195397070
Docket: Exhibit Number Commissioner Admin. Law Judge ORA Analyst
: : : : : :
A.17-04-004 ORA-1 M. Aceves Eric Wildgrube Radu Ciupagea
OFFICE OF RATEPAYER ADVOCATES CALIFORNIA PUBLIC UTILITIES COMMISSION
REPORT ON SOUTHERN CALIFORNIA EDISON’S ENERGY RESOURCE RECOVERY
ACCOUNT COMPLIANCE APPLICATION FOR RECORD PERIOD 2016
A.17-04-004
(PUBLIC)
San Francisco, California September 15, 2017
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TABLE OF CONTENTS
PAGE
MEMORANDUM ................................................................................................... 1
CHAPTER 1: INTRODUCTION ...................................................................... 1-1
I. EXECUTIVE SUMMARY ...................................................................... 1-1
II. SUMMARY OF OBSERVATIONS AND
RECOMMENDATIONS ......................................................................... 1-2
CHAPTER 2: LEAST-COST DISPATCH AND DEMAND
RESPONSE PROGRAMS ....................................................................... 2-1
I. INTRODUCTION AND SUMMARY .................................................... 2-1
II. RECOMMENDATIONS ......................................................................... 2-1
A. El Segundo ...................................................................................... 2-1
B. Eastwood Pumped Hydro ............................................................. 2-1
C. Forecast Accuracy ......................................................................... 2-2
D. Renewable Curtailment ................................................................ 2-2
E. Commitment Cost Cap Calculation ............................................. 2-2
F. Incremental Non-Dispatch ........................................................... 2-3
G. Demand Response .......................................................................... 2-3
III. BACKGROUND ....................................................................................... 2-3
A. Least-cost Dispatch Standards ..................................................... 2-3
IV. DISCUSSION AND ANALYSIS ............................................................. 2-4
A. Forecast Accuracy: Price and Load ............................................ 2-4
B. SCE’s Bidding Strategy ................................................................ 2-8
1. Self-Scheduling Activity ..................................................... 2-9
2. Incremental Bid Cost Calculations ................................... 2-9
3. Commitment Cost Calculation Errors ........................... 2-10
4. Bidding Error - El Segundo ............................................ 2-13
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5. Incremental Non-Dispatch .............................................. 2-15
C. Hydro Management .................................................................... 2-17
1. Pumped Hydro .................................................................. 2-18
D. Dispatchable Renewables Management .................................... 2-21
E. Demand Response Management ................................................ 2-22
1. Bid Calculation and Dispatches and
Dispatch Strategy ............................................................. 2-23
i. Aggregator Managed Portfolios .......................... 2-23
ii. Capacity Bidding Program .................................. 2-24
iii. Summer Discount Plan ......................................... 2-25
2. ORA Assessment of Demand Response
Administration .................................................................. 2-26
V. CONCLUSION ....................................................................................... 2-26
CHAPTER 3: UTILITY-OWNED GENERATION –
HYDROELECTRIC ................................................................................ 3-1
I. INTRODUCTION AND RECOMMENDATIONS ............................... 3-1
II. GENERATION FACILITIES ................................................................. 3-1
III. OUTAGES ................................................................................................. 3-3
A. Big Creek 3, Unit 3 Outage – March 31, 2016 ............................ 3-4
IV. CONCLUSIONS AND RECOMMENDATIONS ............................... 3-10
CHAPTER 4: UTILITY-OWNED GENERATION – NATURAL GAS ....... 4-1
I. INTRODUCTION AND RECOMMENDATIONS ............................... 4-1
II. GENERATION FACILITIES ................................................................. 4-1
A. SCE Peaker Facilities .................................................................... 4-1
1. Barre Peaker ....................................................................... 4-3
2. Center Peaker ..................................................................... 4-3
3. Grapeland Peaker .............................................................. 4-3
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4. McGrath Peaker ................................................................. 4-3
5. Mira Loma Peaker ............................................................. 4-4
B. Mountainview Generating Station ............................................... 4-4
III. OUTAGES ................................................................................................. 4-6
A. Grapeland Peaker Outage – October 20, 2016 ........................... 4-6
IV. CONCLUSIONS AND RECOMMENDATIONS ............................... 4-11
CHAPTER 5: UTILITY-OWNED GENERATION - NUCLEAR ................. 5-1
I. SUMMARY AND RECOMMENDATIONS ......................................... 5-1
II. DISCUSSION AND ANALYSIS ............................................................. 5-1
III. OUTAGES ................................................................................................. 5-5
A. Unit 1 Outage – September 7, 2016 ............................................. 5-5
1. Corrective Actions .............................................................. 5-8
2. Cost of Outage .................................................................... 5-9
IV. CONCLUSIONS AND RECOMMENDATIONS ............................... 5-10
CHAPTER 6: CONTRACT ADMINISTRATION .......................................... 6-1
I. INTRODUCTION .................................................................................... 6-1
II. RECOMMENDATIONS ......................................................................... 6-1
III. BACKGROUND ....................................................................................... 6-1
IV. DISCUSSION AND ANALYSIS ............................................................. 6-3
A. New Contracts ................................................................................ 6-3
1. Conventional and Natural Gas ......................................... 6-3
2. PURPA and CHP ............................................................... 6-3
3. RPS ...................................................................................... 6-4
4. Behind-the-Meter ............................................................... 6-4
B. Contract Assignment Administration ......................................... 6-4
C. Contract Amendments or Modifications ..................................... 6-4
1. Amendments to Facilitate Contractual Transition ......... 6-5
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2. Amendments for Behind-the-Meter Contracts ............... 6-7
3. Amendments Causing a Change in Value ........................ 6-7
i. Heber Geothermal Company LLC Amendment 5, 52MW Geothermal ....................... 6-8
ii. Central Antelope Dry Ranch C Amendment 3, 20MW Solar PV ................................................... 6-9
iii. North Lancaster Ranch Amendment 3, 20MW Solar PV ....................................................... 6-9
iv. Longboat Solar Amendment 1, 20MW Solar PV ................................................................... 6-9
v. Coso Clean Power Amendment 6, 136MW Geothermal .............................................. 6-10
vi. Geysers Power Company Letter Agreement .............................................................. 6-10
vii. Regulus Solar Amendment 5, 60 MW Solar ............................................................... 6-11
viii. Caithness Shepherds Flat Contracts Amendment 2, 845 MW Wind ............................. 6-11
ix. Voyager Wind I Amendment 1, 132 MW Wind ....................................................... 6-11
D. Contract Terminations................................................................ 6-12
E. Discrepancies, Payment Issues, Force Majeure, and
Disputes ........................................................................................ 6-12
1. Force Majeure (Uncontrollable Force) Claims ............. 6-12
2. Disputes ............................................................................. 6-12
V. CONCLUSION ....................................................................................... 6-14
CHAPTER 7: COMPLIANCE AUDIT OF THE ENERGY
RESOURCE RECOVERY ACCOUNT (ERRA) AND OTHER
BALANCING AND MEMORANDUM ACCOUNTS .......................... 7-1
I. INTRODUCTION AND SUMMARY .................................................... 7-1
II. DISCUSSION ............................................................................................ 7-1
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A. Energy Resource Recovery Account (ERRA) ............................ 7-1
B. Regulatory Balancing, Memorandum, and Tracking
Accounts ......................................................................................... 7-3
C. Requested 2018 Revenue Requirement Change ......................... 7-6
III. AUDIT OBJECTIVES, SCOPE AND PROCEDURES ........................ 7-7
IV. CONCLUSIONS AND RECOMMENDATIONS ................................. 7-9
CHAPTER 8: GREENHOUSE GAS COMPLIANCE .................................... 8-1
I. SUMMARY ............................................................................................... 8-1
II. BACKGROUND ....................................................................................... 8-2
A. California Air Resources Board Cap-and-Trade Program ...... 8-2
B. Commission Decisions ................................................................... 8-4
1. Procurement of GHG Compliance Instruments ............. 8-4
2. GHG Emissions .................................................................. 8-5
3. GHG Emissions Costs ........................................................ 8-7
i. Direct GHG Costs ................................................... 8-8
ii. Indirect GHG Costs: ............................................... 8-9
III. DISCUSSION ............................................................................................ 8-9
A. SCE’s Compliance Instrument Procurement for the 2016 Record Period is within the Procurement Limit Established in its BPP ................................................................... 8-9
B. SCE Procured GHG Compliance Instruments in the 2016 Record Period in Accordance with the Restrictions Established in its BPP on Where and How a Utility Can Procure GHG Compliance Instruments ................................... 8-10
C. SCE’s calculation of the WAC for GHG emissions from electric generation resources complies with Attachment C of D.15-01-024 .............................................................................. 8-10
D. The costs and revenues reported related to compliance with the ARB Cap-and-Trade program are in accordance with Template D of D.15-01-024 ................................................ 8-11
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E. ORA Does Not Object to SCE’s GHG Compliance Strategy for Record Period 2016 ................................................ 8-12
1. SCE Adequately Supported its Recorded Direct Emissions and Costs for the 2016 Record Period .......... 8-12
2. SCE’s 2016 Record Period Compliance Instrument Procurements Appear to Be Reasonable and Not Detrimental to Ratepayers............................................... 8-13
IV. CONCLUSION ....................................................................................... 8-15
APPENDIX A: WITNESS QUALIFICATIONS
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MEMORANDUM 1
This report was prepared by the Office of Ratepayer Advocates (ORA) of the 2
California Public Utilities Commission (CPUC or Commission) on Southern California 3
Edison’s (SCE) Energy Resource Recovery Account (ERRA) Compliance Application 4
for the 2016 Record Period. In this docket, SCE’s Application requests a Commission 5
finding that: (1) its fuel and purchased power expenses complied with SCE’s 6
Commission-approved procurement plan and were recorded accurately; (2) its contract 7
administration, management of utility-retained generation (URG), dispatch of generation 8
resources, and related spot market transactions complied with Standard of Conduct Four 9
(SOC 4)1 in SCE’s procurement plan; and (3) all other SCE activities subject to 10
Commission review in this ERRA proceeding complied with applicable Commission 11
decisions and resolutions.2 12
ORA presents its analysis and recommendations associated with SCE’s 13
request. ORA reviewed SCE’s testimony, work papers, responses to data requests, and 14
presentations. It also had several in-person meetings and follow up telephone 15
conversations with SCE staff regarding its testimony, work papers, responses and 16
presentations. 17
ORA’s witnesses’ prepared qualifications are contained in Appendix A of this 18
report. 19
The issues that ORA reviewed are listed below and summarized in Chapter 1. 20
1 See D.02-10-062 at p. 52 (Oct. 24, 2002) [hereinafter “October Decision”] (defining the Standards of Conduct applicable to ERRA). 2 Application of Southern California Edison Company (U338E) for a Commission Finding that its Procurement-Related and Other Operations for the Record Period January 1 Through December 31, 2016 Complied with its Adopted Procurement Plan; for Verification of its Entries in the Energy Resource Recovery Account and Other Regulatory Accounts; for Refund of $3.605 million Recorded in Three Accounts; and Review of Proposal to Return $79.182 million in Unspent Demand Response Funds to Customers at p. 2 (Apr. 3, 2017) (Application (A.) 17-04-004) [hereinafter “SCE’s Application”].
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List of ORA Witnesses and Respective Chapters
Chapter Number
Description Witness
1 Introduction Radu Ciupagea
2 Least Cost Dispatch and Demand
Response Programs Patrick
Cunningham
3 Utility-Owned Generation -
Hydroelectric Michael Yeo
4 Utility-Owned Generation – Natural
Gas Michael Yeo
5 Utility-Owned Generation – Nuclear Michael Yeo
6 Contract Administration and Costs Patrick
Cunningham
7 Balancing and Memorandum
Accounts Brian Lui and Grant Novack
8 Greenhouse-Gas Compliance Tom Gariffo
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CHAPTER 1: INTRODUCTION 1
(Radu Ciupagea) 2
I. EXECUTIVE SUMMARY 3
This testimony contains the results of the Office of Ratepayers Advocates’ 4
(ORA’s) review of Southern California Edison’s (SCE) Energy Resource Recovery 5
Account (ERRA) compliance application for the period from January 1, 2016 to 6
December 31, 2016 (Record Period). SCE filed this application pursuant to Decision (D.) 7
02-10-062, in which the Commission required certain utility procurement activities to be 8
reviewed annually in an ERRA proceeding. 9
According to the Commission the purpose of the ERRA annual review, in general, 10
is to: 11
(1) review whether SCE’s energy procurement activities were 12
consistent with the least cost dispatch principles set forth 13 in Standard of Conduct 4 (SOC 4); 3 14
(2) determine whether SCE accurately recorded procurement 15 expenses that are eligible to be recovered through the 16 ERRA balancing account; 17
(3) review entries in the ERRA balancing account to ensure 18 such entries are accurate and consistent with Commission 19 decisions; and 20
(4) determine whether SCE prudently administered its 21 Qualifying Facilities (QF) contracts and non-QF contracts, 22 and whether the operation of its utility-owned generation 23 units, including maintenance outages, was reasonable.4 24
SCE filed its application on April 3, 2017, requesting Commission approval of 25
activities that occurred during the 2016 Record Period. ORA’s review of SCE’s 26
application is predominantly focused on the 2016 Record Period and includes: least-cost 27
dispatch (LCD) of electric generation resources, including demand response, utility 28
3 D.02-10-062 at p. 52 (Oct. 24, 2002) (“[U]tilities shall prudently administer all contracts and generation resources and dispatch the energy in a least-cost manner.”) 4 D.11-10-002 at p. 3 of Appendix.
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owned generation (UOG) hydroelectric operations, UOG natural gas, solar photovoltaic 1
program (SPVP), fuel expenses and operations of nuclear generation resources, contract 2
administration,5 greenhouse-gas compliance, and an audit of the balancing account 3
entries. In addition, ORA reviewed non-ERRA issues summarized below. 4
In this application, SCE requests review of the revenue collected [$3.692 billion] 5
and procurement expenses [$4.107 billion] in the ERRA account as of 6
December 31, 2016. SCE’s Application requests approval to refund to customers 7
approximately $83.748 million due to a net over-collection in the following three 8
Commission-authorized regulatory Memorandum Accounts: 9
i) Renewables Portfolio Standard Costs Memorandum 10 Account; 11
ii) Project Development Division Memorandum Account; 12
iii) Purchase Agreement Administrative Costs Balancing 13 Account; and 14
iv) Demand Response Program Balancing Account (unspent 15 and uncommitted funds). 16
The scope of ORA’s review in this proceeding included ERRA and Non-ERRA 17
accounts, as well as audits of the various account entries. 18
II. SUMMARY OF OBSERVATIONS AND RECOMMENDATIONS 19
The following is a summary of the observations and recommendations ORA 20
witnesses describe in subsequent chapters: 21
Chapter 2: Least Cost Dispatch and Demand Response Programs - (Patrick 22
Cunningham) 23
EL SEGUNDO 24
ORA recommends that the Commission disallow the full cost of the startup 25
cost data entry error at El Segundo of $158,777. ORA also recommends 26
5 Contract administration includes a review of Department of Water Resources (DWR) contracts, existing QF contracts, Combined Heat and Power (CHP) contracts, inter-utility contracts, conventional energy and natural gas contracts, and renewable contracts. ORA also reviewed contract administration for Demand Response Aggregator Managed Portfolio (AMP) agreements.
