pacific gas and electric company application for

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

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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




TABLE OF CONTENTS

(CONTINUED)

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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




TABLE OF CONTENTS

(CONTINUED)

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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

-iv-

TABLE OF ACRONYMS

Line No. Acronym Description

1 A. Application

2 A/S Ancillary Services

3 AB Assembly Bill

4 AC Alternate Current

5 AET Annual Electric True-Up

6 AFW Application for Work

7 AL Advice Letter

8 AMP Aggregator Managed Portfolio

9 ANSI American National Standards Institute

10 ARB Air Resources Board

11 ATS Applied Technology Services

12 BAV best available volume of emissions

13 BCR Bid Cost Recovery

14 BioMASSMA Biomass Memorandum Account

15 BioMAT Bioenergy Market Adjusting Tariff

16 BioRAMMA Bioenergy Renewable Auction Mechanism Memorandum Account

17 BPP Bundled Procurement Plan

18 Btu British Thermal Unit

19 Burney Burney Forest Products

20 CAISO California Independent System Operator

21 CAM Cost Allocation Mechanism

22 CAP Corrective Action Program

23 CARB California Air Resources Board

24 CBP Capacity Bidding Program

25 CCCSIP Central California Coast Seismic Imaging Project

26 CCM cylinder control module

27 CCGT Combined cycle gas turbine

28 CCSN Central Coastal Seismic Network

29 CDWR California Department of Water Resources

30 CEC California Energy Commission

31 CED ConEdison Development

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Line No. Acronym Description 32 CECM Consolidated Energy Contract Management

33 CFR Code of Federal Regulations

34 CFCU Containment Fan Cooler Unit

35 CGS California Geological Survey

36 CHP Combined Heat and Power

37 CIDI Customer Inquiry, Dispute and Information

38 CNO Chief Nuclear Officer

39 CO carbon monoxide

40 CO2 carbon dioxide

41 CO2e carbon dioxide equivalent

42 COD Commercial Operation Date

43 COL Conclusion of Law

44 Commission California Public Utilities Commission

45 CPUC California Public Utilities Commission

46 CRADA Cooperative Research and Development Agreement

47 CRR Congestion Revenue Rights

48 CSA Capacity Storage Agreement

49 CSIAL Customer-Side Implementation Advice Letter

50 CSR Customer Service Representative

51 CSU California State University

52 CSUEB California State University, East Bay

53 CT Combustion Turbine

54 CTC Competition Transition Charge

55 D. Decision

56 DC Direct Current

57 DCPP Diablo Canyon Nuclear Power Plant

58 DCSSBA Diablo Canyon Seismic Studies Balancing Account

59 DLAP Default Load Aggregation Point

60 DR Demand Response

61 DSOD Division of Safety of Dams

62 ECMS Energy Contract Management and Settlements

63 ECP Employee Concerns Program

64 ECR enhanced community renewables

65 EDG Emergency Diesel Generator

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Line No. Acronym Description 66 EDMS Electronic Document Management System

67 EEI Edison Electric Institute

68 EIM Energy Imbalance Market

69 ERRA Energy Resource Recovery Account

70 EN Energy Bid

71 EPI Electricity Price Index

72 ESA Energy Storage Agreement

73 ESTAR Electric Settlements Tool for Analysis and Reporting

74 EUP Enriched Uranium Product

75 °F Degree Fahrenheit (can be used lowercase)

76 FCE FuelCell Energy

77 FERC Federal Energy Regulatory Commission

78 FF&U Franchise Fees and Uncollectibles

79 FLR Forced Loss Rate

80 FMM Fifteen-Minute Market

81 FNM Full Network Model

82 FIT Feed In Tariff

83 FOF Finding of Fact

84 FOF Forced Outage Factor

85 GCOD Guaranteed Commercial Operation Date

86 GE General Electric

87 GEP Guaranteed Energy Production

88 GFN Good Faith Negotiation

89 GHG Greenhouse Gas

90 GMC Ground Motion Characterization

91 GMC Grid Management Charges

92 GO General Order

93 GRC General Rate Case

94 GRIT Generation Risk Information Tool

95 GSP Gas Supply Plan

96 GT Gas Turbines

97 GTSR Green Tariff Shared Renewables

98 GTSRBA Green Tariff Shared Renewables Balancing Account

99 GTSRMA Green Tariff Shared Renewables Memorandum Account

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Line No. Acronym Description 100 GWh gigawatt-hour

101 HANG2 Hassayampa to North Gila

102 HRSG Heat Recovery Steam Generator

103 I&C Instrumentation and Control

104 ICE Intercontinental Exchange

105 ID&WA Irrigation District and Water Agency

106 IDWA Irrigation District Water Associations

107 IEDD Initial Expected Delivery Date

108 IFM Integrated Forward Market

109 IMHR Implied Market Heat Rate

110 IPRP Independent Peer Review Panel

111 IOU Investor-Owned Utility

112 IT Information Technology

113 KRCC Kern River Cogeneration Company

114 kV kilovolt

115 kW kilowatt

116 kWh kilowatt-hour

117 LCD Least-Cost Dispatch

118 LESS low energy seismic survey

119 LIFO Last-In First Out

120 LMP Locational Marginal Price

121 LMPM Local Market Power Mitigation

122 LSE Load Serving Entities

123 LTSA Long-Term Service Agreement

124 LTSP Long Term Seismic Program

125 MAPE Mean Absolute Percentage Error

126 MCFC Molten Carbonate Fuel Cell

127 MDC Maximum Dependable Capacity

128 MMA Major Maintenance Adder

129 MMBtu Millions of British Thermal Units

130 mmt million metric ton

131 MO Maintenance Outages

132 MPR Market Price Referent

133 MRTU Market Redesign and Technology Upgrade

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Line No. Acronym Description 134 MSG Multi-Stage Generation

135 MTCBA Modified Transition Cost Balancing Account

136 mtCO2e metric tons of carbon dioxide equivalent

137 MW megawatt

138 MWh megawatt-hour

139 NERC North American Electric Reliability Corporation

140 NGR Non-Generator Resource

141 NOx nitrogen oxide

142 NQA Nuclear Quality Assurance

143 NRC Nuclear Regulatory Commission

144 NSGBA New System Generation Balancing Account

145 NTTF Near-Term Task Force

146 O&M Operations and Maintenance

147 OBS Ocean Bottom Seismometer

148 OEM Original Equipment Manufacturer

149 OMS Outage Management System

150 OP Ordering Paragraph

151 OP7860 Operation Procedure 7860

152 ORA Office of Ratepayer Advocates

153 PCIA Power Charge Indifference Adjustment

154 PDR Proxy Demand Resource

155 PDS Project Development Security

156 PEER Pacific Earthquake Engineering Research

157 PG&E Pacific Gas and Electric Company

158 PMG permanent magnet generator

159 PO Planned Outages

160 PPA Power Purchase Agreement

161 PRG Procurement Review Group

162 PRV pressure relief valve

163 Pub. Util. Code

Public Utilities Code

164 PURPA Public Utility Regulatory Policies Act

165 PV Photovoltaic

166 QA Quality Assurance

167 QCR Quarterly Compliance Report

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Line No. Acronym Description 168 QF Qualifying Facility

169 QF/CHP Qualifying Facility and Combined Heat and Power

170 QIC Qualifying Facilities Information Center

171 QV Quality Verification

172 RA Resource Adequacy

173 RAM Renewable Auction Mechanism

174 RDRR Reliability Demand Response Resources

175 REC Renewable Energy Credits

176 REC Renewable Energy Certificate

177 REM Regulation Energy Management

178 ReMAT Renewable Market Adjusting Tariff

179 RF&U Revenue Fees and Uncollectibles

180 RFO Request for Offers

181 RMSE Root Mean Square Error

182 RPS Renewable Portfolio Standard

183 RPSCMA Renewable Portfolio Standard Cost Memorandum Account

184 RTD Real-Time Dispatch

185 RTM Real-Time Market

186 RUC Residual Unit Commitment

187 R. Rulemaking

188 SAP WM SAP Work Management

189 SB Senate Bill

190 SC Scheduling Coordinator

191 SCADA Supervisory Control and Data Acquisition

192 SCE Southern California Edison Company

193 SCEC Southern California Earthquake Center

194 SCR Selective Catalytic Reduction

195 SCUC Security Constrained Unit Commitment

196 SDG&E San Diego Gas & Electric Company

197 SFSU San Francisco State University

198 SFWPA South Feather Water and Power Agency

199 SGDP Smart Grid Demonstration Program

200 SLIC Scheduling and Logging ISO California

201 SOC State of Charge

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Line No. Acronym Description 202 SOC4 Standard of Conduct 4

203 SOFC Solid Oxide Fuel Cell

204 SPPC Sierra Pacific Power Company

205 SQS Safety, Quality and Standards

206 SS Self-Scheduling

207 ST Steam Turbine

208 STARS Strategic Teaming and Resource Sharing

209 SWU Separate Working Unit

210 STES Short Term Electric Supply

211 SubLAP Sub Load Aggregation Point

212 T3 Task Tracking Tool

213 UEG Utility Electric Generation

214 UGBA Utility Generation Balancing Account

215 UOG Utility-Owned Generation

216 USGS U.S. Geological Survey

217 V Volt

218 VOC Volatile Organic Compound

219 VOM Variable Operating and Maintenance Cost

220 VP Vice President

221 WAC Weighted Average Cost

222 WM Water Management

223 WM Work Management

224 WRCC Western Regional Climate Center

225 WREGIS Western Renewable Energy Generation Information System

226 YCWA Yuba County Water Agency


CHAPTER 1

LEAST-COST DISPATCH AND ECONOMICALLY-TRIGGERED

DEMAND RESPONSE

1-i

PACIFIC GAS AND ELECTRIC COMPANYCHAPTER 1

LEAST-COST DISPATCH AND ECONOMICALLY-TRIGGERED DEMAND RESPONSE

TABLE OF CONTENTS

A. Introduction....................................................................................................... 1-1

B. Least-Cost Dispatch ......................................................................................... 1-2

1. Structure of LCD Section ........................................................................... 1-2

2. Overview of Least-Cost Dispatch in the CAISO Markets ........................... 1-3

a. Day-Ahead Markets............................................................................. 1-4

b. Real-Time Markets .............................................................................. 1-6

3. PG&E’s Bidding and Scheduling Processes .............................................. 1-7

a. Least-Cost Dispatch Guidelines and Principles ................................... 1-7

1) Least-Cost Dispatch Principles ..................................................... 1-7

2) Incremental Costs ......................................................................... 1-8

3) Self-Scheduling ........................................................................... 1-10

4) Constraints .................................................................................. 1-11

b. 2017 Least-Cost Dispatch Business Process Overview .................... 1-12

1) Load and Price Forecasts ........................................................... 1-12

2) Load Bidding ............................................................................... 1-15

3) Thermal Resource Bidding and Scheduling ................................ 1-15

4) Description of Proxy/Registered Cost Determination for Thermal Resources..................................................................... 1-17

5) Hydro Resource Bidding and Scheduling.................................... 1-18

6) Hydro Self-Scheduling Decisions ................................................ 1-21

7) Helms Pumped Storage Plant Bidding and Scheduling .............. 1-22

8) Battery Storage Bidding and Scheduling..................................... 1-24

9) Resource Bid Non-Submission ................................................... 1-25

10) Market Transactions.................................................................... 1-26



TABLE OF CONTENTS(CONTINUED)

1-ii

11) Must-Take Resources and Contracts.......................................... 1-27

12) Economic Bidding of Renewable Resources............................... 1-27

13) Bid/Award Validation ................................................................... 1-28

4. Summary Reports/Tables Annual Exception Rates ................................. 1-29

a. Incremental Cost Bid Calculation Exceptions .................................... 1-30

b. Self-Commitment Decision Exceptions.............................................. 1-31

c. Master File Data Change Exceptions ................................................ 1-32

5. Least Cost Dispatch Bidding and Scheduling Cost Impacts..................... 1-33

6. Background Summary Table.................................................................... 1-34

7. 2017 Market and Business Process Changes ......................................... 1-35

a. Demand Response Market Integration .............................................. 1-35

b. Commitment Cost Refinements......................................................... 1-36

c. Energy Imbalance Market and Operations ........................................ 1-36

d. 2017 LCD-Related Modeling and Process Changes ......................... 1-37

8. LCD Summary ......................................................................................... 1-37

C. Economically-Triggered Demand Response Programs.................................. 1-37

1. Introduction .............................................................................................. 1-37

2. Capacity Bidding Program ....................................................................... 1-39

a. Description......................................................................................... 1-39

b. Annual Summary of Results .............................................................. 1-40

1) Times and Duration of Program Dispatches................................ 1-40

2) Satisfaction of DR Program Trigger Conditions........................... 1-41

3) Non-Dispatch Occurrences ......................................................... 1-42




1-iii

4) Dispatch Day Selection ............................................................... 1-46

3. SmartAC .................................................................................................. 1-47

4. Aggregator Managed Portfolio ................................................................. 1-47

5. Economically Dispatched Demand Response Summary ......................... 1-48

D. Conclusion...................................................................................................... 1-48

1-1

PACIFIC GAS AND ELECTRIC COMPANY1

CHAPTER 12

LEAST-COST DISPATCH AND ECONOMICALLY-TRIGGERED 3

DEMAND RESPONSE4

A. Introduction5

This chapter describes the Least-Cost Dispatch (LCD) practices and 6

procedures employed by Pacific Gas and Electric Company (PG&E or the Utility) 7

to meet its customers’ electric requirements in a least-cost manner during the 8

January 1 through December 31, 2017 record period. The testimony and 9

workpapers, taken together, provide a qualitative and quantitative demonstration 10

of LCD for each day during the record period.11

During the record period, PG&E complied with the California Public Utilities 12

Commission’s (CPUC or Commission) Standard of Conduct 4 (SOC4), relevant 13

Commission decisions, and PG&E’s 2014 Bundled Procurement Plan (BPP).114

SOC4 and the related CPUC decisions mandate that PG&E utilize its portfolio of 15

existing resources and market purchases to meet its electric load obligations 16

during the record period in a least-cost manner. In Decision (D.) 04-07-028, the 17

Commission ordered that system reliability and deliverability of power should be 18

included as part of LCD. PG&E complied with D.04-07-028 through bidding and 19

scheduling its resources into the California Independent System Operator 20

(CAISO) markets, as described below in Section B.2. The format of this chapter 21

and the associated workpapers is intended to conform with the requirements in 22

D.15-05-006, as modified by D.15-12-015, which adopted a methodology for 23

making an LCD showing in Energy Resource Recovery Account (ERRA) 24

Compliance proceedings (LCD Decisions).25

In addition, pursuant to the Settlement Agreement between PG&E and the 26

Office of Ratepayer Advocates (ORA) dated September 10, 2015, which was 27

approved by the Commission on December 15, 2016 in PG&E’s 2014 ERRA 28

Compliance proceeding (Application (A.) 15-02-023) (2014 ERRA Settlement), 29

1 PG&E’s 2014 BPP was approved in D.15-10-031 and was in effect during the 2017 record period.

1-2

this chapter also addresses agreed-upon additions to the testimony and 1

workpapers. These include the following:2

Testimony/ Workpaper

Section 2014 ERRA Settlement Requirement

B.3.b.1.d; Workpaper 6

An evaluation of PG&E’s price forecast accuracy for all days during the record period

B.3.b.4; Workpaper 1

A description of the decision-making process that PG&E performs to determine whether proxy or registered costs are selected for resources

B.3.b.8; Workpaper 2

Explanations of instances in which bids were not submitted for thermal resources

C Inclusion of PG&E’s dispatch of Demand Respond (DR) programs that have an economic trigger

The 2014 ERRA Settlement calls for: (1) an independent review of PG&E’s 3

short-term day-ahead load and price forecasts; and (2) an independent review of 4

PG&E’s hydro dispatch models, attendant processes, and dispatch results. In 5

consultation with ORA, PG&E hired consultants to conduct the independent 6

reviews. PG&E includes in this chapter descriptions and details to explain the 7

inputs and outputs of the load and price forecasts (Section B.3.b.1). Likewise, in 8

the hydro section of this chapter, PG&E includes descriptions and details to 9

explain the inputs and outputs of its hydro models (Section B.3.b.5). 10

In addition, pursuant to the Settlement Agreement between PG&E and ORA 11

dated November 16, 2016 (2015 ERRA Settlement), filed for approval in PG&E’s 12

2015 ERRA Compliance proceeding (A.16-02-019) and approved in 13

D.17-03-021, this chapter provides a demonstration of PG&E’s revisions and 14

updates of strategies based on above-normal deviations in the load and price 15

forecasts (Section B.3.b.1). Finally, this chapter includes further explanations 16

regarding renewable resource opportunity costs, and an explanation of 17

economic curtailment for PG&E’s renewable resources (Section B.3.b.11). 18

Section B of this chapter addresses LCD, and Section C addresses 19

economically-triggered Demand Response (DR).20

B. Least-Cost Dispatch21

1. Structure of LCD Section22

PG&E will demonstrate in this Section B and in the accompanying 23

workpapers that during the record period it correctly performed LCD. The 24

1-3

format of PG&E’s testimony and workpapers is based on the LCD Decisions 1

and consists of the following:2

Section Subject

B.2 Overview of Least-Cost Dispatch in the CAISO markets

B.3 PG&E’s Bidding and Scheduling Processes

B.4 Summary Reports/Tables – Annual Exception Rates

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

4. Summary Reports/Tables Annual Exception Rates27

Table 1-1 below highlights an index which maps LCD data requirements 28

with PG&E’s demonstration.29

1-30

TABLE 1-1INDEX OF LCD DATA REQUIREMENTS(a) AND PG&E’S RESPONSES

Line No. CPUC/ORA Metric PG&E’s Response

1 Commitment Cost Decisions Testimony: Section B.3.b.4; B.4.cWorkpaper: 1

2 Bid Cost Calculations Testimony: Section B.3.a.2; B.4.aWorkpaper: 2

3 Self-Commitment Testimony: Section B.4.bWorkpaper: 3

4 Dispatchable Hydro Resources Testimony: Section B.3.b.5Workpaper: 4

5 Background Summary Testimony: Section B.5Workpaper: 5

6 Highest Energy Value Days Workpaper: 6

7 Load Bid Testimony: Section B.3.b.2Workpaper: 7

8 Business Processes and Software Documentation

Workpaper: 8

9 Evaluation of PG&E’s Price Forecast Accuracy

Testimony: Section B.3.b.1 Workpaper: 6

10 Decision Making Process for Proxy vs. Registered Costs

Testimony: Section B.3.b.4; B.4.cWorkpaper: 1

11 Explanation of Thermal Bids Not Submitted

Testimony: Section B.3.b.9Workpaper: 2

_______________

(a) Per the LCD Decisions and the 2014 ERRA Settlement.

Additionally, consistent with the LCD Decisions, PG&E is providing the 1

tables below which document the annual summaries of exception rates for 2

incremental cost bid calculations, self-commitment decisions, and Master 3

File data changes. PG&E has work procedures and systems that are 4

intended to detect and prevent internal errors before the fact, and such 5

procedures and systems are subject to continuous improvement as new and 6

unanticipated events occur. 7

a. Incremental Cost Bid Calculation Exceptions8

All bids submitted to the CAISO are reported in PG&E’s confidential 9

workpapers for Chapter 1 under the folder “Bid Sheets.” There are 10

individual files for each resource with a tab for Energy Bid, A/S, and 11

RUC. For dispatchable thermal resources, the actual incremental bid 12

1-31

cost submitted to the CAISO is compared against the calculated cost, 1

using incremental heat rates, VOM cost adders, GHG costs, and natural 2

gas prices. In 2017, 724,557 bids were submitted to the CAISO for 3

gas-fired dispatchable resources, of which 0.32 percent of the awarded 4

bids were found to have a variance (Workpaper 2). 5

Table 1-2 below summarizes the error and potential cost impact for 6

incremental bid cost calculation variances for dispatchable thermal 7

resources during the record period.8

TABLE 1-2INCREMENTAL BID COST CALCULATION VARIANCE – ANNUAL SUMMARY

Line No. Description

No. of Significant Variances

(in Hours) > $0.10% of Total Bid Hour Count

Potential Cost

Impact $

1 User Error 2,210 0.31% –2 External to PG&E 96 0.01 –

3 Total 2,306 0.32% –_______________

Reference: Workpaper 2: Bid Cost Calculation: Table 2.1 – Annual Bid Cost Calculation Variance – Annual 2017.

During the record period, bids submitted with a significant variance 9

(greater than $0.10/MWh) had no cost impact. Additional details, 10

including a description of the variances and corrective actions, can be 11

found in Workpaper 2.12

b. Self-Commitment Decision Exceptions13

The reasons for self-commitment during the record period are 14

described in Section 3 above, “PG&E’s Bidding and Scheduling 15

Processes.”16

Table 1-3 below summarizes exceptions associated with daily 17

self-commitment decisions for dispatchable thermal resources for the 18

record period.19

1-32

TABLE 1-3SELF-COMMITMENT DECISION VARIANCE – ANNUAL SUMMARY

Line No.

Reason Code Description

Total Count (Hour)

Total MWh Energy Self-Committed

1 – –2 User Error 192 1,440

3 Total 192 1,440_______________

Reference: Workpaper 3: Self Commitment: Table 3.1 – Self Commitment –Annual Report.

During the record period, the vast majority of instances of 1

self-commitment were due to non-discretionary, unit testing purposes. 2

However, there was one instance noted in Table 1-3 where exceptions 3

took place. Details regarding these exceptions and the corrective 4

actions are shown in Section 5 and Workpaper 3. 5

c. Master File Data Change Exceptions6

The Master File describes the detailed characteristics of resources. 7

As described in Section 3, “PG&E’s Bidding and Scheduling Processes,” 8

the proxy or registered costs are intended to reflect start-up and 9

minimum load costs and cannot be changed for at least 30 days. This 10

information is used in CAISO’s optimization to commit units. For the 11

record period, the registered and proxy costs were reviewed, and 12

exceptions are noted below, along with potential cost impact due to lost 13

BCR, in Table 1-4. There were no exceptions for the record period. 14

Additional information is included in Workpaper 1.15

1-33

TABLE 1-4 PROXY VS. REGISTERED COST EXCEPTIONS – ANNUAL SUMMARY

Line No.

No. of Times Proxy Used

No. of Times Registered

Used

No. of Incorrect

SubmissionsPotential

Cost Impact

1 Startup 72 – – –2 Min Load 72 – –

3 Total 144 – – –

4 % of Total Startup and Min Load Submissions

100% – –

_______________

Reference: Workpaper 1: Commitment Cost Decisions (xlsx); Table 1.1 – Annual Summary.

5. Least Cost Dispatch Bidding and Scheduling Cost Impacts1

2

3

TABLE 1-5 BIDDING AND SCHEDULING EVENTS WITH IMPACT

4

5

6

7

8

9

10

11

In response to these events, PG&E improved processes/tools and 12

conducted training to help prevent similar events from occurring again. 13

14

15

1-34

1

2

PG&E has incorporated 3

additional checks 4

to help prevent a similar event from occurring again.5

The dynamic management of LCD for an increasingly complex supply 6

portfolio creates inevitable challenges to perfect execution. The 7

Commission has made clear that the Utility is not to be held to a “perfection” 8

standard with respect to LCD. PG&E bids and schedules a large portfolio of 9

about 350 resources, each of which may have individual operational and 10

contract parameters. PG&E demonstrates in this testimony and the 11

supporting workpapers that it bids and schedules resources, and procures 12

energy for customers, so as to (1) minimize CAISO procurement costs and 13

(2) offset energy supply costs with market revenues. PG&E submitted over 14

2,422,900 hourly Day-Ahead bids and self schedules for 15

16

, result from approximately 200 hourly 17

bids of the 2,422,900, or 0.008 percent of bids. PG&E considers this error 18

rate and cost impacts described in this testimony to be within a reasonable 19

manager standard, especially seen in the context of the overall gains to 20

customers of its least cost dispatch processes. In addition, PG&E has 21

instituted rigorous checks to monitor errors and has subjected our internal 22

processes to ever increasing scrutiny.23

6. Background Summary Table24

Table 1-6 below provides a summary of schedule and dispatch data for 25

the record period, corresponding to the requirement in the LCD Decisions. 26

The table reflects an annual summary by resource type (and divided into 27

dispatchable and non-dispatchable resources) for capacity, day-ahead self-28

schedule (SS) awards and day-ahead market awards.29

1-35

TABLE 1-6 BACKGROUND SUMMARY – ANNUAL REPORT

Line No. Dispatchable

Total Capacity (MWh)(a)

Total Unavailable Capacity (MWh)(b)

Total DA SS Awards (MWh)

Total DA Market Awards

(MWh)

1 CHP2 Hydro3 QF4 Renewable(c)

5 Solar6 Storage7 Wind8 Thermal9 Dispatchable Total

Non-DispatchableTotal Capacity

(MWh)(a)

Total Unavailable Capacity(MWh)(b)

Total DA SS Awards (MWh)

Total DA Market Awards

(MWh)

10 CHP11 FIT12 Hydro13 QF14 Renewable(c)

15 Solar16 Wind17 Nuclear18 Non-Dispatchable Total

19 Grand Total_______________

(a) Capacity (MWh) is calculated using the resource’s P-Max MW multiplied by the number of hours in a day during the applicable time period.

(b) Total Unavailable Capacity represents the total capacity unavailable due to planned or forced outages reported in OMS.

(c) The renewable category consists mainly of biomass, biogas, and geothermal resources.

Reference: Workpaper 5: Background Summary (xlsx); Table 5.1 – Annual Report.

7. 2017 Market and Business Process Changes1

PG&E participates in CPUC proceedings and CAISO initiatives on 2

changes to market design and implementation and then integrates market 3

changes to internal processes. Below is a summary of major market 4

initiatives, changes to PG&E’s resource mix, business process changes and 5

LCD-related modeling and process changes. 6

a. Demand Response Market Integration7

In compliance of the CPUC Rulemaking 13-09-011, PG&E 8

completed enabling one Reliability Demand Response Resources 9

1-36

(RDRR) Program (the Base Interruptible Program) to respond to the 1

CAISO real-time market on May 1, 2017. The implementation allowed 2

PG&E to call the underlying retail program to meet CAISO real-time 3

market dispatches. The bid quantity of RDRR is based on a customer 4

availability forecast provided by a vendor product. The bid price is 5

within the CAISO tariff price range of 95-100 percent of the bid cap.6

Under the same CPUC rulemaking, PG&E was to complete its 7

efforts for all other DR programs (Capacity Bidding Program (CBP), 8

SmartAC™) to be bid as Proxy Demand Resource (PDR) in the CAISO 9

Day-Ahead Market by January 1, 2018. The bid quantity of PDR is 10

based on customer availability forecast provided by the same vendor 11

product as RDRR and the bid price is based on the short-term price 12

forecast.13

b. Commitment Cost Refinements14

There was one change in the Commitment Cost policy that impacted 15

how PG&E bids resources. On December 1, 2017, the CAISO made a 16

small modification to the Electricity Price Index (EPI) for resources with 17

electric usage on startup. The EPI is used for resources with auxiliary 18

power needs on startup as part of the proxy start-up cost calculation. 19

The EPI retail price was modified from time-of-use (peak, off-peak) 20

prices to daily prices. PG&E updated its systems and business 21

processes to conform with this change.22

c. Energy Imbalance Market and Operations23

In 2014 and 2015, the CAISO implemented its Energy Imbalance 24

Market (EIM), integrating two PacifiCorp balancing areas and the NV 25

Energy balancing area into the CAISO real-time markets processes. On 26

October 1, 2016, the CAISO integrated the Puget Sound Energy and 27

Arizona Public Service balancing areas into the EIM. On October 1, 28

2017, the CAISO integrated Portland Gas and Electric into the EIM. The 29

EIM implementation did not require changes to bidding systems during 30

the record period, so PG&E’s review of the market changes focused on 31

the visibility and correctness of market results and new public market 32

1-37

data sources, participation in stakeholder processes, verification of 1

settlements correctness, and participation in CAISO market simulations.2

As further background on the EIM and integration, the day-ahead 3

market processes did not change and continued to be limited to 4

representing internal CAISO supply and demand, and interchanges at 5

boundary tie points of the CAISO balancing area. However, in real time, 6

the “footprint” of the market expanded substantially, with the aim of 7

enabling increased efficient, automated energy trading between the 8

Balancing Areas. A significant expansion of the detailed network model 9

(FNM expansion) used by the CAISO in evaluating electric network 10

transmission accompanied the EIM. The expanded FNM includes 11

information on resources, load and interchange schedules in other 12

Balancing Authority Areas to avoid uncontrolled “loop flows” that reduce 13

the efficiency of transmission within the CAISO markets.14

d. 2017 LCD-Related Modeling and Process Changes15

During the record period, PG&E did not have additional significant 16

LCD- related modeling or process changes other than what has been 17

described above.18

8. LCD Summary19

Section B, “Least-Cost Dispatch” provides a detailed discussion of the 20

CAISO markets, LCD guidelines and principles, PG&E’s resource-specific 21

LCD processes, and LCD documentation and process improvements. 22

PG&E managed its portfolio according to LCD principals and within a 23

reasonable manager standard, with an overall error rate of 0.1 percent.1624

The detailed workpapers supporting this chapter provide all of the actual 25

detailed input and output, information for each day during the record period 26

that demonstrates that PG&E achieved LCD for each day. 27

C. Economically-Triggered Demand Response Programs28

1. Introduction29

This section addresses PG&E’s dispatch of DR programs with an 30

economic trigger during the record period, as directed by the LCD 31

16 The error rate associated with cost impacts is 0.008 percent, as described in Section 5.

1-38

Decisions. Specifically, these decisions require PG&E to include in this 1

application metrics proposed by ORA concerning the dispatch of 2

DR programs with economic triggers. For purposes of this section, the 3

term “dispatch” refers to times when PG&E activates a DR program to 4

reduce load.5

PG&E utilized its DR portfolio during the record period to provide load 6

reductions that enhanced reliability, and reduced peak demand and 7

associated prices. For the record period, dispatch of DR resources was 8

well aligned with periods of high load and high prices. Instances in which 9

economic triggers were met, but DR resources were not dispatched were 10

due to operational constraints of the programs, or due to opportunity costs 11

associated with “customer fatigue,” extraordinary heatwaves and/or 12

congestion conditions that affected resources. During the record year, 13

PG&E operated two DR programs which have economic triggers, the 14

Capacity Bidding Program (CBP) and the SmartAC Program. The 15

Aggregator Managed Portfolio (AMP), which also had an economic trigger, 16

was discontinued on December 31, 2016.17

The remainder of this section consists of the following subsections:18

1) A description of the CBP and a summary of its dispatch during the 19

record period. This includes information about when the program’s 20

trigger conditions were forecasted to be met and when the programs 21

were dispatched. Also included is an explanation of non-dispatch 22

decisions, including the instances when CBP triggers were met but not 23

dispatched, and a description of PG&E’s opportunity cost methodology.24

2) A description of the SmartAC Program, which can be, but was not, 25

economically dispatched during the record period.26

3) A description of the AMP, which was economically dispatched in 27

previous record years, but was closed on December 31, 2016.28

4) Economically Dispatched Demand Response Summary.29

Table 1-7 below provides specific references to testimony or 30

attachments to this chapter that address ORA’s metrics.31

1-39

TABLE 1-7INDEX OF ORA’S METRICS AND PG&E’S RESPONSES

Line No.

