................................................................... 10-8
10-1
PACIFIC GAS AND ELECTRIC COMPANY 1
CHAPTER 10 2
REVIEW ENTRIES RECORDED IN THE GREEN TARIFF SHARED 3
RENEWABLES MEMORANDUM ACCOUNT AND THE GREEN 4
TARIFF SHARED RENEWABLES BALANCING ACCOUNT 5
A. Introduction 6
In this chapter, Pacific Gas and Electric Company (PG&E) presents its 2017 7
recorded Green Tariff Shared Renewables (GTSR) administrative and marketing 8
costs for reasonableness review, as directed by the California Public Utilities 9
Commission (CPUC or Commission) in Decision (D.) 15-01-051, the Decision 10
Approving Green Tariff Shared Renewables Program for San Diego Gas & 11
Electric Company, Pacific Gas and Electric Company, and Southern California 12
Edison Company Pursuant to Senate Bill 43. In addition, PG&E is presenting 13
costs and revenues recorded to the Green Tariff Shared Renewables Balancing 14
Account (GTSRBA) for review to ensure compliance with applicable tariffs1 and 15
Commission directives, as required in D.15-01-051.2 16
Senate Bill (SB) 43 requires the three large electrical utilities to implement 17
the GTSR Program. SB 43 further requires that participating customers pay the 18
administrative and marketing costs of the GTSR Program.3 The 19
Investor-Owned Utilities (IOU) are collecting administrative costs, as well 20
as marketing costs, from GTSR customers through specific charges. 21
In D.15-01-051, the Commission required that administrative and marketing 22
costs be tracked in a memorandum account and be subject to reasonableness 23
review in each IOU’s annual ERRA compliance review. Costs that are found not 24
to be reasonable cannot be collected from customers participating in the 25
1 GTSRBA – Electric Preliminary Statement GR:
http://www.pge.com/tariffs/tm2/pdf/ELEC_PRELIM_GR.pdf. 2 D.15-01-051, Finding of Fact (FOF 137): Coordinating review of true-up of GTSR
charges and credits with the Energy Resource Recovery Account (ERRA) process will provide greater certainty that entries to the GTSR accounts are stated correctly and are consistent with Commission decisions and Conclusion of Law (COL 59): It is appropriate for an IOU to provide a summary and true-up of costs and revenues against charges and credits applied to GTSR customers on an annual basis, either through the IOU’s annual ERRA process or in a separate application.
3 D.15-01-051, p. 108.
10-2
program and will be borne by shareholders. Program startup costs that are 1
found to be reasonable can be amortized.4 2
In D.15-10-051, the CPUC approved two program offerings under the 3
GTSR: (1) a “green tariff” (which PG&E began offering to customers in 4
January 2016 under the program name “PG&E’s Solar Choice”); and (2) an 5
“enhanced community renewables” (ECR) offering—which PG&E opened for 6
developer participation in November 2015 and is called “Regional Renewable 7
Choice.” In D.16-05-006, the Decision Addressing Participation of Enhanced 8
Community Renewables Projects in the Renewable Auction Mechanism and 9
Other Refinements to the Green Tariff Shared Renewables Program, the 10
Commission provided further refinements to both programs. 11
B. Green Tariff Shared Renewables Memorandum Account 12
1. Description of Costs Incurred 13
In 2017, PG&E incurred $1 million in expenses in order to implement 14
and manage the GTSR Program. These expenses can be broken down into 15
five major categories: (1) program management; (2) Information 16
Technology (IT)/billing system; (3) energy procurement; (4) contact center 17
operations; and (5) outreach. The recorded expenses, by category, are 18
shown in Table 10-1. The expenses were recorded into a memorandum 19
account in accordance with D.15-01-051.5 PG&E implemented careful 20
tracking of administrative and marketing costs through the use of internal 21
order numbers in order to maintain non-participant indifference of 22
such costs.6 23
4 D.15-01-051, p. 113. 5 D.15-01-051, COL 58, p. 178. 6 PG&E is providing workpapers for this chapter which provide additional detail.
10-3
TABLE 10-1 GTSR MEMO ACCOUNT 2017 RECORDED COSTS
Line No. Description Amount
1 Program Management $257,199 2 IT/Billing System 11,620 3 Energy Procurement 116,740 4 Contact Center Operations 46,004 5 Outreach 576,291
6 Total $1,007,854
2. Program Management 1
PG&E incurred $257,199 in 2017 in program management labor to 2
implement and manage the GTSR Program. The activities associated with 3
this work included ensuring compliance with all regulatory requirements, 4
implementing customer-facing changes to rates and tariffs, overseeing the 5
contact center and billing operations functions, addressing customer 6
inquiries, managing Green-e Energy compliance, and filing approximately 7
two dozen required reports. The program management function also 8
managed the external advisory board and ran four advisory board meetings 9
in 2017. 10
This category of expenses also included basic project management 11
functions, such as: developing budgets and detailed schedules; establishing 12
internal reports; and managing regular team meetings. Finally, this category 13
of work included financial planning and analysis for the program, as 14
well as incidental administrative charges, such as the Green-e Energy 15
certification fee. 16
3. IT/Billing System Work 17
PG&E incurred $11,620 in 2017 in expenses associated with 18
implementing and maintaining the IT and billing system work for the GTSR 19
Program. In 2017 the work entailed only minor maintenance and 20
enhancements of the IT and billing system functionality. 21
The back-end billing system functionality enables: determination of 22
customer eligibility; enrollment and de-enrollment; calculation of appropriate 23
charges; bill presentment; and all associated revenue accounting and 24
reporting. The functionality also enables Customer Service Representatives 25
10-4
(CSR) to view customized bill impacts for customers, and provides CSRs 1
the ability to enroll and de-enroll customers. Finally, the customer-facing 2
website and energy portal enable customers to self-serve at a lower cost to 3
the program by viewing the same customized bill impact information online, 4
and to enroll in or de-enroll from the program directly. 5
4. Energy Procurement 6
PG&E incurred $116,740 in energy procurement expenses associated 7
with implementation of the GTSR. This work included annual program 8
forum planning and participation, a filing to allow participation of Distributed 9
Energy Resource Provider aggregations, two ECR solicitations, addressing 10
issues from executed PPAs in the RAM 6 solicitation, and additional 11
miscellaneous program support. 12
This category of work also included the planning and execution of 13
ongoing contract management, settlements, and reporting work, as well as 14
renewable energy credit tracking, reporting, and retirement. 15
5. Contact Center Operations 16
PG&E incurred $46,004 in contact center operations expenses in 2017. 17
These included supporting customer inquiries, enrollment and de-enrollment 18
in the GTSR Program through the contact centers. It also included 19
maintenance of contact center tools and resources, such as the Interactive 20
Voice Response system and the CSR tools, to better support customers in 21
learning about or enrolling in the program. 22
6. Outreach 23
PG&E incurred $576,291 in contract and labor costs in development of 24
outreach strategies and tactical plans in 2017. This included development 25
and deployment of acquisition and retention tactics: digital advertisements; 26
paid social media; e-mails; direct mail; bill inserts; small and large 27
commercial business sales support; website; and integrating the solar 28
choice message within other relevant communications. 29
C. Green Tariff Shared Renewables Balancing Account 30
1. Background 31
As discussed above, the Commission approved D.15-01-051, 32
implementing the GTSR Program in January 2015. PG&E’s program 33
10-5
includes two GTSR electric rate schedules: Schedule-EGT, Green Tariff 1
Program, and Schedule E-ECR, Enhanced Community Renewables 2
Program. Under E-GT, customers purchase energy supplies via a portfolio 3
of new solar photovoltaic (PV) generation facilities sized 0.5 to 20 MW 4
located within PG&E’s service area and under contract with PG&E. In 2017, 5
no customers took service under the E-ECR tariff. Consistent with the 6
legislative requirement that non-participating customers remain indifferent to 7
the GTSR Program, the Commission determined that each IOU is required 8
to establish a balancing account to track the costs and revenues of the 9
program.7 10
The purpose of the GTSRBA is to track revenues received and actual 11
expenses incurred to procure renewable generation resources for customers 12
participating in the GTSR Program, taking service under the Green Tariff 13
Rate (Schedule E-GT) and the Enhanced Community Renewable 14
(Schedule E-ECR). During the record period, customers only took service 15
under the E-GT option. An overview the GTSRMA and GTSRBA are shown 16
in Table 10-2 below. 17
7 D.15-01-051, p. 129; FOF 145, “A balancing account will allow the IOU to track revenue
under and over collection of GTSR costs using balancing account ratemaking standards.”