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that the Commission direct SCE to contact Power Costs Inc. to explore the 1
possibility of updating the bidding software in order to prevent completion 2
of a calculation when a parameter has been omitted. 3
EASTWOOD PUMPED HYDRO 4
ORA recommends that the Commission order SCE to demonstrate in future 5
ERRA compliance filings that the utility maximized market revenues from 6
pump-back operations, consistent with SOC4. 7
FORECAST ACCURACY 8
ORA recommends that the Commission order SCE to provide a 9
supplemental narrative to its workpapers in future ERRA compliance 10
applications summarizing the data presented in worksheets, indicating what 11
SCE considers “normal” or “accurate” in regards to forecast accuracy, and 12
interpreting its performance for the Record Period. 13
RENEWABLE CURTAILMENT 14
ORA recommends that the Commission order SCE to include in its future 15
ERRA compliance testimony reporting and quantitative calculations of any 16
renewable resource opportunity costs by technology. 17
The Commission should also order SCE to include in its future ERRA 18
compliance testimony explanations of energy curtailment, such as instances 19
when it is necessary, how the economic decision to curtail a resource is 20
made, the business process for curtailing a resource, and any associated 21
quantitative metrics. 22
COMMITMENT COST CAP CALCULATION 23
ORA recommends that the Commission disallow the cost impact 24
resulting from SCE’s commitment cost cap calculation errors in the 2016 25
Record Period. 26
INCREMENTAL NON-DISPATCH 27
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D.15-05-007 in part concerns the reporting of instances in which the 1
Locational Marginal Price (LMP) of energy is above the incremental 2
economic bid of a resource but no incremental dispatch occurs. SCE 3
reported the number of occurrences, but did not explain them nor describe 4
any follow up action as required. An explanation for why no incremental 5
energy is awarded allows the Commission to determine if LCD was 6
achieved. SCE failed to explain these occasions of sub-optimal dispatch in 7
both the 2016 and 2015 Record Periods. The Commission should order 8
SCE to comply with the decision by including such data in future ERRA 9
applications in order to demonstrate its compliance with LCD standards. 10
DEMAND RESPONSE 11
D.15-05-007 requires SCE to supply metrics and an explanation for times 12
when DR resources met tariff conditions but were not dispatched. SCE 13
must comply with this decision by including such data and a brief 14
explanation for each occurrence in its ERRA compliance applications. The 15
decision also requires that the opportunity cost methodology be explained 16
and demonstrated. The Commission should order SCE to comply with this 17
decision by supplying the bid cost for its Capacity Bidding Program which 18
is based on opportunity costs. SCE currently does not record this data and 19
was thus unable to supply it during ORA’s discovery process. 20
Chapter 3: Utility-Owned Generation – Hydroelectric - (Michael Yeo) 21
Based on ORA’s review of SCE’s March 31 to May 5, 2017 forced outage at Big 22
Creek Unit 3, ORA agrees with the implementation of the corrective actions listed in the 23
Root Cause Evaluation (RCE) Report. ORA also agrees that there was no lost generation 24
for Unit 3 due to drought conditions. 25
Chapter 4: Utility-Owned Generation – Natural Gas - (Michael Yeo) 26
ORA agrees with the implementation of the corrective actions indicated by SCE 27
for the Grapeland Peaker outage on October 20, 2016. 28
Chapter 5: Utility-Owned Generation – Nuclear - (Michael Yeo) 29
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ORA recommends the Commission order SCE to: 1
submit supplemental testimony in November 2017 when the Nuclear 2
Regulatory Commission (NRC) issues its report on the Unit 1 outage. ORA 3
reserves the right to recommend disallowances based on the NRC Report; 4
include NRC reports and correspondences as part of its annual ERRA 5
compliance filings; 6
and order SCE to confer with Arizona Public Service (APS) to: 7
replace the broken sprinkler head; 8
establish an inspection and periodic replacement program to ensure the 9
integrity of safety-related equipment, subject to cost-effectiveness analyses; 10
protect all sensitive electrical equipment from possible water-related hard 11
ground faults whenever the sprinkler system is tested; 12
implement the corrective actions in APS’s RCE Report, subject to cost-13
effectiveness analyses; 14
seek NRC concurrence if APS chooses not to implement some of the corrective 15
actions; and 16
report its compliance on the implementation and effectiveness of all the 17
aforementioned corrective actions in its future annual ERRA Compliance 18
filings. 19
Chapter 6: Contract Administration and Costs - (Patrick Cunningham) 20
ORA does not object to SCE’s administration of its contracts for Record Period 21
2016. 22
Chapter 7: Balancing and Memorandum Accounts - (Brian Lui and Grant Novack) 23
ORA found that SCE appropriately operated the balancing, memorandum, and 24
tracking accounts during the 2016 Record Period, and that the recorded entries in these 25
accounts were appropriate, correctly stated, and in compliance with applicable 26
Commission decisions. 27
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ORA concludes that SCE’s requested total net revenue change (decrease of 1
$83.748 million) in 2018 as shown in ORA Table 7-3, which pertains to the recorded 2
costs and revenues of four accounts, is supported and correctly stated. ORA does not 3
object to SCE’s request for approval of the $83.748 million net revenue requirement 4
decrease. 5
Chapter 8: Greenhouse-Gas (GHG) Compliance - (Tom Gariffo) 6
Overall, ORA does not object to SCE’s request that the Commission find its GHG 7
procurement activity for the 2016 Record Period reasonable and within its procurement 8
authority. ORA finds SCE’s GHG emissions compliance activity and reporting deficient 9
in one respect, and offers the following recommendation: 10
11
12
13
14
15
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CHAPTER 2: LEAST-COST DISPATCH AND 1 DEMAND RESPONSE PROGRAMS 2
(Patrick Cunningham) 3
I. INTRODUCTION AND SUMMARY 4
This chapter reviews Southern California Edison Company’s (SCE) energy 5
bidding and demand response (DR) activities for the 2016 Record Period between 6
January 1, 2016 and December 31, 2016 and assesses whether SCE met the California 7
Public Utilities Commission’s (Commission) least-cost dispatch (LCD) standard. 8
Analysis conducted by the Office of Ratepayer Advocates (ORA) included extensive 9
review of the full application and testimony of the 2016 SCE Energy Resource Recovery 10
Account (ERRA) Compliance application (A.17-04-004). ORA’s analysis included data 11
requests, meeting with witnesses, and review of past ERRA testimony and relevant 12
Commission decisions. Review compared SCE’s performance and conduct against the 13
Commission’s LCD standard to determine if operations were in accordance with the 14
Commission’s Standard of Conduct 4 (SOC4). 15
II. RECOMMENDATIONS 16
A. El Segundo 17
ORA recommends that the Commission disallow the full cost of the startup cost 18
data entry error at El Segundo of $158,777. ORA also recommends that the Commission 19
direct SCE to contact Power Costs Inc. to explore the possibility of updating the bidding 20
software in order to prevent completion of a calculation when a parameter has been 21
omitted. 22
B. Eastwood Pumped Hydro 23
ORA recommends that the Commission order SCE to demonstrate in future ERRA 24
Compliance filings that the utility maximized market revenues from pump-back 25
operations, consistent with SOC4. This demonstration should describe when operational 26
and regulatory constraints made pump-back operations impossible or sub-optimal. The 27
demonstration should also include an explanation of when pump-back operations were 28
possible and cost-efficient, but no pump-back occurred. These inclusions in future 29
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applications will help the utility meet its requirements to demonstrate compliance with 1
LCD standards. 2
C. Forecast Accuracy 3
ORA recommends that the Commission order SCE to provide a supplemental 4
narrative to its workpapers in future ERRA Compliance applications summarizing the 5
data presented in worksheets, indicating what SCE considers “normal” or “accurate” in 6
regards to forecast accuracy, and interpreting its performance for the Record Period. 7
D. Renewable Curtailment 8
ORA recommends that the Commission order SCE to include in its future ERRA 9
Compliance testimony reporting and quantitative calculations of any renewable resource 10
opportunity costs by technology. The Commission should also order SCE to include in its 11
future ERRA Compliance testimony explanations of any energy curtailment, such as 12
instances when it is necessary, how the economic decision to curtail a resource is made, 13
the business process for curtailing a resource, and any associated quantitative metrics. 14
This increased reporting is necessary for SCE to demonstrate that it maintained the most 15
cost-effective mix of resources for which it bears the burden of proving compliance.6 16
E. Commitment Cost Cap Calculation 17
ORA recommends that the Commission disallow the cost impact resulting 18
from SCE’s commitment cost cap calculation errors in the 2016 Record Period. SCE 19
miscalculated its commitment cost cap calculation which prevented accurate least-cost 20
dispatch from 2012 through early 2016. SCE has not sufficiently explained how the error 21
occurred and has failed to establish that the utility acted prudently when the error 22
occurred. SCE has also admitted that the value was not reviewed following entry in 2012 23
and was never intended to be reviewed.7 ORA has already recommended a disallowance 24
for previous Record Periods in its 2015 ERRA Compliance testimony.8 25
6 D.02-12-074, Ordering Paragraph 24. 7 A.16-04-001, Opening Brief of Southern California Edison Company at p. 5-7. 8 A.16-04-001, See Attachment 2.9.
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F. Incremental Non-Dispatch 1
D.15-05-007 in part concerns the reporting of instances in which the Locational 2
Marginal Price (LMP) of energy is above the incremental economic bid of a resource but 3
no incremental dispatch occurs.9 SCE reported the number of occurrences, but did not 4
explain them nor describe any follow up action as required. An explanation for why no 5
incremental energy is awarded allows the Commission to determine if LCD was 6
achieved. SCE failed to explain these occasions of sub-optimal dispatch in both the 2016 7
and 2015 Record Periods.10 SCE must comply with the decision by including such data 8
in future ERRA applications in order to demonstrate its compliance with LCD standards. 9
G. Demand Response 10
D.15-05-007 requires SCE to supply metrics and an explanation for times when 11
DR resources met tariff conditions but were not dispatched. SCE must comply with this 12
decision by including such data and a brief explanation for each occurrence in its ERRA 13
Compliance applications. The decision also requires that the opportunity cost 14
methodology be explained and demonstrated. SCE must comply with this decision by 15
supplying the bid cost for its Capacity Bidding Program which is based on opportunity 16
costs. SCE currently does not record this data and was thus unable to supply it during 17
ORA’s discovery process. 18
III. BACKGROUND 19
A. Least-cost Dispatch Standards 20
Following changes to the energy markets after the 2009 Market Redesign and 21
Technology Upgrade, investor-owned utilities (IOUs) no longer dispatch electricity to the 22
grid themselves. Rather, the California Independent System Operator (CAISO) now 23
makes dispatch decisions based upon system and regional needs. The term “dispatch” 24
will be used in this testimony to refer to SCE offering available energy to the market 25
9 D.15-05-007, Appendix A Item 3e. 10 Attachment 2.9, ORA Report on SCE 2015 ERRA A.16-04-001 at p. 6.
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through an economic or price-taker bid, unless reference is made to a CAISO dispatch 1
event. 2
The procurement and dispatch of electricity by California’s IOUs are guided by 3
decisions and standards set forth in past Commission decisions. D.02-10-062 set 4
minimum standards of behavior and established Standard of Conduct 4 (SOC4) which 5
states, “The utilities shall prudently administer all contracts and generation resources and 6
dispatch the energy in a least-cost manner.”11 D.02-12-074 further defined SOC4 and 7
LCD principles, including, “Least-cost dispatch refers to a situation in which the most 8
cost-effective mix of total resources is used, thereby minimizing the cost of delivering 9
electric services….”12 10
More precise reporting standards were developed most recently by ORA and the 11
IOUs in 2015, and were adopted by the Commission in D.15-05-007. This and other 12
decisions guide SCE to make a complete showing that demonstrates that LCD was 13
achieved in the 2016 Record Period. D.15-05-007 also recognized that the dispatch of 14
demand response (DR) should be reviewed as a part of LCD compliance.13 15
IV. DISCUSSION AND ANALYSIS 16
A. Forecast Accuracy: Price and Load 17
For each day of the year, SCE submits bids to CAISO for both the load it expects 18
to serve (demand) and the supply of electricity it seeks to sell to the market.14 These bids 19
to purchase a quantity of electricity and to sell owned or contracted supplies occur in both 20
the day-ahead market (DAM) and the real-time market (RTM). Energy price forecasts 21
guide the dispatches of 22
.15 An accurate price forecast allows SCE to make energy bids that will 23
11 D.02-10-062 at p. 52. 12 D.02-02-074 at p. 54. 13 D.15-05-007, Ordering Paragraph 3. 14 SCE Testimony at p. 14. 15 Id. at pp. 15, 18.
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minimize ratepayer costs by offering resources at the most prudent prices and scheduled 1
at optimal times on the DAM. Resources which SCE can directly dispatch, such as hydro 2
pump-back operations and day-ahead demand response resources benefit from this 3
accuracy greatly. 4
Load forecasts help guide SCE to purchase the majority of its load in the DAM. 5
Any excess or deficient quantities of daily load must be transacted for on the RTM which 6
is a more volatile market that can result in significant procurement costs.16 An accurate 7
load forecast thus allows SCE to minimize its exposure to risk by purchasing the majority 8
of its load on the DAM. SCE purchased worth of energy from CAISO, 9 17 10
18 The accuracy of both load and price forecasts thus 11
have an impact on LCD principles and can minimize ratepayer impact. 12
ORA used SCE data and figures to find different measurements of the Mean 13
Absolute Percentage Error (MAPE) and variance of SCE’s forecast. A similar process 14
was used for ORA’s analysis of the 2015 application, but this year’s analysis only 15
considered the SCE Default Load-aggregation Point (DLAP) and left out trading hub data 16
because data showing the hourly proportion of dispatch conducted on the trading hub was 17
not available, preventing an accurate approach to weighing the two data sets. The MAPE 18
measures the difference between the forecasted price/load and the actual price/load 19
experienced for the day.19 The variance on Tables 1 and 2 was constructed by taking the 20
actual market price/load and subtracting the forecasted price/load. For energy price, this 21
was done for the average price of each day of the year, with a separate calculation 22
performed for the highest 100 energy value days. For load, the calculation was 23
16 Id. at p. 17. 17 DAM and RTM revenue. Attachment 2.12, SCE Responses to Data Requests at p. 1. 18 Ibid. 19 The MAPE equation is the absolute value of: [(Forecasted Price or Load) – (Actual Price or Load)] / (Actual Price or Load)
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performed for each of the highest 100 energy value days, with a separate calculation for 1
each hour of those highest 100 days. A negative variance would indicate that SCE tended 2
to under-estimate the price/load. 3
Table 1: Price Forecast Comparison between 2014-2016 Record Periods20
MAPE Variance
Year Data Range Median Mean Max Median Mean Max Min
2016 Top 100 Days
2015 Top 100 Days
2014 Top 100 Days
2016 All 365 Days
2015 All 365 Days
2014 All 365 Days
SCE’s price forecasting in 2016 compared to past years in the 4
top 100 highest energy priced days than 2015. Price 5
forecasting for the full year comparatively . 6
. 7
8
9
. 10
20 ORA created this table from SCE’s Section D Price Forecast worksheet. The table uses DLAP data, leaving out SP15 Trading Hub figures. Previous Record Period data was sourced from past ERRA worksheets. Available as Attachment 2.2.
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Table 2: Load Forecast Comparison between 2014-2016 Record Periods21
MAPE Variance
Year Data Range Median Mean Max Median Mean Max Min
2016 Top 100 Days
2015 Top 100 Days
2014 Top 100 Days
2016 All Hours of 100
2015 All Hours of 100
2014 All Hours of 100
Load forecasting accuracy 1
. 2
. 3
4
5
6
7
8 22 9
10
11
21 Attachment 2.2. 22 Attachment 2.12 at p. 2.
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Figure 1: Monthly Difference of Actual Load and Awarded Load
(CONFIDENTIAL)23
Lacking a frame of reference other than historical SCE data, ORA cannot fully 1
judge the acceptability of SCE’s forecast inaccuracies. In its testimony, SCE does not 2
give a summary of its forecast accuracy nor an interpretation of its annual forecast 3
performance. ORA does not recommend any cost disallowances but does recommend 4
that the Commission order SCE to provide a supplemental narrative to its workpapers in 5
future testimony which summarizes the data, indicates what SCE considers “normal” or 6
“accurate,” and interprets its performance for the Record Period. 7
B. SCE’s Bidding Strategy 8
IOUs offer their resources for dispatch in the CAISO market by either making 9
economic bids or self-scheduling the resources for some or all hours of the year. Self-10
scheduled bids are also known as “price-taker” bids since the resource will be paid 11
whatever the price of energy happens to be at the time of dispatch. Most dispatchable 12
23 Attachment 2.2, “Load Graph – 366”.
195397070 2-9
resources, like natural gas plants, have costs such as fuel and operation and must be paid 1
a certain amount in order to break-even or profit from being dispatched. Economic 2
bidding ensures the resource is only run when its market payment is at or above the cost 3
to operation, and thus is the optimal means of offering such resources to the market. 4
Self-scheduling is inherently at odds with LCD principles, but is appropriate for must-run 5
resources such as run-of-the-river hydro or resources with minimal costs of operation 6
such as solar. 7
1. Self-Scheduling Activity 8
In 2016, SCE 9 24 10
In total, of the energy generated by such resources were self-scheduled rather than 11
economic bids.25 ORA recognizes the benefit of occasional self-scheduling of a thermal 12
dispatchable resource and finds these self-scheduling instances to be reasonable. 13
2. Incremental Bid Cost Calculations 14
When calculating economic bids to offer resources to the market, SCE constructs 15
bid prices which will ensure the resource will not run if its costs are higher than the 16
market energy price. Most thermal resources offer a number of different bid prices for 17
different levels of electricity output. CAISO may then dispatch more or less energy from 18
the resource depending on need and the price of electricity. The incremental cost (also 19
known as the marginal energy bid cost) increases as more electricity is offered. Factors 20
of incremental bid costs are the current price of natural gas, heat rate, Greenhouse Gas 21
(GHG) price, and variable operations and maintenance (VOM) costs.26 22
There is occasional variance between the calculated bid and the actual bid 23
submitted to the market.27 In 2016, SCE experienced 3,381 variances out of its 601,377 24
24 SCE Testimony at p. 21; SCE Testimony at p. 15. 25 Attachment 2.15 - SCE Chapter II_Section E_SS and Market Awards_CONFIDENTIAL 26 Attachment 2.12 at p. 4. 27 D.15-05-007 Appendix A set forth a $0.10 variance standard which utilities must report in the ERRA.
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incremental bids, or 0.56% of total bids.28 Eighteen of those variances led to a cost 1
impact totaling $3,340 for the year.29 This represents a slight increase in the amount of 2
variances and total costs compared to Record Period 2015 in which 0.11% of submitted 3
bids suffered variance with a total cost of $2,303.30 4
1,317 variances were due to CAISO or SCE system error. SCE currently has a 5
method in place to assess and dispute CAISO errors and maintains routine IT diagnostics 6
for its own internal systems.31 The remainder of variances were due to four SCE user 7
errors. 8 32 9
10 33 11
Due to the and SCE’s existing and improved 12
safeguards to address errors, ORA does not recommend a disallowance. 13
3. Commitment Cost Calculation Errors 14
Each thermal resource has a cost to startup and run at a minimum load, referred to 15
as commitment costs. These commitment costs are an important factor in determining 16
the accurate bid price of a resource in order to recover all costs involved with generation. 17
If these commitment costs are improperly calculated, then the final bids will not 18
accurately reflect the cost of running the resource, which may result in cost impacts. 19
Commitment costs are calculated by SCE and logged in CAISO’s Master File, 20
which is the record of all dispatchable resources’ operating costs and parameters. 21
Economic bids can be submitted as proxy bids, which are costs calculated by CAISO and 22
that can vary daily based on the price of natural gas. Alternatively, if SCE believes that 23 28 SCE Testimony at p. 20. 29 Id. at p. 21. 30 Attachment 2.9 at p.6. 31 Attachment 2.12 at p. 5-6. 32 Attachment 2.8, “Variance Descriptions” 33 Attachment 2.12 at p. 7.
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the proxy bids set by the CAISO do not adequately reflect the opportunity costs of 1
running a resource, SCE can use the registered cost option. The registered cost option 2
allows SCE to bid up to a cap of 1.5 times the proxy costs, but the bid cannot be updated 3
for at least 30 days. 4
5 34 6
SCE discovered early in 2016 that it had misapplied the cost cap calculation 7
formula, and in some cases had understated the cost of the resource, which resulted in 8
cost impacts to ratepayers.35 SCE determines the cost impacts by comparing the bid cost 9
recovery gains or losses of settlements to what it would have been had SCE correctly 10
calculated the commitment costs.36 During Record Period 2016, of SCE’s 11
registered bid elections contained incorrect submissions and caused a net cost impact of 12
.37 13
SCE’s calculation errors began in May 2012, when SCE utilized a “slightly lower” 14
natural gas transportation cost adder value for several of its resources.38 This caused SCE 15
to underestimate the registered cost cap and “artificially reduc[e]” the registered 16
commitment costs. 39 In other words, SCE attempted to submit registered cost bids at the 17
CAISO-set proxy price in order to capture true opportunity costs of the resources, but 18
wound up bidding below the correct opportunity cost. SCE states that the cause of the 19
error was that, “SCE misapplied the CAISO cost cap calculation formula for several of its 20
resources.”40 21
34 SCE Testimony at p. 22. 35 SCE Testimony at p. 22. 36 This citation refers to a data request for the 2015 Record Period ERRA: Attachment 2.12 at p. 23. 37 Attachment 2.11 - SCE Chapter II_Section E_Commit Cost_CONFIDENTIAL “Summary Tables” 38 Attachment 2.10 – Supplemental Direct Testimony of SCE for A.16-04-001 at p. 2. 39 Id. at p. 2. 40 SCE Testimony at p. 22.
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This error persisted from 2012 until SCE discovered it in February of 2016 while 1
preparing its 2015 ERRA Compliance Application.41 In its opening brief of the 2015 2
ERRA, SCE explained that it did not conduct a review of the natural gas transportation 3
cost adder since it “is never expected to change.”42 It would have been prudent of a 4
reasonable manager to have protocols in place to review data at the time of entry if no 5
review of that data is planned for the future. Incorrect static parameters may cause 6
significant costs to ratepayers if allowed to persist for many years, as this error has 7
demonstrated. 8
ORA’s analysis of the 2015 SCE ERRA Compliance application, A.16-04-001, 9
reviewed this error and ORA performed additional discovery for the years prior to the 10
current Record Period.43 In that analysis, ORA concluded that the errors were 11
unreasonable and SCE’s reporting demonstrated lack of due diligence.44 That proceeding 12
is still open. 13
SCE’s commitment cost calculation error prevented accurate least-cost dispatch in 14
the 2016 Record Period. SCE has not sufficiently explained how the error occurred, 15
failing to establish that the utility acted prudently when the error occurred. SCE has also 16
admitted that the value was not reviewed following entry in 2012 and was never intended 17
to be reviewed.45 ORA has already recommended a disallowance for previous Record 18
Periods in its 2015 ERRA testimony. For the 2016 Record Period, ORA recommends a 19
disallowance of the cost impact resulting from SCE’s commitment cost cap 20
calculation errors. 21
41 Id. at p. 22. 42 A.16-04-001, Opening Brief of Southern California Edison Company at p. 6. 43 Attachment 2.9 at p. 6. 44 Ibid. at p. 5. 45 A.16-04-001, Opening Brief of Southern California Edison Company at p. 6.