ORA’s Metric PG&E’s Response

1 1A Section 2.b.1), Attachment 1A2 1B Attachment 1A3 1C Section 2.b.3), Attachment 1A4 2 Section 2.b.2), Attachment 1B5 3A Attachment 1C6 3B Attachment 1C7 3C Attachment 1C8 4 Section 2.b.3), Attachment 1A9 5 Section 2.b.3)

10 6A Section 2.b.4)11 6B Section 2.b.4)12 6C Section 2.b.4)13 7 Section 2.b.3)

2. Capacity Bidding Program1

a. Description2

The CBP is a voluntary DR program that offers customers capacity 3

and energy payments for being on standby to reduce load and for 4

reducing energy consumption when requested by PG&E. Customers 5

enroll through a third-party aggregator and participate in either a 6

day-ahead notification product or a day-of notification product. CBP 7

operates from May through October, between the hours of 11 a.m. and 8

7 p.m. It is dispatched geographically by Sub Load Aggregation Point 9

(SubLAP). The length of a dispatch is one to four hours. 10

CBP can be dispatched for the following reasons: when PG&E’s 11

procurement stack is expected to require the dispatch of electric 12

generation facilities with heat rates of 15,000 British Thermal Unit 13

(Btu)/kilowatt-hour (kWh) or greater for the day-ahead market and the 14

CAISO day-ahead market price exceeds $70/MWh; when PG&E 15

receives a market award for a PDR bid or dispatch instruction from the 16

CAISO; when PG&E forecasts that generation resources or electric 17

system capacity may not be adequate; or when forecasted temperature 18

for a Load Zone exceeds the temperature threshold for the Load Zone. 19

The $70/MWh price trigger, implemented on June 1, 2017, was 20

designed to target five economic CBP events per month, to provide 21

transparency to aggregators and customers, and to reduce the number 22

1-40

of dispatch exceptions. In 2017, both the $70/MWh price trigger and the 1

15,000 Btu/kWh heat rate trigger had to be met to dispatch a CBP 2

event. PG&E’s dispatch tools were expanded to determine when the 3

CAISO day-ahead market price exceeded the price $70/MWh trigger for 4

each program hour in each SubLAP. 5

b. Annual Summary of Results6

1) Times and Duration of Program Dispatches7

During the record period, PG&E dispatched resources in its 8

CBP Day-Ahead and CBP Day-Of programs on 47 occasions. All 9

dispatches resulted from exceeding both the 15,000 Btu/kWh trigger 10

and the $70/MWh trigger. The number of 2017 CBP events was 11

close to the number of combined CBP and AMP events in previous 12

years (49 in 2016 and 52 in 2015). During the record period, the 13

CBP met trigger conditions 52 fewer hours than 2016. Nonetheless, 14

it was dispatched 14 more hours during the record period. The 15

implementation of the price trigger on June 1, 2017 resulted in 16

greater utilization of CBP resources, as discussed in further 17

detail below.18

Table 1-8 below provides additional detail and a comparison of 19

CBP event count and frequency for 2013 through 2017.20

TABLE 1-8CAPACITY BIDDING PROGRAM DEMAND RESPONSE PROGRAM DISPATCH

Line No. Year

Capacity Bidding Program

Day-Ahead Total Events/Hours

Day-of Total Events/Hours

1 2013 5/20 5/192 2014 11/41 15/603 2015 16/63 18/724 2016 16/58 19/69 5 2017 22/67 25/71

During the record period, PG&E conducted more than 40 formal 21

event dispatch decision-making meetings (Tailboards) in addition to 22

many informal limited scope discussions. During the Tailboards and 23

discussions, PG&E reviewed meteorological forecasts, CAISO and 24

1-41

PG&E peak demand and implied heat rate forecasts, the CAISO’s 1

published day-ahead energy price, and other market and qualitative 2

information. Using this information, PG&E matched its DR 3

dispatches to times of greatest need, from both a pricing and a 4

peak demand perspective, including both PG&E and CAISO 5

system peaks.6

Attachment 1A provides a summary of: (a) the times and 7

duration that all programs were dispatched; (b) all cases where CBP 8

trigger conditions were forecast to be met and all cases where these 9

trigger conditions were actually met; and (c) a list of occurrences 10

when DR resources met program triggers but were not dispatched, 11

along with an explanation of the reason for non-dispatch.12

2) Satisfaction of DR Program Trigger Conditions13

Table 1-9 below summarizes the annual number of hours CBP 14

was dispatched in each SubLAP compared to the annual number of 15

hours that CBP was available. Also included is the annual number 16

of events dispatched compared to the maximum number of 17

events allowed.1718

17 The maximum number of events was established in Resolution E-4819 and implemented on June 1, 2017.

1-42

TABLE 1-9ANNUAL CAPACITY BIDDING PROGRAM HOURS DISPATCHED

LineNo. Load Zone

Number of Hours

Day-Ahead Trigger

Was Met

Total Day-Ahead

Event Hours

Dispatched

Number of Day-Ahead

Events

Number of Hours Day-Of Trigger

Was Met

Total Day-Of Event Hours

Dispatched

Number of Day-Of Events

Maximum Allowable

Event Hours/Year(a)

Maximum AllowableNumber of

Events/ Year(b)

1 PGCC 88 64 21 90 64 23 180 302 PGEB 95 64 21 97 68 24 180 303 PGF1 81 62 20 80 60 22 180 304 PGFG 91 47 15 94 61 20 180 305 PGHB 82 64 21 83 63 22 180 306 PGKN 83 64 21 80 60 22 180 307 PGNB 91 47 15 94 61 20 180 308 PGNC 85 52 17 82 55 18 180 309 PGNP 86 64 21 87 64 23 180 30

10 PGP2 89 64 21 90 64 23 180 3011 PGSB 89 64 21 90 64 23 180 3012 PGSF 87 62 20 90 64 23 180 3013 PGSI 81 62 20 80 60 22 180 3014 PGST 92 67 22 89 63 23 180 3015 PGZP 83 64 21 80 60 22 180 30

_______________

(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

BUT RESOURCE NOT DISPATCHED

Line No. Load Zone

Day-Ahead Hours

Day-Of Hours

1 PGCC 24 262 PGEB 31 293 PGF1 19 204 PGFG 44 335 PGHB 18 206 PGKN 19 207 PGNB 44 338 PGNC 33 279 PGNP 22 23

10 PGP2 25 2611 PGSB 25 2612 PGSF 25 2613 PGSI 19 2014 PGST 25 2615 PGZP 19 20

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

be included in the ERRA Compliance proceeding. 26

1-48

5. Economically Dispatched Demand Response Summary1

PG&E utilized the CBP, the only economically dispatched program 2

during the record period, to provide load reductions that enhanced reliability 3

and reduced peak demand and associated prices. DR resources were well 4

aligned with high load and price time periods. While PG&E did not dispatch 5

its DR resources each time an economic trigger was met, instances of non-6

dispatch were due to operational constraints of the programs or due to 7

opportunity costs associated with customer impact. 8

D. Conclusion9

In compliance with the LCD Decisions and 2014 ERRA Settlement, this 10

chapter and the associated work papers have demonstrated that PG&E:11

Achieved LCD during the record period; and12

Reasonably utilized, integrated and improved the dispatch for economic 13

DR resources during the record period.14

PG&E has fully complied with the Commission decisions addressing LCD 15

practices during the record period, and has provided testimony and workpapers 16

that are consistent with the LCD Decisions to satisfy PG&E’s prima facie17

burden of proof to demonstrate that it achieved LCD. This testimony and the 18

confidential workpapers for Chapter 1 demonstrate that PG&E dispatched 19

its resources in a manner consistent with LCD requirements during the 20

record period.21

PG&E also utilized its DR portfolio during the record period to provide load 22

reductions that enhanced reliability and reduced peak demand and associated 23

prices. In addition, PG&E has provided the information and metrics required by 24

the LCD Decisions for LCD and its economically-triggered DR Programs. 25

Finally, where applicable, the Chapter 1 testimony and workpapers satisfy the 26

requirements of the 2014 ERRA Settlement.27


CHAPTER 1

ATTACHMENT A

SUMMARY OF TRIGGERED DISPATCH FROM

DEMAND RESPONSE PROGRAMS

Atta

chm

ent A

- Tr

igge

rs M

et -

DR

Pro

gram

Dis

patc

hed

Dat

e Tr

igge

r Con

ditio

n W

as F

orec

ast

to b

e M

etTy

pe o

f Tr

igge

rPr

ogra

mLo

catio

n Fo

reca

st S

tart

Ti

me

Fore

cast

End

Tim

eTr

igge

r Was

M

et?

Res

ourc

eD

ispa

tche

d?

Tota

l Cap

acity

of

Prog

ram

Ava

ilabl

e fo

r Dis

patc

h

Fore

cast

ed A

vaila

ble

Load

For

the

Prog

ram

B

eing

Dis

patc

hed

Act

ual L

oad

Ach

ieve

dD

urat

ion

of

Dis

patc

h

5/22

/201

7H

eat R

ate

Day

Ahe

ad

PGC

C, P

GEB

, PG

HB,

PG

KN, P

GN

C, P

GN

P,

PGP2

, PG

SB, P

GST

, PG

ZP5:

00 P

M7:

00 P

MYe

sYe

s2

5/22

/201

7H

eat R

ate

Day

Of

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

5/23

/201

7H

eat R

ate

Day

Ahe

adAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

4

5/23

/201

7H

eat R

ate

Day

Of

PGC

C, P

GEB

, PG

FG,

PGH

B, P

GN

B, P

GN

P,

PGP2

, PG

SB, P

GSF

3:00

PM

7:00

PM

Yes

Yes

46/

16/2

017

Pric

eD

ay O

fPG

EB, P

GFG

, PG

NB

3:00

PM

7:00

PM

Yes

Yes

46/

19/2

017

Pric

eD

ay A

head

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

6/19

/201

7Pr

ice

Day

Of

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

6/20

/201

7Pr

ice

Day

Ahe

adAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

46/

20/2

017

Pric

eD

ay O

fAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

46/

22/2

017

Pric

eD

ay A

head

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

6/22

/201

7Pr

ice

Day

Of

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

6/23

/201

7Pr

ice

Day

Ahe

adPG

NC

, PG

ST4:

00 P

M7:

00 P

MYe

sYe

s3

6/23

/201

7Pr

ice

Day

Of

PGN

C, P

GST

4:00

PM

7:00

PM

Yes

Yes

37/

7/20

17Pr

ice

Day

Ahe

adAl

l Sub

laps

4:00

PM

7:00

PM

Yes

Yes

37/

7/20

17Pr

ice

Day

Of

All S

ubla

ps4:

00 P

M7:

00 P

MYe

sYe

s3

7/27

/201

7Pr

ice

Day

Ahe

adAl

l Sub

laps

6:00

PM

7:00

PM

Yes

Yes

17/

27/2

017

Pric

eD

ay O

fAl

l Sub

laps

6:00

PM

7:00

PM

Yes

Yes

17/

31/2

017

Pric

eD

ay A

head

All S

ubla

ps5:

00 P

M7:

00 P

MYe

sYe

s2

7/31

/201

7Pr

ice

Day

Of

All S

ubla

ps5:

00 P

M7:

00 P

MYe

sYe

s2

8/1/

2017

Pric

eD

ay A

head

All S

ubla

ps4:

00 P

M7:

00 P

MYe

sYe

s3

8/1/

2017

Pric

eD

ay O

fAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

48/

2/20

17Pr

ice

Day

Ahe

adAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

48/

2/20

17Pr

ice

Day

Of

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

8/28

/201

7Pr

ice

Day

Ahe

adAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

48/

28/2

017

Pric

eD

ay O

fAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

48/

29/2

017

Pric

eD

ay A

head

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

8/29

/201

7Pr

ice

Day

Of

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

8/31

/201

7Pr

ice

Day

Ahe

adAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

48/

31/2

017

Pric

eD

ay O

fAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

49/

1/20

17Pr

ice

Day

Ahe

adAl

l Sub

laps

3:00

PM

7:00

PM

Yes

Yes

49/

1/20

17Pr

ice

Day

Of

All S

ubla

ps3:

00 P

M7:

00 P

MYe

sYe

s4

9/5/

2017

Pric

eD

ay O

fAl

l Sub

laps

5:00

PM

7:00

PM

Yes

Yes

29/

11/2

017

Pric

eD

ay O

fAl

l Sub

laps

5:00

PM

7:00

PM

Yes

Yes

29/

26/2

017

Pric

eD

ay O

fAl

l Sub

laps

6:00

PM

7:00

PM

Yes

Yes

19/

27/2

017

Pric

eD

ay A

head

All S

ubla

ps6:

00 P

M7:

00 P

MYe

sYe

s1

9/27

/201

7Pr

ice

Day

Of

All S

ubla

ps6:

00 P

M7:

00 P

MYe

sYe

s1

9/28

/201

7Pr

ice

Day

Ahe

adAl

l Sub

laps

6:00

PM

7:00

PM

Yes

Yes

1

10/6

/201

7Pr

ice

Day

Of

PGC

C, P

GEB

, PG

F1,

PGFG

, PG

KN, P

GN

B,

PGN

P, P

GP2

, PG

SB,

PGSF

, PG

SI, P

GST

, PG

ZP,

6:00

PM

7:00

PM

Yes

Yes

1

10/1

6/20

17Pr

ice

Day

Of

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 5:

00 P

M7:

00 P

MYe

sYe

s2

10/1

7/20

17Pr

ice

Day

Ahe

ad

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 5:

00 P

M7:

00 P

MYe

sYe

s2

10/1

7/20

17Pr

ice

Day

Of

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 5:

00 P

M7:

00 P

MYe

sYe

s2

1-AtchA-1

Atta

chm

ent A

- Tr

igge

rs M

et -

DR

Pro

gram

Dis

patc

hed

Dat

e Tr

igge

r Con

ditio

n W

as F

orec

ast

to b

e M

etTy

pe o

f Tr

igge

rPr

ogra

mLo

catio

n Fo

reca

st S

tart

Ti

me

Fore

cast

End

Tim

eTr

igge

r Was

M

et?

Res

ourc

eD

ispa

tche

d?

Tota

l Cap

acity

of

Prog

ram

Ava

ilabl

e fo

r Dis

patc

h

Fore

cast

ed A

vaila

ble

Load

For

the

Prog

ram

B

eing

Dis

patc

hed

Act

ual L

oad

Ach

ieve

dD

urat

ion

of

Dis

patc

h

10/1

8/20

17Pr

ice

Day

Ahe

ad

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 5:

00 P

M7:

00 P

MYe

sYe

s2

10/1

8/20

17Pr

ice

Day

Of

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 6:

00 P

M7:

00 P

MYe

sYe

s1

10/2

3/20

17Pr

ice

Day

Of

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 5:

00 P

M7:

00 P

MYe

sYe

s2

10/2

4/20

17Pr

ice

Day

Ahe

ad

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 4:

00 P

M7:

00 P

MYe

sYe

s3

10/2

5/20

17Pr

ice

Day

Ahe

ad

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 3:

00 P

M7:

00 P

MYe

sYe

s4

10/2

6/20

17Pr

ice

Day

Ahe

ad

PGC

C, P

GEB

, PG

F1,

PGH

B, P

GKN

, PG

NP,

PG

P2, P

GSB

, PG

SF,

PGSI

, PG

ST, P

GZP

, 3:

00 P

M7:

00 P

MYe

sYe

s4

1-AtchA-2


CHAPTER 1

ATTACHMENT B

SUMMARY OF 2017 CAPACITY BIDDING PROGRAM EVENTS

Atta

chm

ent B

. N

umbe

r of h

ours

whe

n PG

&E fo

reca

sted

that

trig

ger c

riter

ia w

ould

be

reac

hed,

act

ual h

ours

reac

hed,

and

act

ual h

ours

dis

patc

hed

Cap

acity

Bid

ding

Pro

gram

/Day

-Ahe

ad

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

PGC

C12

126

2PG

CC

1515

123

PGC

C6

66

3PG

EB15

156

2PG

EB19

1912

3PG

EB6

66

3PG

F14

44

1PG

F115

1512

3PG

F16

66

3PG

FG10

104

1PG

FG19

1912

3PG

FG6

66

3PG

HB

66

62

PGH

B15

1512

3PG

HB

66

63

PGK

N6

66

2PG

KN

1515

123

PGK

N6

66

3PG

NB

1010

41

PGN

B19

1912

3PG

NB

66

63

PGN

C6

66

2PG

NC

1818

154

PGN

C6

66

3PG

NP

99

62

PGN

P15

1512

3PG

NP

66

63

PGP2

1212

62

PGP2

1515

123

PGP2

66

63

PGSB

1212

62

PGSB

1515

123

PGSB

66

63

PGSF

1010

41

PGSF

1515

123

PGSF

66

63

PGSI

44

41

PGSI

1515

123

PGSI

66

63

PGST

1212

62

PGST

1818

154

PGST

66

63

PGZP

66

62

PGZP

1515

123

PGZP

66

63

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

PGC

C24

2419

5PG

CC

1111

63

PGC

C20

2015

5PG

CC

8888

6421

PGEB

2424

195

PGEB

1111

63

PGEB

2020

155

PGEB

9595

6421

PGF1

2525

195

PGF1

1111

63

PGF1

2020

155

PGF1

8181

6220

PGFG

2525

195

PGFG

1111

63

PGFG

2020

00

PGFG

9191

4715

PGH

B25

2519

5PG

HB

1111

63

PGH

B19

1915

5PG

HB

8282

6421

PGK

N25

2519

5PG

KN

1111

63

PGK

N20

2015

5PG

KN

8383

6421

PGN

B25

2519

5PG

NB

1111

63

PGN

B20

200

0PG

NB

9191

4715

PGN

C25

2519

5PG

NC

1111

63

PGN

C19

190

0PG

NC

8585

5217

PGN

P25

2519

5PG

NP

1111

63

PGN

P20

2015

5PG

NP

8686

6421

PGP2

2525

195

PGP2

1111

63

PGP2

2020

155

PGP2

8989

6421

PGSB

2525

195

PGSB

1111

63

PGSB

2020

155

PGSB

8989

6421

PGSF

2525

195

PGSF

1111

63

PGSF

2020

155

PGSF

8787

6220

PGSI

2525

195

PGSI

1111

63

PGSI

2020

155

PGSI

8181

6220

PGST

2525

195

PGST

1111

63

PGST

2020

155

PGST

9292

6722

PGZP

2525

195

PGZP

1111

63

PGZP

2020

155

PGZP

8383

6421

May

June

July

Aug

ust

Sept

embe

rO

ctob

erA

nnua

l

1-AtchB-1

Atta

chm

ent B

. N

umbe

r of h

ours

whe

n PG

&E fo

reca

sted

that

trig

ger c

riter

ia w

ould

be

reac

hed,

act

ual h

ours

reac

hed,

and

act

ual h

ours

dis

patc

hed

Cap

acity

Bid

ding

Pro

gram

/Day

-Of

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

PGC

C14

148

2PG

CC

1515

123

PGC

C6

66

3PG

EB17

178

2PG

EB19

1916

4PG

EB6

66

3PG

F14

44

1PG

F115

1512

3PG

F16

66

3PG

FG14

148

2PG

FG19

1916

4PG

FG6

66

3PG

HB

88

82

PGH

B15

1512

3PG

HB

66

63

PGK

N4

44

1PG

KN

1515

123

PGK

N6

66

3PG

NB

1414

82

PGN

B19

1916

4PG

NB

66

63

PGN

C4

44

1PG

NC

1818

154

PGN

C6

66

3PG

NP

1111

82

PGN

P15

1512

3PG

NP

66

63

PGP2

1414

82

PGP2

1515

123

PGP2

66

63

PGSB

1414

82

PGSB

1515

123

PGSB

66

63

PGSF

1414

82

PGSF

1515

123

PGSF

66

63

PGSI

44

41

PGSI

1515

123

PGSI

66

63

PGST

1010

41

PGST

1818

154

PGST

66

63

PGZP

44

41

PGZP

1515

123

PGZP

66

63

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

Load

Zon

eFo

reca

sted

Rea

ched

Act

ual

Hou

rsD

ispa

tche

d

Num

ber o

fEv

ents

Dis

patc

hed

PGC

C26

2620

5PG

CC

1010

105

PGC

C19

198

5PG

CC

9090

6423

PGEB

2626

205

PGEB

1010

105

PGEB

1919

85

PGEB

9797

6824

PGF1

2626

205

PGF1

1010

105

PGF1

1919

85

PGF1

8080

6022

PGFG

2626

205

PGFG

1010

105

PGFG

1919

11

PGFG

9494

6120

PGH

B26

2620

5PG

HB

1010

105

PGH

B18

187

4PG

HB

8383

6322

PGK

N26

2620

5PG

KN

1010

105

PGK

N19

198

5PG

KN

8080

6022

PGN

B26

2620

5PG

NB

1010

105

PGN

B19

191

1PG

NB

9494

6120

PGN

C26

2620

5PG

NC

1010

105

PGN

C18

180

0PG

NC

8282

5518

PGN

P26

2620

5PG

NP

1010

105

PGN

P19

198

5PG

NP

8787

6423

PGP2

2626

205

PGP2

1010

105

PGP2

1919

85

PGP2

9090

6423

PGSB

2626

205

PGSB

1010

105

PGSB

1919

85

PGSB

9090

6423

PGSF

2626

205

PGSF

1010

105

PGSF

1919

85

PGSF

9090

6423

PGSI

2626

205

PGSI

1010

105

PGSI

1919

85

PGSI

8080

6022

PGST

2626

205

PGST

1010

105

PGST

1919

85

PGST

8989

6323

PGZP

2626

205

PGZP

1010

105

PGZP

1919

85

PGZP

8080

6022

Aug

ust

Sept

embe

rO

ctob

erA

nnua

l

May

June

July

1-AtchB-2


CHAPTER 1

ATTACHMENT C

SUMMARY OF TOTAL ENERGY DISPATCHED FROM

DEMAND RESPONSE PROGRAMS

Atta

chm

ent C

. Num

ber o

f hou

rs d

ispa

tche

d, e

nerg

y di

spat

ched

and

max

imum

ene

rgy

avai

labl

e

Cap

acity

Bid

ding

Pro

gram

/Day

-Ahe

ad

May

June

July

Load

Zon

eH

ours

Dis

patc

hed

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Act

ual H

ours

Dis

patc

hed

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%PG

CC

620

%PG

CC

1240

%PG

CC

*6

0%PG

EB6

20%

PGEB

1240

%PG

EB6

20%

PGF1

413

%PG

F112

40%

PGF1

620

%PG

FG4

13%

PGFG

*12

0%PG

FG6

20%

PGH

B6

20%

PGH

B*

120%

PGH

B*

60%

PGK

N6

20%

PGK

N12

40%

PGK

N6

20%

PGN

B4

13%

PGN

B12

40%

PGN

B6

20%

PGN

C*

60%

PGN

C*

150%

PGN

C*

60%

PGN

P6

20%

PGN

P12

40%

PGN

P6

20%

PGP2

620

%PG

P2*

120%

PGP2

*6

0%PG

SB6

20%

PGSB

1240

%PG

SB6

20%

PGSF

*4

0%PG

SF12

40%

PGSF

620

%PG

SI*

40%

PGSI

*12

0%PG

SI*

60%

PGST

*6

0%PG

ST15

50%

PGST

620

%PG

ZP*

60%

PGZP

1240

%PG

ZP*

60%

* No

part

icip

atin

g cu

stom

ers

* No

part

icip

atin

g cu

stom

ers

* No

part

icip

atin

g cu

stom

ers

Aug

ust

Sept

embe

rO

ctob

erA

nnua

l

Load

Zon

eH

ours

Dis

patc

hed

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%PG

CC

*19

0%PG

CC

*6

0%PG

CC

1550

%PG

CC

6430

%PG

EB19

63%

PGEB

620

%PG

EB*

150%

PGEB

6424

%PG

F119

63%

PGF1

620

%PG

F115

50%

PGF1

6233

%PG

FG19

63%

PGFG

620

%PG

FG0

0%PG

FG47

29%

PGH

B*

190%

PGH

B*

60%

PGH

B*

150%

PGH

B64

20%

PGK

N19

63%

PGK

N6

20%

PGK

N*

150%

PGK

N64

27%

PGN

B19

63%

PGN

B6

20%

PGN

B0

0%PG

NB

4725

%PG

NC

*19

0%PG

NC

*6

0%PG

NC

*0

0%PG

NC

*52

0%PG

NP

1963

%PG

NP

620

%PG

NP

1550

%PG

NP

6435

%PG

P219

63%

PGP2

620

%PG

P215

50%

PGP2

6440

%PG

SB19

63%

PGSB

*6

0%PG

SB15

50%

PGSB

6435

%PG

SF19

63%

PGSF

620

%PG

SF15

50%

PGSF

6239

%PG

SI*

190%

PGSI

*6

0%PG

SI*

150%

PGSI

*62

0%PG

ST19

63%

PGST

620

%PG

ST*

150%

PGST

6743

%PG

ZP*

190%

PGZP

*6

0%PG

ZP*

150%

PGZP

6440

%* N

o pa

rtic

ipat

ing

cust

omer

s* N

o pa

rtic

ipat

ing

cust

omer

s* N

o pa

rtic

ipat

ing

cust

omer

s* N

o pa

rtic

ipat

ing

cust

omer

s

1-AtchC-1

Atta

chm

ent C

. Num

ber o

f hou

rs d

ispa

tche

d, e

nerg

y di

spat

ched

and

max

imum

ene

rgy

avai

labl

e

Cap

acity

Bid

ding

Pro

gram

/Day

-Of

May

June

July

Load

Zon

eH

ours

Dis

patc

hed

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%PG

CC

827

%PG

CC

1240

%PG

CC

620

%PG

EB8

27%

PGEB

1653

%PG

EB6

20%

PGF1

413

%PG

F112

40%

PGF1

620

%PG

FG8

27%

PGFG

1653

%PG

FG6

20%

PGH

B8

27%

PGH

B12

40%

PGH

B6

20%

PGK

N4

13%

PGK

N12

40%

PGK

N6

20%

PGN

B8

27%

PGN

B16

53%

PGN

B6

20%

PGN

C4

13%

PGN

C*

150%

PGN

C*

60%

PGN

P8

27%

PGN

P12

40%

PGN

P6

20%

PGP2

827

%PG

P212

40%

PGP2

620

%PG

SB8

27%

PGSB

1240

%PG

SB6

20%

PGSF

827

%PG

SF12

40%

PGSF

620

%PG

SI4

13%

PGSI

1240

%PG

SI6

20%

PGST

413

%PG

ST15

50%

PGST

620

%PG

ZP*

40%

PGZP

1240

%PG

ZP6

20%

* No

part

icip

atin

g cu

stom

ers

* No

part

icip

atin

g cu

stom

ers

* No

part

icip

atin

g cu

stom

ers

Aug

ust

Sept

embe

rO

ctob

erA

nnua

l

Load

Zon

eH

ours

Dis

patc

hed

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%Lo

ad Z

one

Hou

rsD

ispa

tche

d

(a)

Tota

l Ene

rgy

Dis

patc

hed

(MW

h)

(b) M

axim

um

Ener

gyA

vaila

ble

(Avg

MW

X

30 h

rs)

(c) =

(a)/(

b)

%PG

CC

2067

%PG

CC

1033

%PG

CC

827

%PG

CC

6435

%PG

EB20

67%

PGEB

1033

%PG

EB8

27%

PGEB

6834

%PG

F120

67%

PGF1

1033

%PG

F18

27%

PGF1

6038

%PG

FG20

67%

PGFG

1033

%PG

FG1

3%PG

FG61

35%

PGH

B20

67%

PGH

B10

33%

PGH

B7

23%

PGH

B63

35%

PGK

N20

67%

PGK

N10

33%

PGK

N8

27%

PGK

N60

33%

PGN

B20

67%

PGN

B10

33%

PGN

B1

3%PG

NB

6135

%PG

NC

*20

0%PG

NC

*10

0%PG

NC

*0

0%PG

NC

5513

%PG

NP

2067

%PG

NP

1033

%PG

NP

827

%PG

NP

6435

%PG

P220

67%

PGP2

1033

%PG

P28

27%

PGP2

6435

%PG

SB20

67%

PGSB

1033

%PG

SB8

27%

PGSB

6438

%PG

SF20

67%

PGSF

1033

%PG

SF8

27%

PGSF

6434

%PG

SI20

67%

PGSI

1033

%PG

SI8

27%

PGSI

6035

%PG

ST20

67%

PGST

1033

%PG

ST8

27%

PGST

6339

%PG

ZP20

67%

PGZP

1033

%PG

ZP8

27%

PGZP

6037

%* N

o pa

rtic

ipat

ing

cust

omer

s* N

o pa

rtic

ipat

ing

cust

omer

s* N

o pa

rtic

ipat

ing

cust

omer

s

1-AtchC-2


CHAPTER 2

UTILITY-OWNED GENERATION: HYDROELECTRIC

2-i



TABLE OF CONTENTS

A. Introduction....................................................................................................... 2-1

B. Overview of PG&E’s Hydroelectric System ...................................................... 2-2

1. Hydro System Characteristics.................................................................... 2-2

2. Hydro Operations and Maintenance Organization ..................................... 2-4

a. Shasta Area......................................................................................... 2-4

b. DeSabla Area ...................................................................................... 2-5

c. Central Area ........................................................................................ 2-5

d. Kings-Crane Valley Area ..................................................................... 2-5

e. Helms Pumped Storage Facility .......................................................... 2-6

f. Support Organizations......................................................................... 2-6

1) Hydro Licensing and Compliance.................................................. 2-6

2) Safety, Quality and Standards....................................................... 2-7

3) Water Management....................................................................... 2-7

4) Project Execution .......................................................................... 2-7

5) Planning ........................................................................................ 2-8

C. Hydro Portfolio Management............................................................................ 2-8

1. Overview.................................................................................................... 2-8

2. Operational Planning................................................................................ 2-10

a. Environmental/Regulatory Considerations Affecting Operations ....... 2-10

b. Management of Water Resources ..................................................... 2-11

c. Outage Planning................................................................................ 2-11

1) Planned Outages ........................................................................ 2-12

2) Maintenance Outages ................................................................. 2-13

3. Conventional Hydro Portfolio Operation................................................... 2-13




2-ii

4. Helms Pumped Storage Operation .......................................................... 2-14

5. Internal Controls....................................................................................... 2-15

a. Guidance Documents ........................................................................ 2-15

b. Operating Plans................................................................................. 2-16

c. Operations Reviews .......................................................................... 2-16

d. Incident Reporting Process................................................................ 2-16

e. Corrective Action Program................................................................. 2-17

f. Outage Planning and Scheduling Processes..................................... 2-17

1) Planning and Scoping ................................................................. 2-18

2) Scheduling .................................................................................. 2-19

3) Outage Execution........................................................................ 2-20

g. Project Management Process............................................................ 2-23

h. Design Change Process .................................................................... 2-23

D. Operational Results ........................................................................................ 2-23

1. Energy Production ................................................................................... 2-24

2. Outages ................................................................................................... 2-25

a. Scheduled Outages ........................................................................... 2-26

b. Forced Outages................................................................................. 2-26

1) January-February Winter Storm-Related Forced Outages.......... 2-27

2) Forced Outages Unrelated to the January-February Winter Storms......................................................................................... 2-45

E. Conclusion...................................................................................................... 2-53

2-1


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



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



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

TABLE 2-1HYDRO GENERATION AREA DETAILS

Line No. Area

No. of Powerhouses

No. of Units MW

No. of FERC

LicensesNo. of Dams

Usable Storage

(acre-feet)Tunnels (Miles)

Canals (Miles)

Flumes (Miles)

1 Shasta 16 28 809.9 6 44 200,714 27.9 44.5 4.62 DeSabla 15 27 785.7 6 32 1,427,239 34.2 48.4 7.43 Central 21 28 522.6 6 71 423,732 37.3 71.3 29.44 Kings Crane