10-6
TABLE 10-2 MEMORANDUM AND BALANCING ACCOUNTS
2. Rate Design Overview 1
Table 10-3 below provides the framework for how the credit and charge 2
components are included in the E-GT tariff option, by illustrating where each 3
of the components is reflected in the rates shown in the tariff and how the 4
tariff rates are presented on customers’ bills. As shown in the tables below, 5
the rate components will roll-up to either to the Solar Charge, Power Charge 6
Indifference Adjustment (PCIA) Program Charge or the Program Charge – 7
Other (generation-related). 8
10-7
TABLE 10-3 ALLOCATION OF CHARGES AND CREDITS
Revenues billed under the E-GT option are credited to the GTSRBA 1
account. Specifically, billed revenues to be credited to the account are as 2
follows: 3
Solar Generation; 4
Program Charge – PCIA; and 5
Program Charge – Other. 6
Expenses for the E-GT option recorded to the GTRSBA include solar 7
generation expenses, the PCIA Program Charge, and a Program Charge for 8
the other expenses (generation-related), net of marketing and administration 9
costs. Expenses for the solar generation charge are recorded (debited) to 10
the GTSRBA for interim pool of resources used to support the program and 11
are similarly credited from ERRA. As described in the preliminary statement 12
10-8
the debit to GTSRBA based on the solar generation rate, excluding 1
Franchise Fees and Uncollectibles (FF&U) accounts expense, multiplied by 2
customer usage, in kilowatt-hour (kWh).8 3
Expenses for the generation-related program charge were similarly be 4
credited from ERRA and debited to the GTSRBA based on the generation 5
related program charge, less allowance for FF&U accounts expense, 6
multiplied by customer usage, in kWh. 7
The class average generation revenue credit on customer bills was 8
allocated to the generation balancing accounts based on PG&E’s 9
Preliminary Statement I allocations. The generation revenue credits will 10
offset the otherwise applicable schedule’s generation revenues, recorded to 11
the generation accounts. 12
3. Balancing Account Entries for the Record Period 13
Table 10-4 summarizes the balancing account entries for the record 14
period. As described above, the billed revenues and expense recorded to 15
the account follow the categories illustrated in Table 1-3 above, for both 16
billed revenues and expenses incurred. In addition to recording expenses to 17
the account, in December 2017, PG&E recorded a true-up entry to reflect 18
actual cost incurred for the interim pool resources for 2016 and for 2017 19
costs through November 2017. 20
D. Conclusion 21
In this chapter, PG&E described its 2017 recorded administrative and 22
outreach expenses for the GTSR Program. PG&E’s workpapers include more 23
detailed information regarding the specific, recorded administrative and outreach 24
expenses. PG&E requests that the Commission review and approve that 25
its 2017 recorded administrative and outreach expenses are reasonable. 26
Additionally, this chapter presents PG&E’s entries to the GTSRBA for 27
compliance review. PG&E requests that the Commission find the entries were 28
made to the GTSRBA in compliance with the applicable tariffs and Commission 29
directives.30
8 Revisions to the Preliminary Statement Part CP, Energy Resource Recovery Account,
and Preliminary Statement Part I, Rate Schedule Summary, were made to accommodate entries associated with the GTSR Program.
4.a CR A credit entry to the revenue from the E-GT Solar Charge Rate, excluding rf&u (283,702) (227,986) (294,401) (205,382) (226,060) # (234,970) (233,963) (292,983) (288,868) (270,378) (274,226) (315,984) (3,148,901)
4.b CR A credit entry equal to revenue from the E-GT Program Charge rate, excluding the marketing and administrative component of the program charge and excluding rf&u (95,857) (93,604) (117,800) (85,634) (92,194) # (97,618) (99,495) (122,817) (119,979) (112,453) (113,491) (132,768) (1,283,710)
4.c CR A credit entry equal to revenue from the E-ECR Program Charge rate, excluding the market and administrative component of the program charge, and excluding rf&U
Expenses - Solar Charge and Program Charge (includes PCIA)
4.d DR or CR
A debit or credit entry to reflect the solar generation expense associated with the interimpool of renewable resources used to support GTSR Program, if applicable, equal to theSolar Charge rate associated with these resources, excluding the allowance for rf&u,multiplied by the kWh delivered under the program to E-GT customers for the month.
4.e DR or CRA debit or credit entry equal to costs associated with renewable generation resourcesprocured to serve customers participating in GTSR Program and taking service underschedule E-GT.
-
4.f DR or CR
A debit or credit entry to reflect the Program Charge expense associated with the GTSRProgram, excluding marketing and administrative expenses, for customers taking serviceunder Schedule E-GT, equal to the program Charge rate, excluding rf&u, multiplied by thekWh delivered under the program to the E-GT customers for the month.
A debit or credit entry to reflect the Program Charge expense associated with the GTSRProgram, excluding marketing and administrative expenses, for customers taking serviceunder Schedule E-ECR, equal to the Program Charge rate, excluding rf&u, multiplied by thekWh delivered under the program to the E-ECR customers for the month.
-
-
True-up Entries
4.h DR
A debit or credit entry associated with the interim pool of renewable resources equal to thedifference between the Solar Charge rate associated with these resources, excluding heallowance for rf&u, and the actual weighted average solar cost for the interim pool ofrenewable resources, multiplied by the kWh delivered under the program to E-GTcustomers.
9,600 9,600
4.i CR
A debit or credit entry associated with two components of the Program Charge - CaliforniaIndependent System Operator (CAISO) Grid Management Charges (GMC) and WesternRenewable Energy Generation Information System (WREGIS) expenses -equal to thedifference between forecasted rate per kWh for these components and the actual rate perkWh for these components, if applicable, multiplied by the kWh delivered under the programto the E-GT customers and the subscription level in kWh delivered to the E-ECR customers.
A monthly entry equal to interest on the average balance in the account at the beginning ofthe month and the balance after the above entries, at a rate equal to one-twelfth of the rateon three-month Commercial Paper for the previous month, as reported in the FederalReserve Statistical Release, H.15 or its successor.
The following revenue entries shall be made each month:
The following expense entries shall be made each month:
The true-up entries shall be made annually as data becomes available:
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 11
SUMMARY OF ENERGY RESOURCE RECOVERY ACCOUNT
ENTRIES FOR THE RECORD PERIOD
11-i
PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 11
SUMMARY OF ENERGY RESOURCE RECOVERY ACCOUNT ENTRIES FOR THE RECORD PERIOD
TABLE OF CONTENTS
A. Introduction ..................................................................................................... 11-1
B. The Energy Revenue Recovery Account ........................................................ 11-1
C. Greenhouse Gas Costs in the ERRA Balancing Account ............................... 11-3
1. Authority to Record Costs to ERRA ......................................................... 11-3
2. PG&E’s Greenhouse Gas Cost Recording Process ................................. 11-3
a. PG&E’s Process for Recording of Direct GHG Costs ........................ 11-3
b. PG&E’s Process for Recording Financially Settled GHG Emissions Costs ................................................................................ 11-5
D. Updated Trigger Amount for 2017 .................................................................. 11-5
E. PG&E’s Solar Choice Program ....................................................................... 11-6
F. Renewables Portfolio Standard Cost Memorandum Account ......................... 11-6
G. Variance Analysis ........................................................................................... 11-6
H. Conclusion ...................................................................................................... 11-7
11-1
PACIFIC GAS AND ELECTRIC COMPANY 1
CHAPTER 11 2
SUMMARY OF ENERGY RESOURCE RECOVERY ACCOUNT 3
ENTRIES FOR THE RECORD PERIOD 4
A. Introduction 5
This chapter presents the accounting entries made to Pacific Gas and 6
Electric Company’s (PG&E) Energy Resource Recovery Account (ERRA) for the 7
period January 1 through December 31, 2017 (record period). This testimony 8
demonstrates that the entries to the ERRA comply with the recovery 9
requirements adopted by the California Public Utilities Commission (CPUC 10
or Commission). 11
B. The Energy Revenue Recovery Account 12
The ERRA is a balancing account that was established in Rulemaking 13
(R.) 01-10-024, pursuant to Decision (D.) 02-10-062, Ordering Paragraph 14
(OP) 14, as modified by D.02-12-074. The purpose of the ERRA is to record the 15
actual electric procurement costs and ERRA revenues for recovery of those 16
costs, pursuant to D.02-10-062 and D.02-12-074, as well as Public Utilities Code 17
(Pub. Util. Code) Section 454.5(d)(3). As defined in D.02-10-062, as modified by 18
D.02-12-074, costs recorded in the ERRA include the cost of Utility-Owned 19
Generation (UOG) fuels, Qualifying Facility (QF) contracts, inter-utility contracts, 20
California Independent System Operator (CAISO) charges, irrigation district 21
contracts and other power purchase agreements, bilateral contracts, forward 22
hedges, pre-payments and collateral requirements associated with electric 23
procurement and ancillary services, along with other authorized power 24
procurement costs.1 Revenues from surplus power sales are also recorded in 25
1 As described in Chapter 9, “CAISO Settlements and Monitoring,” page 9-6, PG&E
began recording non-ERRA market revenues and costs in memorandum accounts.