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4. Bidding Error - El Segundo 1
SCE took over scheduling coordinator responsibilities of El Segundo Units 5/6 2
and 7/8 when the resource joined SCE’s portfolio through a tolling agreement on 3
December 1, 2016.46 While performing data entry, SCE personnel left blank one 4
parameter of a formula used to calculate the startup cost of El Segundo.47 This led to 5
6
7
. The error lasted from 8
December 2016 to January 2017 when it was detected and corrected during a routine data 9
update.48 The average startup cost calculated by SCE was and the average actual 10
startup cost was . El Segundo Units 5/6 and 7/8 underwent startup many times 11
while the error persisted, creating instances of cost impact totaling an estimated 12
$158,777. 49 13
SCE has failed as a reasonable manager regarding this error and cost. The 14
reasonable manager standard states, “Utilities are held to a standard of reasonableness 15
based upon the facts that are known or should be known at the time.”50 This error could 16
have been avoided if appropriate operational or administrative protocols had been in 17
place. 18
A number of numerical values make up the calculation to determine the startup 19
cost of El Segundo and similar dispatchable thermal resources. During data entry, SCE 20
personnel inadvertently left out one parameter of the calculation, leaving one of the 21
entries blank. Power Cost Inc., the software that SCE personnel used to input the 22
46 SCE Testimony at p. 23. 47 Attachment 2.12 at p. 3. 48 Id. at p. 14. 49 Attachment 2.11, “El Segundo SU Cost Bids”. 50 D.90-09-088 Section IV. See also D.16-04-006 at pp. 11-13.
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parameters, treats an empty entry as if a “$0” was entered.51 The software is able to 1
complete the calculation without all entries, and does not produce an alert when a 2
parameter of a formula is left out. SCE operators were aware that the software would 3
assume a $0 value if an input was left out of the calculation, and admit that a validation 4
system that refuses an empty field (as opposed to assuming $0) would help minimize this 5
type of error.52 The software thus had the potential to allow major errors to occur, such 6
as the ones described above, but SCE had no review or verification process in place to 7
mitigate potential errors related to startup cost entry.53 SCE has also stated that it is 8
routine for data entry operators to not leave an entry blank, but rather enter “$0” by hand 9
as to minimize confusion.54 Only after the error was discovered did SCE implement 10
enhanced parameter reviews and communications to be conducted by multiple 11
employees.55 This follow-up to strengthen the data input process is a prudent corrective 12
action, but should have been in place before the error occurred since SCE was aware that 13
the software would treat an empty entry as a $0 entry. 14
The process that discovered the error was an annual process which updates startup 15
and other costs. Contracts are either updated at the start of a year or in June, depending 16
on contract terms.56 El Segundo’s update occurred in January, and operators noticed the 17
empty error and corrected the problem. SCE had no other process in place to verify the 18
validity of startup cost parameters. The units at El Segundo were being dispatched more 19
often due to the error, and personnel at the power plant prepared daily reports including 20
amount of startups and run hours.57 However, personnel at El Segundo do not provide an 21
opinion on the frequency of dispatch unless contractual or air permit limitations are being 22
51 Attachment 2.12 at pp. 15, 17. 52 Attachment 2.12 at pp. 17, 19. 53 Id. at p. 15. 54 Id. at p. 18. 55 SCE Testimony at p. 23. 56 Attachment 2.12 at pp. 9-10. 57 Id. at p. 21.
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reached.58 The annual update was thus the only opportunity to directly identify and 1
correct the error. A reasonable manager would have had review protocols in place at the 2
time when bidding information was initially input after SCE became the scheduling 3
coordinator for the unit. A complementary review process that could detect relatively 4
higher levels of dispatch may also be a prudent protocol to have in place. 5
ORA does not expect SCE to be held to a perfect standard, but SCE failed to have 6
adequate protocols in place despite being aware of the potential for erroneous data inputs 7
to occur.59 ORA recommends that the Commission disallow the full cost of the error of 8
$158,777. ORA also recommends that the Commission direct SCE to contact Power 9
Costs Inc. to explore the possibility of updating the bidding software in order to prevent a 10
calculation when a parameter has been left out. The data input process review that SCE 11
has already put into place is a prudent one that should decrease the likelihood of this error 12
repeating. However, it may be possible for the software developer to implement this 13
change which would prevent this type of error entirely. 14
5. Incremental Non-Dispatch 15
ORA’s analysis includes a review of any problems that prevent dispatch of a 16
resource offered to the market which was not dispatched when its bid was below the 17
LMP. SCE reports that there were occasions in which the LMP was above the 18
economic bid of a resource but no dispatch occurred.60 This amount is of all 19
dispatch hours for the Record Period. If an incremental bid is not awarded energy 20
through a dispatch despite an appropriate price of energy at that time, it is possible that 21
LCD was not achieved. 22
SCE states that it works with CAISO to investigate any “significant gaps between 23
expected and actual revenue” due to non-awards of incremental dispatch, though the 24
58 Id. at p. 22. 59 Id. at p. 17. 60 Attachment 2.8 – ORA-Modified SCE Response to Data Request 21 Question 1 Attachment, “Hours LMP > Bid”.
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utility did not report if any such gaps occurred in the Record Period.61 SCE provided six 1
Customer Inquiry Dispute & Information (CIDI) tickets from the Record Period showing 2
follow-up with CAISO for instances of costly dispatch or failure to dispatch. However, 3
none of the CIDI tickets involve the reported occasions in which LCD was not 4
achieved. SCE provides no specific reason for any of the occasions of incremental 5
non-dispatch reported. By running at a lower rate of generation than appropriate for the 6
resource at the corresponding LMP, the hours represent a missed net revenue of 7
.62 This amount warrants proper investigation and reporting by the utility. 8
SCE states that unawarded incremental bids are solely due to CAISO dispatch 9
decisions or unit outages or tests.63 SCE also states that a dispatch “where the LMP is 10
below the bid price may occur if the CAISO awards Ancillary Services or if the resource 11
is needed for system reliability.”64 These assertions ignore the possibility of SCE or 12
CAISO system errors or other obstructions to dispatch.65 Any failure to achieve dispatch 13
when conditions make dispatch optimal should be investigated by the utility and reported 14
in the ERRA application which is required by D.15-05-007: 15
“Monthly and annual tables will include summaries of … 16
[Item E:] Percentage of times incremental energy was not 17 awarded when incremental bid cost at the awarded MW level 18 was lower than the LMP at the applicable node. Explanation 19 and documentation of CIDI tickets submitted and subsequent 20 actions taken by the utility.”66 21
SCE provided the amount of hours and percentage of times that incremental 22
energy was not awarded, but failed to provide specific explanation of such occurrences 23
61 Attachment 2.12 at p. 24. 62 Attachment 2.8, “Hours LMP > Bid” 63 Attachment 2.12 at p. 28. 64 Attachment 2.12 at p. 26. 65 Such as those experienced and reported by PG&E in its 2016 ERRA Compliance application. See ORA Testimony for A.17-02-005 at pp. 2-10 – 2-11. 66 Underlined for emphasis, D.15-05-007, Appendix A Item 3e.
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and any subsequent follow-up in the ERRA application and ORA data requests for 1
explanations.67 An explanation for why no incremental energy is awarded allows the 2
Commission to discover any problems that could be rectified in order for LCD to occur. 3
SCE has consistently failed to explain these occasions of sub-optimal dispatch in both the 4
2016 and 2015 Record Periods.68 5
C. Hydro Management 6
Hydroelectric generation made up of SCE’s total generation in 2016, and 7
of the utility’s hydro is dispatchable.69 Dispatchable hydro, including pumped storage 8
hydro facilities, can only produce a finite amount of energy depending on the water 9
available and thus is bid into the market by SCE with consideration of the opportunity 10
cost of running the resource.70 Such resources have the highest value to customers when 11
they are dispatched during high energy price periods so that they may offset or suppress 12
high costs. 13
In 2016, SCE had three hydro resources which were dispatchable in the day-ahead 14
or real-time markets: 15
Big Creek, a system of six reservoirs and nine powerhouses 16 with a combined capacity of 1,015 MW;71 17
John S. Eastwood Power Station (Eastwood), a pumped 18 hydro resource which can generate electricity or pump water 19 from a lower reservoir to another at a higher altitude. It can 20 generate 200 MW;72 21
Hoover Dam, which is administered by the Western Area 22 Power Administration and the Bureau of Reclamation. SCE 23
67 SCE ERRA 2017 Chapter II_Section E_Inc Bid Cost Variance_CONFIDENTIAL, “Hours LMP > Bid” and Attachment 2.12 at p. 24. And Attachment 2.12 at pp. 25-28. 68 Attachment 2.9 at p. 6. 69 SCE Testimony at p. 26. 70 Id. at p. 15. 71 SCE Testimony at p. 36. 72 Id. at pp. 36, 54.
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holds a contract for a portion of Hoover Dam’s energy that it 1 may offer for dispatch in the CAISO market.73 2
ORA’s review of dispatchable hydro includes a review of its dispatch on the 3
highest-value energy hours of the year. 4
5
74 Constraints such as the statewide 6
drought which lasted the first half of the year and county, state, and national regulations 7
affected the amount of energy offered, but did not prevent SCE from maximizing the 8
value of water fuel.75 It appears SCE correctly prioritized the 500 highest energy value 9
hours to generate for its dispatchable hydro resources, capturing a high value for its finite 10
resources for ratepayer benefit. 11
1. Pumped Hydro 12
Eastwood’s pump-back capabilities give the resource a capability to consume 13
energy at low energy-value hours in order to pump water from Shaver Lake upstream 14
(through a penstock) to store at a higher-altitude forebay called Balsam Meadow.76 This 15
stored water may be used for generation at hours of high energy prices in order to 16
generate revenue. Pump operations were 17
in 2016.77 SCE asserts that the generally low price of energy in 18
California caused by low natural gas prices and cheap renewable energy created 19
conditions which made pump-back operations inefficient and costly.78 20
Insufficient water levels in Shaver Lake or near-full levels at the Balsam Forebay 21
are two natural conditions which prevented pump-back operations in 2016 as well as 22
73 Attachment 2.3 – ORA-edited Hydro Awards, “Summary”. 74 Attachment 2.3. 75 SCE Testimony at p. 38. 76 Id. at p. 54. 77 Id. at p. 55. 78 Ibid.
195397070 2-19
equipment problems.79 Pump-back operations were feasible from late-April through the 1
end of the year, except for a scheduled outage November 28th to 30th.80 2
Pump-back operation consumes approximately 1.33 MWh of electricity to store 3
1.0 MWh of future generation.81 There are no other economic factors considered for 4
Eastwood’s pump-back operations.82 SCE did not report any conditions when operations 5
were not possible except for outages, equipment problems, and lake level constraints.83 6
SCE should conduct pump-back operations whenever conditions allow and Eastwood is 7
able to consume energy at a price that is 1.33 times lower then what the utility may 8
expect to earn through generation in the following days. 9
Figure 2: 2016 Generation and Pump Production for Eastwood (CONFIDENTIAL)84
79 Attachment 2.12 at p. 29. 80 Ibid. 81 SCE Testimony at p. 55, fn. 52. 82 Attachment 2.12 at p. 30. 83 Id. at p. 29. 84 SCE’s Section D Hydro Awards workbook was used to build this graph. SCE’s data is missing nine days from the Record Period. Available as Attachment 2.3, “Eastwood Production”
195397070 2-20
Eastwood conducted pump-back operations for hours across days, including 1
an hour of pumping during testing.85 Using SCE’s data, ORA finds that across the 2
days in which operation was possible,86 there were days where the lowest hourly 3
LMP was at least 1.33 times lower than the highest hourly LMP.87 Assuming that 4
Eastwood pumped for one hour on each of these days when LMP was lowest, at typical 5
rates of pump-back88 Eastwood would have pumped worth of water. If 6
SCE had used each pumped hour of water to generate electricity at the peak LMP on the 7
same day it was pumped, the annual amount reduced by the cost to pump the water would 8
have been worth .89 The hours of pump-back that Eastwood actually 9
performed moved worth of water.90 Total actual net market revenue for 10
Eastwood in 2016 was .91 ORA’s figure assumes that SCE 11
only pumps for one hour per day rather than three hours per day actual operations tended 12
to perform; ORA is unable to make exhaustive considerations of the multi-regional 13
regulatory and operational constraints of Eastwood, so a conservative assumption of one 14
hour per day was made. 15
There appears to be capability for SCE to increase pump-back operations at 16
Eastwood which would increase the value of the resource and benefit ratepayers. ORA 17
recommends that the Commission order SCE to demonstrate in future ERRA filings that 18
the utility maximized market revenue possible from pump-back operations. This 19
demonstration should describe when operational and regulatory constraints made pump-20 85 Ch. II _Section D_Hydro Awards-LMPs_CONFIDENTIAL 86 5/1/16 to 12/31/16, not including 11/28-11/30. SCE did not give a specific date when operation began to be possible other than “Late-April” so ORA assumed May 1st for this calculation. 87 Attachment 2.3, “Eastwood Pump 2” 88 Pumping in the Record Period typically occurred at . Attachment 2.3, “Eastwood Pump”. 89 The cost of pumped at minimum LMP for the day, and the profit from generating at the maximum LMP for the day, for all days when pumpback operations were possible and the minimum LMP was at least 1.33 times lower than the maximum LMP. The sum for the year is divided by 1.33, since it takes 1.33MWh of pump energy to store 1.0MWh of water due to losses. Attachment 2.3, “Eastwood Pump 2” 90 (typical amount pumped/hour). 91 Attachment 2.3, “Eastwood Pump”.
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back operations impossible or sub-optimal. The demonstration should also include an 1
explanation of when pump-back operations were possible and cost-effective, but no 2
pump-back occurred. 3
D. Dispatchable Renewables Management 4
CAISO reports that curtailment of solar and wind resources is increasing each 5
year, which means the fiscal impacts of curtailment grow as well.92 Utilities are able to 6
decide whether to curtail a resource or not, and modify contracts in order to have the 7
capability to curtail. Curtailment of renewables allows utilities to exercise an economic 8
option to avoid production at times of negative energy prices, when generation is not paid 9
for by the market, but rather is charged by the market. Utilities must strive to partially or 10
fully mitigate costs of curtailment by implementing curtailment response strategies and 11
modifying contracts to facilitate the curtailment response strategies in order to meet LCD 12
principles. 13
SCE possessed renewable contracts with curtailment provisions in 2016, 14
curtailing total.93 SCE did not include any information in its testimony on 15
renewable curtailment. Quantitative data was provided to ORA through data requests, 16
but ORA lacks the resources to make a comprehensive analysis of curtailment strategies 17
and the potential cost savings in dealing with curtailment and over-generation on the 18
CAISO market. Reporting of such data by SCE is necessary for the utility to demonstrate 19
that it has maintained the most cost-effective mix of resources possible. 20
ORA recommends that the Commission order SCE to include in its future ERRA 21
Compliance testimony reporting and quantitative calculations of any renewable resource 22
opportunity costs by technology (e.g. wind, solar, etc.). The Commission should also 23
order SCE to include in its future ERRA Compliance testimony explanations of energy 24
curtailment, such as instances when it is necessary, how the economic decision to curtail 25 92 As reported by CAISO’s Historical Production and Curtailment Data, http://www.caiso.com/Documents/HistoricalProduction-CurtailmentDataNowPosted-ISOWebsite.html. 93 For comparison, SCE generated (did not curtail) MWh of wind and solar energy. Attachment 2.13 - SCE Response to ORA Data Request 8, Question 3 Attachment.
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or not curtail a resource is made, the business process for curtailing a resource, and any 1
associated quantitative metrics. This increased reporting is necessary for SCE to satisfy 2
its burden of proof to demonstrate that it maintained the most cost-effective mix of 3
resources during a Record Period.94 4
E. Demand Response Management 5
SCE’s economically triggered DR resources are integrated into the CAISO 6
market.95 SCE’s determination of a DR resource’s bid price and whether it chose to offer 7
the resource to the market or withhold it must be considered in the review of least-cost 8
dispatch to ensure SCE utilized the most cost-effective portfolio of resources. DR 9
programs that utilize an economic trigger are: Capacity Bidding Program (CBP), 10
Aggregator Managed Portfolio (AMP), and Summer Discount Plan (SDP).96 These 11
programs are further categorized by AMP contracting parties, day-of (DO) versus day-12
ahead (DA) scheduling, sector served, and how many hours the program may be active 13
per day (1 to 4 hours or 2 to 6). These programs were dispatched in 2016 as described 14
below. Use Factor is a measurement of program deployment and is derived by dividing 15
the MWh worth of energy mitigated by the total amount of MWh which the program was 16
available to mitigate in 2016. 17
94 This requirement to show a burden of proof that LCD was achieved is set forth in D.02-12-074, Ordering Paragraph 24. 95 SCE Testimony at p. 18. 96 SCE describes the CBP and SDP as Price Responsive Programs at page 112 of its Testimony. The CBP and AMP are also described as Proxy Demand Resources at page 26 of its Testimony. The SDP is also described as a Reliability Demand Response Resource, since it has both an economic trigger and a reliability condition trigger.
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Table 3: Record Period Dispatch of Demand Response Resources
Program MWh Available in 2016
MWh Dispatched
Use Factor
Energy Cost Avoided97
AMP‐ECI 98
AMP‐Enernoc
CBP‐DA
CBP‐DO 1‐4
CBP‐DO 2‐6
SDP‐Res
SDP‐Com
Grand Total
1. Bid Calculation and Dispatches and Dispatch 1 Strategy 2
i. Aggregator Managed Portfolios 3
The two AMP programs are contracted to third-parties EnerNOC Inc (Enernoc) 4
and Energy Connect Inc. 5
(ECI). The properties of the programs, including conditions for dispatch, are set 6
forth in contracts with the counterparties. 7
Both of these programs were used far less than SCE’s other demand response 8
programs. 9
. AMP-Enernoc was appropriately dispatched 10
when the LMP was above its bid price. The dispatches of AMP-ECI all occurred when 11
LMP was not above its trigger, which likely means that it was only dispatched due to 12
CAISO reliability events. 13
97 “Cost Impact (Dispatches)” as described by SCE Testimony at p. 26. 98 Data submitted by SCE showed incorrect data due to missing LMP entries. ORA filled in LMP entries from using corresponding sub-load aggregation point LMPs given in other worksheets.