Valley13 20 562.0 6 17 51,866 28.6 8.8 2.0

5 Helms 1 3 1,212.0 1 6 252,404 3.9 N/A N/A

6 Total 66 106 3,892.2 25 170 2,355,955 131.9 173.0 43.4

f. Support Organizations7

The Hydro O&M organization works side by side with other Power 8

Generation support organizations to provide safe, reliable, cost-effective 9

generation to California in an environmentally responsible manner.10

Power Generation’s centralized organization provides oversight, 11

direction and support to ensure that critical resources, personnel and 12

technical information and advice are available to support O&M. This 13

includes a centralized management team that provides the following 14

services and expertise:15

1) Hydro Licensing and Compliance16

Hydro Licensing and Compliance manages PG&E’s 25 FERC 17

hydropower licenses and related water rights, permits and 18

agreements. It has the primary responsibility for FERC relicensing19

and for managing license compliance in partnership with 20

Hydro O&M.21

2-7

2) Safety, Quality and Standards1

Safety, Quality and Standards (SQS) is focused on six key 2

functional areas to ensure that Power Generation is focused on 3

public and employee safety; that processes are smart and simple; 4

and that work is performed to high quality and in compliance with all 5

standards and procedures that govern the Power Generation 6

business. Those key areas are:7

Public and Employee Safety;8

Facilities Safety;9

Standards;10

Process;11

Quality; and12

Documentation and Records.13

Technical employees provide direct support for the safe,14

reliable, compliant, and efficient operation of PG&E’s hydroelectric 15

generating units. O&M Specialists act as consultants to the Hydro 16

O&M organization, offering expertise in methods and procedures to 17

help assure compliance with O&M standards.18

In addition, SQS manages the Facility Safety Program for dams 19

and water conveyance facilities to assure compliance with FERC 20

and California Division of Safety of Dams (DSOD) regulations.21

3) Water Management22

Water Management (WM), within the Hydro Licensing 23

Department, supports the Hydro O&M operations through the 24

utilization of sophisticated computer models to schedule the 25

hydroelectric resources based on the latest hydro-meteorological 26

data, forecasts of stream flow runoff, and pricing forecasts. 27

WM produces a calendar year hydro generation forecast.28

4) Project Execution29

Project Execution combines engineering, project management 30

and construction services into an integrated department that 31

manages project work in addition to supporting routine O&M 32

operations. These organizations are:33

2-8

Programs and Designs1

Programs and Designs provides civil, electrical and 2

mechanical engineering and design services for projects at all 3

powerhouses, switchyards, dams, water conveyance systems 4

and appurtenant facilities throughout the PG&E hydro system, 5

as well as for many of the partnership Irrigation Districts and 6

Water Agencies facilities.7

Project Engineering8

Project Engineering provides project management and 9

engineering services to Power Generation projects throughout 10

PG&E's hydro territory. Project work includes both capital and 11

expense safety, reliability, regulatory and efficiency 12

improvement projects. Project Engineering also provides 13

engineering services in support of routine hydro O&M work.14

Construction15

Construction is a mobile construction organization that 16

handles major maintenance and construction projects 17

throughout the hydro system. With both a civil construction 18

group and an electrical-mechanical group, this organization 19

constructs and/or makes major repairs on a wide variety of 20

hydro facilities.21

5) Planning22

Planning supports the Hydro O&M operations by providing a 23

systemwide look into the condition of PG&E’s assets, dovetailing 24

specific equipment program investment strategies with the Power 25

Generation organization’s long-term investment strategy. This 26

allows PG&E to make data-driven investment decisions to improve 27

the safety and reliability of its generating assets.28

C. Hydro Portfolio Management29

1. Overview30

The PG&E hydro portfolio is a complex system composed of many 31

facilities with interrelated operational parameters. Many powerhouses are in 32

“river-chains” where the water is most optimally used sequentially through 33

2-9

the powerhouses as it moves downriver. This requires coordinated 1

operations to assure each powerhouse is online to utilize the water flow as 2

it arrives, without spilling past the powerhouse. Operation of the hydro 3

portfolio also has to take into account the FERC license-mandated minimum 4

and maximum flows and ramping rates on the river to assure compliance 5

with license conditions. Management of this complex portfolio relies on the 6

integration of information and expertise from multiple organizations.7

PG&E is committed to providing safe utility service to its customers. 8

As part of this commitment, PG&E reviews its operations, including 9

operation of its hydro facilities, to identify and mitigate, to the extent 10

possible, potential safety risks to the public, PG&E’s workforce and its 11

contractors. As it operates and maintains its hydro generation facilities, 12

PG&E follows its internal controls to ensure public, workplace, and 13

contractor safety. For example, PG&E’s Employee Code of Conduct 14

describes the safety of the public, employees and contractors as PG&E’s 15

highest priority. PG&E’s commitment to a safety-first culture is reinforced 16

with its Safety Principles, PG&E’s Safety Commitment, Personal Safety 17

Commitment and Keys to Life. These tools were developed in collaboration 18

with PG&E employees, leaders, and union leadership, and are intended to 19

provide clarity and support as employees strive to take personal ownership 20

of safety at PG&E. Additionally, PG&E seeks all applicable regulatory 21

approvals from governmental authorities with jurisdiction to enforce laws 22

related to worker health and safety, impacts to the environment, and public 23

health and welfare.24

As part of PG&E’s Safety Commitment, PG&E follows recognized best 25

practices in the industry. PG&E operates each of its generation facilities in 26

compliance with all local, state and federal permit and operating 27

requirements such as state and federal Occupational Safety and Health 28

Administration requirements and the California Public Utilities Commission’s 29

General Order 167. As discussed below, PG&E does this by using 30

internal controls to help manage the operations and maintenance of its 31

generation facilities.32

With regard to employee safety, Power Generation employees develop 33

a safety action plan each year. This action plan focuses on various items 34

2-10

such as training and qualifications, contractor safety, human performance, 1

approaches to reduce or eliminate recordable injuries and motor vehicle 2

incidents, approaches to sharing safety best practices, and actions to 3

improve the safety culture of the organization.4

With regard to public safety, PG&E continues to develop and implement 5

a comprehensive public safety program that includes: (1) public education, 6

outreach and partnership with key agencies; (2) improved warning and 7

hazard signage at hydro facilities; (3) enhanced emergency response 8

preparedness, training, drills and coordination with emergency response 9

organizations; and (4) safer access to hydro facilities and lands, including 10

trail access, physical barriers, and canal escape routes.11

Fundamental to a strong safety culture is a leadership team that 12

believes every job can be performed safely and seeks to eliminate barriers 13

to safe operations. Equally important is the establishment of an empowered 14

grass roots safety team that can act to encourage safe work practices 15

among peers. Power Generation’s grass roots team is led by bargaining 16

unit employees from across the organization who work to include safety best 17

practices in all the work they do. These employees are closest to the 18

day-to-day work of providing safe, reliable, and affordable energy for 19

PG&E’s customers and are best positioned to implement changes that can 20

improve safety performance.21

2. Operational Planning22

a. Environmental/Regulatory Considerations Affecting Operations23

PG&E’s operation of its hydro system is governed by the 24

25 Operating Licenses issued by FERC, which contain over 500 discrete 25

operating conditions. PG&E safely and reliably operates the system in 26

compliance with all FERC license conditions and all local, state, and 27

federal regulations. In addition, operations are constrained by many 28

conditions imposed by U.S. Forest Service agreements, the DSOD 29

regulations, contractual obligations, water diversion rights and other 30

regulations. PG&E’s hydro projects deliver water at 54 locations for 31

consumption by 39 different user groups under water delivery 32

agreements that contain additional constraints on how the projects are 33

2-11

operated. There are defined minimum and maximum flow requirements 1

in most river reaches below PG&E’s reservoirs and powerhouses. Any 2

changes in the flows have to be performed in compliance with 3

prescribed ramp rates. Reservoirs have both minimum and maximum 4

storage requirements which often vary depending upon the time of year.5

b. Management of Water Resources6

Water resources are fuel for the hydro powerhouses and the 7

efficient management of these resources is paramount to the operations 8

of the hydro portfolio. The WM organization forecasts runoff and 9

provides guidance for scheduling hydroelectric resources consistent with 10

all regulatory rules, agreements, contracts, environmental regulations 11

and recreational needs.12

WM scheduling consultants employ a number of sophisticated 13

computer modeling programs to forecast runoff. These programs use 14

inputs from the current hydrologic state of the watershed (snowpack, 15

current runoff and aquifer outflows), an updated 10-day weather 16

forecast, and the long-range weather forecast, with appropriate 17

probability factors, to compile monthly and daily runoff forecasts that are 18

used to develop optimized monthly water release schedules. The 19

monthly water release schedules are used as guidance by PG&E’s 20

Short Term Electric Supply (STES) organization and Hydro O&M in 21

operating the reservoirs, water conveyance systems and powerhouses.122

c. Outage Planning23

PG&E has formal outage planning and scheduling processes for its 24

generation assets. Management control over the planning and 25

scheduling of outages is a key process for prudent management of 26

PG&E’s generation facilities. The planning and scheduling processes 27

include management approval points for the base yearly outage 28

schedule as well as for any changes to the schedule. Details of the 29

outage planning and scheduling processes are included under Internal 30

1 For further details, see Chapter 1.

2-12

Controls in Section C.5 below. Scheduled outages are classified into 1

one of two groups: (1) Planned Outages; or (2) Maintenance Outages.2

1) Planned Outages3

Planned Outages (PO) are part of the normal course of 4

maintaining a generating facility. Due to the age of PG&E’s hydro 5

portfolio assets and the complexity of the water collection and 6

conveyance systems, and in order to assure that the generating 7

facilities are reliable during periods of high electric demand, most 8

hydro units are scheduled for one PO each year. These POs are 9

typically scheduled during periods of lower electric demand when 10

market prices are lower.11

These outages are for the purpose of accomplishing annual 12

recurring routine maintenance work, equipment repairs that require 13

an outage, minor project work and condition assessment to 14

ascertain risk. Examples of typical annual maintenance tasks 15

include time-based equipment overhauls; time-based equipment 16

inspections; North American Electric Reliability Corporation (NERC) 17

compliance testing; turbine component lubrication, adjustment and 18

repairs; generator inspection and repairs; relay performance tests; 19

annual auto tests; and condition assessment measurements and 20

readings. The need for scheduled maintenance is well documented 21

in PG&E’s past general rate case applications. If major capital 22

projects requiring an outage are planned, the annual outages are 23

modified to accommodate that work.24

Scheduling of POs is an iterative process spanning several 25

years with input from many stakeholders and quarterly submissions 26

to the CAISO. As described in Section C.5.f., the processes for 27

planning and scheduling annual POs demonstrate that POs are 28

scheduled sufficiently in advance, have an adequate duration for 29

planning and preparation, have controls to manage changes, and 30

have reasonable management oversight to assure that units are 31

promptly returned to service.32

2-13

2) Maintenance Outages1

Maintenance Outages (MO) are taken when there is an 2

emerging need for maintenance that can be deferred beyond the 3

end of the next weekend, but requires a capacity reduction before 4

the next PO. Some examples of typical MOs include replacing 5

generator brushes; cleaning brush rigging; performing auto tests; 6

troubleshooting tests; transmission line work; monthly routine minor 7

maintenance; monthly gate travel tests; and out-of-tolerance 8

equipment adjustments.9

MOs must be scheduled with the CAISO a minimum of 72 hours 10

in advance of the unit being taken out of service. Many MOs for 11

routine monthly activities are scheduled much further in advance to 12

assure proper planning and preparation. Every attempt is made to 13

include all maintenance items in the annual PO for each unit, but 14

there are some systems and equipment that must be serviced or 15

tested more frequently, and at times there are issues that emerge 16

between POs that cannot be deferred until the next annual outage.17

3. Conventional Hydro Portfolio Operation18

PG&E’s 65 conventional powerhouses are operated from seven19

around-the-clock switching centers. Six of the switching centers are at 20

powerhouses and one is located in Fresno. Switching center operators 21

receive day-ahead dispatch instructions from PG&E’s STES organization. 22

Operators review the day-ahead schedules and verify that they are 23

attainable. Any operational constraints that may interfere with running the 24

unit to the dispatch schedule are reviewed with STES, and if necessary, the 25

dispatch instructions are adjusted. The conventional hydro powerhouses 26

are operated in accordance with the final dispatch directions provided 27

by STES.28

During daily operations, there is close communication between the 29

operators and STES’s real-time energy desk. Through the Supervisory 30

Control and Data Acquisition (SCADA) system, operators remotely start 31

units, vary the loading and stop units in accordance with dispatch 32

instructions. They continuously monitor and adjust the operations of the 33

units at the powerhouses, the canal flows and levels, the reservoir levels, 34

2-14

the instream flow releases and other pertinent operating parameters. Any 1

operational issues that require a unit to deviate from the dispatch schedule 2

are communicated to the real-time desk, and operators make adjustments in 3

the unit’s operation in accordance with the directions received back from the 4

real-time desk.5

Roving operators visit the remote, unmanned powerhouses to perform 6

station reads and operational checks that cannot be performed through 7

SCADA. They also perform minor maintenance and adjustments, such as 8

lubricating equipment, checking oil reservoirs on equipment, and cleaning 9

strainers. Roving operators are also dispatched to perform remote unit 10

start-ups that cannot be handled through the SCADA system. At the 11

six powerhouses housing switching centers, the switching center operators 12

perform the duties of the roving operators for those local units.13

Water system operators manage the operations of the water delivery 14

systems that feed the powerhouses and make adjustments in the reservoir 15

and canal operations for instream flow releases and water deliveries to 16

third parties. In concert with the switching center operators monitoring 17

SCADA, the water system operators assure safe canal flows and reservoir 18

levels while meeting dispatch requirements.19

4. Helms Pumped Storage Operation20

Helms is operated around-the-clock from a control room in the 21

powerhouse. Similar to conventional powerhouse dispatch described 22

above, the Helms operators receive day-ahead dispatch instructions from23

STES. These instructions include both generating and pumping directions. 24

Operators review the day-ahead schedules and verify that they are 25

attainable. Any operational constraints that may interfere with running the 26

unit to the dispatch schedule, either in generating or pumping mode, are 27

reviewed with STES and if necessary the dispatch instructions are adjusted. 28

Helms is operated in accordance with the final dispatch directions provided 29

by STES.30

Helms has a significant influence on grid stability, and the CAISO’s daily 31

requirements can cause the dispatch of the Helms units to be changed 32

many times throughout the day. Helms operators and the STES real-time 33

2-15

desk stay in constant communication and the operators adjust the unit’s 1

operation in accordance with instruction from the real-time desk.2

Helms operators, similar to roving operators described in Section C.3,3

complete the system reads and operational checks that cannot be 4

performed through SCADA and perform minor maintenance and 5

adjustments in the powerhouse.6

5. Internal Controls7

Internal controls are a means by which an organization’s resources are 8

directed, monitored, and measured. PG&E defines internal controls as a 9

process or set of processes that take into consideration an organization's 10

structure, work and authority flows, people and management information 11

systems and are designed to help the organization accomplish specific 12

goals or objectives.13

PG&E has many internal controls in place to manage the O&M of its 14

generation assets, including its hydro facilities. These controls include: 15

(1) guidance documents; (2) operating plans; (3) operations reviews; 16

(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

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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.

2-26

TABLE 2-4HYDRO PORTFOLIO FORCED OUTAGE FACTOR

Line No. Year FOF (%)

BenchmarkFOF (%)

1 2010 2.082 2011 2.833 2012 9.764 2013 2.805 2014 1.446 2015 1.217 2016 1.368 2017 1.86(a) 3.08

_______________

(a) Excludes storm-related outages; FOF is 6.90 percent when including storm-related outages.

a. Scheduled Outages1

PG&E’s hydro portfolio had 101 scheduled outages 24 hours or 2

greater in duration during the record period. Of this total, 71 were 3

planned outages and 30 were maintenance outages.6 This is an 4

average of just under one scheduled outage per unit across the hydro 5

portfolio.6

b. Forced Outages7

PG&E devotes a great deal of attention to its equipment in its O&M 8

practices. Given that the average age of PG&E’s 106 unit hydro 9

portfolio is about 79 years, and 92 of the 106 units are older than 10

50 years (24 units are over 100 years old), it is to be expected that 11

PG&E, similar to any other generator, will experience some forced 12

outages of its hydro units. Some of these outages are related to 13

unanticipated equipment malfunctions while others are related to 14

external events such as lightning strikes, wildfire, storm-induced 15

transmission line interruptions, debris in the water, or even vandalism. 16

In addition, NERC logging requirements require that unit starts and 17

stops that accompany testing performed after a planned outage be 18

coded as individual forced outages.19

6 A description of the general nature and scope of planned outages and maintenance outages is provided in Section C.2.c. above.

2-27

During forced outages, one of PG&E’s primary goals is to bring the 1

unit back on line safely and expediently. Additionally, PG&E often 2

examines components associated with the specific equipment that 3

failed. This examination helps inform PG&E as to whether modifications 4

or repairs should be made to those components, either at the unit where 5

the outage occurred or at other units with similar components. While 6

this might extend the time before a unit is returned to service, it can 7

potentially avoid a future forced outage.8

During the record period, there were 85 forced outages with 9

durations longer than 24 hours occurring at 42 different units with a 10

powerhouse capacity of 25 MW or greater. The outages have been 11

grouped into those related to the January-February winter storms and 12

those that are unrelated to such storms. 13

1) January-February Winter Storm-Related Forced Outages14

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



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



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


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


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


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


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


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


consistent with the DeSabla Hydro Winter Storm procedure.10




February 18, 2017 at 8:40 a.m. and Unit 2 was returned to 14

service at 8:44 a.m.15


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


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


service due to high flows caused by early January storms. 3



30,000 cfs, as measured downstream of Rock Creek Dam at 6



consistent with the DeSabla Hydro Winter Storm procedure.9




January 12, 2017 at 6:59 p.m. and Unit 2 was returned to 13



from service due to high flows caused by early February storms. 16



30,000 cfs, as measured downstream of Rock Creek Dam at 19



consistent with the DeSabla Hydro Winter Storm procedure. 22



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


o) Salt Springs Powerhouse28


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


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


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


from service due to low bearing cooling water flows. High runoff 24

from February storms caused numerous upstream landslides, 25



February 22, 2017 at 1:48 p.m.28


from service due to low bearing cooling water flows. High runoff 30

from February storms caused numerous upstream landslides, 31



February 27, 2017 at 10:47 a.m.34

2-44

q) Tiger Creek Powerhouse1


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


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


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


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


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


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


CHAPTER 2

ATTACHMENT A

PG&E POWERHOUSES AND GENERATING UNITS


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


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


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

1. Fossil-Fuel Generating Stations ................................................................. 3-2

a. Gateway Generating Station ................................................................ 3-2

b. Colusa Generating Station ................................................................... 3-2

c. Humboldt Bay Generating Station ....................................................... 3-3

2. Fuel Cell Facilities ...................................................................................... 3-3

a. CSU East Bay Fuel Cell Facility .......................................................... 3-3

b. SFSU Fuel Cell Facility ........................................................................ 3-3

3. Solar Stations ............................................................................................. 3-4

a. Vaca Dixon Solar Station ..................................................................... 3-4

b. Westside Solar Station ........................................................................ 3-4

c. Stroud Solar Station ............................................................................ 3-4

d. Five Points Solar Station ..................................................................... 3-5

e. Huron Solar Station ............................................................................. 3-5

f. Cantua Solar Station ........................................................................... 3-5

g. Giffen Solar Station ............................................................................. 3-5

h. Gates Solar Station ............................................................................. 3-6

i. West Gates Solar Station .................................................................... 3-6

j. Guernsey Solar Station........................................................................ 3-6

B. Fossil and Solar Operations and Maintenance Organization ............................ 3-6

C. Internal Controls ............................................................................................... 3-8

1. Guidance Documents................................................................................. 3-9

2. Operations Reviews ................................................................................. 3-10

3. Incident Reporting Process ...................................................................... 3-10


CHAPTER 3 UTILITY-OWNED GENERATION: FOSSIL AND OTHER GENERATION

TABLE OF CONTENTS

(CONTINUED)

3-ii

4. Corrective Action Program ....................................................................... 3-10

5. Outage Planning and Scheduling Processes ........................................... 3-11

a. Planning and Scoping ........................................................................ 3-12

b. Scheduling ......................................................................................... 3-12

c. Outage Execution .............................................................................. 3-13

6. Design Change Process .......................................................................... 3-14

D. Operational Results ........................................................................................ 3-14

1. Energy Production ................................................................................... 3-14

2. Outages ................................................................................................... 3-16

a. Gateway Generating Station .............................................................. 3-17

1) Scheduled Outages ..................................................................... 3-17

2) Forced Outages .......................................................................... 3-18

b. Colusa Generating Station ................................................................. 3-18


2) Forced Outages .......................................................................... 3-18

c. Humboldt Bay Generating Station ..................................................... 3-19


2) Forced Outages .......................................................................... 3-19

E. Conclusion ...................................................................................................... 3-23

3-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 3 2

UTILITY-OWNED GENERATION: FOSSIL AND OTHER 3

GENERATION 4

A. Introduction 5


operation of Pacific Gas and Electric Company’s (PG&E) utility-owned 7

fossil-fuel, fuel cell, and photovoltaic (PV) facilities during the 2017 record year. 8

PG&E’s utility-owned fossil-fuel, fuel cell, and PV portfolio was operated in a 9

reasonable manner during the record period. During the record period, PG&E 10

owned, operated and maintained three fossil-fuel generating stations, two fuel 11

cell facilities, and 10 ground-mounted PV solar stations.1 12

The three fossil-fuel generating stations are Gateway Generating Station 13

(Gateway), Colusa Generating Station (Colusa), and Humboldt Bay Generating 14

Station (Humboldt). Gateway entered commercial operations in January 2009. 15

Humboldt entered commercial operations in September 2010, followed by 16

Colusa in December 2010. These three generating facilities have a combined 17

maximum normal operating capacity of 1,400 megawatts (MW). 18

PG&E’s small fuel cell facilities are the California State University (CSU) 19

East Bay Fuel Cell Facility and the San Francisco State University (SFSU) Fuel 20

Cell Facility. The fuel cells were in service periodically throughout the record 21

period. These fuel cells were installed pursuant to PG&E’s application to install 22

fuel cells on state-owned property approved in D.10-04-028. 23

The 10 ground-mounted PV generating stations are Vaca Dixon, Westside, 24

Stroud, Five Points, Huron, Cantua, Giffen, Gates, West Gates, and Guernsey 25

Solar Stations. These facilities were built as part of the utility-owned generation 26

(UOG) portion of PG&E’s 5-year solar PV Program approved in D.10-04-052. 27

All of PG&E’s solar stations entered into commercial operations prior to the 28

record period. 29

1 PG&E also owns three small PV facilities in San Francisco that entered commercial

operations in 2007. Because these facilities total less than 300 kilowatts (kW), PG&E has not addressed them in this testimony.

3-2

1. Fossil-Fuel Generating Stations 1

a. Gateway Generating Station 2

Gateway is a 530 MW combined cycle power plant consisting of 3

two General Electric (GE) Frame 7FA combustion turbine 4

(CT)-generators, each with its own Vogt-NEM heat recovery steam 5

generator (HRSG), and a single GE steam turbine (ST)-generator. In 6

this standard 2 × 1 configuration, each CT generates power and 7

exhausts directly into its own HRSG where the exhaust heat is captured 8

and generates steam for use in the ST. The exhaust steam leaves the 9

turbine and is condensed for reuse in an air-cooled condenser. Air 10

emissions are controlled through the use of Dry Low Nitrogen Oxide 11

(NOx) combustion coupled with Selective Catalytic Reduction (SCR) 12

systems. For each HRSG, two catalyst systems are used to reduce 13

NOx, carbon monoxide (CO), and Volatile Organic Compound (VOC) 14

production. Additionally, Gateway is equipped with a capacity 15

enhancing technology to improve output during peak generation periods. 16

Duct burners are used to increase steam production in the HRSGs 17

resulting in increased ST output. The duct burners allow Gateway to 18

increase its output by approximately 50 MW above the 530 MW nominal 19

capacity. 20

b. Colusa Generating Station 21

Colusa is a 530 MW combined cycle power plant consisting of 22

two GE Frame 7FA CTs, each with its own HRSG, and a single GE ST. 23

In this standard 2 × 1 configuration, each CT generates power and 24

exhausts directly into its own HRSG where the exhaust heat is captured 25

and generates steam for use in the ST. The exhaust steam leaves the 26

turbine and is condensed for reuse in an air-cooled condenser. Air 27

emissions are controlled through the use of Dry Low NOx combustion 28

coupled with SCR systems. For each HRSG, two catalyst systems are 29

used to reduce NOx, CO and VOC production. Additionally, Colusa is 30

equipped with a capacity enhancing technology to improve output during 31

peak generation periods. Duct burners are used to increase steam 32

production in the HRSGs resulting in increased ST output. The duct 33

3-3

burners allow Colusa to increase its output by approximately 127 MW 1

above the 530 MW nominal capacity. 2

c. Humboldt Bay Generating Station 3

Humboldt is a 163 MW reciprocating engine power plant consisting 4

of 10 Wartsila 18V50 DF natural gas-fired reciprocating engines. Each 5

engine has 18 cylinders, each with a bore of 50 centimeters, and 6

operates at 514 revolutions per minute. Each engine is designed to run 7

on natural gas with 1 percent of total fuel input provided by low sulfur 8

distillate as the pilot fuel. The engines are also designed to run on low 9

sulfur distillate or biodiesel. Each engine is equipped with a separate 10

independent closed loop cooling system. Emission control is 11

accomplished through the use of SCR. Similar to Gateway and Colusa, 12

two catalyst systems are used to reduce NOx, CO, and VOC production. 13

2. Fuel Cell Facilities 14

a. CSU East Bay Fuel Cell Facility 15

The CSU East Bay Fuel Cell facility is a 1.4 MW facility located on 16

the campus of CSU East Bay in Hayward, California. There is one fuel 17

cell at this facility. This fuel cell uses Molten Carbonate Fuel Cell 18

(MCFC) technology and was manufactured by FuelCell Energy (FCE). 19

This facility provides electricity to PG&E’s electrical grid and waste heat 20

for the university’s use. 21

A fuel cell is an electrochemical conversion process that produces 22

electricity from fuel and an oxidant, which react in the presence of an 23

electrolyte. Molten carbonate is used as the electrolyte in a MCFC. The 24

MCFC technology reforms hydrogen from natural gas to power the fuel 25

cell. Within the MCFC stack, an electrochemical reaction occurs 26

between the hydrogen (the fuel) and oxygen (the oxidant) to generate 27

Direct Current (DC) electricity, heat and water. The DC electricity is 28

converted by an inverter into Alternate Current (AC) for supplying the 29

PG&E electrical grid. 30

b. SFSU Fuel Cell Facility 31

The SFSU Fuel Cell facility is a 1.6 MW facility located on the 32

campus of SFSU in San Francisco, California. There are two fuel cells 33

3-4

at this facility. The first fuel cell, like CSU East Bay, is rated at 1.4 MW, 1

uses MCFC technology, and was manufactured by FCE. This fuel cell 2

provides electricity to PG&E’s electrical grid and also provides waste 3

heat for the university’s use. The second fuel cell is rated at 200 kW, 4

uses Solid Oxide Fuel Cell (SOFC) technology, and was manufactured 5

by Bloom Energy. The Bloom fuel cell provides electricity to PG&E’s 6

electrical grid. 7

The SOFC technology converts natural gas into a hydrogen rich gas 8

and then, using silica as the electrolyte, induces an electrochemical 9

reaction between the hydrogen (the fuel) and oxygen (the oxidant) to 10

generate DC electricity. The DC electricity is fed to an inverter, which 11

converts the DC power to AC for supplying the PG&E electrical grid. 12

The SOFC utilizes the heat that is generated internally to improve 13

electric efficiency. 14

3. Solar Stations 15

a. Vaca Dixon Solar Station 16

Vaca Dixon is a 2 MW PV solar station located in Vacaville, 17

California, on a 16-acre site. The solar station includes 9,672 solar 18

modules that provide DC energy; five inverters that convert the DC 19

energy to AC; one transformer that increases the voltage from 20

480 volts (V) to 12.47 kilovolts (kV); and other equipment such as a 21

communications enclosure, two weather stations, and electrical 22

switchgear. 23

b. Westside Solar Station 24

Westside is a 15 MW PV solar station located near Five Points, 25

California, on a 200-acre site. The solar station includes over 26

66,000 solar modules that provide DC energy; 30 inverters that convert 27

the DC energy to AC; 15 transformers that increase the voltage from 28

440 V to 12.47 kV; and other equipment such as a communications 29

enclosure, two weather stations, and electrical switchgear. 30

c. Stroud Solar Station 31

Stroud is a 20 MW PV solar station located near Helm, California, 32

on a 201-acre site. The solar station includes 88,000 solar modules that 33

3-5

provide DC energy; 40 inverters that convert the DC energy to AC; 1

20 transformers that increase the voltage from 440 V to 12.47 kV; and 2

other equipment such as a communications enclosure, two weather 3

stations, and electrical switchgear. 4

d. Five Points Solar Station 5

Five Points is a 15 MW PV solar station located near Five Points, 6

California, on a 162-acre site. The solar station includes over 7





e. Huron Solar Station 12

Huron is a 20 MW PV solar station located near Huron, California, 13

on a 145-acre site. The solar station includes over 90,000 solar 14

modules that provide DC energy; 40 inverters that convert the DC 15

energy to AC; 10 transformers that increase the voltage from 420 V to 16

12.47 kV; and other equipment such as a communications enclosure, 17

two weather stations, and electrical switchgear. 18

f. Cantua Solar Station 19

Cantua is a 20 MW PV solar station located near Cantua Creek, 20

California, on a 171-acre site. The solar station includes approximately 21





g. Giffen Solar Station 26

Giffen is a 10 MW PV solar station located near Cantua Creek, 27

California, on a 97-acre site. The solar station includes close to 28





3-6

h. Gates Solar Station 1

Gates is a 20 MW PV solar station located on a 120-acre site, 2

adjacent to the Huron Solar Station near Huron, California. The solar 3

station includes 91,490 solar modules that provide DC energy; 4

28 inverters that convert the DC energy to AC; 31 transformers that 5

increase the voltage from 420 V to 12.47 kV; and other equipment such 6

as a communications enclosure, two weather stations, and electrical 7

switchgear. 8

i. West Gates Solar Station 9

West Gates is a 10 MW PV solar station located on a 60-acre site, 10

near Huron, California. The solar station includes over 45,752 solar 11




two weather stations, and electrical switchgear. 15

j. Guernsey Solar Station 16

Guernsey is a 20 MW PV solar station located on a 120-acre site, 17

near Hanford, California. The solar station includes 89,400 solar 18




two weather stations, and electrical switchgear. Guernsey also includes 22

single axis trackers that move the solar modules to optimize their 23

position with the sun. 24

B. Fossil and Solar Operations and Maintenance Organization 25

The Fossil and Solar Operations and Maintenance (O&M) organization is 26

responsible for managing PG&E’s fossil, solar PV and fuel cell generating assets 27

to provide safe, reliable, cost-effective and environmentally responsible 28

generation. Most of the fossil portion of the O&M organization is located at the 29

three generating stations. Most of the PV and fuel cell portion of the 30

organization is located at two separate locations—Antioch and Caruthers. The 31

remainder of the fossil, solar PV and fuel cell O&M staff is headquartered in 32

San Francisco. 33

3-7

PG&E’s Safety, Quality and Standards (SQS) organization provides direct 1

support to the Fossil and Solar O&M organization for the safe, reliable, 2

compliant, efficient operation of PG&E’s fossil generating units. O&M 3

Specialists in the SQS organization act as consultants to the Fossil and Solar 4

O&M organization, offering expertise in methods and procedures to help assure 5

compliance with operating and maintenance standards. 6

PG&E’s Environmental Services organization also provides direct support to 7

the Fossil and Solar O&M organization, with a focus on regulatory compliance. 8

Environmental consultants are located at each of the fossil-fuel generating 9

stations and at or near the PV and fuel cell facilities and support the facility staff. 10

PG&E utilizes contract services for much of its major maintenance work at 11

its fossil-fuel generating stations and PV and fuel cell facilities. For Gateway 12

and Colusa, Long-Term Service Agreements (LTSA)2 for the CTs and STs are 13

provided by GE, the Original Equipment Manufacturer (OEM) for the CTs and 14

STs. Also, PG&E has entered into O&M agreements with the fuel cells’ OEMs. 15

PG&E is committed to providing safe utility service to its customers. As part 16

of this commitment, PG&E reviews its operations, including operation of its fossil 17

and other generation facilities, to identify and mitigate, to the extent possible, 18

potential safety risks to the public, PG&E’s workforce and its contractors. As it 19

operates and maintains its fossil and other generation facilities, PG&E follows its 20

internal controls to ensure public, workplace, and contractor safety. For 21

example, PG&E’s Employee Code of Conduct describes the safety of the public, 22

employees and contractors as PG&E’s highest priority. PG&E’s commitment to 23

a safety-first culture is reinforced with its Safety Principles, PG&E’s Safety 24