11-2
the ERRA.2 The ERRA excludes costs associated with non-fuel UOG costs.3 1
PG&E’s ERRA forecast revenue requirement and associated rates are filed 2
annually in June in a separate CPUC proceeding. 3
D.03-07-030 in the Direct Access Suspension R.02-01-011 determined that 4
the calculation of the ongoing Competition Transition Charge (CTC) in 2004 and 5
in future years would be set in the ERRA Forecast proceeding. Costs that are 6
eligible to be collected as an Ongoing CTC are defined in Pub. Util. Code 7
Section 367(a), including QF purchase power contracts and other historical 8
purchase power obligations; these costs are recorded and recovered through 9
the ERRA. Above-market costs that are determined to be eligible for recovery 10
as an Ongoing CTC are credited out of ERRA and recovered through the 11
Modified Transition Cost Balancing Account. 12
D.06-07-029 and D.07-09-044 approved guidelines for allocation of costs 13
and benefits for resources authorized for the Cost Allocation Mechanism (CAM), 14
which recovers the net capacity costs for resources providing Resource 15
Adequacy benefits. D.10-12-035 subsequently authorized recovery of net 16
capacity costs for certain contracts arising from the QF and Combined Heat and 17
Power Settlement. Both of these resource types are recovered through the 18
CAM rate and recorded to the New System Generation Balancing Account 19
(NSGBA). The Commission authorized the CAM effective January 1, 2012.4 20
Net capacity costs that are eligible for recovery through the CAM are credited 21
out of ERRA and recovered through the NSGBA. 22
In OP 19 of D.02-12-074, the Commission directed the three California 23
Investor-Owned Utilities (IOU) to submit ERRA balancing account activity 24
reports (ERRA activity reports) each month to the Energy Division no later than 25
20 days following the end of the month. These monthly reports provide the 26
Commission with an opportunity to review monthly transactions in advance of 27
2 D.02-12-074 modified D.02-10-062 to include the Electric Energy Transaction
Administration costs in the General Rate Case (GRC) proceedings. 3 As set forth in Appendix D of D.02-10-062, the capital-related revenue requirement
associated with PG&E’s UOG (Diablo Canyon, fossil-fueled plants, and hydroelectric facilities) are recovered through base rates in PG&E’s GRC proceedings. Non-fuel variable operations and maintenance costs are also recovered through the base rates established in GRC proceedings.
4 D.11-12-031, OP 1.
11-3
the annual ERRA Compliance Review application.5 As of December 31, 2017, 1
the balance in the ERRA was under-collected by $70.6 million. Table 11-2 2
summarizes the monthly accounting entries made to the ERRA from January 1 3
through December 31, 2017. 4
On January 16, 2014, the Commission issued D.14-01-011, which among 5
other things approved a settlement agreement between PG&E and Office of 6
Ratepayer Advocates (ORA).6 Section 2.4.3 of the settlement agreement 7
provided that PG&E perform an accounting audit of the ERRA at least once 8
every four years. The first audit covered the January 1, 2013 to December 31, 9
2013 record period. Thus, the January 1, 2017 to December 31, 2017 record 10
period is subject to an audit. PG&E is in process of determining the timing of 11
this audit and will present the results of the audit to ORA once the audit is 12
complete. 13
C. Greenhouse Gas Costs in the ERRA Balancing Account 14
1. Authority to Record Costs to ERRA 15
In OP 10 of D.12-04-046, PG&E was granted authority to recover the 16
costs incurred for greenhouse gas (GHG) compliance instrument 17
transactions through ERRA. Direct GHG costs are recorded pursuant to 18
accounting procedure 5.ah.7,8 Direct GHG costs are those costs related to 19
PG&E’s physical procurement of GHG compliance instruments consistent 20
with its BPP authority. 21
2. PG&E’s Greenhouse Gas Cost Recording Process 22
a. PG&E’s Process for Recording of Direct GHG Costs 23
As explained below, the costs associated with PG&E’s purchases of 24
GHG compliance instruments in a given year will not agree to the costs 25
recorded in the ERRA for the same year. If PG&E were to participate in 26
the quarterly Air Resources Board (ARB) auction, those compliance 27
5 A full set of these 2017 reports are included in PG&E’s confidential workpapers. 6 OP 1 of D.14-01-011 approved the Settlement Agreement. 7 See PG&E’s Electric Preliminary Statement Part CP, ERRA at Sheet 8, available at
http://www.pge.com/tariffs/tm2/pdf/ELEC_PRELIM_CP.pdf. 8 Any applicable broker fees are included in this line item. PG&E is authorized to use
brokers for GHG procurement in its Bundled Procurement Plan (BPP).
11-4
instruments would be recorded to PG&E’s inventory when auction 1
results are released.” GHG compliance instruments and offset credits 2
purchased from other third-party sellers is recorded to PG&E’s inventory 3
when they are received. When GHG emissions are recognized as 4
expense, as described below, the associated cost of compliance 5
instruments are recorded in ERRA at the Weighted Average Cost 6
(WAC) of the inventory.9 7
For any given month, the emissions expense charged to ERRA 8
reflects the product of: (1) the best available volume of emissions (BAV) 9
associated with PG&E’s Direct GHG obligations; and (2) the WAC of 10
GHG compliance instruments in PG&E’s inventory that can be used to 11
satisfy this obligation. 12
The monthly BAV represents PG&E’s best available emissions 13
quantities for the month. After the dispatch month, the emissions are 14
estimated by measuring the quantity of fossil fuels combusted by a 15
generating unit and converting it to GHG emissions equivalent 16
(i.e., millions of metric tons of emissions).10 The BAV is adjusted in 17
subsequent months by “true-ups” or “true-downs” to take into account 18
better information that PG&E receives concerning previous month 19
emissions quantities. 20
The WAC is calculated for each specified compliance period. The 21
WAC is calculated by dividing the total costs associated with purchasing 22
GHG compliance instruments for PG&E’s electric portfolio over time by 23
the number of available compliance instrument units held in inventory for 24
the applicable compliance period. Compliance instruments held in 25
inventory are segregated by their eligible compliance periods (based on 26
the vintage year). This methodology is done in accordance with 27
generally accepted accounting practices. 28
9 When the cost, or debit, is recorded in the ERRA, a corresponding entry, a credit, is
recorded to a liability account, reflecting PG&E’s liability to surrender GHG compliance instruments to the ARB. The inventory and liability accounts are reduced when the GHG compliance instruments have been surrendered to the ARB and/or transferred to a third party.
10 For natural gas generation units, PG&E utilizes a conversion factor of 0.053 metric tons of carbon dioxide equivalent ($/mtCO2e) per Million British Thermal Units.
11-5
The Accounting expense is then determined by comparing the total 1
change in the expected gross emissions expense inception to date less 2
the total cumulative recorded emissions expense inception to date. The 3
emissions expense is based on the current WAC of inventory 4
($/mtCO2e) multiplied by emissions volumes ($/mtCO2e). 5
PG&E and ORA have recently reached a settlement on a verification 6
methodology for purposes of facilitating a transparent and efficient audit 7
as it relates to the recording of Direct GHG costs. The Final Joint 8
Proposal on Potential Verification Method for PG&E’s GHG Emissions 9
and WAC for Future ERRA Compliance Filings is attached as 10
Attachment A. 11
b. PG&E’s Process for Recording Financially Settled GHG Emissions 12
Costs 13
As noted in Chapter 7, Greenhouse Gas Compliance Instrument 14
Procurement, PG&E has the option to elect financial settlement of GHG 15
emissions obligations with some of its tolling counterparties.11 In these 16
cases, GHG emission costs are embedded within the contract payments 17
made to the counterparty and therefore recorded in the same ERRA 18
accounting procedure as the contract costs. For example, financially 19
settled tolling agreement costs for both the contract and GHG emissions 20
payments made to the counterparty are recorded in the ERRA pursuant 21
to accounting procedure 5.p for bilateral contracts. 22
D. Updated Trigger Amount for 2017 23
On March 30, 2017, PG&E submitted Advice Letter (AL) 5040-E requesting 24
that the Commission approve PG&E’s 2017 ERRA Trigger amount of 25
$279 million and the threshold amount of $349 million. The trigger amount is the 26
maximum allowable forecast over- or under-collection before an IOU would be 27
required to file an expedited application for a rate change and is equal to 28
4 percent of the prior year’s generation revenues, excluding the revenues 29
associated with the California Department of Water Resources (CDWR.) The 30
threshold amount is equal to 5 percent of the prior year’s generation revenues, 31
11 See Chapter 7, Section C.1., p. 7-5.
11-6
excluding the revenues associated with the CDWR. The CPUC approved 1
AL 5040-E with an effective date of March 30, 2017. 2
E. PG&E’s Solar Choice Program 3
The Green Tariff Shared Renewables (GTSR) Program became effective 4
January 1, 2016. Consistent with the legislative requirement that 5
non-participating customers remain indifferent to the GTSR Program, the 6
Commission determined that each IOU is required to establish a balancing 7
account to track the costs and revenues of the program. ERRA accounting 8
procedures 5.al, 5.am, 5.an, 5.ao, 5.ap and 5.aq enable the transfer of costs 9
between ERRA and the GTSR balancing accounts. In addition, the IOUs are 10
required to establish a memorandum account to track the program 11
administrative and marketing costs. Chapter 10 of PG&E’s Prepared Testimony 12
includes a presentation of administrative and marketing costs incurred in the 13
GTSR Memorandum Account in 2017 that are subject to reasonableness review 14
in this proceeding. 15
F. Renewables Portfolio Standard Cost Memorandum Account 16
The Renewables Portfolio Standard Cost Memorandum Account (RPSCMA) 17
was established to track third-party consultant costs incurred by the CPUC and 18
paid by PG&E in connection with the CPUC’s implementation and administration 19
of the Renewables Portfolio Standard (RPS) as authorized in D.06-10-050.12 20
The CPUC’s Energy Division reviews and approves invoices it receives from 21
independent consultants. PG&E pays the invoiced amount and records the 22
costs in the RPSCMA, and D.06-10-050 authorizes PG&E to request recovery in 23
rates through the ERRA application or other proceeding as authorized by the 24
Commission.13 In 2017, the Energy Division staff did not submit any invoices to 25
PG&E for payment of consulting services. 26
G. Variance Analysis 27
In Table 11-1, PG&E provides a summary of the ERRA procurement costs 28
recorded in the current record review period compared to the forecast included 29
12 Renewable Portfolio Standard Cost Memorandum Account Preliminary Statement:
http://www.pge.com/tariffs/tm2/pdf/ELEC_PRELIM_EL.pdf. 13 D.06-10-050, OP 8.