195397070 2-24
SCE pays the contractor a variable monthly rate for capacity available to be called, 1
and also makes a payment per dispatch. The payment and dispatch terms for AMP 2
resources are set in the contract. The use factor for AMP-ECI in 2015 3
to in 2016, whereas the AMP-Enernoc use factor from to 99 4
Since SCE makes a monthly payment to the contractor regardless of whether dispatch 5
occurs or not, higher levels of dispatch would make better use of ratepayer funds spent on 6
the programs. 7
ii. Capacity Bidding Program 8
The three CBP options may be dispatched 30 hours per month, once per day, for a 9
maximum of 4 or 6 hours per day on non-holiday weekdays on any month of the year.100 10
The day-ahead program requires customers to be notified of a dispatch event on the day 11
before, whereas the day-of programs notify the customers 70 minutes before the event. 12
The CBP programs are bid in at the highest of either the Net Benefits Test (NBT) 13
market price, opportunity cost, or the market equivalent price of a 15,000 BTU/kWh heat 14
rate.101 The NBT is a CAISO-determined price which determines the cost-effectiveness 15
of a DR dispatch; when the LMP would award a price above the NBT, it would be cost-16
effective to dispatch.102 The majority of dispatches of the CBP options appropriately 17
occurred when the day-ahead or real-time LMP was above the NBT.103 18
The other two trigger conditions cannot currently be reviewed by ORA. SCE does 19
not maintain data for opportunity costs, so no data on that trigger condition was 20
provided.104 The price equivalent of 15,000 BTU/kWh varies depending on weather, 21
99 Attachment 2.9 at p. 8. 100 Attachment 2.4, Attachment 2.5 and Attachment 2.6. 101 Attachment 2.4, “Notes” & Attachment 2.12 at p. 31. 102 Attachment 2.14 - ORA Least Cost Dispatch Overview 062117. 103 The proportion of dispatches which occurred when the NBT was above the LMP was , , and for the three CBPs. Please see the Summary tab of worksheets built by ORA from SCE Section H worksheets: Attachment 2.4, Attachment 2.5 and Attachment 2.6. 104 Attachment 2.12 at p. 31.
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forecasted gas prices and other conditions. SCE does not maintain data for this heat rate 1
trigger condition, so again, no data on this trigger condition was provided.105 2
The CBP options pay both a monthly capacity payment to subscribers and a 3
payment each time the program is dispatched. Both vary depending on the amount of 4
energy made available. The dispatch payment was on average and 5
dispatches occurred when the average RTM LMP was approximately . The 6
difference between the dispatch payment and the LMP represents a savings to ratepayers, 7
though other major factors like administrative costs and the monthly capacity payment 8
make direct savings calculations difficult.106 As shown in Table 3, SCE 9
by dispatching the CBP programs rather than generating additional energy. The 10
programs were generally dispatched previous years. 11
iii. Summer Discount Plan 12
The two SDP programs decrease demand by automatically controlling the air 13
conditioning of subscribers in exchange for a bill credit.107 There is a program for the 14
residential sector (SDP-R) and another for the commercial sector (SDP-C). The former 15
represents 16
Both programs may be dispatched 20-180 hours a year, in any month, for no 17
more than 4 hours per day, and not for more than three consecutive non-holiday 18
weekdays.108 19
The programs’ bid price is whichever is the greater of either the NBT threshold or 20
opportunity cost. The opportunity cost is set as the 20th highest price forecasted hour of 21
non-holiday weekday hours between 11am and 9pm each month.109 SCE provided the 22
bid price in response to a data request, which was on average from February 8, 23
105 Ibid. 106 Attachment 2.6, “C”. 107 Attachment 2.12 at p. 32. 108 Id. at p. 35. 109 Attachment 2.7 - 2017 Chapter II_Section H_DR-SDPR, “Notes”
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2016 to October 7, 2016. All dispatches appear to have occurred appropriately; when the 1
LMP was above the bid price and the program was available for dispatch. 2
3
.110 The program is most effective on days 4
when air conditioner use is particularly high, 5
. 6
2. ORA Assessment of Demand Response 7 Administration 8
Ensuring that least-cost dispatch occurred in a record period requires an analysis 9
of how a bid price is constructed and determining if dispatch occurred at that price. 10
SCE’s metrics did not include the bid price for the CBP programs which is essential to 11
LCD analysis and required by Commission decision.111 Furthermore, SCE did not 12
provide any explanation or data on hours when it was appropriate to dispatch a demand 13
response resource, but no dispatch occurred. ORA previously presented these issues of 14
non-compliance to SCE and the Commission in A.16-04-001.112 It is presently 15
impossible to determine if SCE is in compliance with Standard of Conduct 4 with regards 16
to its demand response resources. ORA recommends that the Commission order SCE to 17
comply with D.15-05-007 by supplying demand response metrics and data in its ERRA 18
filings as clearly set forth in the appendices of that decision. 19
V. CONCLUSION 20
In general, SCE adhered to least-cost dispatch principles in the Record Period. 21
Without significant improvement of reporting, ORA cannot determine if SCE met 22
Standard of Conduct 4. In order for SCE to meet its burden of proof, it must provide 23
more information in its initial testimony and workpapers. 24
110 Attachment 2.7, “Summary” 111 D.15-05-007, Appendix 2, Items 1 and 8. 112 Attachment 2.9 at pp. 8-9.
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SCE also failed as a reasonable manager in the matter of the El Segundo cost 1
calculation error. ORA recommends the Commission take action in the form of 2
disallowance and follow-up procedures as mentioned above. 3
The 2016 Record Period cost impact of the commitment cost cap calculation error 4
should also be disallowed as described and recommended by ORA. 5
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CHAPTER 3: UTILITY-OWNED GENERATION – HYDROELECTRIC 1
(Michael Yeo) 2
I. INTRODUCTION AND RECOMMENDATIONS 3
This chapter addresses the operation and management of Southern California 4
Edison’s (SCE) utility-owned hydroelectric (hydro) facilities, and the outages that 5
occurred at those facilities during the 2016 Record Period. 6
After reviewing SCE’s testimony and responses to Office of Ratepayer Advocates’ 7
(ORA’s) data requests, ORA agrees with the implementation of the corrective actions 8
listed in the Root Cause Evaluation Report. ORA also agrees that there was no lost 9
generation for Unit 3 due to drought conditions. 10
II. GENERATION FACILITIES113 11
The Hydro Division is organized into two regions, northern (Northern Hydro) and 12
eastern (Eastern Hydro). Altogether, SCE owns, operates, and maintains 33 hydroelectric 13
generating plants, with an aggregate 1,176 MW of nameplate generating capacity. 14
Figure 3.1 shows its hydro system in California. 15
SCE’s hydro operation for Record Period 2016 was significantly impacted by the 16
drought. With the drought continuing into its sixth consecutive year, precipitation levels 17
for the 2016 calendar year were only approximately 53% of the historic annual 18
average.114 19
113 Information about SCE’s generation facilities was provided in SCE’s testimony at p. 34 and in responses to ORA data requests #1 and #11. 114 SCE testimony SCE-01 at p. 34 Lines 6:8.
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Figure 3.1115 SCE’s Hydro System
115 SCE response to ORA Data Request 11, Question 1.
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III. OUTAGES 1
For the 2016 Record Period, there were three forced outage incidents at Big Creek 2
(see Figure 3-2 for the locations of the Big Creek facilities in relationship to one another): 3
a. Big Creek 3, Unit 3 (34MW) from March 31, 2016 at 4 08:17 hours to May 5, 2016 at 19:20 hours;116 5
b. Big Creek 3, Unit 4 (36MW) from August 4, 2016 at 6 02:46 hours to August 10, 2016 at 17:06 hours; 117 7
c. Big Creek 2A, Units 1 and 2 (55MW each), from August 8 5, 2016 at 08:42 hours to August 8, 2016 at 13:25 hours. 9 118 10
Figure 3.2119 SCE’s Hydro Generation Units at Big Creek
116 SCE response to ORA Data Request 11, Question 8. SCE adds that the information on the end date and time of this outage in its testimony was not correct. 117 SCE response to ORA Data Request 11, Question 39. 118 SCE response to ORA Data Request 11, Question 59. 119 SCE response to ORA Data Request 11, Question 7.
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In all the above forced outages, the bypassed energy is zero.120 SCE defines 1
outage bypassed energy as the energy in MWh lost due to water bypassing a powerhouse 2
due to an outage.121 In other words, the outages for the above units had zero bypassed 3
energy (thus no replacement power122) because the water that was not used during the 4
outages was stored for generation production at a later date. 5
SCE further explains bypassed energy as follows: 6
“Once a reservoir reaches a full level, inflows that exceed the 7 hydraulic capacity of the downstream powerhouse will bypass 8 the powerhouse as spill. If an outage occurs at the 9 powerhouse during this time, it will cause an increase of 10 water bypassing the powerhouse as spill. SCE defines the 11 energy in MWh lost due to water bypassing a powerhouse 12 due to an outage as “outage bypassed energy.” It is additional 13 generation production that would have been possible had the 14 hydro unit not been out of service. 15
“In the case of a unit outage when reservoirs levels are not at 16 full capacity, SCE can either store the water for later use, or 17 utilize a standby unit. This action does not result in outage 18 bypassed energy. Therefore, many of the unit outages that 19 occur in the fall, winter, or spring may not have associated 20 outage bypassed energy because the water has been stored for 21 generation production at a later date.”123 22
ORA’s analysis and testimony focus on the longest duration outage only: the 23
March 31, 2016 lasted over 35 days while the other two were less than a week. In 24
addition, all three forced outages did not result in any replacement power cost to the 25
ratepayers. 26
A. BIG CREEK 3, UNIT 3 Outage – March 31, 2016 27
The Big Creek 3 Unit 3 outage began on March 31, 2016, at 08:17 hours and was 28
back in “ready for service” condition on May 5, 2016, at 19:20 hours. Big Creek 3 Unit 3 29
120 SCE testimony SCE-01 at p. 52 Line 21:22. 121 SCE testimony SCE-01 at p. 37 Line 15:16. 122 SCE response to ORA Data Request 11, Question 23. 123 SCE testimony SCE-01 at p. 37 Line 12:22.
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did not resume generating electricity until May 16, 2016, at 09:00, when it was called 1
upon to do so. This outage happened coincidently right after a planned outage from 2
November 2, 2015 to March 30, 2016.124 3
SCE, in its testimony125 and data request response126, states that the cause of this 4
outage was due to the low level of oil used to provide lubrication between the thrust 5
runner plate and the thrust bearing of the turbine. The oil level was low because the oil 6
overflowed a thrust tub vent. Due to the insufficient amount of lubrication oil, the 7
resulting friction generated heat; this heat subsequently damaged the runner plate, thrust 8
bearing, and shaft seal. 9
The thrust runner plate (see Figure 3-3) is the rotating part of a turbine resting 10
upon thrust bearings (i.e., bearing pads, see Figure 3-4). The thrust bearing mitigates 11
against excessive axial movement of the rotating turbine element (i.e., movement parallel 12
to the turbine shaft). During operation, oil is fed through multiple supply lines to provide 13
lubrication between the thrust runner plate and the thrust bearing. A valve on these 14
supply lines regulates the flow of oil. A shaft seal prevents oil located in this area from 15
mixing with water in the turbine.127 16
According to SCE128, the problem did not exist prior to the planned outage. The 17
oil overflow can occur only (and thus only be observed) during unit operation, and it 18
happened shortly after the unit was returned to service following the aforementioned 19
planned outage.129 20
124 SCE response to Data Request 11, Question 16. 125 SCE testimony SCE-01 at p. 52 Line 3:4. 126 SCE response to ORA Data Request 11, Question 11. 127 SCE response to ORA Data Request 11, Question 11. 128 SCE response to Data Request 11, Question 16. 129 Ibid.
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Figure 3.3130 Thrust Runner Plate
(Old Thrust Runner Plate being removed)
130 SCE response to ORA Data Request 11, Question 11.
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Figure 3.4131 Thrust Bearing
(Cross-Sectional View of Thrust Bearing)
The oil level was low because there was a partially-closed valve which prevented 1
full supply of oil to the bearings during operations.132 SCE indicated that the valve was 2
not damaged133, but failed to explain why it was partially closed during operation, or why 3
it was in the partially-closed position right after the planned shutdown from 4
November 2, 2015 to March 30, 2016. After all, it was the valve’s partially-closed 5
condition that led to the lack of lubrication and subsequent damage to the thrust runner 6
plate, bearings and shaft seal. The data request response134 did not mention whether the 7
valve was replaced after the outage, or inspected to determine why it was partially closed 8
during operation. 9
131 SCE response to ORA Data Request 11, Question 11. 132 SCE testimony SCE-01 at p. 52, Line 7:9. 133 SCE response to ORA Data Request 11, Question 11. 134 Ibid.
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In addition, ORA reviewed the document titled 2016 Big Creek 3 Unit 3 Thrust 1
Bearing Failure, the Root Cause Evaluation (RCE) Report.135 The RCE Report is SCE’s 2
post-mortem report which was included in its Workpapers for SCE-1 Chapters III and IV 3
and SCE-02 Chapter XI (Workpapers); these Workpapers were submitted by SCE to 4
support its testimony. 5
SCE explained why it took it 35½ days to restore the facility back to service as 6
follows: 7
“This amount of time was required to: a) assess the extent of 8 the damage, b) obtain repair parts and c) perform necessary 9 repairs. SCE prioritizes work based on system 10 requirements.”136 11
i. Corrective Actions 12
Following this outage event, repairs were performed to restore Unit 3 back to 13
service. The RCE Report also identified several corrective actions under the headings 14
entitled Causes and Corrective Actions and Lessons Learned. One action includes, “The 15
procedure for adjusting the lube oil system has been changed on this unit and all units in 16
powerhouse to be opened completely to prevent risk of inadequate oil for lubrication.”137 17
ii. Cost of Outage 18
The cost of the outage consists of two components: the cost of energy that SCE 19
had to purchase to replace the unavailable generation facility, and the cost of the repair 20
work at the Big Creek facility. 21
SCE states that there is no lost generation for this incident because the bypassed 22
energy was zero MWh. SCE further explains: 23
“No replacement power costs were incurred during this 24 outage. SCE's plan during April-May, 2016 was to maintain 25 the Big Creek Dam 6 reservoir in an approximately full 26 condition, and the outage did not cause SCE to deviate from 27
135 SCE response to ORA Data Request 11, Question 22. 136 SCE response to ORA Data Request 11, Question 10. 137 RCE Report at p. 4.
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this plan. This reservoir has a capacity of approximately 993 1 AcFt, which corresponds to a reservoir water level (i.e., water 2 surface elevation) of 2,230 Ft. (above sea level); minimum 3 reservoir water level (i.e., water surface elevation) for 4 generator operation is 2184 Ft (above sea level). The 5 reservoir was continuously maintained within approximately 6 1 Ft. of this level during the outage (i.e., was essentially 7 maintained at 100% of capacity). At no time during the 8 outage did this reservoir ’spill.’ That is, at no time did the 9 reservoir discharge water to the Big Creek 3 powerhouse 10 without that water being used for generating purposes by the 11 other four units at the Big Creek 3 powerhouse, and at no 12 time did the reservoir discharge water into the streambed 13 immediately downstream of the dam in excess of the 14 regulatory mandated minimum stream release for the dam.”138 15
SCE’s direct cost of the outage to repair the damage was $61,930. The cost 16
breakdown is as follows: 17
Table 3-1 Direct SCE Cost139
Line No. Description Amount
1 Labor $16,001 2 Non-Labor $45,929
3 Total $61,930
SCE also adds that the costs of labor and materials are funded through SCE’s 18
approved General Rate Case base rates.140 19
Due to the fact that there was no power replacement cost for this outage, the total 20
cost of this outage equals SCE’s direct cost of $61,930. 21
138 SCE response to ORA Data Request 11, Question 27. 139 SCE response to ORA Data Request 11, Question 33. 140 SCE response to Data Request 11, Question 34.
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IV. CONCLUSIONS AND RECOMMENDATIONS 1
Based on ORA’s review of the afore-mentioned documents and report, ORA 2
agrees with the implementation of the corrective actions listed in the RCE Report. ORA 3
also agrees that there was no lost generation for Unit 3 due to drought conditions. 4
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CHAPTER 4: UTILITY-OWNED GENERATION – NATURAL GAS 1
(Michael Yeo) 2
I. INTRODUCTION AND RECOMMENDATIONS 3
This chapter addresses the operation and management of Southern California 4
Edison’s (SCE) utility-owned natural gas facilities, and the outages that occurred at those 5
facilities during the 2016 Record Period. 6
After reviewing SCE’s testimony and responses to Office of Ratepayer Advocates’ 7
(ORA’s) data requests, ORA agrees with the implementation of the corrective actions 8
indicated by SCE for the Grapeland Peaker outage on October 20, 2016. 9
II. GENERATION FACILITIES141 10
SCE owns, operates, and maintains five natural gas-fired peaking generating 11
plants (SCE peakers) and a combined-cycle gas-fired generating station called 12
Mountainview. 13
A. SCE Peaker Facilities 14
As a result of heat and power-demand conditions experienced in southern 15
California during July and August 2006, an “Assigned Commissioners’ Ruling 16
Addressing Electric Reliability Needs in Southern California for Summer 2007” (ACR) 17
in Rulemakings (R.) 05-12-013 and R.06-02-013, directed SCE to develop five SCE-18
owned, black start capable peaker units,142
of up to 250 megawatts (MW) total 19
generating capacity, in order to provide urgently needed capacity and grid reliability for 20
its entire transmission and distribution system.143
The objective was to reduce the risk of 21
shortages and blackouts during peak demand periods and other system emergencies. 22
141 Information about SCE’s generation facilities was provided in SCE’s testimony and data request responses. 142 Black start is the ability to start or restore a power generator to operation without relying on energy sources external to the facility. 143 Consolidated ACR dated 8/15/2006.