Commitment, Personal Safety Commitment and Keys to Life. These tools were 25

developed in collaboration with PG&E employees, leaders, and union leadership 26

and are intended to provide clarity and support as employees strive to take 27

personal ownership of safety at PG&E. Additionally, PG&E seeks all applicable 28

regulatory approvals from governmental authorities with jurisdiction to enforce 29

laws related to worker health and safety, impacts to the environment, and public 30

health and welfare. 31

2 LTSAs are also known as Contractual Services Agreements.

3-8

As part of PG&E’s Safety Commitment, PG&E follows recognized best 1

practices in the industry. PG&E operates each of its generation facilities in 2

compliance with all local, state and federal permit and operating requirements 3

such as state and federal Occupational Safety and Health Administration 4

requirements and the California Public Utilities Commission’s (CPUC) General 5

Order (GO) 167. As discussed below, PG&E does this by using internal controls 6

to help manage the O&M of its generation facilities. 7

With regard to employee safety, Power Generation employees develop a 8

safety action plan each year. This action plan focuses on various items such as 9

training and qualifications, contractor safety, human performance, approaches to 10

reduce or eliminate recordable injuries and motor vehicle incidents, approaches 11

to sharing safety best practices, and actions to improve the safety culture of the 12

organization. 13

With regard to public safety, PG&E continues to develop and implement a 14

comprehensive public safety program that includes public education, outreach 15

and partnership with key agencies, and enhanced emergency response 16

preparedness, training, drills and coordination with emergency response 17

organizations. 18

Fundamental to a strong safety culture is a leadership team that believes 19

every job can be performed safely and seeks to eliminate barriers to safe 20

operations. Equally important is the establishment of an empowered grass roots 21

safety team that can act to encourage safe work practices among peers. Power 22

Generation’s grass roots team is led by bargaining unit employees from across 23

the organization who work to include safety best practices in all the work they 24

do. These employees are closest to the day-to-day work of providing safe, 25

reliable, and affordable energy for PG&E’s customers and are best positioned to 26

implement changes that can improve safety performance. 27

C. Internal Controls 28

GO 167 sets forth standards that govern the O&M of power plants. The 29

purpose of GO 167 is “to implement and enforce standards for the maintenance 30

and operation of electric generating facilities and power plants so as to maintain 31

and protect the public health and safety of California residents and businesses, 32

to ensure that electric generating facilities are effectively and appropriately 33

maintained and efficiently operated, and to ensure electrical service reliability 34

3-9

and adequacy.”3 The standards set forth in GO 167 include operation 1

standards, maintenance standards, and logbook standards. PG&E 2

accomplishes compliance with GO 167 through the use of various internal 3

controls, and through audits by the CPUC. GO 167 was set in place post energy 4

crisis by the CPUC as a way to enforce prudent practices in the availability of the 5

fossil fleet for California. 6

Internal controls are a means by which an organization’s resources are 7

directed, monitored, and measured. PG&E defines internal controls as a 8

process or set of processes that take into consideration an organization’s 9

structure, work and authority flows, people and management information 10

systems and are designed to help the organization accomplish specific goals or 11

objectives. 12

PG&E has many internal controls in place to manage the O&M of its 13

generation assets. These controls include: (1) guidance documents; 14

(2) operations reviews; (3) an incident reporting process; (4) a corrective action 15

program; (5) an outage planning and scheduling process; and (6) a design 16

change process. Each of these controls is discussed below. 17

1. Guidance Documents 18

The guidance documents applicable to PG&E’s fossil and solar 19

operations include PG&E Policy, PG&E Utility Standard Practices, PG&E 20

Utility Procedures, and Power Generation-specific guidance documents. 21

Power Generation-specific guidance documents include Standards, 22

Procedures and Bulletins. In addition, the fossil-fuel generating stations and 23

fuel cell and PV facilities have site-specific procedures. These guidance 24

documents cover virtually all aspects of safety, operations, maintenance, 25

planning, environmental compliance, regulatory compliance, emergency 26

response, work management, inspection, testing and other areas. Each 27

guidance document describes the purpose of the document, the details of 28

the actions and/or processes covered by the document, management’s roles 29

and responsibilities, and the date the document became effective. 30

3 CPUC, GO 167, Section 1.0 Purpose.

3-10

2. Operations Reviews 1

Operations reviews are performed at each of the three fossil-fuel 2

generating stations each year and periodically at remote facilities such as 3

the solar stations and fuel cells by the SQS organization. The purpose of 4

the operations review is to assure that PG&E’s generation facilities are 5

operated in a safe and efficient manner and that they are in compliance with 6

standard operating and clearance procedures. 7

By thoroughly reviewing fossil and solar operations, PG&E can identify 8

possible precursors to more serious problems. The plant managers are 9

provided a report on the overall operational health of their generating 10

stations, with recommendations based on safety, best operating practices, 11

latest operating technologies, training, and reducing the overall cost of 12

production. The recommendations are then implemented on a priority basis 13

within a reasonable time frame. This control enhances PG&E’s ability to 14

improve operations by promoting safe operating practices and verifying 15

compliance with emergency and standard operating and clearance 16

procedures. Operations reviews were completed for Gateway, Colusa, 17

Humboldt, Caruthers Headquarters, Cantua, Gates and West Gates in 2017. 18

3. Incident Reporting Process 19

The incident reporting process is intended to document problems, 20

activities and events that impact or could potentially impact the performance 21

of systems that assure: (1) public safety; (2) facility safety, reliability, 22

availability, and protection of property; and/or (3) environmental or 23

regulatory compliance. By thoroughly analyzing significant problem events 24

that occur in the O&M of PG&E’s facilities, PG&E can report to various 25

regulatory agencies as required, identify possible precursors to repetitive or 26

more serious problems, understand root causes, and communicate lessons 27

learned to other facilities and personnel. 28

4. Corrective Action Program 29

The Corrective Action Program (CAP) documents and tracks corrective 30

actions and commitments. The CAP includes problem identification, cause 31

determination, reporting, development of corrective actions and corrective 32

action implementation tracking. 33

3-11

The CAP for PG&E’s Power Generation organization utilizes SAP 1

notifications and orders to track and document actions that are necessary or 2

have been taken as a result of audit and/or inspection findings, deviations 3

identified in incident reports, regulatory non-compliance issues, engineering 4

deviations and other systemwide issues. 5

5. Outage Planning and Scheduling Processes 6

The outage schedule is developed to communicate when various 7

generating stations will be unavailable due to maintenance or project work. 8

Annual maintenance outages, project-specific outages and combination 9

outages encompassing both project and maintenance tasks are shown on 10

the schedule. The outage schedule for a given outage year is developed 11

through an iterative process, over several years, as projects and 12

maintenance tasks are identified by field employees, management, project 13

managers and others. Typically, no outages are planned during the peak 14

summer generation season. Also, every effort is made to limit the number 15

and duration of outages in the off-peak shoulder months. 16

The yearly outage schedule is not a static document. The schedule is 17

fluid and adaptable to changing requirements for outages. PG&E’s Energy 18

Policy and Procurement organization, the California Independent System 19

Operator (CAISO) and others utilize the schedule to make plans regarding 20

resource allocation, replacement power and restrictions on the system. 21

Therefore, changes in the schedule, particularly in the short term, are 22

discouraged. However, it is inevitable that due to the dynamic nature of the 23

PG&E system, changes will be required. Changes to the schedule may be 24

required based on many factors, including weather conditions, resource 25

constraints, changes in project scope or schedule, and/or emergent work. 26

Depending on the proximity to the outage start date, changes to the scope 27

and schedule require different levels of review and approval. Before outage 28

changes are approved, consideration is given to the impacts of the change 29

on issues such as: effects on equipment reliability, replacement power 30

costs, resources and other scheduled outages. 31

An outage plan is developed prior to the start of the outage. Depending 32

on the size and duration of the outage, an outage plan can be as simple as 33

a list of work orders extracted from the SAP Work Management (SAP WM) 34

3-12

system, or as complex as a critical path, resource-loaded work execution 1

plan detailing each task for a project as well as preventative and corrective 2

maintenance work orders. The development of an outage plan can be 3

broken down into three distinct, but interrelated, processes: (1) planning 4

and scoping; (2) scheduling; and (3) outage execution. 5

a. Planning and Scoping 6

The planning and scoping process entails determining which work is 7

to be executed during the outage. This includes preventative 8

maintenance work orders, corrective work orders for repairs on 9

equipment and/or facilities and project-specific asset replacements or 10

major refurbishments. During this process, the required resources to 11

execute the work and the durations of all work activities are identified. 12

PG&E utilizes SAP WM as the tool to manage preventative and 13

corrective work. Preventative maintenance work orders, sometimes 14

referred to as recurring work, encompass routine maintenance work 15

performed at established intervals. Corrective work orders, sometimes 16

referred to as trouble tags, refer to work identified to correct an issue 17

that is limiting the ability of the equipment or facility to efficiently perform 18

its design function. The SAP WM system is the electronic repository 19

where preventative and corrective work is identified, tracked, organized 20

and managed. The system utilizes maintenance libraries to generate 21

recurring work orders against a piece of equipment at the appropriate 22

frequency as specified by PG&E. Corrective work orders are created in 23

the system by the crews or individuals identifying the problem. 24

The planning and scoping process occurs over a 2- to 3-year period 25

leading up to the outage start date. 26

b. Scheduling 27

The scheduling process includes determining the timing of the start 28

of the outage, as well as the appropriate duration. Outage timing and 29

durations are influenced by many factors, including but not limited to: 30

capital and maintenance work to be performed, system operation 31

constraints, time of year, labor resources available to perform work, 32

CAISO constraints, and transmission system issues. 33

3-13

The scheduling process occurs in conjunction with the scoping and 1

planning process over a 2- to 3-year timeframe. A base preliminary 2

outage schedule is developed from historical outage durations and 3

timing, and OEM recommended frequency based on service hours 4

and/or the number of equipment starts/stops. This schedule is refined 5

over time as the scoping and planning process provides updated 6

information regarding the work to be performed during the outages. 7

In October of the year prior to the outage year, the planned outage 8

schedule is submitted to the CAISO to set the base outage schedule. 9

After this submission, any requests for changes to individual outages 10

are submitted to the responsible plant manager and/or fossil O&M 11

director for approval. The level of management approval is dictated by 12

the proximity of the request to the outage start date. These internal 13

approvals are required before the changes are submitted to the CAISO. 14

c. Outage Execution 15

The outage execution process encompasses not only performing 16

the work planned for the outage, but also following many sub-processes 17

for notifications to and approvals by stakeholders. These include: 18

Notifications to and approvals from the CAISO to separate the 19

unit(s) from the grid. 20

Energy isolation procedures covering the steps required to 21

electrically, hydraulically and mechanically clear the units and 22

facilities (i.e., put them in a safe condition) for the outage work 23

to proceed. 24

Notifications and approvals for any changes in the outage due to 25

emerging work or changed conditions. 26

Restoration procedures to restore the unit to service when the 27

outage work is completed. This includes complying with the steps in 28

the energy isolation procedure and any start-up procedure for new 29

or re-furbished equipment. 30

Notifications to and approvals from the CAISO to restore the unit to 31

service and connect to the grid at the completion of the outage. 32

The three processes detailed above are highly interrelated. Outage 33

scheduling is dependent on planning and scoping. As the defined 34

3-14

outage scope changes, the outage schedule is continuously reviewed 1

and updated based on that changed scope. Conversely, if outside 2

influences require the outage timing or duration to change, the scope of 3

work is reviewed to determine if it can be adjusted to fit the revised 4

timeframe, or if the outage scheduling needs to be moved. During 5

outage execution, emerging work may require an outage extension, 6

which could, in turn, impact the planning and scheduling of outages on 7

other units or facilities. 8

6. Design Change Process 9

Design changes are controlled through the design change process. 10

The design change process is the process for proposing, evaluating, and 11

implementing changes to the design of structures, systems, and equipment 12

at PG&E’s generating facilities. It includes the process for requesting design 13

changes; reviewing and approving design change requests; implementing 14

design changes; closing out design changes; and revising design 15

change notices. 16

D. Operational Results 17

This section examines the operational results during the 2017 record period 18

by reviewing the energy production, fuel usage, and reliability of the fossil-fuel 19

generating stations and the energy production and fuel usage of the PV facilities. 20

The 2017 outages are also reviewed for facilities larger than 25 MW. 21

1. Energy Production 22

The output of Gateway, Colusa, and Humboldt typically varies 23

throughout the day in response to CAISO market awards and dispatch 24

instructions. 25

During 2017, PG&E’s fuel cells were typically self-scheduled in the 26

CAISO markets to run at maximum production. The fuel cells operate at 27

extremely high temperatures (in excess of 1,200 degrees Fahrenheit). 28

When a fuel cell’s output is cycled, the temperature of the fuel cell stack 29

cycles. Since the useful life of a fuel cell stack is reduced with each thermal 30

cycle, PG&E minimizes thermal cycles by running the fuel cells as base 31

loaded resources. 32

3-15

PG&E’s fossil-fuel generating stations provided approximately 1

5,706,889 megawatt-hours (MWh) of energy during the 2017 record period. 2

To generate this amount of energy, the fossil-fuel generating stations burned 3

42,424,631 Million British Thermal Units (MMBtu) of natural gas and 4

27,087 MMBtu of distillate fuel. The resulting net plant heat rate for the 5

fossil-fuel generating stations in 2017 was 7,439 Btu/kilowatt-hours (kWh) as 6

shown in Table 3-1 below.4 7

TABLE 3-1 FOSSIL GENERATION 2017 ENERGY PRODUCTION

Line No. Station

Net Generation (MWh)

Fuel Usage (MMBtu)

Average Net Heat Rate (Btu/kWh)

1 Gateway 2,779,066 20,354,041 7,324 2 Colusa 2,496,298 18,253,302 7,312 3 Humboldt 431,525 3,844,375 8,909

4 Total 5,706,889 42,451,719 7,439 (average)

During 2017, PG&E’s PV generating facilities were included in the 8

CAISO market in accordance with the appropriate CAISO tariff provisions 9

relating to these types of intermittent renewable facilities, and as a result 10

were typically operated at maximum production.5 PG&E’s PV generating 11

facilities provided approximately 297,694 MWh of energy during the 2017 12

record period. 13

D.10-04-052 approving PG&E’s 5-year solar PV Program links PG&E’s 14

recovery of its O&M costs for its PV facilities in its General Rate Cases to 15

the performance of the PV facilities. The decision states that, should the 16

average performance of PG&E’s PV UOG systems fall below 80 percent of 17

expected output, it will weigh heavily in favor of disallowing or refunding 18

some of the O&M costs to ratepayers.6 The PV facilities operated at 19

90.8 percent of the expected output during the 2017 record period. PG&E 20

4 Net plant heat rate is equal to the amount of fuel consumed (Btu) divided by the net

generation (kWh). 5 Nine of PG&E’s PV generation facilities are capable of being curtailed for economic

dispatch purposes. 6 D.10-04-052, Ordering Paragraph 7.

3-16

reduced power output on (curtailed) many of its PV generation facilities 1

during 2017 (at the request of the CAISO and for economic dispatch 2

purposes). Had PG&E not reduced output as directed, PG&E’s PV facilities 3

would have operated at 97.3 percent of the expected output during the 2017 4

record period. 5

2. Outages 6

PG&E’s fossil-fuel generating stations experienced two different types of 7

outages during the record period: (1) scheduled outages; and (2) forced 8

outages. 9

Scheduled outages include both planned outages and maintenance 10

outages. Planned outages are typically scheduled prior to the start of the 11

year. PG&E’s combined cycle plants, Gateway and Colusa, typically 12

schedule planned outages in the spring and fall of each year to address 13

preventive and corrective maintenance issues. Maintenance outages are 14

scheduled when needed throughout the year to perform testing or routine 15

maintenance, or to perform non-emergency repairs when the outage can be 16

deferred beyond the end of the next weekend, but requires a capacity 17

reduction before the next planned outage. Humboldt schedules planned 18

outages for larger scope and duration routine engine maintenance that is 19

hour-based. Humboldt schedules maintenance outages for smaller scope 20

and duration routine engine maintenance that is hour-based. 21

Forced outages occur when equipment suddenly fails and the unit 22

immediately trips, or when the repair need is so urgent that the unit is 23

required to come off line before the end of the next weekend. 24

Consistent with previous Energy Resource Recovery Account 25

compliance proceedings, PG&E is providing general information regarding 26

Scheduled Outages that were 24 hours or more in duration, and specific 27

information regarding each Forced Outage that was longer than 24 hours in 28

duration, for facilities that are 25 MW or greater in size. PG&E provides 29

additional, detailed information concerning the outages that occurred during 30

the record period to the Office of Ratepayer Advocates (ORA) in response to 31

ORA’s Master Data Request. 32

During forced outages, one of PG&E’s primary goals is to bring the unit 33

back on line safely and expediently. Additionally, PG&E often examines 34

3-17

components associated with the specific equipment that failed. This 1

examination helps inform PG&E as to whether modifications or repairs 2

should be made to those components, either at the unit where the outage 3

occurred, or at other units with similar components. While this might extend 4

the time before a unit is returned to service, it can potentially avoid a future 5

forced outage. 6

One of the key industry metrics used to gauge the operating 7

performance of generating units is the Forced Outage Factor (FOF). FOF is 8

a ratio of the hours a unit is forced out of operation to the total hours in the 9

operation period (i.e., month, year). The fossil portfolio 2017 FOF was 10

0.55 percent. This FOF is significantly better than the industry benchmark of 11

1.80 percent. Table 3-2 includes the fossil portfolio FOF for the past 12

five years compared to the industry benchmark.7 13

TABLE 3-2 FOSSIL PORTFOLIO FORCED OUTAGE FACTOR

Line No. Year FOF (%)

Latest Benchmark

1 2012 0.88 2 2013 0.11 3 2014 4.20 4 2015 0.79 5 2016 0.31 6 2017 0.55 1.80

a. Gateway Generating Station 14

1) Scheduled Outages 15

Gateway executed two planned outages in 2017 that lasted 16

24 hours or more. The first planned outage included a CT bore 17

scope inspection, ST L0 blade inspections, plant instrumentation 18

upgrades, boiler feed pump overhauls, valve rebuilds, HRSG 19

maintenance, and catalyst inspections. Generator step-up 20

transformer protection relay replacements were begun in the first 21

7 The industry benchmark is the 2012-2016 North American Electric Reliability

Corporation Generating Availability Data System Generating Unit Statistical Brochure. It is included in PG&E’s workpapers.

3-18

planned outage and completed in the second planned outage, 1

during which PG&E also performed various inspections, routine 2

maintenance and minor corrective work. 3

Gateway did not experience any maintenance outages in 2017 4

lasting 24 hours or more in duration. 5

2) Forced Outages 6

Gateway did not experience any forced outage in 2017 lasting 7

longer than 24 hours in duration. 8

b. Colusa Generating Station 9


Colusa executed two planned outages in 2017 that lasted 11

24 hours or more in duration. In the first planned outage PG&E 12

performed maintenance on all three exciters, the steam bypass 13

valve, the boiler feed water control valve, the HRSG blowdown 14

valve, and the HRSG tubes, and also performed other minor routine 15

maintenance and corrective work. PG&E also performed 16

inspections on the HRSG catalysts, pressure vessels, and CTs, 17

including the CT R0 blades. In the second planned outage, PG&E 18

performed various inspections, including pressure piping weld 19

inspections, transformer inspections, and fire system inspections. 20

PG&E made repairs to the high energy piping, HRSG exhaust and 21

HRSG pin seal, and implemented a high energy piping pipe 22

surveillance program. Routine maintenance and minor corrective 23

work including penetration seal replacements was also completed. 24

Colusa did not experience any maintenance outages in 2017 25

lasting 24 hours or more in duration. 26

2) Forced Outages 27

On June 1, 2017, at 10:08 a.m., Colusa was removed from 28

service to allow PG&E to investigate a leak identified on the auxiliary 29

steam piping. The investigation revealed a cracked flange, likely 30

caused by thermal fatigue. A replacement flange was procured and 31

delivered the same day. PG&E replaced the flange and returned 32

the unit to service on June 2, 2017 at 2:45 p.m. 33

3-19

c. Humboldt Bay Generating Station 1


The preventative maintenance schedule at Humboldt is based 3

on service hours of each engine. Maintenance is necessary for 4

each engine at 1,000, 2,000, 4,000, 6,000, 8,000, 12,000, 18,000 5

and 24,000 hour intervals. The 12,000 and 18,000 hour overhauls 6

are the most extensive and take the most time to plan for and 7

complete. As mentioned earlier, Humboldt schedules planned 8

outages for larger scope and duration engine maintenance, and 9

schedules maintenance outages for smaller scope and duration 10

engine maintenance. Since Humboldt is a 10-engine facility, 11

another engine is typically available to back up an engine that is out 12

of service for an outage. 13

Humboldt executed one planned outage in 2017 lasting 14

24 hours or more in duration. Humboldt experienced 15

26 maintenance outages lasting 24 hours or longer on its 16

10 engines in 2017. 17

The planned outage was for an 18,000-hour major overhaul on 18

Unit 3. 19

The maintenance outages were scheduled primarily to conduct 20

routine inspections and preventative maintenance. Routine 21

preventative maintenance is required on the engines in order to 22

assure reliable service in the future. 23

2) Forced Outages 24

Humboldt experienced 14 forced outages lasting longer than 25

24 hours in 2017. This equates to an average of just over 26

one forced outage per unit in 2017. 27

a) Units 1-3 28

On April 10, 2017, at 8:20 a.m., Unit 1 was forced offline 29

due to a blown rupture disc8 at the SCR inlet. PG&E replaced 30

8 A rupture disc is a non-reclosing pressure-relief device that protects the engine exhaust

from high pressure conditions.

3-20

the rupture disc and tested and restored the unit to service on 1

April 12, 2017 at 12 p.m. 2

On June 21, 2017, at 6:22 p.m., Units 1, 2 and 3 were 3

unable to generate due to the outgoing feeder breaker tripping 4

offline. PG&E investigated the breaker and determined that the 5

trip of the overcurrent ground relay was a result of a 6

combination of factors: large primary currents fed through a 7

small current transformer core, primary currents not centered in 8

the window-type current transformer, and the window-type 9

current transformer being square shaped (as opposed to round). 10

The combination resulted in stray magnetic fields causing local 11

current transformer saturation. The stray magnetic fields 12

created enough current to trip the extremely sensitive 13

secondary 51G element of the overcurrent ground relay. 14

PG&E determined that disabling the 51G element for ground 15

overcurrent relay and replacing its functionality with the 16

59G function would provide the protection without causing 17

similar trips. The units were returned to service on June 23, 18

2017 at 2:35 p.m. 19

On July 9, 2017, at 7:02 p.m., Unit 3 tripped offline due to a 20

breaker opening on the differential current relay. PG&E 21

investigated and found that the differential current relay had 22

failed and needed to be replaced. PG&E replaced the relay, 23

tested the unit, and returned it to service on July 13, 2017 at 24

3:38 p.m. 25

On November 8, 2017, at 7 a.m., Unit 3 was forced out of 26

service from a maintenance outage due to damaged camshaft 27

bearings. After observing particles in the lube oil filter, PG&E 28

decided to schedule an outage for an inspection. During the 29

inspection, several of the camshaft bearings were found to be 30

scored. PG&E then initiated a forced outage to remove the 31

camshaft segments, replace the bearings, and investigate the 32

cause of the damage. 33

3-21

During the investigation of the cause of the bearing scoring, 1

PG&E discovered that the charge air receiver pulsation damper 2

had failed. PG&E subsequently removed the heads to remove 3

and replace the damper. After removing the heads, PG&E 4

found that the heads were leaking water and oil into the 5

cylinders. PG&E believes that the cause of the leaking heads 6

was poor workmanship by the OEM during the planned outage 7

earlier in the year. The replacement of the heads was the 8

critical path in the return to service of this unit. As of the end of 9

2017, the OEM was in the process of replacing the heads. A 10

total of 18 heads will be replaced. The unit remained out of 11

service through the end of 2017. 12

On November 20, 2017, at 8:05 a.m., Unit 2 was forced 13

offline due to water leaking into the crankcase. PG&E 14

investigated and identified a head gasket leak on cylinder A7. 15

PG&E repaired the leak and returned the unit to service on 16

November 23, 2017 at 9 a.m. 17

On December 3, 2017, at 6:05 a.m., Unit 1 tripped offline. 18

PG&E investigated the cause of the trip and found that one of 19

the two speed sensors on the flywheel was not operating 20

properly. PG&E replaced both speed sensors and returned the 21

unit to service the next day at 9:01 a.m. 22

b) Unit 4 23

On July 27, 2017, at 9:10 a.m., Unit 4 tripped offline due to 24

an activation of the oil mist detector. Oil mist detectors help 25

prevent fires and explosions by detecting minute concentrations 26

of oil in the crankcase of each cylinder. PG&E inspected the 27

unit and found that cylinder B9 was leaking water into the 28

crankcase around the liner. PG&E replaced the O-ring, tested 29

the unit, and returned it to service on July 29, 2017 at 30

10:20 a.m. 31

On December 4, 2017, at 9:39 a.m., Unit 4 was forced 32

offline due to a failed rupture disc. During PG&E’s routine 33

inspection with the unit on-line, the operator heard an unusual 34

3-22

sound. The operator investigated the source of the sound and 1

identified a failed rupture disc on the engine exhaust and forced 2

the unit out of service. Scaffolding was erected and PG&E 3

replaced the rupture disc and returned the unit to service the 4

next day at 3:50 p.m. 5

c) Unit 5 6

On December 4, 2017, at 8:50 a.m., Unit 5 was forced 7

offline due to a failed rupture disc. During PG&E’s routine 8

inspection with the unit on-line, the operator heard an unusual 9

sound. The operator investigated the source of the sound and 10

identified a failed rupture disc on the engine exhaust and forced 11

the unit out of service. Scaffolding was erected and PG&E 12

replaced the rupture disc and returned the unit to service the 13

next day at 12:05 p.m. 14

d) Unit 7 15

On May 13, 2017, at 8:35 a.m., Unit 7 failed during start-up 16

because cylinder A7 would not maintain the required 17

temperature. PG&E replaced the gas valve, cylinder control 18

module (CCM) A3 and the knock sensor connection. The CCM 19

is a computer that sends firing signals to the cylinders based on 20

the signals from the engine’s master control module. Each 21

CCM controls three cylinders, with CCM A3 controlling the 22

A7 cylinder. The knock sensor measures detonation in the 23

cylinder. The unit was tested and returned to service the next 24

day at 3 p.m. 25

e) Unit 8 26

On October 17, 2017, at 7:54 a.m., Unit 8 was shut down 27

due to a failed rupture disc. PG&E replaced the rupture disc 28

and returned the unit to service the next day at 4:26 p.m. 29

f) Unit 10 30

On June 24, 2017, at 5:38 a.m., Unit 10 tripped offline due 31

to erratic exhaust gas temperatures measured at cylinder A8. 32

3-23

PG&E replaced the CCM A3, which controls cylinder A8. The 1

unit was tested and returned to service the next day at 9:11 p.m. 2

E. Conclusion 3


PG&E’s utility-owned fossil-fuel, fuel cell, and PV facilities, and outages that 5

occurred at these facilities during the 2017 record year. It demonstrates that 6

PG&E’s utility-owned fossil-fuel and PV portfolio was operated in a reasonable 7

manner during the record period. 8

PG&E has in place a comprehensive management structure, with adequate 9

internal controls, to prudently oversee the operation of its fossil-fuel generating 10

stations and PV facilities. PG&E’s compliance with the operations standards, 11

maintenance standards, and logbook standards set forth in GO 167 are further 12

evidence that PG&E’s fossil and solar portfolio was operated in a reasonable 13

manner. In addition, scheduled outages were planned sufficiently in advance to 14

allow adequate preparation time and were executed efficiently to assure prompt 15

return to service. 16

PG&E’s fossil portfolio was operated in a reasonable manner as 17

demonstrated by the 2017 record year FOF results being significantly better than 18

the industry average and by the small number of forced outages. PG&E acted 19

reasonably in resolving forced outages in a timely manner. 20


CHAPTER 4

UTILITY-OWNED GENERATION: NUCLEAR

4-i


UTILITY-OWNED GENERATION: NUCLEAR

TABLE OF CONTENTS

A. Introduction....................................................................................................... 4-1

B. DCPP’s Operations Organization ..................................................................... 4-1

C. DCPP System Management............................................................................. 4-2

1. Procedures................................................................................................. 4-2

2. Corrective Action Program......................................................................... 4-2

3. Outage Planning and Scheduling Process................................................. 4-3

4. Project Management.................................................................................. 4-4

5. Quality Assurance Program ....................................................................... 4-5

D. Operational Results .......................................................................................... 4-5

1. Capacity Factor and Energy Production..................................................... 4-5

2. Outages ..................................................................................................... 4-7

a. Unit 1 ................................................................................................... 4-9

b. Unit 2 ................................................................................................... 4-9

c. Outage-Related Violations From Nuclear Regulatory Commission ..... 4-9

E. Conclusion...................................................................................................... 4-10

4-1


CHAPTER 42

UTILITY-OWNED GENERATION: NUCLEAR3

A. Introduction4


operation of Pacific Gas and Electric Company’s (PG&E) utility-owned nuclear 6

facility, and outages that occurred at this facility during the 2017 record year.7

PG&E’s utility-owned nuclear facility was operated in a reasonable manner 8

during the record period. During the record period, PG&E owned, operated and 9

maintained one nuclear generating facility, the Diablo Canyon Power Plant 10

(DCPP), located nine miles northwest of Avila Beach in San Luis Obispo County. 11

DCPP consists of twin pressurized water reactors, Units 1 and 2, rated at a 12

nominal 1,122 megawatts (MW) and 1,118 MW, respectively.13

All nuclear activities are regulated and overseen daily by the Nuclear 14

Regulatory Commission (NRC) to ensure that the facility is operated within 15

federal regulations.16

B. DCPP’s Operations Organization17

PG&E’s Nuclear Generation organization, led by the Vice President Nuclear 18

Generation and Chief Nuclear Officer (CNO), has responsibility for all activities 19

necessary for safe operation of the station. The Station Director, the Senior 20

Director, Nuclear Services, the Director of Business Operations, the Director of 21