11-7
in its 2017 ERRA Forecast November Update Application, approved by the 1
Commission in D.16-12-038.2
TABLE 11-12017 ACTUAL RECORDED COSTS COMPARED TO APPROVED FORECAST
Line No. Description
Electric Preliminary Statement Part CP
Accounting ProcedureReference
2017Actual
Recorded
2017Approved Forecast Variance
1 UOG Hydro (incl. IDWA) 5.l and 5.s2 Nuclear Fuel 5.m and 5.y3 QF Contracts 5.n, 5.o, 5.ae & 5.ag4 Post-2002 RPS Eligible 5.r5 Fuel for UOG/NonUOG Gen
(Including Large Hydro), Bilateral Contracts, and Direct GHG Procurement Costs
5.j, 5.k, 5.p and 5.ah
6 Net Market Purchase 5.c and 5.t
7 Subtotal
8 Bilateral Demand Response 5.x9 Hedging Cost 5.q
10 CAISO-Related Cost 5.i, 5.z, and 5.ac11 Other Cost 5.v, 5.w, 5.aa, 5.ad,
(a) Some totals may not add precisely because of rounding.
As Table 11-1 indicates, PG&E’s procurement costs recorded in ERRA were 3
$204.0 million lower than forecasted primarily due to lower than forecast load 4
and market prices.5
A more detailed variance analysis of forecasted and actual amounts is 6
included in PG&E’s confidential workpapers for Chapter 11.7
H. Conclusion8
PG&E has complied with the Commission’s directives and has appropriately 9
recorded entries to the ERRA. PG&E requests that upon verification and review 10
of the costs and revenues recorded to the ERRA the Commission find the ERRA 11
entries presented in Table 11-2 for the record period are reasonable and in 12
compliance with Commission decisions.13
TABL
E 11
-2EN
ERG
Y R
ESO
UR
CE
REC
OVE
RY
ACC
OU
NT
FOR
TH
E YE
AR E
ND
ING
DEC
EMBE
R 3
1, 2
017
Tarif
f Li
ne
Item
DR/C
RTa
riff D
escr
iptio
nJa
n-17
Feb-
17M
ar-1
7Ap
r-17
May
-17
Jun-
17Ju
l-17
Aug-
17Se
p-17
Oct
-17
Nov-
17De
c-17
FY 2
017
YTD
5.a.
CRA
cred
iten
tryeq
ual
toth
ere
venu
efro
mth
eER
RA
rate
com
pone
ntfro
mbu
ndle
dcu
stom
ers
durin
gth
em
onth
,ex
DXu
ding
the
allo
wan
cefo
rFr
anch
ise
Fees
and
Unc
olle
ctib
le (F
F&U
) Acc
ount
s ex
pens
e;
Bille
d R
even
ues
Cur
rent
Mon
th U
nbille
d R
even
ueR
ever
sal o
f Prio
r Mon
th U
nbille
d R
even
ueG
ross
Rev
enue
s
Less
: FF
&U F
acto
r
Rev
enue
s N
et o
f FF&
U
(30
4,65
6,36
1.26
)
(251
,719
,221
.42)
(2
86,6
78,2
16.6
4)
(277
,633
,268
.35)
(2
96,2
56,2
27.1
4)
(329
,015
,684
)
(390
,255
,781
)
(357
,132
,109
)
(318
,627
,115
)
(265
,911
,909
)
(241
,859
,781
)
(261
,061
,191
)
(3,5
80,8
06,8
65)
5.b.
CRA
cred
iten
tryeq
ualt
oR
MR
and
anci
llary
serv
ices
reve
nues
from
PG&E
-ow
ned
gene
ratio
nfa
cilit
ies;
5.c.
CRA
cred
iten
tryeq
ual
tosu
rplu
ssa
les
reve
nues
allo
cate
dto
PG&E
per
the
Ope
ratin
gAg
reem
ent b
etw
een
PG&E
and
the
DW
R, i
f app
licab
le;
5.d.
CRA
cred
it en
try e
qual
to re
venu
es re
ceiv
ed fr
om S
ched
ule
TBC
C;
5.e.
CRA
cred
it en
try e
qual
to re
venu
e as
soci
ated
with
des
igna
ted
sale
s;
5.f.
DRA
debi
tent
ryeq
ualt
one
gativ
eon
e(-
1)tim
esth
ePo
wer
Cha
rge
Indi
ffere
nce
Adju
stm
ent
(PC
IA)l
ess
the
DW
Rfra
nchi
sefe
e,pu
rsua
ntto
D.0
6-07
-030
,exD
Xudi
ngth
eal
low
ance
for
Fran
chis
e Fe
es a
nd U
ncol
lect
ible
(FF&
U) A
ccou
nts
expe
nse.
5.g.
CRA
cred
iten
tryeq
ualt
oth
eco
sts
for
ongo
ing
CTC
asso
ciat
edw
ithQ
Fob
ligat
ions
and
PPA
oblig
atio
ns, a
bove
the
mar
ket b
ench
mar
k cu
rrent
ly a
dopt
ed b
y th
e C
omm
issi
on;
5.h.
DRA
debi
ten
tryeq
ual
tone
gativ
eab
ove-
mar
ket
cost
s,th
atar
eap
plie
dto
posi
tive
abov
e-m
arke
t cos
ts in
the
MTC
BA;
5.i.
DRA
debi
t ent
ry e
qual
to th
e am
ount
pai
d fo
r ISO
-rela
ted
char
ges;
5.j.
DRA
debi
tent
ryeq
ualt
oth
esu
mfo
rth
em
onth
ofth
epr
oduc
tof
:(1
)th
eM
illion
sof
Briti
shTh
erm
alU
nits
(MM
Btu)
ofna
tura
lga
sbu
rned
daily
for
all
purp
oses
atPG
&E’s
foss
ilpl
ants
;an
d(2
)th
atda
y’s
wei
ghte
d-av
erag
eco
stof
gas
ona
Util
ityEl
ectri
cG
ener
atio
n(U
EG) p
ortfo
lio b
asis
($/M
MBt
u);
5.k.
DRA
debi
tent
ryeq
ualt
oth
esu
mfo
rth
em
onth
ofth
epr
oduc
tof:
(1)
the
barr
els
ofdi
stilla
tean
dhe
avy
fuel
oil
burn
edda
ilyfo
ral
lpu
rpos
esat
the
foss
ilpl
ants
;an
d(2
)th
atda
y’s
wei
ghte
d-av
erag
e co
st o
f dis
tilla
te o
r fue
l oil
per b
arre
l on
a “la
st-in
-firs
t-out
” (LI
FO) b
asis
;
5.l.
DRA
debi
tent
ryeq
ualt
oth
ehy
droe
lect
ricfu
elex
pens
es.
The
fuel
expe
nses
inD
Xude
wat
erpu
rcha
se c
osts
for t
he h
ydro
elec
tric
plan
ts;
5.m
.DR
A de
bit e
ntry
equ
al to
fuel
exp
ense
s fo
r the
Dia
blo
Can
yon
NuD
Xear
Pow
er P
lant
;
5.n.
DRA
debi
ten
tryeq
ual
toto
tal
cost
sas
soci
ated
with
QF
oblig
atio
nsth
atar
eel
igib
lefo
rre
cove
ry a
s an
ong
oing
CTC
;
5.o.
DRA
debi
ten
tryeq
ualt
oto
talc
osts
asso
ciat
edw
ithQ
Fob
ligat
ions
that
are
not
elig
ible
for
reco
very
as
an o
ngoi
ng C
TC;
5.p.
DRA
debi
t ent
ry e
qual
to b
ilate
ral c
ontra
ct o
blig
atio
ns;
5.q.
DRA
debi
t ent
ry e
qual
to h
edgi
ng c
ontra
ct o
blig
atio
ns;
5.r.
DRA
debi
tent
ryeq
ualt
ore
new
able
cont
ract
oblig
atio
nsan
dfe
esas
soci
ated
with
parti
cipa
ting
in W
REG
IS;
5.s.
DRA
debi
tent
ryeq
ualt
oco
sts
asso
ciat
edw
ithirr
igat
ion
dist
rictc
ontra
cts
and
othe
rpur
chas
epo
wer
obl
igat
ions
, exc
ludi
ng W
APA
but i
nclu
ding
cap
acity
con
tract
obl
igat
ions
;
5.t.