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SCE filed Application (A.) 07-12-029 in order to recover costs associated with 1
acquiring and installing the five peakers, the first four of which became operational in 2
September 2007. 3
The June 9, 2009 Scoping Memorandum in A.07-12-029 excluded costs related to 4
the fifth peaker which had not yet been constructed, and ordered SCE to file a separate, 5
subsequent application to recover reasonable costs associated with it once it was 6
installed. Decision (D.) 10-05-008 approved SCE’s request for the four peakers. 7
The fifth peaker, the McGrath Peaker Generating Station (McGrath Peaker), 8
became operational on November 1, 2012. SCE then filed A.12-12-028 on 9
December 31, 2012 to demonstrate the reasonableness of the costs incurred to install the 10
McGrath Peaker, and request recovery of the revenue requirement associated with it. The 11
Commission, in D.14-06-043, approved SCE’s request. 12
Each of the five SCE peakers consists of a single, simple-cycle combustion turbine 13
generator of approximately 49 MW rated net capacity. Together, the five SCE Peakers 14
offer 245 MW of generating capacity.144 15
Peaker units, because they are small, generally can reach full generating capacity 16
within 10 to 15 minutes to meet immediate demand on the grid. The SCE peakers 17
contribute to bulk power grid reliability with quick starting and rapid ramping 18
capabilities. 145 Because of their relatively low startup costs and ability to start up and 19
shut down quickly, the SCE peakers can run several times per day, and only when 20
needed. 21
SCE adds that the power from its peakers is used for the CAISO Energy and 22
Ancillary Services markets, where the units can be run to meet unexpected customer 23
demand, respond to unplanned system contingencies, or simply provide required system 24
operating reserves by remaining off-line but immediately available.146 Because of the 25
144 SCE Testimony SCE-01 at p. 56. 145 Ibid. 146 SCE testimony SCE-01 at p. 56.
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peakers’ black-start capability, they can be used to help restore power if the grid 1
experiences a total shutdown or “black-out.”147 2
However, there is a limitation to a peaker’s use on a daily and annual basis; they 3
are not allowed to exceed their respective daily and annual air emissions permit limits.148 4
The five SCE peakers are: 5
1. Barre Peaker 6
The Barre Peaker is located at SCE’s Barre Substation in Stanton, California (CA). 7
The commercial operation date was September 20, 2007. 8
2. Center Peaker 9
The Center Peaker is located at SCE’s Center Substation in Norwalk, CA. The 10
commercial operation date was September 20, 2007. Pursuant to Commission Resolution 11
E-4791, the Peaker underwent Enhanced Gas Turbine upgrades during 2016, which 12
included the integration of a battery energy storage system into the Peaker.149 13
3. Grapeland Peaker 14
The Grapeland Peaker is located at SCE’s Etiwanda Substation in Rancho 15
Cucamonga, CA. The commercial operation date was September 20, 2007. Pursuant to 16
Commission Resolution E-4791, the Peaker underwent Enhanced Gas Turbine upgrades 17
during 2016, which included the integration of a battery energy storage system into the 18
Peaker.150 19
4. McGrath Peaker 20
The McGrath Peaker is located next to NRG’s Mandalay Generating Station in 21
Oxnard, CA. The commercial operation date was November 1, 2012. 22
147 Ibid. 148 Ibid. 149 Ibid. 150 Ibid.
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5. Mira Loma Peaker 1
The Mira Loma Peaker is located at SCE’s Mira Loma Substation in Ontario, CA. 2
The commercial operation date was September 20, 2007. 3
B. Mountainview Generating Station 4
The Mountainview Generating Station (Mountainview Station) is a two-unit (Unit 5
3 and Unit 4) combined-cycle gas turbine (CCGT) power plant located at the corner of 6
Mountain View Avenue and East San Bernardino Avenue in Redlands, CA. According 7
to SCE testimony, Unit 3 and Unit 4 have a combined total nominal capacity of 1,050 8
MW. Each unit consists of two combustion turbines and one steam turbine, and 9
generates approximately 525 MW of power.151 10
The current Mountainview Station was built on the site of SCE’s former San 11
Bernardino Generating Station, which consisted of two units, Unit 1 and 2, both of which 12
were demolished and removed from the site since decommissioning started in 2009. SCE 13
sold the San Bernardino Generating Station as part of its generation divestiture during 14
electric restructuring.152 The sale to Thermo Ecotek Corporation was approved by the 15
Commission in D.97-12-106153. Thermo Ecotek subsequently changed the name of the 16
facility to Mountainview.154 17
The original project proponent of Unit 3 and 4 was Thermo Ecotek, and its 18
Application For Certification (AFC) was filed with the California Energy Commission 19
(CEC) on February 1, 2000.155 The CEC approved the AFC on March 21, 2001. AES 20
Corporation on July 31, 2001 purchased Thermo Ecotek from Ecotek’s parent company, 21
151 SCE’s testimony SCE-01C. 152 The divestiture was undertaken in accordance with Decision 95-12-063, as modified by Decision 96-01-009, Assembly Bill 1890, and Decision 03-02-028. 153 A.96-11-046 In the Matter of the Application of Southern California Edison Company (U-338-E) for authority to sell gas-fired electrical generation facilities. 154 Powermag.com 8/15/2006 article on Mountainview. http://www.powermag.com/mountainview-power-plant-redlands-california/?pagenum=2. 155 http://www.energy.ca.gov/sitingcases/mountainview/
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Thermo Electron Corporation, and the sale included the Mountainview power plant.156 In 1
April 2003, Intergen (a Shell-Bechtel venture) bought the Mountainview Project from 2
AES. 3
Sequoia Generating Company, LLC (Sequoia), a subsidiary of Intergen, managed 4
the Mountainview Station project, as Sequoia’s subsidiary, Mountainview Power 5
Company, LCC (MVL). SCE, in application A.03-07-032,157 filed on July 21, 2003, 6
sought the Commission’s authorization to acquire MVL either as a wholly owned 7
subsidiary and to enter into a Power Purchase Agreement (PPA) with MVL for electricity 8
from the Mountainview Power Project, or as a utility-owned generation facility. The 9
Commission approved the application in D.03-12-059 on December 18, 2003. This 10
application was supplemented with two additional Decisions, D.04-03-037158 and 11
D.04-04-019.159 MVL became a wholly-owned subsidiary of SCE, and held a PPA with 12
SCE. 13
In D.09-03-025160, the Commission approved SCE’s request to operate 14
Mountainview as a utility-owned generation facility rather than as a PPA lessee. In the 15
General Rate Case (GRC) Decision, the Commission “…approve[d] the transfer of 16
ownership”161, and “…allow[ed] SCE to acquire direct ownership of Mountainview, and 17
to include its capital costs in rate base and recover its operating costs through the TY 18
[Test Year] 2009 revenue requirement.”162 19
156 Thermo Electron Corporation’s New Release on July 31, 2001. 157 In the Matter of the Application of Southern California Edison Company (U 338-E) for Approval of a Power Purchase Agreement under PUHCA Section 32(k) Between the Utility and a Wholly-Owned Subsidiary and for Authority to Recover the Costs of Such Power Purchase Agreement in Rates. 158 Opinion Adopting Federal Energy Regulatory Commission’s Changes To The Mountainview Power Purchase Agreement Approved By This Commission In Decision 03-12-059. 159 Order Modifying Decision 03-12-059 And Denying Rehearing Of Decision, As Modified. 160 SCE’s GRC Application A.07-11-011 for Test Year (TY) 2009. 161 D.09-03-025 (A.07-11-011) at p. 33. 162 Id. at p. 365.
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Unit 3 of the Mountainview Station began commercial operation on December 10, 1
2005, and Unit 4 on January 19, 2006. Each unit produces approximately 525 MW: the 2
Station consists of two combustion turbines (CTs) rated at 170 MW each, and one steam 3
turbine (ST) rated at 185 MW.163 4
Although Unit 3 and Unit 4 each have a nominal net capacity rating of 525 MW, 5
actual power output varies above and below this figure as a function of ambient weather 6
(such as temperature and humidity). Additionally, the Mountainview Station is not 7
operated as a “base-load” plant; it is not operated constantly at its full rated output level, 8
but rather as an “intermediate duty” plant. Its power output fluctuates in real-time based 9
on dispatch orders as required to meet current power requirements and changing market 10
conditions.164 11
III. OUTAGES 12
For the 2016 Record Period, ORA reviewed the Grapeland Peaker (Grapeland) 13
outage that started on October 20, 2016. 14
A. GRAPELAND PEAKER Outage – October 20, 2016 15
The Grapeland Peaker outage started on October 20, 2016 at 10:30 hours and 16
ended on October 22, 2016 at 19:30 hours, a total of 2.375 days (2 days and 9 hours).165 17
163 SCE response to ORA Data Request 12, Question 3 in A.16-04-001. 164 SCE Response to ORA Data Request 12, Question 3 in A.16-04-001. 165 SCE response to ORA Data Request 16, Question 5.
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The shutdown was due to the failure of the silencers166 located inside the variable 1
bleed valve167 duct work (the duct in question provides air passage to compressor168 bleed 2
valves169 during start up and shut down). 3
An operator was performing a routine inspection and noticed the variable-bleed 4
valves (VBV) duct outlet screen was partially plugged with noise insulation material. 5
Upon further inspection, it was discovered that noise attenuation components mounted 6
within the VBV duct had broken free. At the time of the inspection, the unit was off line, 7
as it had not been dispatched to generate electricity during that time. An outage was then 8
submitted for further inspection and to implement repairs.170 9
Necessary repairs required removal of the duct work via crane and re-welding of 10
the silencers to the duct work. Repairs were completed on October 22, 2016 and the 11
plant was returned to service.171 12
SCE explained the amount of time taken to do the work repair as follows:172 13
166 SCE response to ORA Data Request 16, Question 7: A silencer reduces the level of noise emitted by the generating station. Silencers of various forms (including equipment enclosures) are used in different areas of the SCE peaker generating stations. 167 SCE response to ORA Data Request 16, Question 9: The term "variable" means that the valve can be modulated to control (i.e., to vary) the amount of compressed air that is being siphoned away. The peaker variable-bleed valves (VBV) are arranged in the flow passage between the low-pressure compressor (LPC) section and high pressure compressor (HPC) section of the combustion turbine. The VBVs are used to control the airflow flow rate out of the HPC section and into the combustion turbine combustion section. This control is needed to prevent turbine stalling and surging conditions during start-up. These valves are fully open at idle and progressively close to zero bleed at approximately at 50% power. 168 SCE response to ORA Data Request 16, Question 11: A compressor is a device that is used to increase the pressure of gas (e.g., air). The SCE peakers are equipped with air inlet ducting and other equipment that guide the flow of air into the compressor section of the combustion turbine. This compressor section increases the air pressure, and routes the compressed air to the turbine combustion section. Natural gas fuel is also injected into the combustion section. The heated, compressed exhaust gases that result from the combustion of the compressed air and fuel, are then routed through the power turbine section of the combustion turbine. This heat energy is extracted by the turbine, and causes the turbine/generator shaft to rotate (i.e. spin) at high speed. The generator converts this rotational energy into electricity. 169 SCE response to ORA Data Request 16, Question 8: A “bleed valve” is a valve which is used to siphon off a portion of the flow (compressed air in this case) from a system. 170 SCE response to Data Request 16, Question 15. 171 SCE testimony SCE-01 at p. 62. 172 SCE response to ORA Data Request 16, Question 6.
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“This amount of time was required to: a) assess the extent of 1 the damage, b) obtain repair parts and c) perform necessary 2 repairs. SCE prioritizes work based on system requirements. 3 Following the conclusion of the outage on October 22, the 4 unit was not immediately started. The unit next operated on 5 October 26, 2016 as it was not required to meet system 6 requirements until that date.” 7
Figure 4-1173 Partial Sectional View of Silencer and Variable Bleed Valve
173 SCE response to ORA Data Request 16, Question 13.
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Figure 4-2174 Cross-Sectional View of the Silencer
ORA reviewed SCE’s application, prepared testimony, and responses to ORA’s 1
data requests for the 2016 Record Period. Also, ORA met with SCE on April 20, 2017 at 2
the Grapeland Peaker site in Rancho Cucamonga to observe the facility in order to have a 3
better understanding of the October 20, 2016 outage. 4
SCE did not issue any post-mortem or Root Cause Evaluation (RCE) Report for 5
this outage. Based on visual examination, SCE personnel concluded that some of the 6
welds, which hold the insulation screen in place, failed.175 In addition, the conditions 7
174 SCE response to ORA Data Request 16 Question 13. 175 SCE response to ORA Data Request 16, Question 22.
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related to this outage did not require involvement of the Air Quality Management District 1
or other agencies.176 2
SCE explains the failure as follows:177 3
“The welds, which secure the insulation retention screens, 4 failed. These screens are mounted on the outside surface of 5 the air flow guides (or "splitters"178). These splitters are 6 mounted inside the duct and channel the air flow. SCE 7 suspects the weld failure resulted from normal levels of duct 8 vibration over the Peakers [after] many years of service. 9
“The screens had detached from the splitters, which resulted 10 in loose insulation partially plugging the duct.” 11
Grapeland began commercial service on September 20, 2007, and it is plausible 12
that the weld would fail after 9 years in service under cyclic conditions. An operator 13
discovered the damage during his/her routine inspection. If left unchecked, the damages 14
might have been worse, and there may have been a much longer down time and larger 15
cost to repair more equipment components. 16
SCE provided an inadequate response to ORA’s request for information on the 17
Commission’s approved depreciation life of the damaged parts.179 SCE predicated its 18
response with an objection to the question stating that it relates to costs that are beyond 19
the scope of this ERRA proceeding, and then added, “SCE utilizes group depreciation 20
methods and the parts in question do not have a separate depreciable life from the rest of 21
the plant.” The response did not provide the specific information sought by ORA. 22
The reasonableness of an equipment failure depends in part on the years in service 23
of the equipment. Expected years in service are normally used to determine the proper 24
depreciation life. ORA expects cooperation from SCE in answering the question on 25
depreciation in future filings. 26
176 SCE response to ORA Data Request 16, Question 23. 177 SCE response to ORA Data Request 16, Question 17. 178 See Figure 4-2 for the location of the splitters. 179 SCE response to ORA Data Request 16, Question 31.
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Corrective Actions 1
The sound insulation was replaced. The other parts that came loose were 2
reattached to the duct work. The insulation was replaced and the loose screens (that hold 3
the insulation in place) were reattached. 180 SCE did not indicate in the data request 4
response whether the new reattachments were new welds or other types of connections, 5
such as bolted connections. 6
SCE also inspected and repaired these screens at two other facilities.181 Going 7
forward, the welds will be inspected during regularly scheduled maintenance outages.182 8
Cost of Outage 9
The cost of the outage consists of two components: the cost of energy purchased 10
to replace the unavailable generation facility, and the cost of the repair work at 11
Grapeland. 12
According to SCE, the replacement power cost for the 2.375-day outage was 13
$11,967.94.183 14
As for SCE’s direct cost of the outage, SCE stated the total cost was $8, 873 (labor 15
cost was $1,304 and the non-labor cost was $7,569).184 16
The total cost to SCE of this outage from both replacement power and SCE’s 17
direct cost is $20,841. 18
IV. CONCLUSIONS AND RECOMMENDATIONS 19
After reviewing SCE’s testimony and responses to ORA’s data requests, ORA 20
agrees with the implementation of the corrective actions indicated by SCE for the 21
Grapeland Peaker outage on October 20, 2016.22
180 SCE response to ORA Data Request 16, Question 17. 181 SCE response to ORA Data Request 16, Question 38. 182 SCE response to ORA Data Request 16, Question 22. 183 SCE response to ORA Data Request 6, Question 3. 184 SCE response to ORA Data Request 16, Question 33.
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CHAPTER 5: UTILITY-OWNED GENERATION - NUCLEAR 1
(Michael Yeo) 2
I. SUMMARY AND RECOMMENDATIONS 3
This chapter addresses the operation of the Palo Verde Nuclear Generating Station 4
(Palo Verde) in Arizona, and outages that occurred at this facility during the 2016 Record 5
Period. 6
After reviewing SCE’s testimony and responses to ORA’s data requests, ORA 7
recommends that the Commission order SCE to: 8
a. submit supplemental testimony in November 2017 when 9 the Nuclear Regulatory Commission (NRC) issues its 10 report on the Unit 1 outage. ORA reserves the right to 11 recommend disallowances based on the NRC Report; 12
b. include NRC reports and correspondence as part of its 13 annual Energy Resource Recovery Account (ERRA) 14 Compliance filings. 15
ORA also recommends that the Commission order SCE to confer with Arizona 16
Public Service (APS) to: 17
a. replace the broken sprinkler head; 18
b. establish an inspection and periodic replacement program 19 to assure the integrity of safety-related equipment, subject 20 to cost-effectiveness analyses; 21
c. protect all sensitive electrical equipment from possible 22 water-related hard ground faults whenever the sprinkler 23 system is tested; 24
d. implement the corrective actions in APS’s Root Cause 25 Evaluation (RCE) Report, subject to cost-effectiveness 26 analyses; 27
e. seek NRC concurrence if APS chooses not to implement 28 some of the corrective actions; and 29
f. report its compliance on the implementation and 30 effectiveness of all the aforementioned corrective actions 31 in its future annual ERRA Compliance filings. 32
II. DISCUSSION AND ANALYSIS 33
The Palo Verde Nuclear Generating Station (Palo Verde Station) is located near 34
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Wintersburg in western Arizona, about 50 miles west of downtown Phoenix, Arizona. 1
The facility is regulated by the United States Nuclear Regulatory Commission (NRC), 2
whose regulatory activities include reactor safety oversight and reactor license renewal of 3
existing plants, materials safety oversight and materials licensing, and nuclear waste 4
management. 5
The Palo Verde Station consists of three pressurized water reactor units, Unit 1, 2 6
and 3. 7
a. Unit 1 has a rated capacity of 1,311 MWe, and its reactor 8 core is rated for 3,990 MWt.
185 Its original operating 9
license was issued on June 1, 1985, and the current 10 operating license, renewed on April 21, 2011, is due to 11 expire on June 1, 2045. 12
b. Unit 2 has a rated capacity of 1,314 MWe, and its reactor 13 core is rated for 3,990 MWt. Its original operating license 14 was issued on April 24, 1986, and the current operating 15 license, renewed on April 21, 2011, is due to expire on 16 April 24, 2046. 17
c. Unit 3 has a rated capacity of 1,312 MWe, and its reactor 18 core is rated for 3,990 MWt. Its original operating license 19 was issued on November 25, 1987, and the current 20 operating license, renewed on April 21, 2011, is due to 21 expire on November 25, 2047. 22
The three Palo Verde nuclear units are identical units located contiguously with 23
each other on the same site (see Figure 5-1). The cross-sectional view of a Palo Verde 24
unit is shown in Figure 5-2 25
The operating license holder is Arizona Public Service (APS), an electric utility 26
company in Arizona; APS is also regulated by the Arizona Corporation Commission, the 27
state agency which regulates most of the energy utilities in Arizona. 28
185 MWe stands for Megawatt Electric, and is the rating of the generator output to the power grid. MWt, stands for Megawatt Thermal, and is the rating of the actual reactor core. Information on the MWe and the MWt capacities was provided in SCE testimony and on the NRC website.
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There are seven owners of the Palo Verde Station, and the ownership breakdown 1
is as follows186
: 2
i. SCE 15.8%
ii. APS 29.1%
iii. Salt River Project 17.5%
iv. El Paso Electric 15.8%
v. Public Service of New Mexico 15.8%
vi. Southern California Public Power Authority 10.2%
vii. Los Angeles Department of Water & Power 5.7%
TOTAL 100.00%
Figure 5.1187
Layout of the three Palo Verde Station Units
186 SCE response to ORA Data Request 15, Question 2. 187 SCE response to Data Request 15, Question 6.
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Figure 5.2188
Cross-Sectional View of a Palo Verde Unit
188 SCE response to ORA Data Request 15, Question 13.
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III. OUTAGES 1
ORA selected the Palo Verde Station Unit 1(PV1) forced outage on 2
September 7, 2016 for more in-depth follow-up review and analysis. 3
A. UNIT 1 Outage – September 7, 2016 4
This particular outage lasted 5 days, 11 hours and 43 minutes (5.49 days) – 5
from September 7, 2016 at 21:32 hours to September 13, 2016 at 09:15 hours. In 6
its testimony, SCE stated that the shutdown started when a fire protection sprinkler 7
head broke. That led to a series of events, which led to the eventual shutdown of 8
the unit. 9
When the fire water pipeline was re-pressurized after testing, the sprinkler 10
head broke. 300 gallons of water189 were sprayed onto the load center control190 11
power bus,191 and this resulted in a hard ground fault.192 12
One of the buses fed electrically from the now ground-faulted load center 13
L25 was Bus D11. The Operator manually depressed the static transfer switch to 14
transfer Bus D11 to another power source, but the switching failed. The switching 15
failed because a capacitor on Bus D11 failed to open, resulting in a momentary 16
high voltage transient.193 Electrical power was needed in Bus D11 because it 17
powered the pressurizer194 spray valve (PSV) #100F;195 the latter was stuck in a 18
189 SCE response to ORA Data Request 15, Question 18. 190 SCE response to ORA Data Request 15, Question 10: A load center is an electrical service box or panel that receives incoming electrical current and distributes it to one or more downstream electrical buses or circuits, e.g. Bus D11. Each bus or circuit is equipped with a protective circuit breaker. 191 SCE response to ORA Data Request 15, Question 12: The load center control power bus is the electrical circuit through which electrical current is delivered to the load center. 192 SCE response to ORA Data Request 15, Question 9: A “hard ground fault” is an accidental short-circuit in the flow of electricity that does not automatically reset, and a “hard ground indication” is a signal that indicates that an electrical ground fault has occurred. 193 SCE response to ORA Data Request 15, Question 18. 194 See Figure 5-2 for the location of the pressurizer. 195 SCE response to ORA Data Request 15, Question 18.