Quality Verification (QV), and the Manager of Employee Concerns Program 22

(ECP) report to the CNO.23

The Station Director is responsible for operations, maintenance, and nuclear 24

work management. Operations Services, Maintenance Services, Nuclear Work 25

Management, Chemistry and Radiation Protection, Learning and Performance 26

Improvement report to the Station Director. The Senior Director, Nuclear 27

Services is responsible for providing engineering and design services, project 28

management, security, the emergency response program, regulatory and risk 29

programs, and performance improvement. The Director of Business Operations 30

is responsible for business planning. The Director of QV is responsible for 31

independent oversight of nuclear activities. Finally, the Manager of ECP32

administers the ECP required by NRC regulations.33

4-2

C. DCPP System Management1

Plant safety is essential to the successful operation of a nuclear power 2

station. Nuclear plants that focus on cost and production at the expense of 3

safety may be required by the NRC to shut down for extended periods of time to 4

correct safety problems. PG&E has remained focused on plant safety and 5

equipment reliability by pursuing critical projects in expense and capital even as 6

it pursues cost control efforts. Due to PG&E’s effective balancing of plant safety 7

and reliability, DCPP has performed well with reliability maintained at extremely 8

high levels to the benefit of PG&E’s customers.9

PG&E has many internal controls in place to manage the operations and 10

maintenance of DCPP. These controls include: (1) procedures; (2) a Corrective 11

Action Program (CAP); (3) an outage planning and scheduling process; (4) a12

project management process; and (5) a Quality Assurance (QA) Program. Each 13

of these controls is discussed below.14

1. Procedures15

Procedures cover virtually all aspects of safety, operations, 16

maintenance, planning, environmental compliance, regulatory compliance, 17

emergency planning, work management, inspection, testing and other 18

areas. Each procedure describes the purpose of the document, the details 19

of the actions and/or processes covered by the document, management’s 20

roles and responsibilities, and the date the document became effective.21

2. Corrective Action Program22

The CAP is the main process that DCPP uses to identify, analyze, and 23

resolve plant problems, and is required by the regulations of the NRC.124

Elements of the program include issue identification, issue significance 25

reviews, various levels of cause analysis up to root cause analysis, 26

corrective action development and implementation, and performance 27

trending and monitoring. The program is used to develop corrective actions 28

to prevent recurrence of problems.29

1 See 10 Code of Federal Regulations (CFR) 50, Appendix B.

4-3

3. Outage Planning and Scheduling Process1

As discussed in Section D.2 below, nuclear generating units must be 2

shut down periodically to be refueled. Planning the duration of each 3

refueling outage is a complex task. Every refueling outage has work 4

activities that are similar in scope and length including: (1) shutdown and 5

cool down of the reactor; (2) disassembly of the reactor vessel; (3) fuel 6

replacement; and (4) reassembly of the reactor vessel, followed by heatup 7

and startup of the plant. During these refueling periods, scheduled8

maintenance is conducted, surveillance tests2 are performed, and plant 9

modifications are completed. Because DCPP Units 1 and 2 do not routinely 10

shut down at other times, a great deal of maintenance is planned for these 11

refueling outages.12

The DCPP refueling outage planning process is governed by a system 13

of milestones. The outage is broken down into individual steps to allow a 14

logical process for developing a schedule and monitoring outage preparation 15

activities. Each outage has a set of milestones and due dates. The 16

milestones are consistent from outage to outage. Nuclear Work 17

Management and senior leadership monitor completion of the milestones to 18

ensure the organization is prepared for the upcoming outage.19

The outage preparation milestones begin with a review of the long-range 20

outage plan by Nuclear Work Management, approximately 24 months prior 21

to the outage start date. Other significant milestones include outage scope 22

freeze at approximately 12 months prior to outage start and issuance of the 23

initial schedule at approximately 11 months prior to outage start. The initial 24

schedule undergoes two additional revisions prior to the outage start to 25

incorporate activity logic ties and resource availability. An additional review 26

of the outage safety plan and the outage safety schedule is performed by 27

the Plant Staff Review Committee one month prior to outage start. The final 28

schedule is issued two weeks prior to the outage start.29

The initial start time for future outages is developed years in advance of 30

the outage start through a coordinated effort between Nuclear Work 31

Management and Engineering Services. Outage start dates are typically in 32

2 Surveillance tests are tests required by the NRC-approved technical specifications.

4-4

the spring or fall to support operation during the summer months and are 1

coordinated with reactor fuel core cycle length (currently from 18 to 2

20 months on each unit). This planning minimizes years in which an outage 3

occurs on both Units 1 and 2. The outage initial start date is then 4

coordinated through PG&E’s Energy Policy and Procurement organization, 5

well in advance of the actual outage start date.6

All key steps necessary to determine the duration of a refueling outage 7

are developed through the milestone process discussed above. In the 8

outage schedule, some “float” hours are included to accommodate any 9

minor issues that arise during the outage. The float hours are intended to 10

assure that the unit is returned to service as planned in the outage schedule.11

Nuclear Work Management, through the milestone structure, identifies 12

most of the outage design scope (including both major and minor items) 13

approximately 22 months prior to the outage start. This scope is reviewed 14

and approved by station leadership and is finalized 20 months prior to the 15

outage start. Required preventive maintenance items are identified and 16

approved by Engineering Services 15 months prior to the outage start. 17

Preventive maintenance items are items that are needed on a recurring 18

frequency to ensure a safe and reliable plant. Examples of preventive 19

maintenance include motor overhauls, valve refurbishments and instrument 20

calibrations. 21

Once the outage scope milestone is completed, there is a process for 22

incorporating late scope additions and scope deletions. For significant 23

scope items or challenges to the scope, approval by a Readiness Review 24

Board, consisting of upper management and chaired by the Station Director, 25

is required. These items are presented to the board and either approved as 26

scope addition or rejected. This process is utilized for all refueling outages 27

at DCPP and was accordingly used to develop and modify the outage scope 28

for the 2017 Unit 1 1R20 refueling outage discussed in Section D.2 below.29

4. Project Management30

Project work is controlled through the project management process. 31

Projects are assigned a project manager who has responsibility for the 32

project scope, cost and schedule, and coordinates and manages the project 33

from inception to closeout. Project management procedures and tools are in 34

4-5

place to provide Nuclear Generation project managers with guidelines for 1

successfully achieving the project objective of each project they manage. 2

These procedures are intended to be applicable to all project types, sizes 3

and phases, and are anticipated to improve the consistency and quality of 4

project management throughout Nuclear Generation. Project managers are 5

responsible for regular project reporting to management.6

5. Quality Assurance Program7

QA audits, assessments, reviews and inspections are required by the 8

NRC. These processes evaluate plant activities to ensure they are being 9

performed in accordance with NRC QA program requirements and other 10

recognized industry standards. Quality oversight activities at DCPP are 11

performed in accordance with the following regulations: 10 CFR 50, 12

Appendix B; NRC Regulatory Guide 1.33 (that endorses American National 13

Standards Institute (ANSI) N18.7); NRC Regulatory Guide 1.44 (that 14

endorses ANSI N45.2.12); NRC Regulatory Guide 1.58 (that endorses 15

ANSI N45.2.6); and NRC Regulatory Guide 1.123 (that endorses 16

ANSI N45.2.13). 17

QV has overall responsibility for independent quality oversight of 18

DCPP plant operations, maintenance, radiation protection, chemistry, 19

emergency planning, environmental protection plan, fitness for duty, 20

engineering, design, procurement, outage management, work control, and 21

strategic projects. The work performed by the QV section includes 22

independent QA audits, assessments, reviews, quality control inspections, 23

welding nondestructive examinations, source assessments, and24

supplier audits.25

D. Operational Results26

1. Capacity Factor and Energy Production27

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

(1) refueling (planned) outages; (2) maintenance outages; (3) forced 21

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


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


CHAPTER 5

COSTS INCURRED AND RECORDED IN THE DIABLO CANYON

SEISMIC STUDIES BALANCING ACCOUNT

5-i


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. CPUC Independent Peer Review Panel..................................................... 5-5

3. LTSP.......................................................................................................... 5-5

a. Seismic Source Studies....................................................................... 5-6

b. Ground-Motion Studies........................................................................ 5-7

c. LTSP Project Management.................................................................. 5-8

D. Conclusion........................................................................................................ 5-9

5-1


CHAPTER 52

COSTS INCURRED AND RECORDED IN THE DIABLO CANYON 3

SEISMIC STUDIES BALANCING ACCOUNT4

A. Introduction5

In Decision (D.) 10-08-003, the California Public Utilities Commission 6

(CPUC or Commission) granted Pacific Gas and Electric Company’s (PG&E)7

request to comply with the California Energy Commission’s (CEC) 8

recommendation to perform additional seismic studies in and around the 9

Diablo Canyon Nuclear Power Plant (DCPP) as part of the relicensing process.10

Decision 12-09-008 authorized PG&E to record in the Diablo Canyon Seismic 11

Studies Balancing Account (DCSSBA) and recover in rates its actual costs of 12

implementing the DCPP seismic activities up to $64.25 million. As discussed in 13

D.12-09-008, these activities have a genesis in Assembly Bill (AB) 1632, and are 14

sometimes referenced as PG&E’s AB 1632 seismic studies.15

In D.12-09-008, the Commission directed that costs incurred and recorded 16

in the DCSSBA should be recovered in PG&E’s annual Energy Resource 17

Recovery Account (ERRA) proceedings, and indicated that PG&E should 18

provide support for the amounts actually incurred and recorded in the DCSSBA, 19

consistent with PG&E’s request in Application (A.) 10-01-014 and in any 20

subsequent Tier 3 advice letters. Additionally, the Commission directed PG&E 21

to provide support in the ERRA proceedings for costs recorded in the 22

Independent Peer Review Panel (IPRP) subaccount of the DCSSBA.23

Decision 14-08-032, the Commission decision authorizing PG&E’s 24

2014-2016 General Rate Case (GRC) revenue requirement, directed PG&E to 25

remove $4.84 million in Long-Term Seismic Program (LTSP) costs from the 26

2014 revenue requirement for the purposes of the 2014-2016 GRC and transfer 27

the LTSP costs to the DCSSBA. Decision 17-05-013, the Commission decision 28

authorizing PG&E’s 2017-2019 GRC revenue requirement, adopted a settlement 29

agreement under which PG&E agreed to remove $4.2 million in LTSP costs from 30

the 2017-2019 revenue requirement and to continue the practice of recording 31

annual seismic studies costs to the DCSSBA. The LTSP costs are subject to 32

5-2

the same annual ERRA Compliance proceeding and Tier 3 Advice Letter 1

provisions adopted for the DCSSBA in D.12-09-008.2

In 2015, AB 361 added Section 712 to the California Public Utilities Code, 3

which requires the Commission to continue the IPRP until August 26, 2025.4

The costs for the DCPP seismic activities recorded in the DCSSBA during5

2017 total $4.52 million:1 (1) $0.52 million for AB 1632 activities;6

(2) $0.01 million for IPRP costs; and (3) $3.99 million for LTSP activities. PG&E 7

is seeking review and approval of these expenditures. As discussed below, 8

these costs were reasonably incurred. Accordingly, PG&E requests authority to 9

transfer $4.52 million from the DCSSBA to the Utility Generation Balancing 10

Account (UGBA), for recovery from customers as described in Chapter 13.11

B. Description of Costs Incurred12

PG&E has completed the AB 1632 seismic studies identified in D.12-09-008. 13

The final report from the studies was issued on September 10, 2014. Through 14

2017, PG&E has incurred a total of $54.6 million in AB 1632-related expenses, 15

below the $64.25 million cap set by D.12-09-008.16

The AB 1632 costs recorded in the DCSSBA during 2017 were incurred for 17

activities related to operations and maintenance (O&M) of the Point Buchon 18

Ocean Bottom Seismometer (OBS) array and project management costs.19

Costs recorded in the DCSSBA for the CPUC IPRP during 2017 were 20

related to IPRP meetings, review of PG&E documents related to the AB 1632 21

and LTSP studies, and the preparation of IPRP Reports.22

The LTSP costs recorded in the DCSSBA in 2017 were incurred to:23

(1) conduct seismic source studies including earthquake and geodetic 24

monitoring; and (2) conduct ground motion studies including: (a) continue 25

development of new models and methods required for implementation of a fully 26

non-ergodic ground-motion model for the Central California coast region; 27

(b) continue development of improved methods for numerical simulations of 28

ground motions, and perform 1-D simulations for large earthquakes at short 29

distances to constrain source scaling; (c) develop a 3-D crustal model for the 30

Central California coast region and perform 3-D simulations; (d) initiate 31

development of methods supporting fault-rupture hazard assessment; and 32

1 Total may not tie precisely to amounts presented in Chapter 13 because of rounding.

5-3

(e) continue support for hard-rock site characterization. These studies were 1

conducted by the U.S. Geological Survey (USGS) (through PG&E’s Cooperative 2

Research and Development Agreement (CRADA) with the USGS), the Southern 3

California Earthquake Center (SCEC), the Pacific Earthquake Engineering 4

Research (PEER) Center, and other universities. Additional costs for the LTSP 5

were for project technical management and the administration of Nuclear Quality 6

Assurance (NQA) procedures.7

The costs that were recorded in the DCSSBA from 2009 through 2016 have 8

been described in testimony in previous ERRA Compliance proceedings, most 9

recently in A.17-02-005, which addressed 2016 expenditures. The following 10

table presents actual 2017 costs by category:11

TABLE 5-1DIABLO CANYON SEISMIC STUDIES BALANCING ACCOUNT RECORDED COSTS

(MILLIONS OF DOLLARS)

Line No. Category

Actual Costs Incurred in

2017

1 D.12-09-008 – AB 1632 Seismic Studies –2 OBS O&M 0.343 Project Management 0.18

4 Subtotal $0.52

5 D.12-09-008 – CPUC Independent Peer Review Panel (IPRP) –6 IPRP $0.01

7 Subtotal $0.01

8 D.17-05-013– Long-Term Seismic Program (LTSP) –9 Seismic Source Studies $0.88

10 Ground-Motion Studies 2.4911 Project Management 0.62

12 Subtotal $3.99

13 Total $4.52

C. The Costs Recorded in the DCSSBA Are Reasonable and Consistent With 12

D.12-09-008, D.14-08-032 and D.17-05-01313

1. AB 1632 Seismic Studies14

As noted above, PG&E has completed the seismic studies identified in15

D.12-09-008.16

5-4

a. Ocean Bottom Seismometer1

PG&E continued to operate the OBS array approved in 2

D.12-09-008. Six new autonomous OBS instruments were delivered in 3

May 2016 to replace the previous OBS array at no cost to PG&E. 4

Four new OBS units were deployed offshore, one unit was repurposed 5

and installed at the Central Coast Seismic Network (CCSN) Alexander 6

Ranch site, and one unit was held in reserve as a spare.7

PG&E incurred and recorded costs totaling $0.34 million for OBS8

activities in 2017. These costs were associated with the semi-annual 9

retrieval, maintenance, and redeployment of the autonomous OBS 10

array, as well as the submittal of necessary documentation to California 11

state agencies (e.g., amendments to the lease and post-installation 12

survey reporting required by the California State Lands Commission). 13

PG&E concluded the OBS monitoring program in November 2017 and 14

transitioned to local on-call storage for the OBS instruments. This 15

option will enable PG&E to quickly redeploy the instruments in the event 16

of a significant offshore earthquake. Future costs associated with 17

redeployment will be recorded as part of LTSP activities under 18

the DCSSBA.19

b. AB 1632 Project Management20

The seismic activities described above required project 21

management during 2017. This category of costs includes PG&E 22

oversight of project activities, employee-related labor costs, and NQA23

management. There are several departments within PG&E that incur 24

internal labor costs to support the AB 1632 projects and interact with the 25

IPRP, including Geosciences (i.e., Project Manager, Technical Director, 26

Quality Assurance (QA) Manager), External Communications, 27

Government Regulatory Relations, Procurement and Reprographic 28

Services. There are also outside contractors who provide project 29

management support, graphic services, and NQA management and 30

oversight.31

Project management costs incurred and recorded to the DCSSBA 32

for AB 1632-related activities during 2017 total $0.18 million.33

5-5

2. CPUC Independent Peer Review Panel1

Funding of the IPRP is included as a separate subaccount in the 2

DCSSBA. In D.10-08-003, the CPUC established the IPRP, whose 3

members include the CPUC, CEC, California Geological Survey (CGS),4

California Coastal Commission, California Seismic Safety Commission, and 5

the City and County of San Luis Obispo. Since its inception, the IPRP has 6

reviewed and commented on PG&E’s seismic study plans, held public 7

meetings, participated in the federal and state permitting processes required 8

to perform the seismic studies, and issued 12 written reports addressing 9

PG&E’s seismic study activities.10

In previous years, the IPRP has focused on review of seismic hazard 11

studies prepared in response to AB 1632. IPRP comments and review 12

helped evaluate the AB 1632 Central California Coast Seismic Imaging 13

Project (CCCSIP) report and its incorporation into seismic hazard 14

evaluations submitted to the Nuclear Regulatory Commission (NRC). 15

Following completion of the CCCSIP and acceptance of the seismic hazard 16

evaluations by the NRC, the IPRP has continued to review seismic hazard 17

studies conducted under the DCPP LTSP. 18

PG&E is responsible for the IPRP costs. During 2017, PG&E received 19

invoices from the IPRP totaling $0.01 million. Given Public Utilities Code 20

Section 712’s requirement that the Commission continue the IPRP until 21

August 2025, PG&E anticipates that it may incur costs going forward for the 22

IPRP involvement with issues raised by the CCCSIP report and studies 23

conducted under the LTSP. PG&E will record those costs in the IPRP 24

subaccount of the DCSSBA.25

3. LTSP26

PG&E’s DCPP LTSP began in 1985. The LTSP was established to 27

satisfy DCPP License Condition, Item 2.C.(7), which required reevaluation of 28

the seismic design bases for DCPP. Following the NRC review of the LTSP 29

report, where the NRC concluded that PG&E had met DCPP License 30

Condition 2.C.(7) (NUREG-0675, Supplement No. 34, June 1991), PG&E 31

made the following commitments: (1) continue to maintain a strong 32

geosciences and engineering staff to keep abreast of new geological, 33

seismic, and seismic engineering information and evaluate such information34

5-6

with respect to its significance to DCPP; and (2) continue to operate a 1

strong-motion accelerometer array and the CCSN. These commitments are 2

documented in Section 2.5 of the DCPP Facility Safety Analysis Report 3

(Geology and Seismology).4

Each year, PG&E performs studies to support these commitments.5

Project selection is based on criteria that consider significance to the 6

seismic hazard, past and present projects addressing the same parameter, 7

benefits-to-costs, and the likelihood of success.8

The activities of PG&E’s LTSP during 2017 are described in more 9

detail below.10

a. Seismic Source Studies11

The CCSN was installed in 1987 as part of the LTSP to monitor 12

earthquake activity in the central coast region. The network has been 13

systematically upgraded and now consists of 15 digital, 3-component 14

seismographic stations located primarily along the coast, from 15

Piedras Blancas to Point Sal. These are continuous recording 16

instruments, and the data are telemetered to a central recorder in 17

San Francisco and to the USGS. 2017 activities included O&M of the 18

seismographic stations and working with the CGS and USGS on 19

earthquake locations, interpretations and data archiving.20

PG&E incurred and recorded costs in the DCSSBA totaling 21

$0.88 million in 2017 for LTSP seismic source studies. These costs 22

included funding to outside contractors and labor costs for individual 23

PG&E scientists to conduct seismic source study research. PG&E will 24

continue to incur costs for seismic source studies as part of the LTSP.25

Upholding PG&E’s LTSP commitment requires work to continually 26

improve the models that are used for seismic source characterization 27

and ground motion characterization. Toward this end, in addition to the 28

seismic monitoring described above, geologic and geophysical studies 29

are conducted to examine alternative models of likely long-term 30

earthquake behavior on faults. Such efforts include collaborative 31

monitoring of crustal motions along the central California coast ranges 32

using Geographic Positioning System arrays (through the PG&E/USGS 33

CRADA), examination of global empirical data on earthquake ruptures 34

5-7

and their relationship to fault segment boundaries or fault intersections, 1

and evaluation of physical earthquake simulation models to inform 2

PG&E about how faults may behave at time scales much greater than 3

the historical record.4

Other LTSP-related source characterization efforts include 5

evaluation of submarine landslides to better understand the potential for 6

landslide generated tsunamis offshore DCPP, integration of the AB 1632 7

3-D Low Energy Seismic Survey data for the Hosgri and Shoreline fault 8

zones into earthquake source characterization models, continuing to 9

study how best to model the frequency distribution of earthquake sizes 10

on faults, the identification and characterization of active faults using 11

alignments of micro-seismicity, and participation in field studies of 12

significant international earthquakes analogous to those in California 13

through the National Science Foundation-sponsored Geotechnical 14

Extreme Events Reconnaissance Program.15

b. Ground-Motion Studies16

As part of PG&E’s LTSP commitment, PG&E conducts 17

ground-motion studies and associated research to continue to support 18

improvements to the ground-motion models. The main effort is to 19

quantify and validate the reduction of uncertainty in the median ground 20

motion by developing improved source and site-specific (non-ergodic) 21

ground-motion models to replace the current (partially non-ergodic) 22

ground-motion models. Current partially non-ergodic models include 23

site-specific site response effects but do not include source/site-specific 24

path and source effects.25

Developing non-ergodic models for the repeatable path effects 26

requires collecting local ground-motion data and 3-D velocity structure 27

data. With models for both the 1-D and 3-D velocity structures,28

earthquake source effects can be removed from the numerical 29

simulations, and path effects can be isolated and modeled. The 30

numerical simulation results are then checked by comparisons with the 31

observed ground-motion data in the region.32

The ground-motion tasks funded in 2017 associated with the plan to 33

transition from partially non-ergodic to fully non-ergodic ground-motion 34

5-8

models are categorized into four groups: (1) non-ergodic empirical 1

models, which include (a) the development of a new non-ergodic ground 2

motion model for California whose coefficients vary as a function of the 3

site and earthquake location, and (b) the development of a hazard 4

computation code capable of handling non-ergodic source, path and 5

site-effects components; (2) 1-D simulations for ergodic models, which 6

aim at constraining ground-motion scaling for sites close to large 7

earthquakes, and that include the continuation of the SCEC Broad-Band 8

Platform improvement and validation effort for kinematic models; (3) 3-D9

simulations of path effects which include tomographic inversions, 10

3-D crustal modeling, simulations runs, and validation of simulations for11

the Los Angeles area; and (4) fault rupture hazard, aimed at improving 12

the estimate of surface rupture at specific locations along the faults.13

Additional ground-motion tasks funded in 2017 addressed:14

(1) continued analysis of fragile geologic features near DCPP that can 15

be used to test the hazard results over time periods of thousands to tens 16

of thousands of years; (2) the development of models to address the 17

high-frequency amplification in hard-rock sites at the surface and at 18

depth; and (3) the characterization of ground motion for creeping faults 19

through dynamic simulations analysis.20

PG&E incurred and recorded costs in the DCSSBA totaling 21

$2.49 million in 2017 in connection with ground-motion activities. These 22

costs included funding to the USGS, SCEC, PEER, and other 23

institutions and labor costs for individual PG&E scientists conducting 24

ground-motion research.25

PG&E will continue to incur costs to conduct ground-motion studies 26

in future years as part of the transition from the partially non-ergodic 27

methods previously used to fully non-ergodic ground-motion 28

modeling approaches. 29

c. LTSP Project Management30

The ongoing LTSP activities require ongoing project management. 31

This category of costs includes the costs of: (1) PG&E labor and 32

personnel; and (2) QA management and oversight.33

5-9

LTSP project management costs incurred and recorded totaled 1

$0.62 million in 2017. These costs include PG&E labor to oversee work 2

performed by the USGS, PEER, SCEC and other contractors; database 3

management; QA-management; and employee-related costs. PG&E 4

will continue to incur costs for LTSP project management at a 5

sustained level.6

D. Conclusion7

The $4.52 million in costs recorded to the DCSSBA during 2017 for the 8

seismic studies described in this testimony are consistent with the costs and 9

programs approved by the Commission in D.12-09-008, and with the costs 10

required to be recorded in the DCSSBA by D.14-08-032 and D.17-05-013.11

As demonstrated by this testimony, these costs were reasonably incurred. 12

Accordingly, the Commission should authorize PG&E to transfer $4.52 million 13

from the DCSSBA to the UGBA for recovery from customers as described in 14

Chapter 13.15


CHAPTER 6

GENERATION FUEL COSTS AND

ELECTRIC PORTFOLIO HEDGING

6-i


GENERATION FUEL COSTS ANDELECTRIC PORTFOLIO HEDGING

TABLE OF CONTENTS

A. Introduction....................................................................................................... 6-1

B. Gas Procurement ............................................................................................. 6-1

1. Portfolio Overview...................................................................................... 6-1

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

1. Background.............................................................................................. 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

4. Transaction Compliance Reports............................................................. 6-12


GENERATION FUEL COSTS ANDELECTRIC PORTFOLIO HEDGING


6-ii

5. PG&E Compliance with Its Hedging Targets............................................ 6-12

a. PG&E’s Hedging Positions, as Measured Against the Hedging Targets, Were Compliant with the Adopted Hedging Plan................. 6-12

b. PG&E’s Portfolio Position Has Been Fundamentally Affected by the Load Shift to Community Choice Aggregators............................. 6-13

c. PG&E’s Hedging Activities During the Record Period Were Compliant with the Hedging Plan....................................................... 6-13

6. PG&E Transacted Within BPP Procurement Limits ................................. 6-14

I. Internal Procedures and Controls................................................................... 6-15

1. Segregation of Duties............................................................................... 6-15

2. Risk Management Policies....................................................................... 6-15

3. Prescriptive Hedging Plan........................................................................ 6-16

4. Controls Framework................................................................................. 6-16

J. Conclusion...................................................................................................... 6-17

6-1


CHAPTER 62

GENERATION FUEL COSTS AND3

ELECTRIC PORTFOLIO HEDGING4

A. Introduction5

This chapter reviews actions taken by Pacific Gas and Electric Company 6

(PG&E) regarding generation fuel procurement for:7

PG&E-owned conventional generation;8

PG&E tolling agreements;9

Hydroelectric; and10

Diablo Canyon Nuclear Power Plant (DCPP).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

6 2014 BPP, Sheet 51.7 2014 BPP, Appendix C, Section B.2, Sheets 75-76.8 2014 BPP, Appendix C, Section B.3, Sheets 76-77.

6-7

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

design. Table 6-3 reflects component coverage targets in PG&E’s 2014 BPP.29

6-9

TABLE 6-3 SUMMARY OF PG&E’S 2014 BPP NUCLEAR FUEL COMPONENT COVERAGE TARGETS

Table 6-411 reflects PG&E’s strategic inventory coverage targets. 1

TABLE 6-4 SUMMARY OF PG&E’S NUCLEAR FUEL STRATEGIC INVENTORY COVERAGE TARGETS

For the period of January 1 through December 31, 2017, DCPP’s recorded 2

nuclear fuel expenses for this period were . 3

During the period January 1 through December 31, 2017, DCPP’s Unit 1 4

completed its 20th cycle of operation and underwent a 61-day refueling outage. 5

The Unit started its 21st cycle of operation upon completion of the planned 6

outage. The average annual capacity factor for Unit 1 during 2017 was 7

83.3 percent. The total Unit 1 nuclear fuel expense for 2017 was . 8

During the period January 1 through December 31, 2017, DCPP’s Unit 29

continued to operate in its 20th cycle of operation. The average annual capacity 10

11 Strategic Inventory percentage is based on Separative Work Unit.

6-10

factor for Unit 2 during 2017 was 99.7 percent. The total Unit 2 nuclear fuel 1

expense for 2017 was . 2

Miscellaneous fuel expenses for 2017 include costs associated with a new 3

loss-of-coolant analysis which will be required to satisfy changing regulations by 4

the Nuclear Regulatory Commission. Nuclear Fuel Contracts executed during 5

the record period are included in Table 6B-6. The transactions were consistent 6

with the Commission-approved Nuclear Fuel Procurement Plan.7

Pursuant to D.05-09-006, PG&E agreed to provide certain information on 8

Fuelco activities and operating costs to the Commission in the annual ERRA9

compliance review proceeding. D.05-09-006 also directed PG&E to expand its 10

annual report on interactions with Fuelco to include any activities undertaken 11

outside the scope of Fuelco’s general purposes to monitor the full impact on 12

ratepayers of PG&E’s participation in Fuelco. The required data has been 13

compiled and provided in Tables 6B-4 and 6B-5. The current composition of 14

Fuelco includes Ameren Missouri and PG&E, with expenses shared on an equal 15

50 percent basis. 16

F. Nuclear Fuel Carrying Costs17

Nuclear fuel inventory carrying costs are recovered through ERRA at the 18

short-term interest rate. The nuclear fuel inventory carrying costs for 201719

are . 20

G. STARS Alliance21

OP 3 of D.12-05-010 directed PG&E to provide a report concerning its 22

activities and operating costs associated with PG&E’s participation in the 23

STARS Alliance. The objective of the STARS Alliance is to increase efficiency 24

and to reduce costs related to the operation of the members’ nuclear power 25

generation facilities. The other anticipated benefits include more efficiently 26

coordinating the purchase and location of assets necessary to ensure 27

purchasing power and effective responses to potential disruption in operations, 28

and collectively to achieve the safest and most efficient generation of electricity 29

from nuclear units.30

PG&E provides as Attachment C-1 the Annual Report of Utility on the 31

Activities of the STARS Alliance for the recorded and budget year 2017 in the 32

format required by the Commission in D.12-05-010, Appendix A. 33

6-11

Attachment C-2 also specifies the Utility Savings/Avoided Costs by STARS 1

Team/Project as required by D.12-05-010. The cost of the STARS Alliance 2

allocated to PG&E was $456,281, with the savings/avoided costs of $16,374,988 3

for all four STARS Alliance members. Based on the results for 2017, if not for 4

PG&E’s participation in the STARS Alliance, the costs to operate DCPP would 5

have been higher. Treatment of cost recovery and avoided cost aspects of 6

PG&E’s participation in the STARS Alliance is an aspect of PG&E’s General 7

Rate Case proceeding.8

H. Electric Portfolio Hedging9

1. Background10

PG&E’s 2014 BPP Hedging Plan was approved on October 22, 2015. 11

PG&E continued implementing the plan during 2017. PG&E demonstrates 12

compliance with its Hedging Plan in this section.13

2. All Transactions Complied with Approved Products and Approved 14

Transaction Processes15

During 2017, all PG&E financial transactions used only approved 16

products (2014 BPP, Appendix A, Table A-1 for electric products and 17

Table A-4 for gas products), and approved procurement processes 18

(2014 BPP, Appendix B, Table B-1). Each transaction and its approved 19

product type and transaction process is included in PG&E’s QCR filings, and 20

also summarized in Tables 6B-7 through 6B-10.21

3. PG&E Consulted with the PRG as Required22

As required by the BPP, PG&E consulted its PRG prior to executing 23

hedging transactions beyond three months in duration. PG&E reviewed with 24

the PRG its planned execution of hedges on:25

1) December 13, 2016, for hedging activities in the first quarter of 2017 26

(January 1-March 31, 2017);27

2) March 21, 2017, with a minor correction March 21, 2017, for hedging 28

activities in the second quarter of 2017 (April 1-June 30, 2017);29

3) June 20, 2017, for hedging activities in the third quarter of 2017 30

(July 1-September 30, 2017); and31

4) September 19, 2017, for hedging activities in the fourth quarter of 2016 32

(October 1-December 31, 2017).33

6-12

In each of these quarterly consultations, PG&E also shared with the 1

PRG, as required by D.15-10-031, any transactions executed according to 2

the previously shared strategy or plan. A copy of each PRG presentation is 3

included in the confidential attachments to the QCR, which are included as 4

workpapers for PG&E’s Prepared Testimony.5

4. Transaction Compliance Reports6

Transaction Compliance Reports, which are included in Attachment L of 7

each QCR, demonstrate that each financial transaction complies with each 8

of the applicable provisions of the Hedging Plan, and also with the 2014 9

BPP procurement limits. The Hedging Plan includes seven provisions that 10

can apply to each transaction, depending on the type of product transacted. 11

The compliance reports demonstrate how the transaction complied with 12

each of these provisions. 13

5. PG&E Compliance with Its Hedging Targets14

a. PG&E’s Hedging Positions, as Measured Against the Hedging 15

Targets, Were Compliant with the Adopted Hedging Plan16

As detailed in Section C.2 of the Hedging Plan, PG&E’s compliance 17

with the Plan, as measured against the Hedging Targets, is judged at 18

the end of 19

20

12 21

22

232425

Table 6B-11 demonstrates that PG&E’s hedging positions complied 26

with the Hedging Plan, as measured against the Hedging Targets, as of 27

28

29

30

31

12 PG&E’s 2014 BPP Hedging Plan, Section C.2, Hedging Targets.

6-13

1

2

b. PG&E’s Portfolio Position Has Been Fundamentally Affected by the 3

Load Shift to Community Choice Aggregators4

5

6

7

8

9

10

11

12

13

14

15

16

c. PG&E’s Hedging Activities During the Record Period Were 17

Compliant with the Hedging Plan 18

19

20

21

2223242526

1327

28

29

30

31

32

33

13 2014 BPP Hedging Plan, Section C.2., Measuring Hedge Coverage.

6-14

1

2

3

4 5 6 7 8 9

1011121314

1415

16

17

18

19202122

1523

24

25

26

27

28

29

30

6. PG&E Transacted Within BPP Procurement Limits31

PG&E’s 2014 BPP includes limits on electric energy and natural gas 32

procurement.16 These limits apply to all fixed-price energy and gas 33

contracts beyond prompt month. Figures 6B-1 and 6B-2 demonstrate PG&E 34

14 2014 BPP Hedging Plan, Section D.2, Unusual Events, Market Dislocations, and Emergencies

15 PG&E’s 2014 BPP Hedging Plan, Section C.2, Hedging Targets and Limits, emphasis added.

16 2014 BPP, Appendix C, Sections A.2 and B.1, Sheets 68-75.