DRA
debi
t ent
ry e
qual
to s
pot m
arke
t pur
chas
es;
5.u.
DRA
debi
t ent
ry e
qual
to s
yste
m to
lling
or c
apac
ity c
ontra
ct o
blig
atio
ns;
5.v.
DR/C
RA
debi
t or c
redi
t ent
ry e
qual
to p
re-p
aym
ents
and
cre
dit a
nd c
olla
tera
l pay
men
ts, i
nDXu
ding
al
lass
ocia
ted
fees
,fo
rpr
ocur
emen
tpu
rcha
sean
d,if
appl
icab
le,
reim
burs
emen
tsof
pre-
paym
ents
, cre
dit a
nd c
olla
tera
l pay
men
ts;
5.w
.DR
A de
bit e
ntry
equ
al to
any
oth
er p
ower
cos
ts a
ssoc
iate
d w
ith p
rocu
rem
ent;
5.x.
DRA
debi
tent
ryeq
ualt
oin
cent
ive
paym
ents
rela
ted
toau
thor
ized
bila
tera
ldem
and
resp
onse
agre
emen
ts;
5.y.
DRA
mon
thly
entry
equa
lto
the
inte
rest
onth
em
onth
lynu
DXe
arfu
elin
vent
ory
atth
ebe
ginn
ing
ofth
em
onth
and
one-
half
the
bala
nce
ofth
ecu
rren
tmon
th’s
activ
ity,m
ultip
lied
ata
rate
equa
lto
one-
twel
fthof
the
rate
onth
ree-
mon
thC
omm
erci
alPa
perf
orth
epr
evio
usm
onth
, as
repo
rted
in th
e Fe
dera
l Res
erve
Sta
tistic
al R
elea
se, H
.15
or it
s su
cces
sor;
5.z.
DR/C
RA
cred
it or
deb
it en
try e
qual
to th
e re
venu
es o
r cos
ts re
late
d to
CR
Rs;
5.aa
.DR
Ade
bit
entry
equa
lto
the
incr
emen
tal
IEco
sts
thro
ugh
2014
rela
ted
toR
FOs
seek
ing
term
sof
less
than
five
year
s.Af
ter
2014
,ade
bite
ntry
equa
lto
allI
Eco
sts
rela
ted
toal
lR
FOs;
5.ab
.DR
A de
bit e
ntry
equ
al to
act
ual w
ave
ener
gy p
roje
ct (W
aveC
onne
ct) e
xpen
ditu
res
5.ac
.DR
/CR
A cr
edit
or d
ebit
entry
equ
al to
the
reve
nues
or c
osts
rela
ted
to c
onve
rgen
ce b
iddi
ng;
5.ad
.DR
Ade
bite
ntry
equa
lto
pow
erpu
rcha
sepa
ymen
tspr
ovid
edto
elig
ible
Net
Ener
gyM
eter
ing
cust
omer
sfo
ren
ergy
prod
uced
byon
-site
gene
ratio
nin
exce
ssof
cons
umpt
ion
over
a12
-m
onth
perio
d.Po
wer
purc
hase
paym
ents
may
inD
Xude
addi
tiona
lco
mpe
nsat
ion
for
rene
wab
le a
ttrib
utes
whe
re a
pplic
able
.
5.ae
.DR
A de
bit e
ntry
equ
al to
the
capa
city
and
ene
rgy
cost
s fo
r QF/
CH
P Pr
ogra
m c
ontra
cts.
5.af
.CR
Acr
edit
entry
equa
lto
the
netc
apac
ityco
sts
reco
rded
inth
eQ
F/C
HP
Prog
ram
and
Mar
shLa
ndin
g su
bacc
ount
s of
the
New
Sys
tem
Gen
erat
ion
Bala
ncin
g Ac
coun
t (N
SGBA
).
5.ag
.DR
/CR
Ade
bit
orcr
edit
entry
equa
lto
the
cost
orre
venu
eas
soci
ated
with
com
bine
dhe
atan
dpo
wer
syst
ems
auth
oriz
edin
D.0
9-12
-042
,D.1
0-12
-055
and
D.1
1-04
-03
3,an
dde
fined
inPG
&E’s
tarif
fs E
-CH
P, E
-CH
PS, a
nd E
-CH
PSA;
11-8
TABL
E 11
-2EN
ERG
Y R
ESO
UR
CE
REC
OVE
RY
ACC
OU
NT
FOR
TH
E YE
AR E
ND
ING
DEC
EMBE
R 3
1, 2
017
(CO
NTI
NU
ED)
Tarif
f Li
ne
Item
DR/C
RTa
riff D
escr
iptio
nJa
n-17
Feb-
17M
ar-1
7Ap
r-17
May
-17
Jun-
17Ju
l-17
Aug-
17Se
p-17
Oct
-17
Nov-
17De
c-17
FY 2
017
YTD
5.ah
.DR
Ade
bit
entry
equa
lto
the
GH
Gpr
ocur
emen
tco
sts
for
PG&E
’sG
HG
com
plia
nce
inst
rum
ent t
rans
actio
ns u
nder
the
Cal
iforn
ia c
ap-a
nd-tr
ade
prog
ram
pur
suan
t to
AB 3
2.
5.ai
.CR
Acr
edit
entry
equa
lto
one-
twel
fthof
the
auth
oriz
edfo
reca
sted
dire
ctan
din
dire
ctG
HG
cost
s, d
efer
red
for f
utur
e re
cove
ry in
rate
s.
5.aj
.DR
Ade
bit
entry
equa
lthe
auth
oriz
eden
ergy
stor
age
proc
urem
ent
eval
uatio
npr
ogra
mfu
ndam
ount
aut
horiz
ed in
D.1
4-10
-045
.
5.ak
.DR
Acr
edit
orde
bit
entry
tore
flect
the
sola
rge
nera
tion
expe
nse
asso
ciat
edw
ithth
ein
terim
pool
of r
enew
able
reso
urce
s
5.al
.DR
Acr
edit
orde
bite
ntry
tore
flect
the
Prog
ram
Cha
rge
expe
nse
asso
ciat
edw
ithth
eG
TSR
prog
ram
5.am
.DR
Acr
edit
orde
bit
entry
tore
flect
Prog
ram
Cha
rge
expe
nse
asso
ciat
edw
ithth
eG
TSR
prog
ram
5.an
.DR
Ade
bito
rcr
edit
entry
equa
lto
expe
nses
asso
ciat
edw
ithth
eG
TSR
Prog
ram
’sEn
hanc
edC
omm
unity
Sol
ar (E
CR
) opt
ion
reso
urce
s th
at is
uns
ubsc
ribed
5.ao
.DR
Ade
bit
orcr
edit
entry
totra
nsfe
rex
pens
esfro
mth
eG
TSR
BAfo
rre
new
able
reso
urce
spr
ocur
ed
5.aq
.DR
Ade
bite
ntry
equa
lto
the
year
-end
bala
nce
trans
ferr
edfro
mth
eLo
ng-T
erm
Proc
urem
ent
Plan
Tec
hnic
al A
ssis
tanc
e M
emor
andu
m A
ccou
nt (L
TAM
A).
ERRA
Mon
thly
Act
ivity
Bef
ore
Inte
rest
(65,
316,
402)
(
31,8
00,5
44)
(
60,8
87,2
39)
(
42,0
34,2
97)
(
23,9
09,1
25)
1
00,0
46,7
87
38,9
67,7
63
81,2
88,7
21
41,9
94,6
95
26,7
60,2
50
(
41,6
69,3
30)
(
49,9
63,9
52)
(26
,522
,672
)-
-5.
ap.
DR/C
RA
mon
thly
entry
equa
lto
inte
rest
onth
eav
erag
eba
lanc
ein
the
acco
unta
tthe
begi
nnin
gof
the
mon
than
dth
eba
lanc
eaf
tert
heab
ove
entri
es,a
tara
teeq
ualt
oon
e-tw
elfth
ofth
era
teon
thre
e-m
onth
Com
mer
cial
Pape
rfo
rth
epr
evio
usm
onth
,as
repo
rted
inth
eFe
dera
lR
eser
ve S
tatis
tical
Rel
ease
, H.1
5 or
its
succ
esso
r.