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partially-open position because the high voltage transient caused it to open 1
initially,196 but then it could not be fully closed because of its failed O-rings. 2
With the PSV 100F partially open, cool water began to inject into the 3
pressurizer. This dousing caused the pressure to drop in the pressurizer.197 4
Attempts were made to close the PSV 100F, but were unsuccessful. 5
Meanwhile, the pressure in the Reactor Coolant System198 (RCS) began to drop. 6
At this point, the Control Room staff manually tripped Unit 1. 7
SCE explains, “The shutdown was required because the pressure in the 8
pressurizer was decreasing and the decrease could not be stopped by plant 9
operators. In order to control temperature in a pressurized water reactor, the 10
pressure in the system needs to be maintained within required parameters. If the 11
pressure is too high or too low, the reactor will trip automatically or need to be 12
tripped manually before the system reaches the design set point.”199 13
ORA reviewed SCE’s application, prepared testimony, and responses to 14
ORA’s data requests for the 2016 Record Period. Also, ORA had a conference 15
call with SCE on June 29, 2017 to provide an overview of the outage; that call 16
included a slide presentation. 17
In addition, ORA reviewed the following documents: 18
a. Palo Verde’s in-house Root Cause Evaluation 19 (RCE) Report #16-14218-021 Revision 1 on the 20 September 7, 2016 shutdown. 21
One important aspect that the RCE Report 22 indicated was that there were no safety 23 components which contributed to the event or 24 causes.200 However, the RCE Report did provide a 25
196 SCE response to ORA Data Request 15, Question 18 and 26. 197 SCE response to ORA Data Request 15, Question 18 and 19. 198 The RCS is shown in orange in Figure 5-2. 199 SCE response to ORA Data Request 15, Question 19. 200 RCE Report R1 at p. 12.
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table of corrective actions to prevent recurrence of 1 the outage; those items are listed on page 22 to 26 2 of the RCE Report (Attachment 5.1). SCE states, 3 “The corrective actions APS implemented to 4 correct the problems that caused the outage are 5 discussed in the Root Cause Evaluation Report 6 that APS developed regarding this outage.”201 In 7 addition, SCE adds that the repairs, corrective 8 actions, and extent of condition analysis 9 performed by APS were appropriate and 10 reasonable.202 11
b. Emerson Process Management’s March 14, 2017 12 Technical Evaluation Report entitled 2625 Volume 13 Booster Failure to Exhaust Serial Numbers: 14 R000550123, R000143943, 0020659951. 15
Emerson Process Management did a forensic 16 analysis of the pressurizer spray valve positioner 17 that did not fully close after the high voltage 18 transient that caused it to open. This analysis 19 determined that the root cause of the outage was 20 multiple failed O-rings in the volume booster of the 21 valve positioner.203 22
ORA is unable to determine whether the NRC has determined any APS 23
failures due to this incident because the NRC Report on this outage will not be 24
completed till sometime in November 2017.204 25
SCE explained why it took APS about five and half days to restore the 26
facility back to service as follows: 27
“Arizona Public Service Company (APS) took as 28 much time as needed to accurately and safely identify 29 and evaluate the cause(s) of the unplanned outage, 30
201 SCE response to ORA Data Request 15, Question 39. 202 Ibid. 203 SCE response to ORA Data Request 15, Question 26. 204 SCE response to ORA Data Request 15, Question 28.
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implement corrective actions, and restore the unit to 1 power operation. Resumption of power after a repair 2 typically requires additional time due to nuclear 3 procedures that require methodical and cautious 4 increases in reactor and turbine generator power.”205 5
1. Corrective Actions 6
The items that were found damaged in this incident were:206 7
a. Fire sprinkler head – Wet Pipe Sprinkler System: 8 this system was installed during original plant 9 construction and is approximately 30 years old. 10 The system is maintained by the Palo Verde fire 11 protection group and there is no warranty on the 12 equipment. 13
b. Capacitor – Static Transfer Switch: this static 14 transfer switch is also original plant equipment and 15 is maintained by the Palo Verde electrical shop. 16 The capacitor in question was installed during 17 routine preventive maintenance in October 2014 18 and is replaced every 9 years. This capacitor has a 19 24 month warranty from the time the component is 20 received. This component was received onsite in 21 2006, therefore at the time of failure the capacitor 22 was not under warranty. 23
c. O-Ring – Volume Booster: this component is part 24 of a larger system and the booster was received on 25 site in July 2014, the warranty for these 26 components are 12 months after first use. The 27 component was put in service in October 2014 and 28 failed in September of 2016 and therefore was not 29 under warranty. 30
When ORA asked SCE to list all the parts that were repaired and/or 31
replaced, SCE directed ORA to the RCE Report.207 However, ORA could not 32
find, in the RCE Report, a reference to the replacement of the fire sprinkler head. 33
205 SCE response to ORA Data Request 15, Question 8. 206 SCE response to ORA Data Request 15, Question 33. 207 SCE response to ORA Data Request 15, Question 21.
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It is not clear what actions had actually been taken, such as, the capping of the 1
sprinkler at that location, the rerouting or removal of the sprinkler line, or the 2
installation of a new sprinkler head. 3
ORA considers that it is reasonable for the sprinkler head, after 30 years in 4
service, to break during sprinkler system testing. However, there should be an 5
inspection and periodic replacement program to assure the integrity of equipment 6
before such testing. In addition, APS should protect all sensitive electrical 7
equipment from possible water-related hard ground faults whenever the sprinkler 8
system is tested. ORA could not find, in the RCE Report, corrective actions to 9
address the afore-mentioned items of concern to prevent similar outage incident; 10
this outage, though it only lasted 5.5 days, resulted in a ratepayer cost of 11
dollars (see below). 12
The RCE Report, in addition to identifying the damaged parts replaced, 13
also lists other corrective action items (see Attachment 5-1). The corrective 14
actions, as shown in Attachment 5-1, are grouped into four priorities –immediate 15
action, Level 1, Level 2 and Level 3. Each corrective action item has a proposed 16
due date, and some were indicated in the RCE Report as already completed. 17
2. Cost of Outage 18
The cost of the outage consists of two components: the cost of energy that 19
SCE had to purchase to replace the unavailable generation facility, and the cost of 20
the repair work at Palo Verde Unit 1. 21
SCE’s portion of the replacement power cost for the 5.49-day outage was 22
.208 23
SCE’s direct cost of the outage to repair the damage was $23,912.27. The 24
cost breakdown is as follows: 25
208 SCE response to ORA Data Request 15, Question 31.
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Table 5-1
Direct SCE Cost209
Therefore, the total cost of this outage from both replacement power and 1
SCE’s direct cost is estimated to be . 2
IV. CONCLUSIONS AND RECOMMENDATIONS 3
Based on ORA’s review of the afore-mentioned documents and report, 4
ORA recommends that the Commission order SCE to: 5
a. submit supplemental testimony in November 2017 6 when the NRC issues its report on the Unit 1 7 outage. SCE’s testimony should provide a 8 description of all NRC findings of APS failures (if 9 any), the actual NRC Report, and SCE’s 10 explanation of those NRC findings. ORA reserves 11 the right to recommend disallowances based on the 12 NRC Report; and 13
b. include NRC reports and correspondence as part of 14 its annual ERRA Compliance filings. 15
ORA also recommends that the Commission order SCE to confer with APS 16
to: 17
a. replace the broken sprinkler head; 18
209 SCE response to ORA Data Request 15, Question 37.
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b. establish an inspection and periodic replacement 1 program to assure the integrity of safety-related 2 equipment, subject to cost-effectiveness analyses; 3
c. protect all sensitive electrical equipment from 4 possible water-related hard ground faults whenever 5 the sprinkler system is tested; 6
d. implement the corrective actions in APS’s RCE 7 Report, subject to cost-effectiveness analyses; 8
e. seek NRC concurrence if APS chooses not to 9 implement some of the corrective actions; and 10
f. report its compliance on the implementation and 11 effectiveness of all the aforementioned corrective 12 actions in its future annual ERRA Compliance 13 filings. 14
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CHAPTER 6: CONTRACT ADMINISTRATION 1
(Patrick Cunningham) 2
I. INTRODUCTION 3
This chapter of testimony presents the Office of Ratepayer Advocates’ 4
(ORA) review and analysis of Southern California Edison Company’s (SCE) 5
contract administration as presented in its testimony in Chapter VII of SCE’s 6
Energy Resource Recovery Account (ERRA) Compliance Application 7
(A.) 17-04-004. ORA reviewed SCE’s administration, modification, and 8
termination of current Qualifying Facility (QF) and non-QF contracts. Also, ORA 9
reviewed new contracts seeking approval through the application. Bilateral 10
disputes and modifications which resulted in a notional change in value of the 11
contract were analyzed in depth. Financial transactions and hedging representing 12
SCE’s execution of long term economic power to purchase economic short power 13
were also reviewed. The analysis presented in this chapter is conducted by ORA 14
to ensure the utility prudently administered its contracts for the benefit of 15
ratepayers under guidance set by the California Public Utilities Commission’s 16
(Commission) Standard of Conduct 4. 17
II. RECOMMENDATIONS 18
ORA does not object to SCE’s request for approval of new contracts. SCE 19
prudently managed its contracts, modifications to contracts, and in general 20
administered its contracts appropriately. 21
III. BACKGROUND 22
On April 1, 2017, SCE filed its ERRA application seeking Commission 23
approval of its contract administration, least-cost dispatch (LCD), and 24
procurement activities for the 2016 Record Period. ORA gathered additional 25
information about specific contracts in SCE’s portfolio that underwent 26
modification, termination, and expiration in the Record Period through its Master 27
Data Request (MDR), subsequent data requests, review of past ERRA 28
applications, review of Commission decisions, and discussions. 29
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In the ERRA compliance filing, ORA reviewed contracts in SCE’s 1
portfolio which underwent introduction, modification, dispute, or termination 2
during the Record Period. Public Utilities Code Section 454.5(d)(2) established 3
“a regulatory process to verify and ensure that each contract was administered in 4
accordance with terms of the contract, and contract disputes that may arise are 5
reasonably resolved.” ORA’s review and analysis of a utility’s energy 6
procurement contracts are guided by two major ERRA decisions: Decision 7
(D.) 02-10-062 and D.02-012-074 (the October and December decisions 8
respectively). The October decision set forth the guidelines for California’s three 9
investor-owned utilities (IOUs or utilities) to resume procurement responsibilities 10
following the Energy Crisis of 2000-2001.210 This Decision ordered the utilities to 11
comply with minimum standards of conduct, including Standard of Conduct 4 12
(SOC 4). SOC 4 states that, “the utilities shall prudently administer all contracts 13
and generation resources and dispatch the energy in a least-cost manner.”211 SOC 14
4 was modified by the December decision to include specific terms regarding 15
contract administration: 16
Prudent contract administration includes 17 administration of all contracts within the terms and 18 conditions of those contracts... In administering 19 contracts, the utilities have the responsibility to 20 dispose of economic long power and to purchase 21 economic short power in a manner that minimizes 22 ratepayer costs… The utility bears the burden of 23 proving compliance with the standard set forth in its 24 plan.212 25
210 D.02-12-074 at p. 2. 211 D.02-10-062 at p. 52 and Conclusion of Law 11 at p. 74. 212 D.02-12-074 at p. 54.
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IV. DISCUSSION AND ANALYSIS 1
A. New Contracts 2
1. Conventional and Natural Gas 3
SCE executed forty-nine new conventional and natural gas contracts in 4
2016. SCE is seeking approval for six of these new contracts through this ERRA 5
application.213 6
SCE defines conventional energy contracts as fossil-fired resources that are 7
not exclusively Qualifying Facilities (QF), Combined Heat and Power (CHP), 8
Renewable Portfolio Standard (RPS), or behind-the-meter (BTM).214 This 9
category also includes the agreement for electricity from the Hoover dam, which 10
does not appropriately fit into any other category.215 11
The six contracts for which SCE is seeking approval are all natural gas 12
transportation agreements between SCE and Southern California Gas Company. 13
Each contract is an auto-renewal for existing approved contracts that were 14
renewed on February 1, 2016. There was no change in notional value of the 15
contracts and SCE was unable to renegotiate the contracts due to the nature of the 16
decision which authorized them.216 17
ORA recommends that the Commission approve the six Southern 18
California Gas Company contracts listed on Table VII-41 of SCE’s testimony.217 19
2. PURPA and CHP 20
Four PURPA/CHP contracts were executed in 2016, all of which have 21
already been approved through Commission filings or Quarterly Compliance 22
Reports.218 23
213 SCE Testimony at p. 116. 214 SCE Testimony at p. 102. 215 Attachment 6.1 – Data Request Responses at p. 1. 216 Id. at pp. 2-3. 217 SCE Testimony at p. 116. 218 Id. at p. 131.
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3. RPS 1
Sixteen RPS contracts were executed in 2016, all of which were pre-2
approved through the Renewable Market Adjusting Tariff (ReMAT) program or 3
by advice letter.219 4
4. Behind-the-Meter 5
Sixteen BTM contracts were executed in 2016.220 Three are Aliso Canyon 6
Demand Response contracts and have been approved through the 2016 Quarter 7
Third Quarter Compliance Report process. The remaining thirteen are Preferred 8
Resources Pilot contracts which were executed by SCE in 2016 but are still 9
awaiting approval in a separate process.221 10
B. Contract Assignment Administration 11
SCE seeks approval for two contract re-assignments executed in 2016. 12
Stem DRAM LLC executed a Consent to Assignment on August 15, 2016, 13
14 222 Sempra Generation LLC also 15
executed a Consent to Assignment on November 29, 2016, 16
17 223 SCE states that ratepayers either 18
benefit or are indifferent to these adjustments, with which ORA agrees. ORA 19
does not oppose these two contract assignment modifications. 20
C. Contract Amendments or Modifications 21
ORA reviewed SCE’s testimony regarding contract administration practices 22
and activities focusing specifically on the contracts that underwent modification or 23
219 Id. at p. 158. 220 Id. at p. 211. 221 The approval of these contracts is not within the scope of ERRA. The active Commission proceeding for them is A.16-11-002. 222 SCE Testimony at p. 122. 223 Id. at p. 123.
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amendment during 2016. ORA reviewed these modifications to determine if the 1
utility met the following criteria: 2
Did SCE adequately justify the rationale for the 3 contract amendment? 4
Is the contract amendment necessitated by 5 operational needs? 6
Is the contract amendment in SCE’s ratepayers’ 7 best interest? 8
What is the actual or notional value of the contract 9 amendment? 10
How is the actual and/or notional value of the 11 amendment accounted for in SCE’s expense and/or 12 revenue account? 13
ORA reviewed each amendment presented in the ERRA Compliance 14
application. Below are amendments that caused a change in contract value or 15
present an issue worthy of mention in this testimony. 16
1. Amendments to Facilitate Contractual 17 Transition 18
SCE executed 28 amendments and letter agreements to its QF and CHP 19
contracts in 2016.224 A number of these amendments were executed in order to 20
extend contracts that were nearing termination but whose counterparties were 21
finalizing changes necessary to initiate a new form of contract design, new 22
interconnection agreement, or to implement new CAISO processes.225 Eight of the 23
thirteen contracts expired without replacement due to delay or failure to re-sign a 24
new agreement.226 These new contract designs required entirely new agreements 25
and could not be conducted through an amendment. The extensions typically 26
added 1-3 months to the terms of the existing contract. The extension 27
224 SCE Testimony at p. 132. 225 Attachment 6.1 at p. 4-6. 226 Ibid.
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amendments were a work-around to the administrative burden of creating a new 1
contract which would only last a short amount of time before the new contract 2
design was adopted. The following PURPA/CHP contracts received such 3
amendments: 4
Altagas Pomona Energy Letter Agreement and 5 Amendment 5, 40 MW CHP 6
AES Tehachapi Wind LLC 85-A Amendments 7 and 7 8, 14.89 MW Wind 8
AES Tehachapi Wind LLC 85-B Amendments 7 and 9 8, 21.24 MW Wind 10
Desert Water Agency Amendment 1, 1 MW Hydro 11
Difwind Farms Limited V Amendment 3, 7.9 MW 12 Wind 13
Difwind Partners Trust Amendments 5 and 6, 14 MW 14 Wind 15
Section 16-29 Power Purchase Contract Trust 16 Amendment 6 & 7, 34 MW Wind 17
Section 22 Power Contract Trust Amendment 3 and 4, 18 17 MW Wind 19
Westwind Trust Amendment 4 and 5, 12.77 MW Wind 20
Painted Hills Wind Developers Amendment 6, 19.045 21 Wind 22
The Bank of New York Mellon Trust Company Letter 23 Agreement, 6 MW Wind 24
Oak Creek Energy Trust Amendment 3, 21.59 MW 25 Wind 26
Energy Development & Construction Corp 27 Amendment 2 and 3, 11.7 MW Wind 28
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Five227 of the amendments included provisions to decrease the cost of 1
energy SCE paid the counter-party by a small amount.228 Since these amendments 2
involve QF resources, their payments are guided by Commission decisions and 3
SCE has very limited capabilities to alter contract value. SCE reported that the 4
price of energy was reduced to 85% of the contracted price but did not create an 5
analysis of the cost savings this resulted in.229 All changes in notional value were 6
positive, representing a benefit to ratepayers through cost savings. ORA does not 7
object to these amendments which avoided administrative burden and facilitated 8
ease of transition to new contracts. 9
2. Amendments for Behind-the-Meter 10 Contracts 11
SCE executed 258 amendments for its BTM contracts in 2016. Of these, 12
27 were for distributed generation resources, 132 for energy efficiency, three for 13
demand response, and 96 for energy storage amendments. None of these 14
amendments represent a change in value of the contract or harm ratepayer 15
interests. Change in notional value is determined by generally comparing the 16
change in the total benefits and costs of a contract’s full term following the 17
amendment’s modifications.230 The majority of amendments 18
.231 19
3. Amendments Causing a Change in Value 20
A number of amendments slightly decreased the amount of energy SCE 21
may purchase from contracted solar resources. 22
23
227 Altagas, AES Tehachapi Wind 85-B, Difwind Farms Limited, Section 16-29, Oak Creek Energy. SCE Testimony Section VII.D.2.e. 228 Attachment 6.1 at p. 11. 229 Telephonic Conference between ORA (Patrick Cunningham) and SCE (Marci Palmstrom & David Cox) 7/25/17. 230 Attachment 6.1 at p. 9. 231 SCE Testimony at p. 213.