6-15

compliance with these limits at the end of 2017. The compliance reports 1

included in each QCR demonstrate compliance for every transaction.2

I. Internal Procedures and Controls3

Consistent with D.11-07-039, OP 3, PG&E provides the following high-level 4

discussion of its internal procedures and controls for ensuring compliance with 5

its Hedging Plan. PG&E employs the following system of internal procedures 6

and controls to ensure compliance:7

1. Segregation of Duties8

2. Risk Management Policies9

3. Prescriptive Hedging Strategies10

4. Controls Framework11

1. Segregation of Duties12

PG&E separates the duties of executing, monitoring and tracking, and 13

settling hedging transactions among its Front Office, Middle Office and 14

Back Office. The Middle Office reports to the Chief Risk Officer, while the 15

Front Office and Back Office report to the Senior Vice President, Energy 16

Policy and Procurement.17

The Front Office is responsible for negotiating and executing 18

transactions that comply with the Hedging Plan and internal controls; and 19

ensuring the terms of the transaction are captured in PG&E’s trade 20

capture system.21

The Middle Office reviews each transaction for completeness and 22

accuracy and also establishes and manages several of the trading controls 23

in the Controls Framework. The Middle Office also reports the status of 24

hedging programs and portfolio risk measures to PG&E senior 25

management.26

The Back Office confirms non-cleared transactions with counterparties 27

and settles transactions after delivery or expiration. The Back Office is also 28

responsible for managing existing contracts.29

2. Risk Management Policies30

PG&E maintains Risk Management Policies and Standards that provide 31

guidelines to the PG&E Front, Middle and Back Offices on management and 32

control of risks associated with fluctuations in electricity and gas prices and 33

6-16

counterparty credit exposure. PG&E’s Corporation Risk Policy Committee 1

and Utility Risk Management Committee are delegated, from the Board of 2

Directors, the responsibility for ensuring that PG&E management adheres to 3

the Risk Policies and Standards. PG&E’s Middle Office monitors 4

compliance with these policies and standards and regularly measures and 5

reports market and portfolio risk to the committees.6

3. Prescriptive Hedging Plan7

PG&E’s Hedging Plan is prescriptive, that is, it specifies which positions 8

are to be hedged, which products are to be used, and the timeline for 9

execution. The Hedging Plan is periodically updated and changes are 10

implemented after final CPUC approval is received, and after internal 11

processes are modified to ensure that the updated Hedging Plan can be 12

monitored for consistency with the CPUC-approved plan and internal 13

governance requirements.14

4. Controls Framework15

The Controls Framework is centered on assuring data quality and 16

completeness, guiding trading activities with an electronic model, and 17

monitoring trader activity relative to authorized plans and counterparty credit 18

limits. Controls are separated into six categories:19

1) Electronic Model – PG&E uses an electronic model to guide its financial 20

traders in implementing the Hedging Plan. The model includes the 21

long- and short positions in PG&E’s portfolio and applies each of the 22

provisions of the Hedging Plan to these positions to determine for the 23

current trading month which products should be traded and the quantity 24

of each product. The model is refreshed overnight after each trading 25

day to ensure the portfolio positions are current. The model is 26

developed by the Middle Office in consultation with the Front Office and 27

is validated for accuracy by a separate, independent team of qualified 28

analysts also in the Middle Office.29

2) Trade Limits – PG&E sets limits on its Front Office trading activities to 30

help ensure that its traders comply with its approved Hedging Plan. 31

PG&E breaks down the annual Hedging Plan trading limits approved by 32

its risk committees into monthly limits for monitoring trading activities.33

6-17

3) Trade Preview – Prior to execution, PG&E traders preview all trades in 1

an electronic blotter system that tests each trade against their monthly 2

trade limits and counterparty credit limits. PG&E traders are not allowed 3

to execute trades that are not pre-approved by this system.4

4) Trade Capture – PG&E traders are required to enter all completed 5

transactions into a trade capture system on the day the transaction is 6

executed. PG&E’s Middle Office reviews all trades to ensure that they 7

are captured accurately in the trade capture system.8

5) Transaction Monitoring – PG&E’s risk management system provides 9

reports that monitor compliance with the risk management policies and 10

trading limits. In addition, the system tracks counterparty-credit11

exposure.12

6) Compliance Reports – PG&E developed an automated compliance 13

report that demonstrates compliance of its electric and gas financial 14

hedge trades. The report demonstrates that all the trades executed on 15

a specified trading day comply with each provision of PG&E’s 16

Hedging Plan.17

J. Conclusion18

The preceding discussion demonstrates that PG&E procured fuel for its 19

utility-owned generation facilities and tolling agreements, acquired water for 20

hydroelectric generation, and procured nuclear fuel for DCPP consistent with the 21

2014 BPP and Commission decisions addressing procurement. In addition, the 22

preceding discussion demonstrates that PG&E’s electric portfolio hedging 23

activities complied with its Hedging Plan and the 2014 BPP.24


CHAPTER 6

ATTACHMENT A

LETTER FROM RUBY PIPELINE OFFICER CERTIFYING PG&E’S

“MOST FAVORED NATIONS” (LOWEST RATE) STATUS

6-AtchA-1


CHAPTER 6

ATTACHMENT B

GENERATION FUEL COSTS

6-AtchB-1


CHAPTER 62

ATTACHMENT B3

GENERATION FUEL COSTS 4

TABLE 6B-1 SUMMARY OF 2017 PG&E GAS DELIVERIES BY FACILITY OR TOLLING AGREEMENT

Line No. Generating Facility

Volume(a)

(Million MMBtu)

ERRACost(b)

($ Millions)

1 Oroville Cogen2 O.L.S. Energy-Agnews, Inc.3 PG&E - Gateway4 PG&E - Humboldt5 Calpine Peakers Feather River6 Calpine Peakers Yuba City7 PG&E Colusa - Maxwell8 Calpine Creed Energy Center9 Calpine Goose Haven Peaker

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.

(b) 2014 BPP, Appendix C, Table C-10, Sheet 76.(c)

6-AtchB-3

TABLE 6B-4 ANNUAL REPORT OF PACIFIC ENERGY FUELS COMPANY ON THE ACTIVITIES OF FUELCO, LLC

ADMINISTRATIVE COSTS ASSOCIATED WITH THE PROCUREMENTOF NUCLEAR FUEL AND FUEL-RELATED PRODUCTS OR SERVICES


Recorded Year2017

Budget Year2017

1 Total Common Costs(a)

2 Out of Pocket

3 Labor

4 Total Fuelco

5 PG&E/PEFCO Share %6 PG&E/PEFCO Share $7 Special Project Costs8 Out of Pocket(b)

9 Labor

10 Total Fuelco

11 PG&E %(c)

12 PG&E $(c)

13 Total PG&E Share $_______________

(a) Currently expensed on Fuelco books.(b) 2018 subscriptions capitalized as deferred charges on

Fuelco books.(c) Reflects composite participation in one or more projects.

6-AtchB-4

TAB

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6-AtchB-5

TABLE 6B-6 NUCLEAR FUEL CONTRACTS EXECUTED IN 2017

(WITH DELIVERIES BEYOND 2017) (MILLIONS OF DOLLARS)

Line No. Contract No.

Execution Date

Term of Services Services Amount

TABLE 6B-7 SUMMARY OF PG&E ELECTRIC PORTFOLIO GAS FINANCIALTRANSACTIONS LISTED BY 2014 BPP APPROVED PRODUCT

Line No. Product

2014 BPP Table A-4

Line Number

Volume(Million MMBtu)

Notional Value

($ Millions)Number of

Trades

1 Natural Gas Futures 22 Natural Gas Futures (Basis) 23 Financial Options (Calls) and Swaptions 3

4 Total Transacted

Totals may not match sum of components due to rounding.

TABLE 6B-8 SUMMARY OF PG&E ELECTRIC PORTFOLIO GAS FINANCIAL

TRANSACTIONS LISTED BY 2014 BPP APPROVED TRANSACTION PROCESS

Line No. Product

2014 BPP Table B-1

Item Number

Volume(Million MMBtu)

Notional Value


Trades

1 Transparent Exchanges (Electronic Trading) 62 Transparent Exchanges (Voice Brokers) 63 Electronic Solicitations (IM or Voice) 10

4 Total Transacted

Totals may not match sum of components due to rounding.

6-AtchB-6

TABLE 6B-9 SUMMARY OF PG&E ELECTRIC PORTFOLIO ELECTRICITY FINANCIAL

TRANSACTIONS LISTED BY 2014 BPP APPROVED PRODUCT

Line No. Product

2014 BPP Table A-1

Line Number

Volume(GWh)

Notional Value


Trades

1 Electricity Futures 13

2 Total Transacted

TABLE 6B-10 SUMMARY OF PG&E ELECTRIC PORTFOLIO ELECTRICITY FINANCIAL

TRANSACTIONS LISTED BY 2014 BPP APPROVED TRANSACTION PROCESS

Line No. Product

2014 BPP Table B-1

Item Number

Volume(GWh)

Notional Value


Trades

1 Transparent Exchanges (Electronic Trading) 62 Transparent Exchanges (Voice Brokers) 6

3 Electronic Solicitations (IM or Voice) 10

4 Total Transacted

6-AtchB-7

TABLE 6B-11 COMPLIANCE WITH 2014 BPP HEDGING TARGETS

$ MILLIONS

Line No. Position 1 2 3 4 5 6

_______________

Note: Table 6B-11 provides PG&E's electric portfolio position at the end of the Plan Year,

6-AtchB-8

FIGURE 6B-1 DEMONSTRATION OF COMPLIANCE

WITH 2014 BPP ELECTRICAL ENERGY PROCUREMENT LIMITS

_______________

Note:

6-AtchB-9

FIGURE 6B-2 DEMONSTRATION OF COMPLIANCE

WITH 2014 BPP NATURAL GAS PROCUREMENT LIMITS

_______________

Note:


CHAPTER 6

ATTACHMENT C

ANNUAL REPORT OF UTILITY ON

THE ACTIVITIES OF STARS ALLIANCE, LLC

UTILITY SAVINGS/AVOIDED COSTS BY

STARS TEAM/PROJECT

Recorded Year 2017 Budget Year 2017

Total Common Costs (1)Labor, Benefits, & Bonus $ 356,265 $ 364,800 Travel Expenses $ 329,484 $ 544,835 Non-travel Meals $ 43,122 $ 25,000

Sub-Total Labor, Benefits & Bonus $ 728,871 $ 934,635 Contractor Support $ 330,707 $ 294,400 Legal $ 210,003 $ 126,500 Office Supplies & Expenses $ 79,946 $ 32,000 Building Lease/Utilities $ 229,311 $ 240,000 Communications $ 18,217 $ 30,000 Insurance $ 7,604 $ 16,000 Infrastructure $ 112,839 $ 145,654 Office Furniture & Equipment $ 95,155 $ 17,396 Computer Equipment $ 12,470 $ 8,850

Total STARS Alliance $ 1,825,123 $ 1,845,435 Utility Share (%) 25% 25%Utility Share ($) $ 456,281 $ 461,359

Total Utility Share $ 456,281 $ 461,359

(1) Currently expensed on STARS Alliance books.

ATTACHMENT C

ANNUAL REPORT OF UTILITY ON THE ACTIVITIES OF STARS ALLIANCE, LLCRECORDED YEAR 2017 AND BUDGET YEAR 2017

(All Data in Whole Numbers)

6-AtchC-1

STARS TotalEmergency Planning Peer Team $ 207,411Regulatory Affairs Peer Team $ 42,880Supply Chain (STARS Contracts) $ 12,221,425Rebates $ 3,903,272

Total Savings / Avoided Costs $ 16,374,988

UTILITY SAVINGS / AVOIDED COSTS BY STARS TEAM / PROJECT(All Data in Whole Numbers)

Teams / Projects may change annually based upon the needs of the Utility and STARS

6-AtchC-2


CHAPTER 7

GREENHOUSE GAS COMPLIANCE

INSTRUMENT PROCUREMENT

7-i


GREENHOUSE GAS COMPLIANCEINSTRUMENT PROCUREMENT

TABLE OF CONTENTS

A. Introduction and Bundled Procurement Plan Background................................ 7-1

B. Background Information ................................................................................... 7-2

1. Assembly Bill 32 Cap-and-Trade Program................................................. 7-2

2. Electric Sector GHG Emissions ................................................................. 7-3

3. PG&E’s GHG Compliance Instrument Procurement Authority ................... 7-4

C. PG&E’s GHG Procurement Activity During the Record Period......................... 7-4

1. Facilities Comprising PG&E’s Direct GHG Costs....................................... 7-5

2. PG&E’s GHG Procurement Activity ........................................................... 7-5

3. PG&E’s GHG CARB Auction Procurement Activity.................................... 7-6

4. PG&E’s GHG Market Transactions Procurement Activity .......................... 7-7

D. PG&E Complied With the GHG Procurement Plan .......................................... 7-8

1. 2014 BPP GHG Procurement Strategy...................................................... 7-8

2. Procurement Limits for GHG Products....................................................... 7-8

E. Conclusion...................................................................................................... 7-10

7-1


CHAPTER 72

GREENHOUSE GAS COMPLIANCE3

INSTRUMENT PROCUREMENT4

A. Introduction and Bundled Procurement Plan Background5

The California Air Resources Board (CARB) Cap-and-Trade regulation 6

established requirements for emissions reporting and compliance 7

demonstrations by covered entities. Pacific Gas and Electric Company (PG&E)8

has a need to procure greenhouse gas (GHG) compliance instruments to satisfy 9

its compliance obligation as a covered entity and to fulfill certain contractual 10

requirements.11

This chapter describes the GHG compliance instrument procurement 12

activities undertaken by PG&E, pursuant to its 2014 Bundled Procurement Plan 13

(BPP) during the January 1 through December 31, 2017 record period.114

PG&E’s 2014 BPP addresses the means, strategies, and limits applicable to 15

PG&E’s procurement of GHG compliance instruments. 16

This testimony and supporting workpapers demonstrate that PG&E’s 2017 17

GHG compliance instrument procurement activities complied with the 18

requirements established in the 2014 BPP. This testimony also describes 19

PG&E’s bundled electric GHG procurement regulatory framework to illustrate 20

those requirements impacting PG&E’s management of its GHG procurement 21

plan. Specifically:22

Section B describes the regulatory authority impacting PG&E’s GHG 23

procurement, including: (1) an overview of the CARB Cap-and-Trade 24

Program to regulate GHG emissions; (2) a description of CARB 25

requirements to calculate GHG emissions for covered entities in the electric 26

generation sector; and (3) a summary of the regulatory authority the 27

California Public Utilities Commission (Commission) provides to PG&E to 28

procure GHG compliance instruments on behalf of its bundled electric 29

portfolio.30

1 The 2014 BPP was approved by the Commission in Decision (D.) 15-10-031.

7-2

Section C describes the resources that comprised PG&E’s direct physical 1

obligation to procure compliance instruments during the record period, 2

including those emissions generated by Utility-Owned Generation (UOG) 3

and imported electricity, as well as any PG&E contracts with physical 4

settlement of GHG compliance instruments, and describes the means by 5

which PG&E procured GHG compliance instruments, including an 6

accounting of PG&E’s GHG procurement activities during the record period 7

related to PG&E’s direct physical obligation.8

Section D shows that PG&E complied with the requirements set forth in the 9

2014 BPP to procure GHG compliance instruments, including limits on GHG 10

compliance instrument procurement.11

Together, this testimony and the supporting workpapers demonstrate that 12

PG&E’s 2017 GHG compliance instrument procurement activities complied with 13

its 2014 BPP.214

B. Background Information15

This section describes CARB and Commission requirements relevant to 16

PG&E’s procurement of GHG compliance instruments for the bundled electric 17

portfolio. This section also establishes that GHG procurement activities are 18

reviewed for compliance with the 2014 BPP in this proceeding.19

1. Assembly Bill 32 Cap-and-Trade Program20

Assembly Bill 32 is California’s landmark GHG legislation that requires 21

the reduction of statewide GHG emissions to 1990 levels by 2020. To this 22

end, the CARB promulgated a statewide Cap-and-Trade regulation that 23

established a market based price for GHG emissions.24

For the electric generation sector, covered entities include operators of 25

any facility that annually emits at least 25,000 metric tons of carbon dioxide 26

equivalents (mtCO2e).3 Facilities are required to obtain and surrender 27

compliance instruments equivalent to the GHG emissions for each such 28

facility. Importers of electricity into California are also responsible for 29

obtaining and surrendering compliance instruments for GHG emissions 30

2 See 2014 BPP, Appendices C and G.3 Units of GHG are typically measured in terms of mtCO2e.

7-3

deemed to be associated with electricity imports for purposes of compliance 1

with Cap-and-Trade.2

There are two types of compliance instruments: (1) allowances, which 3

are limited tradable authorizations created by CARB to emit up to 1 mtCO2e;4

and (2) offset credits, which are tradable compliance instruments issued by 5

CARB that represent verified reductions of 1 mtCO2e from projects whose 6

emissions or avoided emissions are not from a source covered under the7

Cap-and-Trade Program. For compliance purposes, an offset credit and an 8

allowance have limited differences. Allowances have a unique vintage year 9

and each vintage may be used in the vintage year issued or in future years,10

but future vintage allowances may not be used to satisfy any compliance 11

obligations prior to the vintage year. For example, 2019 vintage allowances 12

can be used to fulfill 2019 or 2020 obligations, but not 2016 obligations.13

Unlike an allowance, an offset credit is not limited by vintage and can be 14

utilized for any surrender year. However, an entity can only use offset 15

credits to meet up to 8 percent of its compliance obligation in any 16

compliance period. In addition, CARB’s Cap-and-Trade regulation allows 17

CARB to invalidate an offset credit for errors, regulatory violations, or fraud.418

2. Electric Sector GHG Emissions19

For the electric generation sector, CARB requires specific 20

methodologies to calculate emissions from electricity generating facilities 21

located in the state of California (in-state facilities) and a separate 22

methodology is required to calculate emissions for electricity imported into 23

the state of California (imported electricity). For in-state electric generation24

facilities, carbon dioxide equivalent (CO2e) compliance obligations are 25

calculated based upon the combustion of fossil fuel used, and not the 26

electrical energy produced. PG&E’s UOG facilities and all facilities 27

associated with its tolling contracts are entirely located in the state of 28

California. For imported electricity, CO2e emissions are calculated based on 29

the electrical energy imported. The compliance obligation associated with 30

4 In event of invalidation, CARB requires the party holding the offset to replace within six months of notification.

7-4

imported electricity emissions may be further reduced through adjustments1

for certain renewables procurement and qualified exports.2

3. PG&E’s GHG Compliance Instrument Procurement Authority3

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

was $13.57 per allowance.99

9 https://www.arb.ca.gov/cc/capandtrade/auction/auction_archive.htm.

7-7

1

2

3

10 4

5

6

7

8

9

10

11

12

13

14

15

16

17

4. PG&E’s GHG Market Transactions Procurement Activity18

19

.20

21

22

23

24

25

26

27

28

10

7-8

D. PG&E Complied With the GHG Procurement Plan1

This Section D demonstrates that PG&E’s procurement complied with its 2

2014 BPP. First, PG&E’s GHG procurement adhered to the relevant elements 3

of and strategies established in the 2014 BPP. This section also demonstrates 4

that PG&E’s GHG procurement activities complied with the limits established in 5

the 2014 BPP.6

1. 2014 BPP GHG Procurement Strategy7

PG&E’s 2014 BPP includes elements of PG&E’s GHG procurement 8

strategy.11 The strategy defines how PG&E will participate in the GHG 9

market to procure necessary compliance instruments to comply with the 10

Cap-and-Trade Program and meet physical contractual obligations. 11

12

13

14

15

16

17

18

19

20

21

22

2. Procurement Limits for GHG Products23

The 2014 BPP includes GHG Purchase Limits.12 The GHG Purchase 24

Limit establishes the maximum amount of GHG products PG&E may 25

purchase in the current year to fulfill its “direct compliance obligation,” 26

defined as the tons of emissions for which PG&E has an obligation to retire 27

allowances on its own behalf as a regulated entity under CARB’s 28

Cap-and-Trade Program, and/or is otherwise obligated to procure for a 29

third party. A “purchase” is defined as taking title of the GHG product 30

11 See 2014 BPP, Appendix G, Section D, Sheets 133-144.12 See 2014 BPP, Appendix C, Section C, Sheets 77-81 (regarding GHG

procurement limits).

7-9

(i.e., allowance or offset) when it is delivered. Thus, forward purchases 1

count against the procurement limit when the product is delivered, which 2

may not be the same year the transaction is executed.3

Tables 7-3 demonstrate that PG&E transacted within its 2017 GHG 4

Purchase Limit established by its 2014 BPP. Specifically, Table 7-3 shows 5

that GHG procurement by PG&E in 2017 did not exceed the GHG 6

Purchase Limit.137

As set forth in D.12-04-046 and in the 2014 BPP, PG&E’s GHG 8

Purchase Limit is calculated as: 9

LCY = A + (100% * FDCY) + (60% * FDCY+1) + (40% * FDCY+2) + 10

(20% * FDCY+3)11

Where: 12

– L is the maximum number of GHG Products PG&E can purchase for13

purposes of meeting its direct compliance obligation;14

– CY is Current Year, i.e., the year in which PG&E is transacting in the15

market;16

– A is PG&E’s net remaining compliance obligation to date, calculated as17

the sum of the actual emissions for which PG&E is responsible for18

retiring GHG Products (or obligated to purchase for a third party) up to19

the Current Year, minus the total GHG Products PG&E has purchased20

up to the Current Year that could be retired against those obligations;21

and22

– FD is PG&E’s “forecasted compliance obligation” or the projected23

amount of emissions for which PG&E is responsible for retiring GHG24

Products (or obligated to purchase for a third party) calculated using an25

Implied Market Heat Rate (IMHR) that is two-standard deviations above26

the expected IMHR.27

13 2014 BPP, Sheet 81.

7-10

TABLE 7-3 2017 GHG PRODUCTS PURCHASED BY PG&E COMPARED TO GHG LIMIT

MILLION MTCO2E

As shown in Table 7-3, PG&E’s purchases of GHG compliance 1

instrument products did not exceed the GHG Purchase Limit of 2

. The quarterly PRG presentations concerning GHG compliance 3

instrument procurement and attachments included in each Quarterly 4

Compliance Report also demonstrate that PG&E complied with its GHG 5

Purchase Limit.14 These documents are included as confidential 6

workpapers to support PG&E’s Prepared Testimony in this proceeding. 7

The PRG presentations are also included.8

E. Conclusion9

This chapter, as well as information included in PG&E’s workpapers to this 10

chapter, demonstrates that during the 2017 record period, PG&E’s procurement 11

of GHG compliance instruments complied with the requirements the 2014 BPP 12

because PG&E utilized the means, strategies and limits described therein.13

14 See Fourth Quarter 2017 Bundled Electric GHG Update, p. 8, included with Fourth Quarter GHG Workpapers.


CHAPTER 8

CONTRACT ADMINISTRATION

8-i



TABLE OF CONTENTS

A. Introduction....................................................................................................... 8-1

B. Contract Management and Electric Settlement Process .................................. 8-1

1. Overview.................................................................................................... 8-1

2. Contract Review, Interpretation and Administration ................................... 8-2

3. Active Compliance Monitoring.................................................................... 8-3

4. Construction Monitoring and Performance Testing .................................... 8-4

a. Construction Monitoring and Safety..................................................... 8-4

b. Performance Testing ........................................................................... 8-5

5. Settlement and Payment............................................................................ 8-5

6. Dispute Resolution..................................................................................... 8-7

7. Tools, Systems and Controls ..................................................................... 8-8

C. Contract Administration During the Record Period......................................... 8-10

1. Procurement Programs and Solicitations................................................. 8-10

a. Solar Photovoltaic.............................................................................. 8-10

b. ReMAT .............................................................................................. 8-11

c. BioMAT.............................................................................................. 8-11

d. Energy Storage.................................................................................. 8-12

e. Resource Adequacy .......................................................................... 8-12

f. Renewable Energy Sales .................................................................. 8-12

2. Contracts Executed.................................................................................. 8-13

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




8-ii

6. Force Majeure Claims.............................................................................. 8-14

7. Disputes ................................................................................................... 8-14

a. Alpaugh 50, LLC; Alpaugh North, LLC; CED Corcoran Solar, LLC; and CED White River Solar, LLC (PG&E Log Nos. 33R118, 33R119, 33R121, 33R122)................................................................ 8-14

b. Hecate Energy Molino LLC (PG&E Log No. 40S003)........................ 8-15

c. Coalinga Cogeneration Company (PG&E Log No. 25C124QTR)...... 8-15

d. Panoche Energy Center (PG&E Log No. 33B076) ............................ 8-15

e. Global Ampersand, LLC, El Nido Biomass Facility and Chowchilla Biomass Facility (PG&E Log Nos. 33R016 and 33R017) .................. 8-15

8. Contracts That Expired or Terminated ..................................................... 8-16

D. Other Matters ................................................................................................. 8-16

1. Poco Power, LLC v. PG&E ...................................................................... 8-16

2. Orion Solar I, LLC (PG&E Log No. 33R162) ............................................ 8-17

3. Thermal Energy Development Corporation (PG&E Log No. 16P054)...... 8-17

E. Request for Approval of Amendments............................................................ 8-17

1. Crockett Cogeneration Co (PG&E Log No. 01C045) ............................... 8-18

F. Conclusion...................................................................................................... 8-18

8-1


CHAPTER 82

CONTRACT ADMINISTRATION3

A. Introduction4

Pacific Gas and Electric Company’s (PG&E) Energy Contract Management 5

and Settlements (ECMS) Department administers PG&E’s energy procurement 6

contracts and payments with counterparties. 7

During the record period, PG&E complied with the California Public Utilities 8

Commission’s (CPUC or Commission) Standard of Conduct 4 (SOC4), adopted 9

in Decision (D.) 02-10-062 and elaborated on in D.02-12-069, D.02-12-074, 10

D.03-06-076, and D.05-01-054, regarding prudent contract administration. This 11

chapter describes PG&E’s contract administration practices, changes that 12

occurred to the contracts administered, and the results achieved with regard to 13

contract administration during the record period. The monthly energy purchases14

and costs incurred during the record period are shown in Table 8-1 at the end of 15

this chapter.16

In this chapter, PG&E will demonstrate that it complied with SOC4 with 17

regards to prudent contract administration during the record period by providing:18

1. An overview of ECMS processes, including contract administration during 19

the developing and operational phases of a contract, with descriptions of 20

tools, systems and controls. Additional information about ECMS processes, 21

tools, systems and controls is provided in PG&E’s confidential workpapers 22

for Chapter 8.23

2. A summary of contract activities that occurred during the record period 24

including: (1) programs and solicitations; (2) contracts executed; (3) project 25

development and construction monitoring; (4) contracts that began delivery, 26

(5) contract amendments, consents to assignment and other transactions; 27

(6) force majeure claims; (7) disputes, (8) contracts that expired or 28

terminated; (9) other matters, and (10) amendments requiring approval.29

B. Contract Management and Electric Settlement Process30

1. Overview31

Once a contract or transaction is executed, administration and 32

settlement of the contract or transaction becomes the responsibility33

8-2

of ECMS. ECMS uses a number of tools, systems, and controls to 1

administer contracts, and follows processes and procedures to ensure that 2

transactions, new contracts, and amendments to existing contracts are 3

implemented and administered consistently with the terms and conditions 4

contained in each agreement. In general, ECMS processes involve:5

Contract review, interpretation, and administration;6

Active compliance monitoring;7

Construction monitoring and performance testing;8

Settlement and payment;9

Dispute resolution; and10

Tools, systems, and controls.11

Each of these processes is described in more detail below.12

2. Contract Review, Interpretation and Administration13

Prior to contract execution, Contract Managers review each proposed14

transaction and work with the assigned Settlements Analyst and15

Commercial Lead for the transaction to ensure that agreements can be16

administered by ECMS.17

The ECMS Director approves each proposed transaction on behalf of 18

ECMS, as applicable, after the Commercial Lead provides a summary of the 19

transaction and discusses unique provisions. ECMS staff summarizes the20

transaction from a contract administration perspective and answers any21

questions.22

Once a contract is executed, assigned Contract Managers review the23

contract to determine the actions required to ensure compliance with the 24

provisions that are either PG&E’s or the counterparty’s responsibility.25

Contract Managers enter contract deadlines, requirements and tasks in the 26

Task Tracking Tool (T3) and review data entries in the Consolidated Energy 27

Contract Management (CECM) Database. Contract Managers meet28

with key internal groups to review these documents, respond to questions,29

obtain uniform understanding of the terms of each transaction, and meet 30

with the assigned Settlements Analyst to review contract provisions31

regarding payment prior to the commercial operation date and the first 32

settlement month, and following initial delivery of contracted products.33

8-3

In addition to this contract review, ECMS reviews and interprets the 1

contract throughout its term in response to specific questions from other2

PG&E business groups, or as issues arise. Contract Managers also provide3

support and guidance to the business groups on the use of the ECMS tools 4

and systems.5

3. Active Compliance Monitoring6

PG&E ensures compliance with contract terms by continual monitoring 7

of contract requirements throughout the contract term. Such activities 8

involve tracking contract milestones and deadlines, ensuring that PG&E and 9

the contract counterparties comply with all contract provisions, and 10

monitoring performance for projects that are already delivering contracted 11

products to PG&E. ECMS reviews construction progress reports for 12

contracts that have construction milestones and verifies the commercial 13

operation date certification by the counterparties’ independent licensed 14

engineers, as applicable. PG&E also specifically monitors Renewable 15

Portfolio Standard (RPS) contracts consistent with the Commission’s 16

request that each utility ensure that Renewable Energy purchases are from 17

an Eligible Renewable Energy Resource, as defined in California Public 18

Utilities Code Section 399.12.19

During the record period, ECMS and other groups in Energy Policy and 20

Procurement conducted the following active monitoring activities in relation 21

to renewable generation from RPS contracts:22

Periodic review of the California Energy Commission (CEC) website and 23

verification that the counterparty’s facility is pre-certified as a renewable 24

resource before the facility begins delivering electricity to PG&E, and 25

remains fully-certified throughout the delivery term.26

Verification that counterparty’s account is set up in the Western 27

Renewable Energy Generation Information System (WREGIS). Review 28

and verification of Renewable Energy Certificate (REC) transfers from a 29

facility to PG&E via the WREGIS website and verification that metered 30

volumes generated by RPS certified facilities match the REC quantities 31

received. PG&E works with counterparties and WREGIS to identify why 32

any REC deficits occurred and resolve REC deficits. If REC deficits are 33

8-4

unresolved, then PG&E will adjust invoices as applicable under the 1

Power Purchase Agreements (PPA).2

Verification that the counterparties delivering to PG&E attest in each 3

invoice submitted to PG&E that the facilities in connection to their 4

contracts remain: (1) certified by the CEC as a California RPS eligible 5

resource; and (2) registered with WREGIS as a Generating Unit (as 6

defined in the WREGIS Operating Rules). 7

4. Construction Monitoring and Performance Testing8

a. Construction Monitoring and Safety9

Contract Managers and Engineers monitor the development of 10

counterparty energy projects, generally from contract execution through 11

commercial operation. Typically, a contract requires the counterparty to 12

provide written progress reports on the project’s development status to 13

PG&E on a monthly or quarterly basis. The assigned Engineer and14

Contract Manager review these reports. When further information is 15

deemed necessary, a follow-up conference call with counterparty 16

personnel and a site inspection may be conducted to ensure that PG&E 17

has an accurate understanding of project status.18

During construction monitoring, PG&E reviews and tracks 19

development activities, including: site control; permitting;20

interconnection; financing; construction; and safety. Local, state, and 21

federal agencies that have review and approval authority over the 22

generation facilities are charged with enforcing safety, environmental,23

and other regulations for the project, including decommissioning.24

Safety is also addressed as part of a generator’s interconnection 25

process, which requires testing for safety and reliability of the 26

interconnected generation. PG&E’s general practice is to declare that 27

a facility under contract has commenced deliveries under the contract 28

only after the interconnecting utility and the California Independent 29

System Operator (CAISO) have concluded such testing and given 30

permission to commence commercial operations.31

8-5

b. Performance Testing1

Some contracts require the counterparty to periodically demonstrate 2

the performance capabilities of the applicable generating station(s) 3

through testing. Engineers witness performance tests of counterparties’ 4

generating stations. Performance testing typically determines a facility’s 5

full-load generating capacity and heat rate. Performance test-related 6

activities include developing test procedures, witnessing tests, and 7

reviewing and approving test reports/results. The test results are 8

reported to various organizations within PG&E.9

5. Settlement and Payment10

The Electric Settlements section within ECMS is responsible for 11

ensuring the proper settlement of all contracts in PG&E’s electric portfolio,12

including: RPS contracts; Tolling agreements; Qualifying Facility (QF) 13

Must-Take agreements; agreements from the Qualifying Facility and 14

Combined Heat and Power (QF/CHP) Settlement; Feed-In Tariff (FIT) 15

agreements; Resource Adequacy (RA) purchase agreements; Irrigation 16

Districts and Water Agencies (ID&WA) legacy contracts; and Power Trading 17

Master agreements.18

The purpose of the settlement process is to ensure that all contract 19

payments are in accordance with the terms and conditions of each contract,20

and that these costs are fully documented and properly reported in PG&E’s 21

financial systems. The settlement process includes: the collection and 22

validation of generation; generator scheduling, and outage data; 23

the collection of pricing from market indices; the calculation and generation 24

of invoices; and the preparation of payment data for the Accounts Payable 25

Department. Settlement data is collected from various sources, including:26

PG&E’s metering systems; the CAISO; other PG&E departments; various 27

price indices; and the generators themselves. The settlements cycle 28

generally takes up to 25 calendar days to process all invoices through 29

calculation, approval, and payment.30

After each month’s settlement activities are complete, Electric 31

Settlements prepares additional financial and other reports.32

Electric Settlements also oversees process improvements on other 33

information systems in Energy Policy and Procurement so that the 34

8-6

Information Technology tools are maintained to keep pace with additional 1

contract requirements. Additional responsibilities include: maintaining and 2

testing Energy Policy and Procurement’s internal controls in accordance 3

with Sarbanes-Oxley requirements; and acting as the principal liaison to 4

PG&E’s Corporate Accounting Department concerning energy-related 5

disclosures for compliance reporting purposes.6

Electric Settlements currently has four distinct areas of responsibility:7

(1) RPS Settlements; (2) Tolling Settlements; (3) QF/CHP and FIT 8

Settlements; (4) and CAISO Settlements and Reporting. These functions 9

and the tools that support these functions are described below:10

RPS Settlements: Responsible for invoice validation and payment 11

processing of all RPS contracts, bilateral purchase and sales contracts 12

which include Power Trading Master agreements (including all electric 13

financial instruments), and RA purchase agreements.14

Tolling Settlements: Responsible for the invoice validation and 15

payment processing of all conventional natural gas tolling contracts and 16

the quarterly Greenhouse Gas (GHG) invoices from the California Air 17

Resources Board.18

QF/CHP and FIT Settlements: Responsible for administering and 19

settling the QF Must-Take agreements, ID&WA legacy contracts, and 20

the form agreements that arose from the QF/CHP Settlement and were21

approved by the CPUC in D.10-12-035. In addition, this group settles 22

the FIT agreements promulgated by California Assembly Bill (AB) 1969, 23

AB 1613, Senate Bill (SB) 32 Renewable Market Adjusting Tariff 24

(ReMAT), and SB 1122 Bioenergy Market Adjusting Tariff (BioMAT).25

CAISO Settlements and Reporting: Responsible for validation, 26

settlement and reporting of procurement costs and generation revenues 27

associated with PG&E’s participation in the CAISO electricity markets as 28

described in Chapter 9. Provides reporting data and analysis to internal29

organizations for the monthly Corporate Accounting close, the30

Controller’s Gross Margin Analysis, WREGIS data submittal, RPS31

reports, the 10-Q/10-K processes, GHG and various internal and 32

external requests using the following tools:33

8-7

– Qualifying Facilities Information Center (QIC): The QIC system 1

is a tool used to administer QF contracts. QIC is a database for 2

information about each QF contract, including: delivery and 3

payment history; scheduled maintenance outages; performance 4

factors; curtailment information; and meter data. Electric 5

Settlements also uses QIC to generate payment invoices.6

This system is in the process of being replaced by OpenLink 7

Endur described below.8

– OpenLink Endur: The OpenLink Endur system provides a module 9

for managing, invoicing, and reporting all power trading activities.10

Electric Settlements uses the Endur system to review generation 11

data and to invoice transactions. This system is gradually being 12

phased in to replace QIC described above. In 2017, AB 1969, 13

ReMAT, QF/CHP, and about three quarters of RPS bilateral 14

contracts were settled in the Endur system. The remaining 15

contracts are expected to be migrated from QIC to Endur in 2018.16

– Electric Settlements Tool for Analysis and Reporting (ESTAR):17

ESTAR is used to manage complex contracts currently not 18

supported in the QIC system. This system collects unit specific 19

temperature and gas meter data to calculate the gas balancing 20

true-up adjustments for Tolling Agreements. This tool is also used 21

to calculate payment amounts for contracts not yet programmed in 22

Endur. Currently, ESTAR interfaces with the QIC system, which 23

prepares monthly invoices for each counterparty. Upon full 24

implementation, ESTAR calculations will work with the Endur 25

system.26

For a detailed description of the processes that Settlements uses, refer 27

to the confidential workpapers that accompany this chapter (see “Electric 28

Settlements’ Payment Guidelines”).29

6. Dispute Resolution30

ECMS manages any disputes that arise in connection with the contracts. 31

PG&E’s policy is to initially pursue resolution of issues through discussions. 32