Begi
nnin
g Ba
lanc
e
9
6,75
9,36
8
31
,480
,997
(308
,748
)
(61
,226
,359
)
(103
,320
,223
)
(127
,317
,981
)
(27
,332
,521
)
11
,628
,118
92
,967
,806
135
,074
,568
161
,980
,799
120
,453
,792
96,7
59,3
68
Endi
ng B
alan
ce
3
1,48
0,99
7
(308
,748
)
(61
,226
,359
)
(103
,320
,223
)
(127
,317
,981
)
(27
,332
,521
)
11
,628
,118
92
,967
,806
135
,074
,568
161
,980
,799
120
,453
,792
70
,591
,762
70,5
91,7
62
11-9
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 11
ATTACHMENT A
FINAL JOINT PROPOSAL ON POTENTIAL VERIFICATION
METHOD FOR PG&E’S GREENHOUSE GAS EMISSIONS AND
WEIGHTED AVERAGE COSTS FOR FUTURE ERRA
COMPLIANCE FILING
11-AtchA-i
PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 11
ATTACHMENT A FINAL JOINT PROPOSAL ON POTENTIAL VERIFICATION METHOD FOR
PG&E’S GREENHOUSE GAS EMISSIONS AND WEIGHTED AVERAGE COSTS FOR FUTURE ERRA COMPLIANCE FILING
TABLE OF CONTENTS
A. Definitions of Terms Based on D.14-10-033 ........................................ 11-AtchA-1
B. PG&E's Proposed Definitions of Terms ............................................... 11-AtchA-1
C. Attachments A and B ........................................................................... 11-AtchA-2
D. ORA's Sample ..................................................................................... 11-AtchA-4
E. PG&E's Response to ORA Sample ..................................................... 11-AtchA-4
11-AtchA-1
PACIFIC GAS AND ELECTRIC COMPANY 1
CHAPTER 11 2
ATTACHMENT A 3
FINAL JOINT PROPOSAL ON POTENTIAL VERIFICATION METHOD 4
FOR PG&E’S GREENHOUSE GAS EMISSIONS AND WEIGHTED 5
AVERAGE COSTS FOR FUTURE ERRA COMPLIANCE FILING 6
A. Definitions of Terms Based on D.14-10-033 7
1) Recorded Direct GHG Costs: 8
The recorded direct Greenhouse Gas (GHG) costs include two 9 variables: (a) total direct emissions, and (b) costs of compliance 10 instruments purchased to satisfy this liability. Recorded year direct 11 GHG costs represent the actual costs for Utility-Owned Generation 12 (UOG) and imports, tolls and other contracts for which the utility has 13 responsibility for cap-and trade costs.1,2 14
2) Recorded: 15
We use the term “recorded” to describe both the actual cost and 16 revenue amounts recorded, and the estimate of indirect GHG costs 17 embedded in electricity prices.3 18
3) Direct Emissions: 19
Direct emissions should be calculated on an annual basis based on 20 monthly dispatched resources using methodologies consistent with the 21 Auction Rate Bond regulations for measuring GHG emissions.4 22
B. PG&E's Proposed Definitions of Terms 23
1) “December Close” means represents the best available information/data 24
(i.e., Weighted Average Costs (WAC), emissions volumes, etc.) for the 25
1 D.14-10-033, p.18. 2 D.14-10-033, p.18. Also, Footnote 24, states: “The specific terms of a utility’s contract
may specify whether the utility provides physical compensation (a transfer of compliance instruments) or financial compensation (payment to the entity for the cost of the applicable compliance instruments) for the cap-and-trade costs. Physical settlement is a direct cost, but the utilities can choose to report financially settled tolling agreements as direct or indirect costs. Financially settled qualifying facility contracts where the financial obligation is embedded in the market price of energy purchases or within the specific contract terms for energy payment may be categorized as indirect GHG costs.” D.14-10-033, p. 18.
3 D.14-10-033, Footnote 10, p. 8. 4 D.14-10-033, p. 18.
11-AtchA-2
entire Record Year as of the month ended December, as available during 1
the month end accounting close. 2
2) “Direct Physical GHG Costs” means those actual costs resulting from Pacific 3
Gas and Electric Company’s (PG&E) need to procure GHG compliance 4
instruments in connection with (1) UOG facilities; (2) certain tolling 5
agreements where PG&E elects to physically settle contractual GHG 6
obligations; and (3) electricity imports. Direct Physical GHG Costs are 7
recorded to the Energy Resource Recovery Account (ERRA) Balancing 8
Account Line Item 5 ah. 9
3) “Direct Physical GHG Emissions” are GHG emissions associated with (1) 10
UOG facilities; (2) certain tolling agreements where PG&E elects to 11
physically settle contractual GHG obligations; and (3) electricity imports. 12
4) “Financial GHG Costs” are GHG costs associated with PG&E's tolling 13
agreements and other contracts for which PG&E elects to financially settle 14
contractual GHG obligations or contract with financial settlement specifically 15
for GHG costs. Financial GHG Costs are recorded to ERRA Balancing 16
Account Line Items other than Line Item 5 ah. 17
5) “Financially Settled GHG Emissions” are GHG emissions associated with 18
PG&E's tolling agreements and other contracts for which PG&E elects to 19
financially settle contractual GHG obligations or contracts with financial 20
settlement specifically for GHG costs. 21
6) “PG&E’s Electric Portfolio” includes those UOG or electric generation 22
facilities contracted to PG&E. PG&E’s Electric Portfolio does not include 23
resources use to serve PG&E’s natural gas utility customers. 24
7) “Record Year” refers to the calendar year addressed in an ERRA 25
Compliance Application. 26
C. Attachments A and B 27
In its 2017 and subsequent ERRA Compliance Applications, PG&E is to 28
complete and submit Template C of Attachment C, and Modified Template D-2 29
of Attachment D of D.15-01-024 (See Attachments A and B, respectively 30
provided at the end of this document). Information used to populate 31
Attachments A and B will be as of the close of the Record Year, which is the 32
best available information at the time of December close, and so will not 33
necessarily be identical to tables provided in the ERRA Forecast Proceeding. 34
11-AtchA-3
Information and recorded entries made after December close will not be used to 1
populate information presented in Attachments A and B. 2
1) To support PG&E’s WAC and Direct Physical GHG Costs for the Record 3
Year, PG&E will submit tables in substantially the form of Attachment A as a 4
workpaper to its ERRA Compliance Application. 5
The purpose of Attachment A, Table 1, is to calculate the WAC of 6
compliance instruments of PG&E’s Electric Portfolio.5 WAC is not impacted 7
by financial settlement of contractual GHG obligations. Attachment A, Table 8
1 will be submitted as an active spreadsheet showing all calculations and 9
formulas used. 10
The purpose of Attachment A, Table 2 is to support the applied WAC for 11
monthly Direct Physical GHG Costs of PG&E’s Electric Portfolio. 12
Attachment A, Table 2 will be partially submitted as an active spreadsheet 13
showing all calculations and formulas used. 14
PG&E’s official system of record to calculate the WAC of compliance 15
instruments is Endur. While PG&E can replicate calculations performed in 16
Endur to produce the WAC, numbers calculated in the spreadsheet provided 17
may vary from the official record due to rounding in the Endur system versus 18
the spreadsheet. 19
2) To support PG&E’s recorded monthly Direct Physical GHG Costs and 20
Financial GHG Costs as of the Record Year’s December Close, PG&E will 21
submit a table in substantially the form of Attachment B, as a workpaper (in 22
a spreadsheet format) to its ERRA Compliance Application 23
Included in the spreadsheet (Attachment B), PG&E will provide separate 24
tabs for each of line 2 through line 7, including monthly GHG emissions for 25
5 For definition of recorded direct GHG costs, Refer to section 4.2.1 and Footnote 24 of
D.14-10-033, page 18. D.14-10-033 (page 18) states: “Recorded Direct GHG costs represent the actual costs for utility owned generation and imports, tolls and other contracts for which the utility has responsibility for cap-and-trade costs.” Footnote 24 of the Decision states: “The specific terms of a utility’s contract may specify whether the utility provides physical compensation (a transfer of compliance instruments) or financial compensation (payment to the entity for the cost of the applicable compliance instruments) for the cap-and-trade costs. Physical settlement is a direct cost, but the utilities can choose to report financially settled tolling agreements as direct or indirect costs. Financially settled qualifying facility contracts where the financial obligation is embedded in the market price of energy purchases or within the specific contract terms for energy payment may be categorized as indirect GHG costs.”