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represents a benefit to ratepayer costs.232 These amendments will 1
decrease SCE’s overall RPS procurement by a small amount. The utility currently 2
exceeds RPS requirements by a large margin so it is unlikely these small 3
reductions will have an adverse impact on future RPS obligations.233 SCE may 4
also be anticipating load departure due to the development of Community Choice 5
Aggregators in its territory. Shedding small amounts of contracted capacity, 6
especially must-take energy, will facilitate ratepayer savings in the event of load 7
departure. 8
Several amendments resulted in changes of notional value, all of which 9
reduced costs or increased value, benefitting ratepayers. One contract, Heber 10
Geothermal, experienced a payment by SCE beyond what was anticipated by the 11
contract and is described below along with other significant amendments which 12
experienced a change in value. 13
ORA does not object to SCE’s administration and conduct of all contract 14
amendments for Record Period 2016. 15
i. Heber Geothermal Company LLC 16 Amendment 5, 52MW Geothermal 17
Executed in 2016 after the contract expired, this amendment retroactively 18
extended the contract’s term by one day (from December 14, 2015 to December 19
15, 2015) in order to avoid a potential dispute.234 SCE agreed to pay 97.7% market 20
price for energy delivered on that day rather than the higher contracted price, and 21
zero payment for RA capacity.235 22
232 SCE provides brief financial analysis of these contracts in testimony Section VII.D.2.e. Contract IDs #5625, #5629, . 233 As of 4/11/17, SCE was projected to have 41.4% of its sales in renewables, above the required 33%. Commission, California Renewables Portfolio Standard Homepage. Accessed 7/26/17. http://www.cpuc.ca.gov/RPS_Homepage/. 234 SCE Testimony at p. 134. 235 Attachment 6.2 at p. 2.
195397070 6-9
SCE did not report the cost of paying for this resource’s generation on 1
December 15, 2015, but using CAISO’s public database, ORA estimates it was 2
approximately $33,658.236 The potential cost of a legal dispute may have been 3
greater than this amount. ORA finds this amendment to be a prudent decision. 4
ii. Central Antelope Dry Ranch C 5 Amendment 3, 20MW Solar PV 6
Central Antelope Dry Ranch C (CADRC) came online on May 6, 2016, 7
following an amendment executed on March 30, 2016, which resulted from a 8
.237 The 9
amendment allows for 10
11
12
iii. North Lancaster Ranch Amendment 3, 13 20MW Solar PV 14
North Lancaster came online on December 31, 2016, following an 15
amendment executed on September 21, 2016, which resulted from 16 238 The amendment provides for 17
18
19
20
iv. Longboat Solar Amendment 1, 20MW 21 Solar PV 22
Longboat Solar came online December 16, 2016, following an amendment 23
executed on January 19, 2016.239 The amendment 24
236 CAISO’s OASIS reports the average day-ahead LMP at the resource’s price node for the day was $27.605. That amount multiplied by the resource’s 52 MW capacity, multiplied by 97.7%, multiplied by 24 hours for the day is $33,658.72. Attachment 6.3. 237 SCE Testimony at p. 163. 238 SCE Testimony at p. 164. 239 Id. at p. 170.
195397070 6-10
The 1
amendment results in a 2
3
v. Coso Clean Power Amendment 6, 4 136MW Geothermal 5
The amendment is effective July 1, 2016.240 6
7
8
9
10
11
vi. Geysers Power Company Letter 12 Agreement 13
This PPA was executed on July 29, 2014 and the letter agreement was 14
executed on July 26, 2016. The contract will 15
16
17 242 18
243 19
20 244 21
22 245 23
240 Id. at p. 202. 241 Id. at pp. 162, 202. 242 Id. at p. 162. 243 Attachment 6.1 at p. 15. 244 Id. at p. 14. 245 Id. at p. 13.
195397070 6-11
vii. Regulus Solar Amendment 5, 60 MW 1 Solar 2
This amendment 3 246 4
5
6
7
viii. Caithness Shepherds Flat Contracts 8 Amendment 2, 845 MW Wind 9
Caithness Shepherds Flat is a set of three PPAs for wind resources located 10
in Oregon.248 The amendment (2nd amendment for each resource) 11
12
13
ix. Voyager Wind I Amendment 1, 132 MW 14 Wind 15
This PPA was executed on November 19, 2015 with the amendment 16
following on December 22, 2016.249 The amendment 17
18
19
20
21
22
246 SCE Testimony at p. 163. 247 Attachment 6.1 at p. 7. 248 SCE Testimony at p. 177. 249 Id. at p. 179. 250 Id. at p. 8.
195397070 6-12
D. CONTRACT TERMINATIONS 1
Eighty-eight of SCE’s contracts were either terminated or allowed to expire 2
in 2016.251 The vast majority of terminations were either due to failures to meet 3
pre-operational deadlines or by mutual agreement between SCE and the 4
counterparties. SCE appears to have conducted the terminations properly and 5
pursued securities and payments where appropriate. 6
E. DISCREPANCIES, PAYMENT ISSUES, FORCE 7 MAJEURE, AND DISPUTES 8
Issues of contract administration may arise if SCE has a difference of 9
interpretation of contract terms with counterparties.252 Inadvertent under and over 10
payments may also occur during each Record Period. SCE also has a process for 11
counterparties to file claims for an uncontrollable force which led to an 12
interruption of delivery of electricity. Major and outstanding issues from 2016 are 13
listed below. 14
1. Force Majeure (Uncontrollable Force) Claims 15
SCE received seventeen claims from counterparties seeking to excuse non-16
delivery of electricity due to an uncontrollable force. Six were denied by SCE, 17
three was approved, and eight remained outstanding at the time of the filing of the 18
ERRA application.253 ORA believes SCE administered these claims prudently. 19
2. Disputes 20
In the application, SCE describes nine different new or ongoing disputes 21
with various contract counterparties in different states of resolution. Disputes that 22
were settled this year led to either ratepayer indifference or benefit. ORA 23
concludes that SCE has prudently handled and reported the disputes against them. 24
Brief descriptions follow: 25
251 There were 18 Conventional, 29 PURPA, 32 RPS, 9 BTM. 252 Attachment 6.1 at p. 12. 253 SCE Testimony at pp. 145, 195.
195397070 6-13
Ormesa LLC’s geothermal project was derated 1 following a Capacity Demonstration test, leading to 2 damages and refunds paid to SCE. Ormesa disputed 3 the timing of payments and requested a second test, 4 but ultimately withdrew its protest.254 5
Coso Energy Developers requested a second test after 6 its geothermal project was derated. SCE denied the 7 retest, collected a refund, and considers the matter 8 closed as Coso has not communicated further.255 9
Blythe Energy and SCE 10 11
12 13
NRG/GenOn Energy Management 14 15 16
17
Satsuma and SCE are in dispute regarding the 18 termination of a PPA following costs exceeding 19 expectations. SCE is satisfied with the current state of 20 dispute, and expects the statute of limitations to cause 21 expiration of the case in 2017.258 22
Sand Canyon of Tehachapi held a PPA which was 23 terminated by SCE when costs exceeded contract caps. 24 Counterparties may attempt to sue SCE for breach of 25 contract, but arbitration is not yet scheduled.259 26
Western Water and Power Production had a PPA 27 which was terminated due to delays. A final 28 judgement ruled in favor of SCE in August 2016.260 29
254 Id. at p. 150. 255 SCE Testimony at p. 259. 256 Id. at p. 123. 257 Id. at p. 124. 258 Id. at p. 200. 259 Id. at p. 201. 260 Id. at p. 202.
195397070 6-14
Coso Clean Power initiated a dispute regarding Energy 1 Replacement Damage Amounts. 2
3 4
5
Caithness Shepherds Flat, a set of three wind farms 6 totaling 845 MW, 7
8 9
A 10 settlement was reached and executed in March, 2017, 11
12 13 14 15
16
V. CONCLUSION 17
Based on ORA’s review and analysis of the contracts above and the 18
testimony and information provided, ORA does not object to SCE’s administration 19
of its contracts for Record Period 2016. 20
261 Id. at p. 203. 262 SCE Testimony at p. 203.
195397070 7-1
CHAPTER 7: COMPLIANCE AUDIT OF THE ENERGY 1 RESOURCE RECOVERY ACCOUNT (ERRA) AND OTHER BALANCING 2
AND MEMORANDUM ACCOUNTS 3
(Brian Lui and Grant Novack) 4
I. INTRODUCTION AND SUMMARY 5
In its Application, SCE requests the Commission find that SCE’s 6
procurement related expenditures and other operations for the 2016 Record Period 7
of January 1 through December 31, 2016, and verify SCE’s entries in the Energy 8
Resource Recovery Account (ERRA) and twenty-one (21) other regulatory 9
accounts (i.e. Balancing and Memorandum accounts). The ERRA accounting 10
entries for the 2016 Record Period are summarized in Table 7-1, which shows an 11
over-collected balance of $20.311 million as of December 31, 2016. 12
This chapter presents ORA’s review of SCE’s ERRA and 21 other 13
balancing and memorandum accounts for the 2016 Record Period. ORA found no 14
required accounting adjustments and no exceptions to the recovery 15
requirements.263 ORA found that the ERRA entries and the 21 other balancing 16
and memorandum account entries are appropriate, correctly stated, and in 17
compliance with applicable Commission decisions. 18
II. DISCUSSION 19
A. Energy Resource Recovery Account (ERRA) 20
The ERRA accounting entries for the 2016 Record Period are summarized 21
in Table 7-1 below (Note: Totals may not sum by amounts shown on table due to 22
rounding): 23
263 SCE’s Greenhouse Gas Compliance Instrument procurement is addressed in ORA Chapter 8.
195397070 7-2
Table 7-1264 Energy Resource Recovery Account (ERRA)
Record Period 2016 ($000’s)
Description
Beginning Balance (1/1/16)
(439,063)Commission Authorized Transfers 1,742 Significant Adjustments (Greater than $1 Million)
3,021
Other Entries/Adjustments
(25)
Adjusted Beginning Balance
(434,326)
ERRA Revenue (3,691,912)
ERRA Expenses 4,107,194
(Over)/Under Collection 415,282
Interest
(1,268) Total ERRA Ending Balance (12/31/16) $(20,311)
The ERRA is established pursuant to Decision (D.) 02-10-062.265 The 1
purpose of the ERRA is to record the difference between ERRA-related revenue 2
and SCE’s recorded fuel costs and purchased power-related expenses, excluding 3
California Department of Water Resources (DWR) power contract expenses. 4
Electric Energy Transaction Administration (EETA) costs should be excluded 5
from the ERRA consistent with D.02-12-074.266 Pursuant to D.04-01-048, SCE is 6
authorized to record the above-market cost of Qualifying Facilities and Purchase 7
Agreements in the ERRA.267 8
264 SCE Direct Testimony Table XI-13. 265 D.02-10-062 at p. 61. 266 D.02-12-074 at p. 46. 267 D.04-01-048 at p. 24.
195397070 7-3
B. Regulatory Balancing, Memorandum, and 1 Tracking Accounts 2
The revenue, expenses, and ending balances of the 22 ratemaking accounts 3
for the applicable Record Periods are summarized in Table 7-2 (below): 4
Table 7-2268 Applicable Ratemaking Accounts
($000’s)
SOURCE:
SCE-2
TABLE
NUMBER
ACCOUNT BEGINNING
BALANCE 1/01/16
ENDING
BALANCE 12/31/16
CHANGE
XI-13 Energy Resource Recovery Account Balancing Account (ERRA BA)
(439,063)
(20,311)
418,752
XI-14 Base Revenue Requirement Balancing Account (BRRBA)
(318,847)
(426,718)
(107,871)
XI-15 Nuclear Decommissioning Adjustment Mechanism (NDAM)
(78,254)
(3,759)
74,495
XI-16 Public Purpose Programs Adjustment Mechanism (PPPAM)
314,251
109,268
(204,983)
XI-17 California Alternate Rates for Energy (CARE) Balancing Account (CBA)
(20,519)
(17,491)
3,028
XI-18 New System Generation Balancing Account (NSGBA)
(170,971)
(5,992)
164,979
XI-19 Medical Programs Balancing Account (MPBA)
(24,789)
(19,328)
5,461
268 SCE Direct Testimony Chapters XI, XII, and XIII.
195397070 7-4
SOURCE:
SCE-2
TABLE
NUMBER
ACCOUNT BEGINNING
BALANCE 1/01/16
ENDING
BALANCE 12/31/16
CHANGE
XI-21 Pension Costs Balancing Account (PCBA)
94
(8,135)
(8,229)
XI-22 Post-Employment Benefits Other than Pensions Balancing Account (PBOP BA)
(11,443)
(15,826)
(4,383)
XI-23 Results Sharing Memorandum Account (RSMA)
-
-
-
XI-24 Statewide Marketing, Education and Outreach Balancing Account (SME&OBA)
(3,617)
(10,309)
(6,692)
XI-25 Energy Settlement Memorandum Account (ESMA)
(4,517)
(48)
4,469
XI-27 Litigation Costs Tracking Account (LCTA)
6,259
3,217
(3,042)
XI-28 Charge Ready Program Balancing Account (CRPBA)
-
-
-
XI-30 Green Tariff Marketing, Education and outreach Memorandum Account (GTME&OMA) 2015 Record Period
-
32
32
XI-30 Green Tariff Marketing, Education and outreach Memorandum Account (GTME&OMA) 2016 Record Period
32
332
300
XI-31 Green Tariff Shared Renewables Administrative Costs Memorandum Account (GTSRACMA) 2015
-
77
77
195397070 7-5
SOURCE:
SCE-2
TABLE
NUMBER
ACCOUNT BEGINNING
BALANCE 1/01/16
ENDING
BALANCE 12/31/16
CHANGE
Record Period
XI-31 Green Tariff Shared Renewables Administrative Costs Memorandum Account (GTSRACMA) 2016 Record Period
77
519
442
XI-32 Green Tariff Shared Renewables Balancing Account (GTSRBA)
-
(1)
(1)
XI-33 Project Development Division Memorandum Account (PDDMA)
(4,906)
(3,832)
1,074
XI-35 Purchase Agreement Administrative Costs Balancing Account (PAACBA) 2015 Record Period
(762)
(1,242)
(480)
XI-35 Purchase Agreement Administrative Costs Balancing Account (PAACBA) 2016 Record Period
(1,242)
(1,076)
166
XI-37 Renewables Portfolio Standard Costs Memorandum Account (RPSCMA)
1,021
1,215
194
XII-38 Pole Loading and Deteriorated Pole Programs Balancing Account (PLDPBA)
(36,181)
(43,494)
(7,313)
195397070 7-6
SOURCE:
SCE-2
TABLE
NUMBER
ACCOUNT BEGINNING
BALANCE 1/01/16
ENDING
BALANCE 12/31/16
CHANGE
XIII-44 Demand Response Program Balancing Account (DRPBA) 2015 Record Period
(129,617)
(171,993)
(42,376)
XIII-44 Demand Response Program Balancing Account (DRPBA) 2016 Record Period
(171,993)
(118,226)
53,767
C. Requested 2018 Revenue Requirement Change 1
SCE is seeking a net revenue decrease in 2018 of $83.748 million, 2
including franchise fees and uncollectibles (FF&U) associated with four (4) 3
accounts. During the 2016 Record Period, one account authorized by the CPUC 4
was under-collected: the Renewables Portfolio Standard Costs Memorandum 5
Account (RPSCMA). Also during the 2016 Record Period, three accounts 6
authorized by the CPUC were over-collected: the Project Development Division 7
Memorandum Account (PDDMA), the Purchase Agreement Administrative Costs 8
BA (PAACBA), and the Demand Response Program Balancing Account 9
(DRPBA). The requested $83.748 million represents the remaining costs 10
associated with the under-collected account after offset with the over-collected 11
account. A summary of SCE’s requested net revenue decrease is shown in Table 12
7-3 below. 13
195397070 7-7
Table 7-3269 Summary of Requested 2018 Revenue Requirement Change
($000’s)
Balancing and Memorandum Accounts Revenue Change (1) Project Development Division Memorandum Account
-2,717
(2) Purchase Agreement Administrative Costs BA -1,076(3) Renewables Portfolio Standard Costs Memorandum Account
188
(4) Demand Response Program Balancing Account -79,182Total Net Over-Collection -82,787
FF&U -961Total Revenue Requirement Change - Decrease $ -83,748
III. AUDIT OBJECTIVES, SCOPE AND PROCEDURES 1
ORA reviewed SCE’s ERRA and 21 other balancing and memorandum 2
accounts for the 2016 Record Period. The objective of ORA’s review was to 3
determine whether entries recorded in the ERRA and the 21 other balancing and 4
memorandum accounts were appropriate, correctly stated, and in compliance with 5
applicable Commission decisions. ORA’s audit procedures included, but were not 6
limited to the following: 7
Reviewing SCE’s application testimony, exhibits, 8 workpapers, and data request responses; 9
Reviewing applicable Advice Letters and Commission 10 decisions; 11
Performing analytical reviews of monthly entries, 12 including reviews of monthly balances recorded for 13 each of the balancing and memorandum account tariff 14 line items during the record period, and evaluating 15 monthly and annual fluctuations; 16
Selecting a sample of balancing and memorandum 17 account monthly and tariff line items to determine 18 whether adequate support exists. ORA examined 19 invoices, journals, general ledger entries, and related 20
269 SCE Direct Testimony Table XI-11.
195397070 7-8
materials for amounts recorded in the balancing and 1 memorandum accounts and verified the mathematical 2 accuracy of accounting worksheets and supporting 3 documentation. ORA also visited SCE’s offices to 4 review and discuss each of the selected balancing and 5 memorandum monthly and tariff line items in detail 6 with SCE staff and to trace those line items to 7 supporting documents; 8
Reviewing Monthly Interest Rates used and the 9 interest amount calculations; 10
Reviewing to determine whether revenues and costs 11 recorded were appropriate and correctly stated; 12
Reviewing to determine whether SCE complied with 13 applicable Commission decisions and advice letter 14 resolutions; and 15
Reviewing copies of internal audit reports270 issued 16 during the 2016 Record Period related to balancing 17 account administration (reports listed in SCE Chapter 18 14). 19
On a judgment sample test basis, ORA reviewed those source documents 20
that support the revenues, costs,271 and expenses recorded in the ERRA. A 21
“judgment sample” is a type of nonrandom sample selected by the auditor based 22
on the judgment (opinion) of the auditor. Factors considered when selecting a 23
judgment sample include auditor judgments about various elements including but 24
not limited to the internal control environment, exposure/materiality, risk, and 25
results of analytical reviews. ORA’s judgement sample consisted of 27 26
monthly/tariff line items recorded in the ERRA. 27
ORA applied a similar sample test-basis audit methodology to review the 28
supporting documentation for the revenues, costs and expenses recorded in the 21 29
other balancing and memorandum accounts. 30
270 Includes SCE Direct Testimony Section XIV. 2016 ERRA Review – ERRA-Related Audit Testimony. 271 Includes CAISO-related costs also shown in SCE Direct Testimony Table X-10.