If a contract issue cannot be resolved through initial discussions, ECMS may 33

conduct negotiations directly with the counterparty to resolve the dispute, as 34

8-8

prescribed per the contract. If such discussions and negotiations are 1

unsuccessful and formal litigation or arbitration becomes necessary, PG&E 2

develops and pursues resolution strategies consistent with the best interests 3

of customers. ECMS supports such discussions and negotiations and works 4

with PG&E’s Law Department and other internal stakeholders, as applicable, 5

in resolving contract disputes. These activities include support for discovery 6

and developing positions and proposals for dispute resolution.7

7. Tools, Systems and Controls8

ECMS uses a number of tools and systems that serve as controls in the 9

contract management and electric settlements process. These tools and 10

systems help ensure that contracts are prudently administered according to 11

their terms and conditions, and that there is continuity in ECMS for the entire 12

length of the contract term, which is important given that many of PG&E’s 13

contracts have terms of up to 30 years.14

Furthermore, these tools, systems and controls play a key role in 15

helping ECMS document, maintain and report contract information for the 16

purpose of providing data to both internal and external stakeholders.17

Upon execution of a contract, an assigned lead creates or updates 18

a record within ECMS tools and systems (e.g., CECM Database, as defined 19

below). The lead requests that the assigned Contract Managers review their 20

entries for completeness. For contract data that changes (e.g., project 21

status), ECMS, along with other PG&E departments (e.g., Energy Policy and 22

Procurement, Market and Credit Risk Management, etc.), reviews the data 23

for consistency.24

The primary tools, systems and controls used by ECMS are described 25

below:26

Master Contract List: A complete listing of all of the contracts 27

administered by ECMS. The list: (1) is used only by internal 28

stakeholders (e.g., Energy Policy and Procurement, Law, Internal Audit, 29

etc.); (2) contains links to documents stored in the Electronic Document 30

Management System (EDMS) and Documentum (D2) (described 31

below); and (3) includes the assigned Contract Manager and 32

Settlements Analyst for each contract.33

8-9

Electronic Document Management System (EDMS) and 1

Documentum (D2): PG&E’s legacy and replacement electronic 2

document storage systems: EDMS and D2 are web-based electronic 3

document storage systems that contain documents pertaining to our 4

contracts, and are secure storage and retrieval systems. Contract 5

Managers use EDMS and D2 to archive and access electronic copies of 6

documents. These documents include executed contract documents 7

and significant correspondence. Upon completed migration of all 8

documents from EDMS into the D2 system, EDMS will be9

decommissioned.10

Consolidated Energy Contract Management (CECM) Database: A11

database containing information about contracts executed by Energy 12

Policy and Procurement including, but not limited to: Western System13

Power Pool and Edison Electric Institute (EEI) master enabling 14

agreements; tolling and renewable agreements; energy storage, QF, 15

CHP, and other must-take contracts. The CECM Database contains 16

information such as: type of energy products; critical milestones;17

regulatory and permitting status; pricing; and credit information 18

(as applicable). The CECM Database allows for a more accurate and 19

efficient compilation of information for various internal and external 20

reports, such as the Transaction Tracking List, and various regulatory 21

reports (e.g., Energy Division Monthly RPS Database).22

Task Tracking Tool (T3): A milestone tracking system within the 23

CECM Database. T3 integrates the contractual milestone dates that are 24

managed in the CECM Database and eliminates the need to track, 25

manage, and update the same contractual milestone dates in a separate 26

system. Updates made to contractual dates and milestones in the 27

CECM Database are automatically reflected in T3. T3 also: (1) tracks 28

contractual deadline requirements, and tasks related to the29

management of contracts; (2) provides automatically-scheduled 30

notifications and escalations to Contract Managers and their supervisors31

in order for action to be taken well-in-advance of contractual deadlines; 32

and (3) ensures that tasks and obligations are tracked through to their 33

resolution.34

8-10

Transaction Tracking List: A chronological listing of executed 1

contracts, as well as subsequent transactions (e.g., amendments, letter 2

agreements, etc.), including a short description of the transaction. 3

The Transaction Tracking List is a tool used in preparing recurring 4

reports as it tracks contract execution dates, advice letter filings, and 5

CPUC approvals for relevant agreements.6

Scheduling Protocols: Contract-specific reports summarizing basic 7

contract information, such as: contract quantity; delivery point; contact 8

information; scheduling terms; and operational parameters for PG&E’s 9

contracted generation.10

Contract Management Intranet Site (SharePoint): An intranet site, 11

maintained and controlled by ECMS, which facilitates the sharing of 12

contract information with other stakeholders within PG&E. The following 13

tools and systems reside on or can be accessed from the Contract 14

Management SharePoint site: Master Contract List; EDMS/D2; CECM 15

Database; T3; Transaction Tracking List; Scheduling Protocols.16

C. Contract Administration During the Record Period17

This section discusses the administration of contracts that were in or added 18

to PG&E’s portfolio during the record period, and any significant changes to 19

these contracts that occurred.20

1. Procurement Programs and Solicitations21

This section describes PG&E’s solicitations and procurement programs 22

which had procurement activity during the record period.23

a. Solar Photovoltaic24

Pursuant to D.14-11-042, PG&E issued the 2016 Photovoltaic (PV)25

Request for Offers (RFO) for PG&E’s PV Program on December 7, 26

2016. PG&E sought to procure 68.75 megawatts (MW) of the 27

137.5 MW remaining PV capacity from new and existing PV facilities 28

during this solicitation. During the record period, PG&E executed 29

three PPAs pursuant to the 2016 PV RFO totaling 60 MW.30

PG&E issued the 2017 PV RFO for PG&E’s PV Program on 31

December 20, 2017. PG&E is seeking to procure 77.5 MW from new 32

8-11

and existing PV facilities. The execution of selected PPAs is targeted 1

for May 2018.2

b. ReMAT3

Pursuant to D.12-05-035 and D.13-05-034, PG&E issued bi-monthly 4

auctions during the record period for the ReMAT program. PG&E was 5

allocated 218.8 MW of the 750 MW total statewide goal to procure from 6

small distributed generation qualifying as “eligible renewable energy 7

resources” up to 3 MW in project size. PG&E executed ReMAT PPAs 8

totaling 6.17 MW during the record period. The ReMAT program 9

currently has 30.89 MW of total capacity from executed, non-terminated 10

ReMAT PPAs.11

On December 6, 2017, the U.S. District Court for the Northern12

District of California (Court) granted summary judgment in favor of13

Winding Creek Solar LLC (Winding Creek), in the case Winding Creek 14

Solar LLC v. Michael Peevey, et al. The Court determined that ReMAT 15

is not compliant with the federal Public Utilities Regulatory Policy Act 16

(PURPA). On January 3, 2018, the CPUC filed a motion to stay the17

Court’s order pending the CPUC’s appeal of the order. As of the date of 18

this filing, PG&E has suspended the execution of new ReMAT PPAs in 19

accordance with a directive received from the CPUC in a letter dated 20

December 15, 2017.21

c. BioMAT22

Pursuant to D.14-12-081 and D.15-09-004, PG&E issued bi-monthly 23

auctions during the record period for the BioMAT program Category 124

(biogas from wastewater treatment, municipal organic waste diversion, 25

food processing, and codigestion) and Category 2 (biogas from dairy 26

and other agricultural bioenergy), and monthly auctions for Category 327

(biogas or biomass using byproducts of sustainable forest 28

management). PG&E was allocated 111 MW of the 250 MW total IOU 29

procurement target from bioenergy resources. During the record period, 30

PG&E executed four BioMAT PPAs for a total of 3.85 MW. The BioMAT 31

program currently has 5.45 MW of total capacity from executed, non-32

terminated BioMAT PPAs.33

8-12

As described above, the CPUC advised in its December 15, 2017,1

letter that it is evaluating the implications of the Winding Creek decision 2

for the BioMAT program. In the interim, and as of the date of this filing, 3

PG&E has suspended the execution of new BioMAT PPAs until further 4

direction.5

d. Energy Storage6

Pursuant to D.13-10-040, PG&E issued the 2016 Energy Storage 7

RFO in November 2016 to procure towards PG&E’s overall target of 8

580 MW of energy storage resources. The 2016 RFO solicited offers for 9

energy storage at the transmission, distribution, and customer 10

connected domains. During the record period, PG&E executed 11

four front-of-the-retail-meter Capacity Storage Agreements (CSA), and 12

one behind-the-retail-meter CSA. PG&E filed an application seeking 13

Commission approval of the agreements resulting from the 2016 RFO14

on December 1, 2017. The Energy Storage program currently has 15

procured 185 MW of total capacity from executed, non-terminated 16

Energy Storage Agreements (ESA). 17

e. Resource Adequacy18

Pursuant to D.04-10-035, D.05-10-042 and D.12-04-046, PG&E 19

held RFOs in each quarter of the 2017 period for RA contracts. The 20

ensuing RA purchase and sale contracts were in compliance with 21

PG&E’s Bundled Procurement Plan and all executed contracts were 22

reported in PG&E’s Quarterly Compliance Reports.23

f. Renewable Energy Sales24

Pursuant to D. 16-12-04, PG&E issued the Renewable Energy 25

Sales Solicitation in January 2017 to sell excess Bundled RPS energy 26

and Renewable Energy Certificates (RECs). The ensuing Renewable 27

Energy Sale contracts were in compliance with PG&E’s 2016 RPS Plan 28

and followed the strategy described in the Sales Framework in 29

Appendix J of the 2016 RPS Plan.30

8-13

2. Contracts Executed1

The list below summarizes the number of contracts executed during the 2

record period. A detailed listing of the contracts executed during the record 3

period can be found in Tables 8-2 and 8-3 at the end of this chapter.4

CONTRACTS EXECUTED

Line No. Type of Contract

Number of Contracts Executed

1 BioMAT 42 EEI Master 43 Energy Storage 54 QF/CHP Settlement Agreements 45 ReMAT 66 Resource Adequacy 257 RPS 8

8 Total 56

3. Project Development and Construction Monitoring Results5

ECMS monitors the construction of projects under development, and 6

tracks contract milestones and deadlines, including construction start dates 7

and commercial operation dates. In addition, ECMS reviews periodic written 8

reports from developers, and when additional action is advisable, conducts 9

conference calls with developers, and inspects project sites. During the 10

record period, several counterparties exercised permitted extensions of 11

contract milestones or missed key PPA milestones, as reported in 12

Tables 8-4 and 8-5 at the end of this chapter.13

4. Contracts That Began Delivery14

The list below summarizes the number of contracts that began 15

delivering during the record period. A detailed listing of the contracts that16

began delivering during the record period can be found in Table 8-6 located 17

at the end of this chapter.18

8-14

CONTRACTS THAT BEGAN DELIVERY


Number of Contracts

That Began Delivery

Total Contract

Size (MW)

1 GTSR – PG&E Solar Choice 5 28.252 QF/CHP Settlement Agreements 4 18.53 ReMAT 6 6.2114 RPS 18 219.2

5 Total 33 272.161

5. Contract Amendments, Consents to Assignment and 1

Other Agreements2

Contracts that had amendments, Consent to Assignments, and other 3

similar agreements executed during the record period are listed in Table 8-74

located at the end of this chapter.5

6. Force Majeure Claims6

A force majeure is an instance when unforeseeable circumstances 7

occur that prevent one or both parties from fulfilling the contract according to 8

the contract language. PG&E responds to force majeure claims by 9

reviewing the contract as well as the facts surrounding the force majeure 10

claim. The force majeure claims addressed during the record period are 11

listed in Table 8-8 located at the end of this chapter.12

7. Disputes13

This section describes matters in which PG&E and a counterparty 14

engaged in a dispute resolution process provided for under the agreement. 15

a. Alpaugh 50, LLC; Alpaugh North, LLC; CED Corcoran Solar, LLC;16

and CED White River Solar, LLC (PG&E Log Nos. 33R118, 33R119, 17

33R121, 33R122)18

On May 12, 2016, ConEdison Development (CED) initiated the 19

dispute resolution process for: Alpaugh 50, LLC; Alpaugh North, LLC; 20

CED Corcoran Solar, LLC; and CED White River Solar, LLC. CED 21

claimed that all four facilities were being curtailed in excess of the 22

50-hour dispatch down limits in the PPAs, asserting that participating 23

transmission owner-related outages were the main cause of the 24

outages. PG&E and CED engaged in multiple dispute resolution 25

8-15

discussions during the record period. This dispute is ongoing and has 1

not been resolved at the time of this filing.2

b. Hecate Energy Molino LLC (PG&E Log No. 40S003)3

On December 30, 2016, Hecate Energy initiated the dispute 4

resolution process under its ESA. The dispute was resolved during the 5

2017 record period, but prior to PG&E’s filing of its 2016 ERRA 6

Compliance testimony. Therefore, PG&E addressed this dispute and 7

the resolution in its 2016 ERRA Compliance testimony.8

c. Coalinga Cogeneration Company (PG&E Log No. 25C124QTR)9

On May 25, 2017, Coalinga Cogeneration Company (Coalinga) 10

initiated the dispute resolution process under the PPA. Coalinga 11

disputed PG&E’s denial of Coalinga’s June 2016 claim of force majeure12

related to failure of a third-party crude oil pipeline, which resulted in a 13

reduction of Coalinga’s capacity payments. PG&E and Coalinga 14

engaged in multiple dispute resolution meetings during the record 15

period. This dispute is ongoing and has not been resolved at the time of 16

this filing.17

d. Panoche Energy Center (PG&E Log No. 33B076)18

On October 19, 2017, Panoche Energy Center, LLC (Panoche) 19

initiated the dispute resolution process under the PPA, regarding 20

PG&E’s calculation of monthly contract capacity adjustments under the 21

PPA. PG&E and Panoche engaged in multiple dispute resolution 22

discussions during the record period. This dispute is ongoing and has 23

not been resolved at the time of this filing.24

e. Global Ampersand, LLC, El Nido Biomass Facility and Chowchilla 25

Biomass Facility (PG&E Log Nos. 33R016 and 33R017)26

On November 16, 2017, Global Ampersand, LLC (Global) initiated 27

the dispute resolution process for the El Nido Biomass Facility and the 28

Chowchilla Biomass Facility, regarding multiple payment issues related 29

to scheduling and outage notification. PG&E and Global engaged in 30

management negotiations during the record period. This dispute is 31

ongoing and has not been resolved at the time of this filing.32

8-16

8. Contracts That Expired or Terminated1

The list below summarizes the number of contracts that were expired or 2

terminated during the record period. A detailed listing of the contracts that 3

expired or terminated during the record period can be found in Table 8-9 at 4

the end of this chapter.5

CONTRACTS THAT EXPIRED OR TERMINATED


Number of Contracts Expired

Number of Contracts

Terminated

1 Conventional/Tolling 2 02 EEI Master 0 13 Energy Storage 0 24 QF 11 105 QF/CHP Settlement Agreements 1 06 ReMAT 0 47 Renewable and Non-Renewable

Energy 1 0

8 RPS 6 1

9 Total 21 18

D. Other Matters6

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


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


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


CONTRACT AMENDMENTS AND CONSENTS TO ASSIGNMENT DURING RECORD PERIOD 2017

8-26


CONTRACT AMENDMENTS AND CONSENTS TO ASSIGNMENT DURING RECORD PERIOD 2017(CONTINUED)

8-27


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

4 12/29/2016 33R056 Topaz Solar Farm RPS 2/21/20175 2/9/2017 33R093 Geysers RPS 5/31/2017

6 2/14/2017 33B116 Oroville Tolling Agreement Tolling 5/3/2017

7 2/24/2017 33R074 SFWP - Sly Creek / Kelly Ridge RPS Pending

8 2/24/2017 33R140 El Dorado Irrigation District RPS 6/23/20179 2/27/2017 25C164 PE - KES Kingsburg QF 3/7/2017

10 3/31/2017 33R063 Ivanpah Unit 1 RPS 5/26/2017

11 3/31/2017 33R064 Ivanpah Unit 3 RPS 5/26/2017

12 5/15/2017 33R052 High Plains Ranch II RPS 5/30/2017

13 5/15/2017 33R088 High Plains Ranch III RPS 5/30/2017

14 10/4/2017 33R402RM Mini Hydro ReMAT Pending

15 10/9/2017 33R093 Geysers RPS Pending


17 10/11/2017 33B112 Bear Mountain Limited Tolling 11/9/2017

18 10/16/2017 12C020 Greenleaf Unit #1 QF Pending


8-28


CONTRACTS THAT EXPIRED OR TERMINATED DURING RECORD PERIOD 2017

Line No. Date

PG&E Log Number Project Name Contract Type Description

1 1/4/2017 13H015 Mega Renewables (Hatchet Creek) QF Expired2 1/23/2017 16P002 Pacific-Ultrapower Chinese Station QF Expired3 1/31/2017 10P005 HL Power QF Terminated4 2/2/2017 19P005 DG Fairhaven Power QF Expired5 2/21/2017 13H017 Mega Renewables (Bidwell Ditch) QF Expired6 2/27/2017 13H001 El Dorado Hydro (Montgomery Creek) QF Expired7 3/1/2017 33R369RM 2042 Baldwin ReMAT Terminated8 3/9/2017 33R371RM 2257 Campbell ReMAT Terminated9 3/20/2017 33R370RM 2245 Gentry ReMAT Terminated10 4/16/2017 33R012 Buena Vista Wind Project RPS Expired11 4/28/2017 33R360RM 2275 Hattesen ReMAT Terminated12 5/3/2017 40S006 Stem Energy Northern CA, LLC Energy Storage Terminated13 5/14/2017 19H051 Humboldt Bay MWD QF Terminated14 5/31/2017 19C010 Humboldt Redwood Company QF Terminated15 5/31/2017 25C016 Algonquin Power Sanger LLC QF Terminated16 6/12/2017 33R361 Maricopa West Solar RPS Terminated17 6/20/2017 33B079 JR Simplot Conventional Expired18 6/28/2017 40S002 Energy Nuevo Storage Farm Energy Storage Terminated19 6/30/2017 33B219 Merced Irrigation District Conventional Expired20 7/26/2017 01C084 PE - Berkeley, Inc. QF Expired21 8/14/2017 13H036 Mega Renewables (Silver Springs) QF Expired22 9/7/2017 15P028 Rio Bravo Rocklin QF Terminated23 9/7/2017 25P026 Rio Bravo Fresno QF Terminated24 9/25/2017 16W011A Cogeneration Capital Association QF Expired25 9/25/2017 16W173 Cogen Capital (Altamont Power) QF Expired26 9/30/2017 33R411 Direct Energy Business Marketing , LLC 1, 2 RPS Expired27 9/30/2017 33R412 EDF Trading North America, LLC 1, 2 RPS Expired28 9/30/2017 33R413 Exelon Generation Company, LLC 1, 2 RPS Expired29 9/30/2017 33R414 Peninsula Clean Energy Authority 1, 2 RPS Expired30 10/16/2017 13H006 Sutter's Mill QF Terminated31 10/31/2017 04H061QPA4 Indian Valley Hydro PURPA Expired32 10/31/2017 13C038 Burney Forest Products QF Terminated33 11/24/2017 06H159 David O. Harde QF Terminated34 11/30/2017 33B056 Conoco Phillips Company EEI Master Terminated35 12/1/2017 13P045 Wheelabrator Shasta QF Terminated36 12/31/2017 06W146B EDF Renewable Windfarm V, Inc. (70 MW - B) QF Expired37 12/31/2017 06W148 EDF Renewable Windfarm V, Inc. (10 MW) QF Expired

38 12/31/2017 33R252 / 33B210

PCWA - French Meadows / Oxbow / Hell Hole / Middle Fork / Ralston

Renewable and Non-Renewable Energy Expired

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.


CHAPTER 9

CAISO SETTLEMENTS AND MONITORING

9-i


CAISO SETTLEMENTS AND MONITORING

TABLE OF CONTENTS

A. Introduction ....................................................................................................... 9-1

B. CAISO Market Costs ........................................................................................ 9-1

1. Day-Ahead Market ..................................................................................... 9-2

2. Real-Time Market ...................................................................................... 9-2

3. Congestion Revenue Rights ...................................................................... 9-3

4. Bid Cost Recovery ..................................................................................... 9-3

5. Other .......................................................................................................... 9-3

C. Grid Management Charges .............................................................................. 9-4

D. FERC Fees ....................................................................................................... 9-4

E. PG&E CAISO Market Cost Validation Business Process ................................. 9-4

F. Additional Items ................................................................................................ 9-5

1. Good Faith Negotiation .............................................................................. 9-5

2. Non-ERRA Memorandum Accounts........................................................... 9-6

G Conclusion ........................................................................................................ 9-7

9-1


CHAPTER 9 2

CAISO SETTLEMENTS AND MONITORING 3

A. Introduction 4

This chapter describes the procurement costs and revenues associated with 5

Pacific Gas and Electric Company’s (PG&E) participation in the California 6

Independent System Operator (CAISO) electricity markets, both Day-Ahead and 7

Real-Time. PG&E receives revenue for electric generation provided to the 8

CAISO markets and is charged for demand representing PG&E’s bundled 9

customer load. The costs and revenues described here reflect the portion of 10

PG&E’s electric supply portfolio, for which PG&E is the Scheduling Coordinator 11

(SC). SCs are entities authorized by the CAISO to schedule and bid power on 12

behalf of CAISO market participants. SCs also make and receive market 13

payments and have the ability to validate and dispute market charges with the 14

CAISO. The CAISO Settlements Department is responsible for fulfilling this 15

payment and validation role within PG&E. 16

CAISO net charges eligible for ERRA cost recovery in 2017 17

totaled $317,320,385. This included charges for Market Costs ($260,886,980), 18

Grid Management Charges ($50,950,476) and FERC Fees ($5,482,929). 19

Beginning in November 2017, CAISO market revenue included $2,138,538 for 20

two resources, Burney Forest Products and Wheelabrator Shasta, being booked 21

to non-ERRA memorandum accounts as discussed below in Section E2.1 22

B. CAISO Market Costs 23

During the January 1 to December 31, 2017 record period, PG&E incurred a 24

net expense of $260,886,980 for participation in the CAISO markets. This is 25

representative of the cost of serving PG&E’s bundled customer load through the 26

CAISO markets netted against the revenues received for PG&E’s supply 27

resources. The aspects of the CAISO’s markets described in this section 28

represent the large majority of this cost. 29

1 See Chapter 9 Workpaper for more detail.

9-2

1. Day-Ahead Market 1

The CAISO runs a Day-Ahead Market for energy and Ancillary Services 2

(A/S), referred to as the Integrated Forward Market (IFM). Total Day-Ahead 3

Market purchases and sales of energy netted to a charge of $200,892,641 4

for the record period. PG&E’s electric supply portfolio receives revenues for 5

awarded energy and capacity through these markets. PG&E is also 6

charged for the amount of demand scheduled and bid on behalf of PG&E’s 7

bundled customer load. In addition to the energy and A/S markets, the 8

CAISO also runs a Residual Unit Commitment (RUC) process after the IFM. 9

If needed, the CAISO procures additional capacity through this process. 10

Based on the CAISO’s procurement through the IFM and RUC, it may be 11

necessary to collect additional funds, or market uplifts, from market 12

participants based on their net market positions. These uplift charges are 13

often based on the amount of demand a market participant has in the 14

CAISO’s markets. This amount includes charges for energy purchased for 15

PG&E’s bundled customer load, A/S portfolio obligations, and market uplifts 16

needed to maintain cash neutrality for the CAISO. These charges are offset 17

by revenues for awarded energy and A/S schedules for PG&E’s portfolio 18

generation. 19

2. Real-Time Market 20

The CAISO’s Real-Time Market (RTM) includes the costs and revenues 21

related to the dispatch of energy, unscheduled bundled customer load and 22

procurement of A/S. The RTM is comprised of 5-minute dispatch and 23

settlement and the Fifteen-Minute Market (FMM) resulting from the 24

implementation of Federal Energy Regulatory Commission (FERC) 25

Order 764 beginning in 2014. RTM purchases and sales of energy netted to 26

a charge of $59,718,936 in 2017. Also included are the financial 27

settlements related to intertie awards, for both imports and exports, which 28

are generated through the Hour-Ahead Scheduling Process and the FMM. 29

The dispatch of energy in Real-Time is settled through the use of imbalance 30

energy charge codes. Dispatches are paid or charged through the 31

Instructed Imbalance Charge Code mechanism, while deviations from 32

schedule or dispatch are settled through the Uninstructed Imbalance Charge 33

9-3

Code mechanism. Similar to the Day-Ahead Market, market uplifts are 1

utilized to fund any revenue shortfalls in the RTM. 2

3. Congestion Revenue Rights 3

Congestion Revenue Rights (CRR) are financial instruments that allow 4

the holder to hedge congestion costs in the IFM. CRRs are defined 5

between any two nodes in the CAISO transmission network model. 6

The revenue (or shortfall) associated with a CRR on a path is the difference 7

between the congestion component of the source Locational Marginal Price 8

(LMP) and the congestion component of the sink LMP. CRRs, with their 9

associated cash flows, enable Load Serving Entities (LSE), such as PG&E, 10

to mitigate potential congestion costs associated with the price the CAISO 11

charges to serve LSE loads. CRRs are acquired through a yearly and 12

monthly allocation and auction process. CRR credits to PG&E in 2017 13

totaled $10,204,764. 14

4. Bid Cost Recovery 15

In situations where generation resources do not fully recover their costs 16

through the markets, the CAISO utilizes the Bid Cost Recovery (BCR) 17

mechanism to further compensate resources. Generation that is committed 18

by the CAISO is entitled to fully recover bid costs, startup costs, and 19

minimum load costs associated with the specific resource. A BCR payment 20

will be made if a resource is not fully compensated for these costs across a 21

full trade day and across all markets. The CAISO utilizes market uplifts to 22

procure the funds required for BCR payments to generators. PG&E’s 23

electric portfolio both, receives revenue for its generation resources, and 24

is also subject to the BCR uplift charges based on portfolio positions 25

and demand. BCR netted to a credit of $5,646,881 in 2017. 26

5. Other 27

Other charges of $16,127,048 included Unaccounted for Energy, 28

Convergence Bidding, Ancillary Services, Day-Ahead Integrated Forward 29

Market Credit Allocation, Real-Time Imbalance Energy Offset and other 30

miscellaneous categories. 31

9-4

C. Grid Management Charges 1

Grid Management Charges (GMC) are comprised of daily and monthly 2

charges, which are assessed to market participants for the purpose of 3

recovering all of the CAISO’s operating costs. The CAISO currently has 4

incorporated three cost service-based GMCs, a fixed Transmission Ownership 5

Rights GMC, as well as four transactional and administrative GMCs. The cost 6

services GMC consist of: (1) a Market Services Charge; (2) a System 7

Operations Charge; and (3) a CRR Services Charge. The four transactional 8

fees consist of: (1) a Bid Segment Fee; (2) a CRR Transaction Fee; (3) an 9

Inter-SC Trade Transaction Fee; and (4) a SC ID Charge. All of these GMCs 10

represent the various ways market participants interact with the CAISO on a 11

day-to-day basis. PG&E was charged $50,950,476 in GMCs during the record 12

period. 13

D. FERC Fees 14

FERC fees are allocated to CAISO market participants in accordance with 15

the CAISO Tariff. The fees represent estimated and actual FERC operating 16

costs for its electric regulatory program. The CAISO allocates the fees to each 17

market participant based on their use of the CAISO grid. PG&E was 18

allocated $5,482,929 in FERC fees during the record period. 19

E. PG&E CAISO Market Cost Validation Business Process 20

The CAISO utilizes over 200 charge codes to settle its markets and the 21

various instruments and products associated with those markets. The CAISO 22

publishes multiple iterations of settlement statements that market participants 23

are able to download and validate prior to invoicing. Settlement statements are 24

published for each trade date. SCs are able to dispute these statements if 25

errors are discovered. 26

PG&E utilizes a shadow settlement tool for the charge code validation and 27

dispute process. PG&E loads the necessary CAISO statements and supporting 28

inputs for shadow settlement into the shadow system and runs estimates for 29

CAISO charge codes. PG&E then uses the information in the shadow system to 30

validate charge codes for CAISO settlement statements. A charge code dispute 31

may be necessary when, after validating the different charge codes by 32

comparing CAISO settlement statements with the shadow estimates, there is a 33

9-5

discrepancy. This process is conducted for each trade date to ensure that 1

CAISO is accurately settling the market. Once a dispute is filed with CAISO, 2

it can be denied or accepted. If accepted, the correction usually appears in the 3

next published version of the settlement statement. 4

F. Additional Items 5

1. Good Faith Negotiation 6

In 2016 Chapter 9 Energy Resource Recovery Account (ERRA) 7

Compliance Testimony, PG&E discussed an outstanding Good Faith 8

Negotiation (GFN) with the CAISO relating to an April 14-16, 2016 market 9

event at Agua Caliente, a contracted resource. The event was precipitated 10

by the CAISO invoking Operation Procedure 7860 (OP7860) for the 11

stranded generation of Agua Caliente due to an outage on the Hoodoo 12

Wash – North Gila transmission line. OP7860 was created to allow Agua 13

Caliente to generate when it is isolated from the CAISO grid. Under 14

OP7860, PG&E followed one of the listed options exporting and importing 15

Agua Caliente's power at Palo Verde in Arizona to re-enter the CAISO 16

Balancing Authority through an alternate route at Devers. Due to both high 17

congestion at North Gila and high negative Day-Ahead prices, this action 18

resulted in net charges of $2.4 million to PG&E over the period. PG&E 19

disputed the charges with the CAISO but the dispute was denied. 20

Subsequently, PG&E initiated a GFN on July 27, 2016, to address the 21

disputed charges through an alternate resolution process and also 22

requested the CAISO to clarify its future use of OP7860. 23

From August 2016 through June 2017, both PG&E and the CAISO 24

conducted due diligence, and held several meetings to better understand 25

the specific operating factors surrounding the April 14-16, 2016 event at 26

Agua Caliente. One outcome of these discussions was PG&E successfully 27

convincing the CAISO to retire OP7860 effective April 28, 2017, arguing that 28

it gave no additional scheduling options or guidance that otherwise would 29

not be available during a transmission outage. 30

On June 27, 2017, the CAISO finalized its GFN conclusion, reaffirming 31

that its modeling of the Day-Ahead Market had been correct and in 32

accordance with the CAISO Tariff. Congestion had resulted from the 33

9-6

transmission outage at North Gila-Hoodoo Wash combining with a second 1

event - an unanticipated de-rate of a 500 kilovolt line at Hassayampa to 2

North Gila (HANG2) originating outside the CAISO footprint by Arizona 3

Public Service. Agua Caliente had settled not on the contract path wheeling 4

from Palo Verde, as PG&E originally assumed, but on actual operating flows 5

from HANG2. Based on the additional information obtained through the 6

GFN, PG&E concurred with the CAISO conclusion that the settlement costs 7

for Agua Caliente had been accurately calculated for this event in dispute. 8

2. Non-ERRA Memorandum Accounts 9

Beginning in November 2017, PG&E financial reporting began recording 10

non-ERRA market revenues and costs in Bioenergy Renewable Auction 11

Mechanism Memorandum Account (BioRAMMA) and Biomass 12

Memorandum Account (BioMASSMA), two new memorandum accounts 13

established to track electric procurement costs associated with Power 14

Purchase Agreements (PPA) that were executed to comply with California 15

Public Utilities Commission (CPUC) Resolutions E-4770 and E-4805. These 16

resolutions ordered the large investor-owned utilities to procure a share of 17

capacity from existing biomass facilities that use specific forest fuels stocks 18

under the Governor's Proclamation on Tree Mortality and the Drought 19

(October 30, 2015). PG&E was required to procure at least 20 megawatts 20

(MW) from this solicitation and subsequently executed one PPA with Burney 21

Forest Products (Burney). Total 2017 BioRAMMA CAISO market revenues 22

were $1,306,713. PG&E executed a second PPA with Wheelabrator Shasta 23

to meet its remaining compliance obligation under Resolution E-4805. The 24

market revenues for the Wheelabrator Shasta contract were recorded in 25

BioMASSMA. Since the capacity procured pursuant to the Burney PPA was 26

27 MW, 20 MW of the total procurement were attributable to meeting the 27

requirements of Resolution E-4770 and recorded to BioRAMMA, while the 28

remaining 7 MW were attributed to meeting the requirements of 29

Resolution E-4805 and recorded in BioMASSMA. Total 2017 BioMASSMA 30

market revenues were $831,825. The disposition of the memo accounts' 31

balances into a new Tree Mortality Non-Bypassable Charge balancing 32

account will occur upon its approval by the CPUC currently anticipated 33

toward the end of 2018. 34

9-7

G Conclusion 1

The above testimony describes the CAISO costs that were incurred during 2

the record period and demonstrates that these costs were reasonable and 3

prudently incurred. 4


CHAPTER 10

REVIEW ENTRIES RECORDED IN THE GREEN TARIFF SHARED

RENEWABLES MEMORANDUM ACCOUNT AND THE GREEN

TARIFF SHARED RENEWABLES BALANCING ACCOUNT

10-i


REVIEW ENTRIES RECORDED IN THE GREEN TARIFF SHARED RENEWABLES MEMORANDUM ACCOUNT AND THE GREEN TARIFF SHARED RENEWABLES

BALANCING ACCOUNT

TABLE OF CONTENTS

A. Introduction ..................................................................................................... 10-1