11-AtchA-4
the record year, for each source contributing to the total emissions per 1
category recorded as of December close. For example: Line 2 would 2
include 12 months entries for each of PG&E's three UOG facilities. 3
ORA will use PG&E's data provided in Attachment B to draw its sample 4
(See Section 3). 5
D. ORA's Sample 6
The purpose of the sampling approach is for ORA to perform a thorough 7
review and verification of PG&E’s calculations of GHG emissions and associated 8
GHG costs for the Record Year under review. 9
The sample will be based on data submitted by PG&E in Attachment B 10
(Modified Template D-2 of Attachment D of D.15-01-024). 11
Provided that PG&E submits a completed Attachment B at the time it files its 12
ERRA Compliance Application, ORA will draw and provide the sample to PG&E 13
no later than a month from the date PG&E files its ERRA Compliance 14
Application. 15
E. PG&E's Response to ORA Sample 16
No later than three weeks from the date ORA provides the Sample to PG&E, 17
PG&E will provide the information listed in Section 5.1 through Section 5.3 to 18
ORA. 19
5.1) PG&E's GHG Emissions Recorded During the Record Period From Its 20
UOG Facilities, Specified Imports and Unspecified Imports 21
a. Calculations of GHG Emissions 22
PG&E to provide detailed calculations of GHG emissions (in an 23
active spreadsheet format, showing all calculations, assumptions and 24
formulas used), by source for each of the months sampled by ORA. 25
PG&E’s official system of record to calculate the GHG emissions is 26
Endur. While PG&E can replicate calculations performed in Endur to 27
produce the sampled month’s emissions volume, numbers calculated in 28
the spreadsheet provided may have variances due to rounding in the 29
Endur system versus the spreadsheet. 30
b. Supporting Evidence 31
PG&E to demonstrate that the methodology used to calculate the 32
GHG emissions is consistent with the draft emissions calculated under 33
11-AtchA-5
the California Air Resources Board Mandatory Reporting Regulation. 1
Supporting evidence will be calculated using the UOG facility’s gas 2
burns during the record period and an emission factor from the facility’s 3
PG&E to provide detailed calculations of GHG emissions, for each 8
source for each of the months provided in ORA's sample. 9
PG&E will use a spreadsheet in a format similar to the spreadsheet 10
provided by PG&E labelled “Data Request 15 (GHG volumes and 11
costs)” in response to ORA's Data Request 15 Q-2.2); with the addition 12
of one data point: GHG unit cost (such as ICE forward price etc.). 13
For ease of reference, the following Table 11-1 for information on 14
physically-settled contracts provides the fields that should be included to 15
populate the spreadsheet: 16
TABLE 11-1
Source Name Unit Log
number Contract Type
(Tolling/QF/Other)
Emission Date
(Year and Month)
GHG Emissions (MTCO2e)
Physically-Settled
Contracts: Unit GHG
Cost ($/MTCO2e)
GHG Costs
($)
ERRA Tariff line item
b. Supporting Evidence: 17
Invoices showing final settled emissions data and payments. 18
References and excerpts from contracts showing settlement terms 19
covering the calculations of GHG emissions and costs. (See examples 20
from PG&E responses to ORA DR 15, A.17-02-005) 21
5.3) PG&E's Recorded GHG Emissions Recorded During the Record Year 22
From Its Financially-Settled Contracts and/or Tolling Agreements 23
a. Calculations of GHG Emissions and Costs 24
PG&E to provide detailed calculations of GHG emissions and 25
associated costs for each source for each of the months provided in 26
ORA's sample. PG&E will use a spreadsheet in a format similar to the 27
spreadsheet provided by PG&E labelled "Data Request 15 (GHG 28
11-AtchA-6
volumes and costs)" in response to ORA's Data Request 15 Q-2.2); with 1
the addition of one data point: GHG unit cost (such as ICE forward 2
price etc.). 3
For ease of reference, see the following Table 11-2 for information 4
on financially-settled contracts provides the fields that should be 5
included to populate the spreadsheet: 6
TABLE 11-2
Source Name Unit Log
number Contract Type
(Tolling/QF/Other)
Emission Date (Year and
Month)
GHG Emissions (MTCO2e)
Physically-Settled
Contracts: Unit GHG
Cost ($/MTCO2e)
GHG Costs
($)
ERRA Tariff line item
b. Supporting Evidence 7
Invoices showing settled emissions data and payments during the 8
record period. 9
References and excerpts from contracts showing settlement terms 10
covering the calculations of GHG emissions and costs. 11
(See examples from PG&E responses to ORA DR 15, A.17-02-005) 12 13
11-AtchA-7
ATTACHMENT A TABLE 1: REPORTING TEMPLATE TO CALCULATE WEIGHTED AVERAGE COST (WAC) OF
COMPLIANCE INSTRUMENTS IN RECORD YEAR
Month Transaction
Date Transaction
Type Quantity Cost
($/MT)
Sales Price ($)
Total Cost ($)
Inventory Balance
($)
Total Qty in
Inventory WAC
No Formula
No Formula No Formula No Formula
Formula No Formula
Formula Formula Formula Formula
TABLE 2: PG&E RECORDED DIRECT PHYSICAL GHG COSTS IN ERRA (TARIFF LINE ITEM 5.AH.)
Month MM-YY
End of Month WAC Supported by Table 1
Monthly Emissions (MT) Fixed Number, No Formula
End of Month WAC * Monthly Emissions $Formula
Balancing Account Entry with adjustment (as recorded to line 5ah) (Refer to Note 4)
Fixed Number, No Formula (supported by Accounting Entries)
Notes: (1) “Attachment A” reflects Template C of Attachment C of D. 15-01-024. When filing “Attachment
A,” PG&E will follow the definitions and conventions as required in Template C of Attachment C of D. 15-01-024. PG&E will clearly identify and provide explanation including supporting calculations of any entries deviating from the requirements in Template C of Attachment C of D. 15-01-024.
(2) “Attachment A” or Template C of Attachment C of D. 15-01-024 is based (amongst other data) on running weighted average costs of compliance instruments held in inventory since the inception of the program (i.e. since the First Compliance Period under the Cap-and-Trade Program).
(3) PG&E is to provide “Attachment A” in an active spreadsheet format i.e., showing all calculations and formulas used.
(4) PG&E is to provide references and explanation including calculations to any hard entries (not resulting from a calculation or not linked to a referenced calculation).
(5) PG&E is to provide calculations including supporting data used to produce entries recorded under “Balancing Account Entry with adjustment (as recorded to line 5ah),” as applicable. Note; however, the supporting documentation provided for the monthly entries may differ in future years as PG&E will rely on Endur’s automation process to post the monthly entries. Accounting will provide calculations or reconciliations to demonstrate the GHG emissions expenses recorded during each month as reported, to line 5ah, was appropriately calculated. For definitions and descriptions, refer to Attachment C of D. 15-01-024. Attachment A and resulting WAC calculation are confidential.
11-AtchA-8
ATTACHMENT B
Modified Template D-2: Annual GHG Emissions and Associated Costs(a)
ERRA Compliance Application for Record Period Under Review (GHG Emissions Recorded in January through December of Record Year)
4 Energy Imports (Specified) 5 Energy imports (Unspecified) 6 Physically Settled Qualifying Facility
(QF) Contracts
Financially Settled GHG Emissions (MT CO2e)
7 Contracts with Financial Settlement
8 Subtotal
15 GHG Costs ($)
16 Direct Physical GHG Costs
17 Direct GHG Costs - Financial Settlement
______________
(a) As of December, Close of Record Year. Any information recorded or available after December Close will not be reflected in Attachment B.
Notes: (1) "Attachment B" is a modified version of Template D-2 of Attachment D of D. 15-01-024. When
filing "Attachment B," PG&E will follow the definitions and conventions as required in Template D-2 of Attachment D of D. 15-01-024. PG&E will clearly identify and provide explanation including supporting calculations of any entries deviating from the requirements in Template D-2 of Attachment D of D. 15-01-024.
(2) PG&E’s Note: Multiplying monthly WACs shown in Table A and monthly physical emissions shown in Table B will not necessarily replicate monthly accounting entries to ERRA line item 5 ah due to PG&E’s utilization of gross-on, gross-off accounting.
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 12
MAXIMUM POTENTIAL DISALLOWANCE
12-i
PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 12
MAXIMUM POTENTIAL DISALLOWANCE
TABLE OF CONTENTS
A. Introduction ..................................................................................................... 12-1
B. Calculation Methodology for Maximum Potential Disallowance ...................... 12-1
C. Calculation of Maximum Potential Disallowance ............................................ 12-2
D. Conclusion ...................................................................................................... 12-3
12-1
PACIFIC GAS AND ELECTRIC COMPANY 1
CHAPTER 12 2
MAXIMUM POTENTIAL DISALLOWANCE 3
A. Introduction 4
The purpose of this chapter is to present the maximum potential 5
disallowance calculation for Standard of Conduct 4 (SOC4) violations for the 6
January 1-December 31, 2017 record period. SOC4 states that: 7
…the utilities shall prudently administer all contracts and generation 8 resources and dispatch the energy in a least-cost manner.1 9
Pacific Gas and Electric Company (PG&E) agreed to provide this chapter in 10
its Settlement Agreement with the Office of Ratepayer Advocates in the 2014 11
Energy Resource Recovery Account (ERRA) Compliance proceeding 12
(Application (A.) 15-02-023) (Settlement Agreement).2 By providing this 13
testimony, PG&E is not explicitly or implicitly indicating that there were any 14
SOC4 violations during the January 1-December 31, 2017 record period. 15
Rather, PG&E does not believe that there were any SOC4 violations, but is 16
providing this calculation consistent with the Settlement Agreement. 17
B. Calculation Methodology for Maximum Potential Disallowance 18
PG&E’s SOC4 is limited to the administration of contracts and generation 19
resources and to the dispatch of energy in a least-cost manner. Expenses that 20
are included under SOC4: contract negotiation and management; dispatch of 21
Utility-Owned Generation (UOG) and third-party resource; and fuel costs to UOG 22
facilities. There are costs at issue in this proceeding that do not fall under the 23
purview of SOC4, such as the costs for UOG replacement energy or seismic 24
studies cost. 25
SOC4 is limited in scope and, accordingly, the potential for disallowance is 26
also limited. In Decision (D.) 02-12-074, the California Public Utilities 27
Commission (Commission) adopted a limit for potential disallowances of SOC4 28
in Ordering Paragraph (OP) 25. The maximum potential disallowance risk is 29
1 D.02-10-062, pp. 50-52. 2 Settlement Agreement, p. 9. The Settlement Agreement was approved at the
Commission on December 20, 2016 in D.16-12-045.