B. Green Tariff Shared Renewables Memorandum Account .............................. 10-2

1. Description of Costs Incurred ................................................................... 10-2

2. Program Management ............................................................................. 10-3

3. IT/Billing System Work ............................................................................. 10-3

4. Energy Procurement ................................................................................ 10-4

5. Contact Center Operations ...................................................................... 10-4

6. Outreach .................................................................................................. 10-4

C. Green Tariff Shared Renewables Balancing Account..................................... 10-4

1. Background .............................................................................................. 10-4

2. Rate Design Overview ............................................................................. 10-6

3. Balancing Account Entries for the Record Period .................................... 10-8

D. Conclusion ...................................................................................................... 10-8

10-1


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.

10-9

TABLE 10-4 BALANCING ACCOUNT ENTRIES

Tariff Line Item DR/CR Tariff Description Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 FY 2017 YTD

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

Current Month Unbilled Revenue

E-GT Solar Charge Unbilled revenue, excluding rf&u (212,034) (205,603) (211,008) (195,687) (215,552) # (203,701) (216,867) (229,991) (228,447) (241,901) (270,285) (301,169) (2,732,245) Reversal of Prior Month E-GT Solar Charge Unbilled net revenue 204,147 212,034 205,603 211,008 196,210 # 215,090 203,701 216,867 229,991 228,447 241,901 270,285 2,635,285 E-GT / E-ECR Program Charge Unbilled revenue, excluding rf&u (68,107) (66,241) (67,743) (63,124) (69,357) # (65,540) (69,750) (73,970) (73,474) (77,802) (86,930) (96,864) (878,902)

Reversal of Prior Month E-GT / E-ECR Solar Charge Unbilled net revenue 45,537 68,107 66,241 67,743 63,296 # 69,205 65,540 69,750 73,970 73,474 77,802 86,930 827,595 Net Revenues (410,015.18) (313,293.62) (419,107.36) (271,077.31) (343,655.52) (317,534.67) (350,833.26) (433,143.99) (406,806.79) (400,612.85) (425,229.22) (489,569.34) (4,580,879)

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.

291,589 221,555 299,806 190,062 245,401 223,581 247,129 306,107 287,324 283,832 302,610 346,868 3,245,862

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.

118,427 91,738 119,302 81,016 98,255 93,954 103,705 127,037 119,483 116,781 122,619 142,702 1,335,017

4.g 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-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.

-

GTSRBA Monthly Expense 410,015 313,294 419,107 271,077 343,656 317,535 350,833 433,144 406,807 400,613 425,229 499,169 4,590,479

GTSRBA Monthly Activity Before Interest - - - - 0 - - - - - - 9,600 9,600

4.j DR/CR

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.

59 64 61 69 73 76 88 94 94 95 97 103 973

GTSRBA Beginning Balance 95,486 95,545 95,608 95,670 95,739 95,812 95,888 95,976 96,070 96,164 96,259 96,356 95,486 GTSRBA Ending Balance 95,545 95,608 95,670 95,739 95,812 95,888 95,976 96,070 96,164 96,259 96,356 106,058 106,058

Billed Revenues - Net

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:


CHAPTER 11

SUMMARY OF ENERGY RESOURCE RECOVERY ACCOUNT

ENTRIES FOR THE RECORD PERIOD

11-i


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


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


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,

5.ak, 5.al, 5.ap12 CTC & CAM Credits 5.g, 5.h, and 5.af

13 Total Procurement Cost Recorded in ERRA(a)

$3,879.2 $4,083.2 $(204.0)

_______________

(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

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ligat

ions

and

PPA

oblig

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ns, a

bove

the

mar

ket b

ench

mar

k cu

rrent

ly a

dopt

ed b

y th

e C

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5.h.

DRA

debi

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tone

gativ

eab

ove-

mar

ket

cost

s,th

atar

eap

plie

dto

posi

tive

abov

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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

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oth

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mfo

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onth

ofth

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tof

:(1

)th

eM

illion

sof

Briti

shTh

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nits

(MM

Btu)

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daily

for

all

purp

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atPG

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foss

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ants

;an

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d-av

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stof

gas

ona

Util

ityEl

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cG

ener

atio

n(U

EG) p

ortfo

lio b

asis

($/M

MBt

u);

5.k.

DRA

debi

tent

ryeq

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mfo

rth

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ofth

epr

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tof:

(1)

the

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els

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62

11-9


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


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


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

previous year’s Mandatory Reporting Regulation verified report. 4

5.2) PG&E's GHG Emissions Recorded During the Record Year From Its 5

Physically-Settled Contracts and/or Tolling Agreements 6

a. Calculations of GHG Emissions: 7

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)

Line Description

1 Direct GHG Emissions (MTCO2e)

2 Utility Owned Generation (UOG) 3 Physically Settled Tolling

Agreements

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.


CHAPTER 12

MAXIMUM POTENTIAL DISALLOWANCE

12-i


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


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.


CHAPTER 13

COST RECOVERY AND REVENUE REQUIREMENT

13-i


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


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

pursuant to Decision (D.) 17-05-013.

13-2

TABLE 13-1 INCREMENTAL DIABLO CANYON SEISMIC STUDIES BALANCING ACCOUNT COSTS

(THOUSANDS OF NOMINAL DOLLARS)

Line No. Revenue Requirements 2017

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).


APPENDIX A

STATEMENTS OF QUALIFICATIONS

DLB-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

Renewables Balancing Account”: 9

Section C, “Green Tariff Shared Renewables Balancing Account.” 10

Q 5 Does this conclude your statement of qualifications? 11

A 5 Yes, it does. 12

CKC-1


STATEMENT OF QUALIFICATIONS OF CANDICE K. CHAN 2


A 1 My name is Candice K. Chan, and my business address is Pacific Gas and 4

Electric Company, 245 Market Street, San Francisco, California. 5


(PG&E). 7

A 2 I am currently the Director of the Energy Contract Management and 8

Settlements section of the Energy Policy and Procurement Department, 9

responsible for managing back office contract management and settlement 10

operations associated with electric and gas procurement. 11


A 3 I earned a Bachelor of Arts degree in Communication Studies, with a 13

specialization in Business Administration from the University of California, 14

Los Angeles, and a Master’s degree in Business Administration from the 15

Haas School of Business at the University of California, Berkeley. In 2002, 16

I joined PG&E as a Manager of Performance Management in the Shared 17

Services organization, responsible for: consulting on financial analysis; 18

reporting; operational performance metrics and management; performance 19

data systems; and performance improvement initiatives. In 2004, I joined 20

PG&E’s Finance Department, leading the business planning function for 21

Shared Services. From 2006-2009, I served as the Program Director and 22

Chief of Staff to the Office of the President and Chief Executive Officer, 23

managing: key operational planning; and governance and communication 24

activities on behalf of the senior executive team. In 2009, I joined the 25

Energy Procurement Department in my current role. 26




Chapter 8, “Contract Administration”; and 30

Chapter 9, “CAISO Settlements and Monitoring.” 31



AD-1


STATEMENT OF QUALIFICATIONS OF ARMANDO DURAN 2


A 1 My name is Armando Duran, and my business address is Pacific Gas and 4



(PG&E). 7

A 2 I am the Accounting Manager in the Energy Accounting Department within 8

the Corporate Accounting organization at PG&E. In this position, I am 9

responsible for overseeing the Direct Greenhouse Gas Expense accounting 10

transactions recorded to the Energy Resource Recovery Account balancing 11

account, as well as various accounting transactions recorded to other 12

applicable balancing accounts as authorized in regulatory cases before the 13

California Public Utilities Commission. 14


A 3 I received my Bachelor of Science degree in Business Administration, 16

emphasis in Accounting, from California State University, Sacramento in 17

1985. I earned a Certified Public Accountant certificate in the state of 18

California in 1990. 19

I joined PG&E in 1986, and have held various positions within Customer 20

Billing, Internal Audit, and the Corporate Accounting Department. I have 21

over 32 years of regulated utility accounting and regulatory experience from 22

having held positions of increasing responsibility at PG&E in the Controller’s 23

organization. 24




Chapter 11, “Summary of Energy Resource Recovery Account Entries 28

for the Record Period.” 29



KAE-1


STATEMENT OF QUALIFICATIONS OF KELLY A. EVERIDGE 2


A 1 My name is Kelly A. Everidge, and my business address is Pacific Gas and 4



(PG&E). 7

A 2 I am the Director of the Strategy and Policy Risk, Compliance and Reporting 8

Department. I am responsible for overseeing cost recovery and regulatory 9

compliance policies, with a focus on California Public Utilities Commission, 10

Federal Energy Regulatory Commission and North American Electric 11

Reliability standards and obligations affecting PG&E’s energy procurement 12

activities. In addition, I am responsible for ensuring the Energy Policy and 13

Procurement organization’s compliance with the Securities and Exchange 14

Commission reporting requirements, Section 404 of the Sarbanes-Oxley 15

Law, all internal audit recommendations, and systems and process 16

improvement. 17


A 3 I joined Energy Policy and Procurement from Business Finance, where 19

I was responsible for managing the business planning function, including 20

budget, forecasting, operational performance analysis, and strategic 21

planning. I joined PG&E in 1997, and have held various roles of increasing 22

scope and responsibility. I spent five years in Energy Policy and 23

Procurement, where I served as Director, Energy Contract Management and 24

Settlements and Chief of Staff, responsible for contract management, 25

settlement, payments, and financial reporting operations associated with 26

electric and gas procurement. Prior to joining Energy Policy, I served in 27

roles within the Risk Management and Finance organizations, and managed 28

front, middle, and back office functions at PG&E's former subsidiary, the 29

National Energy Group. I received a Bachelor of Science degree in Finance 30

from California State University, Sacramento, and a Master’s degree in 31

Business Administration from Golden Gate University, San Francisco. 32

KAE-2



Recovery Account Compliance Review proceeding: 3

Chapter 12, “Maximum Potential Disallowance.” 4


A 5 Yes, it does. 6

FF-1


STATEMENT OF QUALIFICATIONS OF FRANKLIN FUCHS 2


A 1 My name is Franklin Fuchs, and my business address is Pacific Gas and 4

Electric Company, 245 Market Street, San Francisco, California. 5


(PG&E). 7

A 2 I am a Manager in the Demand Response Department within the Customer 8

Care organization at PG&E. In this position, my responsibilities include the 9

overall administration of PG&E’s Demand Response programs, which 10

include the Capacity Bidding Program, Base Interruptible Program, 11

SmartAC™, Optional Binding Mandatory Curtailment Program, and 12

Scheduled Load Reduction Program, and oversight of PG&E’s Demand 13

Response Auction Mechanism. 14


A 3 I have a Bachelor of Arts degree in Environmental Studies from the 16

University of Colorado, a Bachelor of Science degree in Finance from the 17

University of Louisville, and a Masters of Business Administration from the 18

University of Texas. I also am a holder of the right to use the Chartered 19

Financial Analyst® designation. I have approximately 13 years of 20

experience in the energy industry with approximately four years of utility 21

experience. I have held positions in commodity forecasting and analysis, 22

customer account management, marketing and strategy, and the 23

development of PG&E’s Risk Informed Budget Allocation framework. 24




Chapter 1, “Least-Cost Dispatch and Economically-Triggered 28

Demand Response”: 29

Section A, “Introduction”; and 30

Section C, “Economically-Triggered Demand Response Programs.” 31



LGF-1


STATEMENT OF QUALIFICATIONS OF LUCY G. FUKUI 2


A 1 My name is Lucy G. Fukui, and my business address is Pacific Gas and 4



(PG&E). 7

A 2 I am the Manager of Regulatory Analysis and Forecasting in the Energy 8

Accounting Department within the Corporate Accounting organization at 9

PG&E. In this position, I am responsible for overseeing and advising on 10

cost recovery. I am also responsible for leading various reporting activities 11

on the monthly accounting entries made into the Energy Resource Recovery 12

Account balancing account, in compliance with California Public Utilities 13

Commission directives. 14


A 3 I received my Bachelor of Science degree in Business Administration, 16

emphasis in Accounting, with a minor in Computer Science, from the 17

University of San Francisco. I earned a Certified Public Accountant 18

certificate in the state of California in 1990. 19

Prior to joining PG&E in 1991, I was an Auditor with Deloitte and Touche 20

and an Accounting Manager for a small software company. I have over 21

20 years of regulated utility accounting and regulatory experience from 22

having held positions of increasing responsibility at PG&E, in the Controller’s 23

and Regulatory Affairs organizations. 24




Chapter 11, “Summary of Energy Resource Recovery Account Entries 28

for the Record Period”; and 29

Chapter 13, “Cost Recovery and Revenue Requirement.” 30



CDH-1


STATEMENT OF QUALIFICATIONS OF CARY D. HARBOR 2


A 1 My name is Cary D. Harbor, and my business address is Pacific Gas and 4

Electric Company, Diablo Canyon Power Plant. 5


(PG&E). 7

A 2 I am the Director of Nuclear Business Operations for the newly-created 8

Nuclear Line of Business (LOB); in this capacity I am responsible for the 9

Nuclear LOB strategic and integrated planning, General Rate Case 10

activities, Risk Assessment and Mitigation Phase, and matrixed 11

organizations including business finance and supply chain. 12


A 3 I received a Bachelor of Science degree in Nuclear Engineering from 14

University of California, Santa Barbara, in 1989. I joined PG&E in 1989 as a 15

Power Production Engineer in the Engineering Department. I have since 16

held positions as the Supervisor of Regulatory Services, Operations Shift 17

Foreman/Manager (Senior Reactor Operator licensed by the Nuclear 18

Regulatory Commission), Performance Improvement Manager, Quality 19

Verification Director, Nuclear Maintenance and Construction Services 20

Director and the Director of Compliance Alliance and Risk for our nuclear 21

plant operations, and the Director of Generation Compliance, Risk and 22

Business Planning for the Generation LOB. Additionally, I was a witness in 23

PG&E’s 2012, 2013, 2014, 2015, and 2016 Energy Resource Recovery 24

Account Compliance Review proceedings. 25




Chapter 4, “Utility-Owned Generation: Nuclear.” 29



MH-1


STATEMENT OF QUALIFICATIONS OF MOLLY HOYT 2


A 1 My name is Molly Hoyt, and my business address is Pacific Gas and Electric 4

Company, 245 Market Street, San Francisco, California. 5


(PG&E). 7

A 2 I manage the Community Renewables team in the Customer Energy 8

Solutions – Clean Energy Programs organization. In this role, I oversee the 9

development and management of PG&E’s Solar Choice and Regional 10

Renewable Choice programs. 11


A 3 I received a Bachelor of Science degree in Business Administration from 13

San Jose State University and a Master’s degree in Business Administration 14

from the University of Notre Dame. I joined PG&E in 2008 as a Principal 15

Product Manager, and have managed several programs over the years 16

including the ClimateSmart™ Program, the Winter Gas Savings Program, 17

and our Greenhouse Gas Revenue Return Programs. I have served as the 18

product development witness in the Green Tariff Shared Renewables 19

proceeding since 2012, and have testified in front of the California Public 20

Utilities Commission twice in that proceeding. Since 2013, I have served as 21

Chief Executive Officer of the ClimateSmart Charity. Prior to PG&E, 22

I worked in marketing and product management roles in the wireless 23

telecommunications industry for AirTouch International, Openwave Systems 24

Inc., and Vodafone Group Plc. For the three years immediately prior to 25

PG&E, I was a partner in a sustainability consulting firm called Origo Inc. 26

From 2002-2003, I served on the board of the northern California 27

chapter of the Product Development and Management Association. 28




MH-2

Chapter 10, “Review Entries Recorded in the Green Tariff Shared 1

Renewables Memorandum Account and The Green Tariff Shared 2

Renewables Balancing Account”: 3

Section B, “Green Tariff Shared Renewables Memorandum 4

Account.” 5


A 5 Yes, it does. 7

FI-1


STATEMENT OF QUALIFICATIONS OF FELIPE IBARRA 2


A 1 My name is Felipe Ibarra, and my business address is Pacific Gas and 4



(PG&E). 7

A 2 I am a Principal Gas Trader in PG&E’s Electric Gas Supply Department, 8

which is part of the Energy Policy and Procurement Department. I am 9

responsible for trading natural gas associated with PG&E’s electric portfolio. 10


A 3 I earned a Bachelor of Science degree in Mathematics from San Jose State 12

University in 2003. From 2007 to present, I have been employed by PG&E 13

in various positions, including Financial Analyst in Risk Management, 14

Analyst Electric Fuels, and currently Principal Gas Trader in the Electric 15

Fuels Department. 16




Chapter 6, “Generation Fuel Costs and Electric Portfolio Hedging”: 20

– Section B, “Gas Procurement.” 21

– Attachment A, “Letter from Ruby Pipeline Officer Certifying PG&E's 22

“Most Favored Nations” (Lowest Rate) Status”; and 23

– Attachment B, “Generation Fuel Costs,” Tables 6B-1, 6B-2, 24

and 6B-3. 25



MK-1


STATEMENT OF QUALIFICATIONS OF MICHAEL KOWALEWSKI 2


A 1 My name is Michael Kowalewski, and my business address is Pacific Gas 4

and Electric Company, 77 Beale Street, San Francisco, California. 5


(PG&E). 7

A 2 I am a Portfolio Manager in the Electric Gas Supply Department, which is 8

part of the Energy Policy and Procurement Department. I am responsible 9

for managing the financial gas position of PG&E’s electric portfolio. 10


A 3 I earned a Bachelor of Arts degree in Economics from the University of 12

California, Berkeley, in 1992. From 1992 to present, I have been employed 13

by PG&E in various positions including Manager of PG&E’s Electric Portfolio 14

Gas Trading Operations, Renewable Energy Transactor, Gas Trader, 15

Product Manager, Project Manager, and Financial and Regulatory Analyst. 16





Section H, “Electric Portfolio Hedging”; and 21

Section I, “Internal Procedures and Controls.” 22

Attachment B, “Generation Fuel Costs,” Tables 6B-7, 6B-8, 6B-9, 23

6B-10, 6B-11 and Figures 6B-1 and 6B-2. 24



VKL-1


STATEMENT OF QUALIFICATIONS OF VINCENT K. LOH 2


A 1 My name is Vincent K. Loh, and my business address is Pacific Gas and 4



(PG&E). 7

A 2 I am a Senior Manager in the Portfolio Management group in the Energy 8

Policy and Procurement organization and am responsible for leading 9

commercial greenhouse gas policy and strategy. 10


A 3 I received my Bachelor of Science degree in Computer Engineering from 12

Boston University. I hold Master’s degrees in Computer Engineering from 13

Boston University, and in Business Administration from University of 14

California, Berkeley, Haas School of Business. I have worked at: 15

Massachusetts Institute of Technology, as a Research Specialist; Fidelity 16

Investments, as a Quantitative Analyst; Morgan Stanley, as a Commodity 17

Trader; PG&E Energy Services, as a Risk Management Specialist; and as a 18

Product Manager for Charles Schwab & Co, Inc. and OpenLink Financial. 19

In 2003, I joined PG&E in the Energy Procurement Department where 20

I held positions in Short-Term Strategy and Portfolio Management to 21

manage the energy, resource adequacy, hedging, and congestion revenue 22

rights portfolios. In 2012, I joined the Market and Credit Risk Department to 23

oversee implementation of PG&E’s risk policies. I re-joined Portfolio 24

Management as the Senior Manager in 2014 to lead commercial policy, 25

planning, compliance, and commodity procurement. 26




Chapter 7, “Greenhouse Gas Compliance Instrument Procurement.” 30



MM-1


STATEMENT OF QUALIFICATIONS OF MARK MAYER 2


A 1 My name is Mark Mayer, and my business address is Pacific Gas and 4

Electric Company, Diablo Canyon Power Plant. 5


(PG&E). 7

A 2 I am a Manager in the Nuclear Fuels Purchasing group for Diablo Canyon 8

Power Plant (Diablo Canyon). I am responsible for contracts associated 9

with the fabrication of nuclear fuel for Diablo Canyon and the purchase of 10

feed materials (uranium, conversion services, and enrichment services). 11


A 3 I received a Bachelor of Science degree in Nuclear Engineering from the 13

Massachusetts Institute of Technology. I have worked for PG&E at 14

Diablo Canyon for over 30 years, primarily in engineering. My previous 15

engineering responsibilities have included reactor engineering and system 16

and transient analysis. I am a registered Professional Engineer in the state 17

of California. 18





Section E, “Nuclear Fuel Expenses”; and 23

Section F, “Nuclear Fuel Carrying Costs.” 24

Attachment B, “Generation Fuel Costs,” Tables 6B-4, 6B-5, 25

and 6B-6. 26



SPN-1


STATEMENT OF QUALIFICATIONS OF STUART P. NISHENKO2

Q 1 Please state your name and business address.3

A 1 My name is Stuart P. Nishenko, and my business address is Pacific Gas 4

and Electric Company, 245 Market Street, San Francisco, California.5


(PG&E).7

A 2 I am a Principal Seismologist/Geophysicist in the PG&E Geosciences 8

Department. I serve as the Technical Manager of the Central Coastal 9

California Seismic Imaging Project (CCCSIP) and the Long-Term Seismic 10

Program (LTSP). I report directly to the Director of the PG&E Geosciences 11

Department.12

Q 3 Please summarize your educational and professional background.13

A 3 I received a Bachelor of Science degree in Geology from the City College of 14

New York, and Master of Arts and Doctor of Philosophy degrees in 15

Seismology and Geophysics from Columbia University. I have more than 16

30 years post-graduate experience with expertise in seismology, 17

geophysics, seismisc hazards assessment and emergency management.18

As Technical Manager of the CCCSIP and LTSP, I am responsible for 19

the planning, execution, and analysis of all seismic and geophysical data 20

related to the project. I will testify about CCCSIP earthquake monitoring 21

offshore Diablo Canyon Power Plant and other LTSP activities.22

Q 4 What is the purpose of your testimony?23


Recovery Account Compliance Review proceeding:25

Chapter 5, “Costs Incurred and Recorded in the Diablo Canyon Seismic 26

Studies Balancing Account.”27

Q 5 Does this conclude your statement of qualifications?28

A 5 Yes, it does.29

YP-1


STATEMENT OF QUALIFICATIONS OF YANEE PONGSUPAPIPAT2


A 1 My name is Yanee Pongsupapipat, and my business address is Pacific Gas 4

and Electric Company, 77 Beale Street, San Francisco, California.5


(PG&E).7

A 2 I am an Accounting Supervisor and am responsible for overseeing 8

accounting for PG&E and its subsidiaries. I also serve as Chief Financial 9

Officer of Fuelco, LLC, and represent PG&E as a member of the Strategic 10

Teaming and Resource Sharing (STARS) finance team.11


A 3 I received a Master’s degree in Business Administration, with an emphasis 13

in Accounting, from California State University, East Bay. I joined PG&E in 14

2013 as a Senior Accounting Analyst in the Controller Department. Over the 15

past three years, I have held several roles of increasing responsibility in the 16

Controller Department. I assumed my current position in 2014.17




Chapter 6, “Generation Fuel Costs and Electric Portfolio Hedging”:21

Section G, “STARS Alliance.”22

Attachment C, “Annual Report of Utility on the Activities of Stars 23

Alliance, LLC.; Utility Savings/Avoided Costs by Stars Team/Project;24

and Independent Auditor’s Report and Financial Statements.25


A 5 Yes, it does.27

SR-1


STATEMENT OF QUALIFICATIONS OF STEVE ROYALL2


A 1 My name is Steve Royall, and my business address is Pacific Gas and 4

Electric Company, 245 Market Street, San Francisco, California.5


(PG&E).7

A 2 I am a Director in the Power Generation Department.8


A 3 I joined PG&E in 2007 as Director in the Generation Department, 10

responsible for managing the Gateway Generating Station. Prior to PG&E, 11

I worked at Northern California Power Agency, where I was the Assistant 12

General Manager of power generation and the Manager of gas-fired 13

generation. I have more than 37 years of experience working in power 14

generation projects in the areas of operation, engineering, construction, and 15

commissioning. I have been involved in projects that resulted in 16

approximately 3,500 megawatts of new generation in California and 17

Washington over the last 37 years, including PG&E’s new Gateway 18

Generating Station, and Colusa Generating Station. Other former 19

employers include Calpine Corporation, Phillips Oil Company and 20

Freeport-McMoRan Corporation. I am also the Co-Chair of both the: 21

Electric Utility Cost Group – Fossil committee; and the Combined Cycle 22

Users Group, assuming Chairmanship in Fourth Quarter 2015. I was a 23

witness in PG&E’s 2014 and 2015 Energy Resource Recovery Account 24

Compliance Review proceeding.25




Chapter 3, “Utility-Owned Generation: Fossil and Other Generation.”29


A 5 Yes, it does.31

AJS-1


STATEMENT OF QUALIFICATIONS OF ALVA J. SVOBODA2


A 1 My name is Alva J. Svoboda, and my business address is Pacific Gas and 4

Electric Company, 77 Beale Street, San Francisco, California.5


(PG&E).7

A 2 I am Manager of Market Design Integration in the Short-Term Electric 8

Supply Department of the Energy Portfolio Commercial Operations9

organization at PG&E. I am responsible for supporting the optimization of 10

short-term operations.11


A 3 I earned a Bachelor of Arts degree in Mathematics from University of 13

California, Santa Barbara in 1980; a Master of Science degree in Operations 14

Research from University of California, Berkeley in 1984; and a Doctorate in 15

Operations Research from University of California, Berkeley in 1992. 16

I joined PG&E in 1997 and have worked in Short-Term Electric Supply from 17

that time to the present.18




Chapter 1, “Least-Cost Dispatch and Economically-Triggered Demand 22

Response”:23

– Section A; “Introduction”;24

– Section B, “Least-Cost Dispatch”; and25

– Section D, “Conclusion.”26


A 5 Yes, it does.28

ALT-1


STATEMENT OF QUALIFICATIONS OF ALVIN L. THOMA2


A 1 My name is Alvin L. Thoma, and my business address is Pacific Gas and 4

Electric Company, 245 Market Street, San Francisco, California.5


(PG&E).7

A 2 I am the Director for Operations and Maintenance of PG&E’s generation 8

facilities in the southern portion of our system in PG&E’s Power Generation 9

organization. During the first half of the record period, I was the Director of 10

Fossil and Solar Operations and Maintenance, and in the second half of the 11

record period I was Director for Hydro Operations and Maintenance.12


A 3 I earned a Bachelor of Engineering degree in Chemical Engineering from 14

Vanderbilt University in 1979. I am a Registered Chemical Engineer in the 15

state of California. I joined PG&E in 1979 as an Engineer in the Department 16

of Engineering Research. From 1979-1989, I held a variety of research, 17

engineering design, project management and operations positions 18

supporting PG&E’s geothermal facilities. From 1989-1995, I led project 19

management and outage management groups supporting PG&E’s fossil 20

power plants. From 1995-2000, I led the project management activities at 21

PG&E Energy Services. I continued in this capacity when PG&E Energy 22

Services was sold and became Chevron Energy Solutions. In 2006, 23

I returned to PG&E as Manager of Project Management in Power 24

Generation, and was promoted to Director of the Projects, Engineering, and 25

Construction section of PG&E’s Power Generation Department in 2007. 26

In 2009, I took on the role of Director of Hydro Operations and Maintenance. 27

In 2012, I became the Director of Hydro Licensing. In 2015, I became 28

Director of Fossil and Solar Operations and Maintenance. I was a witness in 29

PG&E’s 2012 and 2016 Energy Resource Recovery Account Compliance 30

Review proceedings.31

ALT-2




Chapter 2, “Utility-Owned Generation: Hydroelectric”:4

– Attachment A, “PG&E Powerhouses and Generating Units.”5

Chapter 6, “Generation Fuel Costs and Electric Portfolio Hedging”:6

– Section C, “Distillate Expenses”; and7

– Section D, “Water Purchased for Power.”8


A 5 Yes, it does.10