12-2
equal to two times PG&E’s annual procurement administrative expenditures.3 1
The Commission further defined that “annual procurement administrative 2
expenditures” include costs “related to DWR contract administration, 3
utility-related generation, renewables, QFs, demand-side resources, and any 4
other procurement resources.”4 In D.03-06-067, the Commission modified 5
OP 25 to state that the specific dollar amounts for each utility shall be reviewed 6
in each General Rate Case (GRC) or cost of service proceeding.5 7
C. Calculation of Maximum Potential Disallowance 8
Each year, the maximum potential disallowance risk is based on PG&E’s 9
procurement related administrative expenses and is determined by the most 10
recently adopted GRC decision. On May 18, 2017, the Commission adopted 11
$60.289 million as part of the 2017 GRC Settlement in D.17-05-013. The 12
$60.289 million includes costs comprised of four Major Work Categories (MWC) 13
to support expenses for the Energy Procurement and Policy organization as 14
illustrated in Table 12.1. 15
TABLE 12-1 2017 GRC ADOPTED SETTLEMENT
(MILLIONS OF DOLLARS)
Old Cost Model
New Cost Model
Line No. MWC MWC Description
2017 Adopted
Settlement
2017 Imputed Regulatory
Values
1 CT Acquire and Manage Electric Supply $53,702 $39,218
2 CV Acquire and Manage Gas Supply 4,343 3,239
3 AB Misc. Expense/Support 2,784 1,577
4 CY Manage Electric Grid Operations (GII) – –
5 $60,289 $44,034
The 2017 GRC adopted funding levels do not provide the granularity of the 16
MWC expense line items. Therefore, to calculate PG&E’s maximum 17
3 D.02-12-074, pp. 77-78, OP 25. 4 Id., p. 55. 5 D.03-06-067, p. 23, OP 3.
12-3
disallowance, PG&E uses the Budget Report submitted on July 10, 2017, 1
in compliance with the 2017 GRC D.17-05-013.6 2
Since PG&E’s 2017 GRC was filed, PG&E has changed its cost allocation 3
methodology. As a result, the 2017 GRC decision and adopted values reflect 4
the old cost model allocation methodology which included “fully-loaded” labor 5
cost. To properly compare the adopted level, the adopted values were 6
converted to the new cost allocation methodology, which includes labor plus 7
minimal labor-related overheads. The translated adopted amounts are also 8
referred to as Imputed Regulatory Values. The net result is the reduction from 9
$60.289 million to $44.034 million7 for the relevant MWCs. 10
Thus, the maximum potential disallowance for PG&E’s 2017 ERRA 11
Compliance Review Application is $88.068 million, which is two times 12
$44.034 million. 13
D. Conclusion 14
PG&E requests that the Commission approve its calculation of the maximum 15
potential disallowance provided in this chapter. 16
6 D.17-05-13, p. 233. 7 July 10, 2017 Budget Report, Appendix B, p. AppB-4, lines 83, 85-87, lists PG&E’s
MWCs AB, CT and CV expenses for the Energy Procurement and Policy organization. A copy of the Budget Report has been included as part of the Chapter 12 workpapers.
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 13
COST RECOVERY AND REVENUE REQUIREMENT
13-i
PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 13
COST RECOVERY AND REVENUE REQUIREMENT
TABLE OF CONTENTS
A. Introduction ..................................................................................................... 13-1
B. Incremental Costs and Revenue Requirement ............................................... 13-1
C. Cost Recovery for the Diablo Canyon Seismic Studies Balancing Account ... 13-2
D. Conclusion ...................................................................................................... 13-2
13-1
PACIFIC GAS AND ELECTRIC COMPANY 1
CHAPTER 13 2
COST RECOVERY AND REVENUE REQUIREMENT 3
A. Introduction 4
The purpose of this chapter is to present the 2017 revenue requirement and 5
describe the associated cost recovery proposal for costs recorded in 2017 in the 6
Diablo Canyon Seismic Studies Balancing Account (DCSSBA). Specifically, in 7
this chapter Pacific Gas and Electric Company (PG&E) presents the revenue 8
requirement associated with the costs recorded in the DCSSBA for which PG&E 9
is seeking approval in this proceeding, and proposes to continue the currently 10
adopted cost recovery mechanism for the DCSSBA. 11
B. Incremental Costs and Revenue Requirement 12
PG&E is seeking recovery of a revenue requirement totaling $4.741 million 13
for Diablo Canyon seismic study costs. The revenue requirement is comprised 14
of the actual recorded costs presented in Chapter 5 plus interest and an amount 15
for Revenue Fees and Uncollectibles (RF&U). The electric RF&U factor 16
currently in effect is 0.011389.1 The RF&U amount will be updated to reflect the 17
RF&U factor in effect at the time the California Public Utilities Commission 18
(CPUC or Commission) approves a decision in this filing. Table 13-1 below 19
summarizes the total revenue requirements requested by PG&E in this 20
proceeding. 21
1 See Attachment 2 of Advice 3894-G/5159-E which updated PG&E’s RF&U factor
1 DCSSBA (Chapter 5) $4,529(a) 2 Interest During the Record Period 159 3 Placeholder RF&U(b) 53
4 Total Revenue Requirement $4,741 _______________
(a) Totals may not tie precisely to amounts in Chapter 5 because of rounding.
(b) The placeholder RF&U is calculated using the 2018 factor as approved in Advice 3894-G/5159-E. This amount will be updated using the adopted factor in place at the time of approval by the Commission.
See Chapter 5 for a discussion of costs recorded to the DCSSBA and 1
PG&E’s authority to recover these costs. 2
C. Cost Recovery for the Diablo Canyon Seismic Studies Balancing Account 3
Consistent with the approach PG&E has proposed in previous ERRA 4
compliance proceedings, and which the Commission has adopted, most recently 5
in D.17-03-021 in PG&E’s 2015 ERRA Compliance proceeding,2 PG&E 6
proposes that the actual costs from the DCSSBA, plus an allowance for RF&U, 7
be transferred to the Utility Generation Balancing Account (UGBA), or its 8
successor, as part of the Annual Electric True-Up (AET) for recovery 9
through rates. 10
D. Conclusion 11
PG&E requests that the CPUC approve recovery of a revenue requirement 12
totaling $4.741 million associated with costs recorded in the DCSSBA through 13
the Utility Generation Balancing Account. The total revenue requirement will be 14
adjusted to reflect the final RF&U amount based on the adopted RF&U factor in 15
place at the time this application is approved by the Commission. 16
2 See, D.17-03-021, pp. 8-9, and Ex. PG&E-1, p. 14-5, from that proceeding
(A.16-02-019).
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX A
STATEMENTS OF QUALIFICATIONS
DLB-1
PACIFIC GAS AND ELECTRIC COMPANY 1
STATEMENT OF QUALIFICATIONS OF DONNA L. BARRY 2
Q 1 Please state your name and business address. 3
A 1 My name is Donna L. Barry, and my business address is Pacific Gas and 4
Electric Company, 77 Beale Street, San Francisco, California. 5
Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 6
(PG&E). 7
A 2 I am a Regulatory Principal in Rates and Regulatory Analytics Department 8
within the Regulatory Affairs organization. I am responsible for developing 9
testimony and analysis to support proceedings filed at the California Public 10
Utilities Commission on matters related to energy procurement and 11
cost recovery. 12
Q 3 Please summarize your educational and professional background. 13
A 3 I received my Bachelor of Science degree in Civil Engineering from 14
Washington State University and a Master’s degree in Business 15
Administration from Santa Clara University. 16
I began my career with PG&E in 1989 as an Engineer in the Engineering 17
and Construction Business Unit’s Gas Construction Department managing 18
gas distribution and pipeline replacement construction projects. From there, 19
I took an assignment in the Gas Supply Business Unit in the Gas 20
Engineering and Construction (GEC) Department as a Project Manager, 21
managing three gas backbone transmission projects before joining the Gas 22
Planning section in GEC where I analyzed the reliability of local transmission 23
and distribution systems. I subsequently joined the Cost of Service section 24
in the Rates Department where I performed Cost of Service studies and 25
marginal cost analyses supporting various gas and electric rate applications. 26
I joined the Electric Restructuring Cost Recovery section of the Revenue 27
Requirements Department in 2001 and Electric Energy Revenue and 28
Analysis and Ratemaking section in 2002. I was a Principal Case Manager 29
and Witness for the Energy Resource Recovery Account (ERRA) Forecast 30
and ERRA Compliance Review proceedings between 2003 and 2014 31
responsible for case managing and testimony development. The 32
department and section were renamed as the Energy Supply Proceedings 33
DLB-2
Department in 2012. In 2014, I moved to the Revenue Requirements and 1
Analysis Department and moved to my current position in Rates and 2
Regulatory Analytics in 2017. 3
Q 4 What is the purpose of your testimony? 4
A 4 I am sponsoring the following testimony in PG&E’s 2017 Energy Resource 5
Recovery Account Compliance Review Proceeding: 6
Chapter 10, “Review Entries Recorded in the Green Tariff Shared 7
Renewables Memorandum Account and the Green Tariff Shared 8