195397070 7-9
IV. CONCLUSIONS AND RECOMMENDATIONS272 1
ORA found that SCE appropriately operated the balancing, memorandum, 2
and tracking accounts during the 2016 Record Period, and that the recorded entries 3
in these accounts were appropriate, correctly stated, and in compliance with 4
applicable Commission decisions. 5
ORA concludes that SCE’s requested total net revenue change (decrease of 6
$83.748 million) in 2018 as shown in ORA Table 7-3, which pertains to the 7
recorded costs and revenues of four accounts, is supported and correctly stated. 8
ORA does not object to SCE’s request for approval of the $83.748 million net 9
revenue requirement decrease. 10
272 As previously stated in fn. 1, SCE’s Greenhouse Gas Compliance Instrument procurement is addressed in ORA Chapter 8.
195397070 8-1
CHAPTER 8: GREENHOUSE GAS COMPLIANCE 1
(Tom Gariffo) 2
I. SUMMARY 3
In the 2016 Record Period from January 1, 2016 through 4
December 31, 2016, SCE incurred greenhouse gas (GHG) direct compliance costs 5
of for compliance with the California Air Resources Board (ARB) 6
Cap-and-Trade Regulation.273 ORA reviewed SCE’s reported compliance costs, 7
GHG compliance instrument procurement, 2016 Quarterly Compliance Reports 8
(QCRs), Procurement Review Group (PRG) meeting materials, and data request 9
responses. ORA is satisfied that SCE procured GHG compliance instruments in 10
accordance with its approved GHG Procurement Plan within its Bundled 11
Procurement Plan (BPP). ORA also reviewed SCE’s GHG compliance instrument 12
procurement strategy. Based on its review, ORA has no objection to SCE’s 13
request that the California Public Utilities Commission (Commission) find SCE’s 14
GHG procurement activity for the 2016 Record Period reasonable and within its 15
procurement authority. SCE submitted its Energy Resource Recovery Account 16
(ERRA) Review of Operations 2016 testimony in April of 2017 along with 17
supporting workpapers, but neither provided sufficient information to determine if 18
SCE’s GHG compliance costs and procurement activities for the 2016 Record 19
Period were accurately recorded, reasonable, and within its procurement authority. 20
The data used by ORA to ascertain SCE’s compliance came from workpapers 21
included with SCE’s testimony filing and responses to ORA data requests. 22
273 Direct SCE 2016 ERRA Testimony Table I-1:15.
195397070 8-2
II. BACKGROUND 1
A. California Air Resources Board Cap-and-Trade 2 Program 3
The ARB Cap-and-Trade program is a market based regulation that is 4
designed to reduce GHG emissions from multiple sources. It covers about 450 5
entities. The program is designed to meet the goal of reducing GHG emissions to 6
1990 levels by the year 2020. ARB has three main responsibilities under the Cap-7
and-Trade program: (1) cap GHG emissions by issuing a number of tradeable 8
permits (allowances) equal to the emission cap; (2) reduce the cap over time to 9
reach 1990 emissions by 2020; and (3) enforce the cap by requiring each entity to 10
turn in one allowance for every metric ton of carbon dioxide gas equivalent 11
(MTCO2e) that an entity emits. 12
The Cap-and-Trade program is structured into three compliance periods: 13
First compliance period: 2013-2014 14
Second Compliance period: 2015-2017 15
Third Compliance period: 2018-2020 16
Compliance with Cap-and-Trade began in 2013 for electricity generators 17
and large industrial facilities emitting 25,000 MTCO2e or more annually (covered 18
entities).274 Covered entities must report their emissions to ARB annually and 19
emissions are verified through an independent third-party verification process. 20
Under ARB regulations, covered electric utilities are subject to specific 21
compliance requirements and obligations.275 To meet its compliance obligation an 22
entity can use California GHG emission allowances or offset credits (offsets are 23
limited to 8% of an entity’s obligation per compliance period). An entity may 24
bank allowances from previous vintage years, but may not borrow from future 25
274 Starting in 2015, the program expanded to cover distributors of transportation, natural gas, and other fuels. 275 A compliance obligation is the quantity of verified reported emissions or assigned emissions for which an entity must submit compliance instruments to ARB.
195397070 8-3
vintage years to meet a compliance obligation.276 Table 8.1 below shows what 1
vintage year allowances may be used to meet an annual or triennial compliance 2
obligation. 3
Table 8.1: Eligible Allowance Vintage for Cap-and-Trade
Second Compliance Period
Second Compliance Period
Covered Emissions
Year
Compliance Obligation Due
Date
Percent of Compliance Obligation Due
Eligible Vintages of Allowances
2015 November 1, 2016 30% of 2015 covered emissions
Vintages 2013-2015, any combination
2016 November 1, 2017 30% of 2016 covered emissions
Vintages 2013-2016, any combination
2017 November 1, 2018 70% of 2015 and 2016, and 100% of 2017 covered emissions
Vintages 2013-2017, any combination
Under ARB reporting requirements, for the 2016 compliance year, facilities 4
and suppliers are required to submit their GHG emissions reports by April 11, 5
2017, and June 1, 2017 for power entities; verified data (by independent 6
evaluators) are due to ARB on September 1, 2017; and the Cap-and-Trade 7
Compliance deadline is November 1, 2017. Entities must surrender sufficient 8
compliance instruments to cover 30% of their qualifying emissions by November 9
1, 2017. 10
In addition to the compliance obligation associated with utility-owned 11
facilities (for facilities that emit at least 25,000 MTCO2e per year), electric utilities 12
276 Section 95856 of the Cap-and-Trade Regulation. “To fulfill a compliance obligation, a compliance instrument must be issued from an allowance budget year within or before the year for which an annual compliance obligation is calculated or the last year of a compliance period for which a triennial compliance obligation is calculated.”
195397070 8-4
are also responsible for imported electricity.277 Under the Cap-and-Trade 1
regulations utilities can apply a Renewables Portfolio Standard (RPS) Adjustment 2
for electric imports from unspecified sources, where the electricity is not directly 3
delivered to California.278 For electric power entity data reports, the deadline for 4
corrections to the RPS Adjustment is due to ARB on July 17, 2017.279 5
B. Commission Decisions 6
1. Procurement of GHG Compliance 7 Instruments 8
Decision (D.) 12-04-046 (Decision on System Track I Rules and Rules 9
Track III of the Long-Term Procurement Plan Proceeding and Approving 10
Settlement) Ordering Paragraph (OP) 8 authorizes the electric utilities to procure 11
GHG allowances, allowance futures and forwards, and offsets and offset forwards 12
within separately calculated Direct Compliance Obligation Purchase limits and 13
Financial Exposure Purchase Limits, as set forth in Appendix 1 of the Decision.280 14
The Direct Compliance Obligation Purchase Limit sets the maximum 15
amount of compliance instruments an Investor-Owned Utility (IOU) is allowed to 16
purchase in the current year. Note that under this framework, the IOUs are not 17
allowed to purchase allowances with vintages more than three years from the 18
current year. The annual Direct Compliance Obligation Purchase Limit is 19
calculated based on the following formula: 20
277 Also, an electric utility is responsible for GHG compliance costs for GHG emissions associated with contracts, where a utility has assumed the cost of compliance on behalf of a third-party (either agreeing to compensate a third-party for the costs of their compliance obligations or where a the utility is responsible for procuring compliance instruments on the third-party behalf). 278 The RPS Adjustment decreases an entity’s compliance obligation based on low-carbon or emissions-free power generation that it is responsible for and happens entirely outside of California. 279 http://www.arb.ca.gov/cc/reporting/ghg-rep/ghg-rep-dates.htm. 280 “Direct Compliance Obligation” is defined as the tons of emissions for which the utility has an obligation to retire allowances on its own behalf as a regulated entity under the Cap-and-Trade regime, and/or is otherwise obliged to procure instruments on behalf of a third party that is a regulated entity under the Cap-and-Trade regime (e.g. contractual arrangements where the IOU is responsible for procuring allowances on a third party’s behalf, or could elect to assume that responsibility). Appendix 1, D.12-04-046.
195397070 8-5
LCY = A + 100% * FDCY + 60% * (FDCY + 1) + 1 40% * (FDCY + 2) + 20% * (FDCY + 3) 2
Where: 3
“L” is the maximum number of GHG compliance 4 instruments an IOU can purchase for purposes of 5 meeting their direct compliance obligation. 6
“A” is the utility’s net remaining compliance 7 obligation to date, calculated as the sum of the actual 8 emissions for which the utility is responsible for 9 retiring allowances (or purchasing on behalf of a third 10 party) up to the Current Year, minus the total 11 allowances or offsets the utility has purchased up to 12 the Current Year that could be retired against those 13 obligations. 14
“FD” is the utility’s forecasted compliance obligation, 15 the projected amount of emissions for which the utility 16 is responsible for retiring allowances, or responsible 17 for purchasing on behalf of a third party, calculated 18 using an implied market heat rate (IMHR) that is two-19 standard deviations above the expected IMHR. 20
“CY” is the current year, i.e., the year in which the 21 utility is transacting in the market. 22
2. GHG Emissions 23
D.14-10-033, as modified by D.14-10-055 and D.15-01-024281 requires the 24
electric utilities to calculate and report the GHG emissions and associated costs 25
using specific conventions and methodologies.282 Utilities incur GHG costs 26
directly (referred to here as “Direct GHG Cost”) for purchasing compliance 27
instruments for their own direct GHG emissions under the Cap-and-Trade 28
program, and indirectly (referred to here as “Indirect GHG Cost”) through GHG 29
Cap-and-Trade costs embedded in the prices of the wholesale market. 30
281 For ease of reference, and because the correct attachments are in D.15-01-024, this testimony shortens subsequent citations to D.14-10-033, as modified by.14-10-055 and D .15-01-024, to “D.15-01-024,” unless the citation is to the portions of D.14-10-033 that were not subsequently revised. 282 D.15-01-024, Attachment D. .
195397070 8-6
A utility’s direct GHG emissions, expressed in metric tons of carbon 1
dioxide equivalents (MTCO2e), could consist of the following sources (Refer to 2
Figure 8.1 below for visual depiction of categories of GHG emissions and 3
associated costs methodologies): 4
Direct GHG Emissions with Physical Compliance 5 Obligations: 6
(1) Utility Owned Generation (UOG): based on 7 actual plant output, a facility-specific heat rate, and 8 ARB-specific emissions factors of fuels; and 9
(2) Energy Imports: specified imports based on actual 10 plant output purchased by a utility and specific 11 emissions factors; and unspecified imports based on 12 the ARB emission factor for unspecified imports, the 13 ARB transmission loss factor, and any applicable RPS 14 adjustment. 15
Direct GHG Emissions Based on Contractual 16 Obligations: 17
(3) Qualifying Facility (QF) Contracts: physical 18 settled emissions based on actual plant output 19 purchased by a utility and the contract-specific 20 settlement terms; and 21
(4) Tolling Agreements: based on actual plant output 22 purchased by a utility, the resource-specific heat rate, 23 and ARB-specific emissions factors for fuels. 24
GHG Emissions Based on Financial Settlement 25 Contracts: 26
(5) Contracts with Financial Settlements: emissions 27 from utility contracts in which a utility is explicitly 28 responsible for providing the financial settlement for 29 GHG costs (utilities are allowed to record financially 30 settled emissions as direct or indirect emissions). 31
A utility’s indirect GHG emissions, expressed in MTCO2e, could consist 32
of the following sources (See Figure 7.1): 33
(6) CAISO Market Purchases: emissions based on net 34 market energy purchases and either ARB’s emission 35 factor for generic system power or a market heat rate-36 implied emission factor; and 37
195397070 8-7
(7) Contract Purchases: emissions based on actual plant 1 output purchased by the utility and contract-specific 2 settlement terms where the responsibility for financial 3 settlement of GHG costs is not explicitly addressed. 4
Figure 8.1 Schematic of Direct and Indirect GHG Emissions and Methodology of
Calculation of Associated Costs by Type of Sources
3. GHG Emissions Costs 5
Decision 15-01-024 requires the electric utilities to calculate the recorded 6
costs associated with GHG emissions covered by compliance obligations under the 7
Cap-and-Trade program using the following methodologies: 8
195397070 8-8
i. Direct GHG Costs 1
The recorded direct GHG costs are the sum of each month’s Weighted 2
Average Cost (WAC) of compliance instruments inventory multiplied by that 3
month’s actual direct emissions for which the utility has a physical compliance 4
obligation.283 Thus, the direct GHG costs, based on the WAC, could be applicable 5
to GHG emissions from a UOG resource, imports, QF contracts, and tolling 6
agreements, where a utility has physical compliance obligations. 7
For GHG emissions and costs associated with financially settled tolling 8
agreements that a utility might record as direct emissions and costs, the recordings 9
are based on actual contract settlement, not on the WAC. These emissions and 10
costs are therefore not included in the calculation of WAC or in the calculation of 11
Direct GHG costs, which is based on monthly emissions.284 12
For the purpose of WAC calculations, a utility shall calculate the WAC 13
based on its entire inventory of allowances and offsets eligible to meet the 14
compliance obligation for the current compliance period under the Cap-and-Trade 15
program.285 For instance, when calculating the WAC for 2015, the first year of the 16
second compliance period spanning 2015-2017, a utility must calculate it based on 17
every allowance it holds with vintage years 2015, 2016, and 2017, plus any 2013 18
and 2014 allowances that were not used to meet its obligation in the first 19
compliance period.286 The intent of the WAC is to spread ratepayer costs over 20
multiple years of the Cap-and-Trade program so that, depending on a utility’s 21
GHG procurement strategy, rates will remain relatively constant even if the utility 22
283 D.15-01-024, Attachment C. 284 Direct Cost for Tolling Agreements with financial settlements = Settlement Price * Emissions Quantity; where settlement price is the unit price at which the utility will financially compensate its tolling counterparty for GHG (usually the ARB auction clearing price); and Emission Quantity is the emissions obligation for the entire month calculated in accordance with the tolling agreement. 285 D.14-10-033 at p. 23. 286 Under ARB regulations, there are no restrictions on which vintage year of offsets a utility can use to meet a compliance obligation.
195397070 8-9
chooses to procure many compliance instruments in one year and very few in the 1
next.. There is no requirement that utilities procure a minimum or consistent 2
amount of compliance instruments as long as they can meet annual and period 3
compliance obligations. 4
ii. Indirect GHG Costs: 5
The recorded indirect GHG costs equal to the subtotal of indirect GHG 6
emissions (CAISO market purchases and contract purchases) multiplied by the 7
annual average of CAISO’s daily GHG Allowance Price Index computed by 8
averaging the published daily price for the recorded year and divided by the 9
number of days in that year. 10
III. DISCUSSION 11
A. SCE’s Compliance Instrument Procurement for the 12 2016 Record Period is within the Procurement 13 Limit Established in its BPP 14
During the 2016 Record Period, SCE procured a combined GHG 15
allowances and offsets. SCE did not procure any future year allowances or carbon 16
offsets in 2016. Per SCE Advice Letter 3349-E,287 the most recent update to the 17
procurement limits established in SCE’s 2010 BPP, its direct GHG compliance 18
obligation purchase limit for 2016 is MTCO2e.288 SCE’s total 19
procurement of GHG compliance instruments in Record Period 2016 was within 20
its 2016 GHG procurement limit. 21
287 SCE response to ORA Data Request 17, question 1:“SCE's GHG instrument procurement limits for RY 2016 were approved by the Commission in Advice Letter 3349-E.” 288 SCE response to Data Request 17, question 1: “in compliance with these limits SCE could have procured a combined total of allowances and offsets during 2016 equal to the combined totals of the rows labeled Transaction Year 2016 in Tables E-13 and E-14 of Sheets E-9 and E-10, respectively; minus amounts procured prior to 2016.” The combined total of Transaction Year 2016 in Table E-13 and E-14 of AL 3349-E is as follows: (17,876,525+11,938,937+8,301,826+3,781,565)+(4,204,073+1,981,103+889,105+433,196) = 49,406,330. This does not subtract amounts procured prior to 2016, but SCE did not provide the amount procured prior to 2016 in response to the Data Request.
195397070 8-10
B. SCE Procured GHG Compliance Instruments in 1 the 2016 Record Period in Accordance with the 2 Restrictions Established in its BPP on Where and 3 How a Utility Can Procure GHG Compliance 4 Instruments 5
During the 2016 Record Period, 6
7
8
. Based on ORA’s review of SCE’s 9
direct ERRA testimony, SCE’s responses to ORA data requests, and SCE’s QCR 10
material from Record Period 2016, as well as ORA’s participation in PRG 11
meetings, SCE procured GHG compliance instruments during Record Period 2016 12
in accordance with its BPP. 13
C. SCE’s calculation of the WAC for GHG emissions 14 from electric generation resources complies with 15 Attachment C of D.15-01-024 16
During the 2016 Record Period, SCE appears to have conformed to the 17
calculation and reporting methodologies detailed in Attachment C290 of D.15-01-18
024, referenced in D.15-01-024 OP. 1. First and foremost, SCE employs 19
Template C for reporting quantity of instruments in inventory, price and amount of 20
instrument transactions, and the resulting WAC. Also, SCE’s cost of emissions 21
compliance is calculated for each month as the “(WAC) of compliance 22
instruments held in inventory at the end of a month multiplied by the quantity of 23
emissions generated in that month for which the utility has a physical compliance 24
obligation.”291 Based on ORA’s review, it appears SCE correctly followed 25
289 SCE’s 2010 AB 57 Bundled Procurement Plan, Clean Version at p. 64. 290 SCE provided Attachment C for reference in response to ORA Data Request 2, Question 2. 291 D.15-01-024 Attachment C at p. 1.
195397070 8-11
directions in Attachment C as to how purchases and sales should be treated in the 1
running calculation of the WAC.292 2
D. The costs and revenues reported related to 3 compliance with the ARB Cap-and-Trade program 4 are in accordance with Template D of D.15-01-024 5
During the 2016 Record Period, it appears that SCE calculated and reported 6
costs and revenues as required by the methodologies detailed in Attachment D293 7
of D.15-01-024, referenced in D.15-01-024 OP. 1. 8
Regarding Template D-1 on SCE’s GHG free allowance revenues and 9
returns to customers, the gross auction revenue in line 5 meets expectations. 10
Furthermore, the Net Revenue for Customers, after set-asides for outreach, 11
administrative expenses, and qualified renewables projects including the Multi 12
Family Solar Rooftops program, appears satisfactory. SCE also separates out the 13
Emissions-Intensive and Trade-Exposed (EITE) Customer Return and Small 14
Business Volumetric Return from the Net Revenue for Customers to generate the 15
Residential Volumetric Return, and divides the per household Return in half to 16
represent its two-part distribution in April and October. 17
Template D-2 on SCE’s GHG emissions costs includes the required data 18
for lines 2-12, and the WAC from Template C-1 is transferred to line 13. The 19
recorded and final costs reported do not deviate greatly from the forecasted costs, 20
and do not increase in a way that appears unexpected given the design of Cap-and-21
Trade to annually increase costs per MTCO2e. 22
292 D.15-01-024 Attachment C at pp. 3-4. 293 SCE referred ORA to Template D for the 2016 Record Period as filed in the 2018 Forecast of Operations Filing A. 17-05-006, Exhibit SCE-1, Table D-2, in response to ORA Data Request 2, Question 1.
195397070 8-12
E. ORA Does Not Object to SCE’s GHG Compliance 1 Strategy for Record Period 2016 2
1. SCE Adequately Supported its Recorded 3 Direct Emissions and Costs for the 2016 4 Record Period 5
SCE reports in its 2016 Record Period direct ERRA testimony that it 6
recorded in Direct and Tolling Contract GHG Costs.294 SCE 7
provided a breakdown of monthly emissions volume and recorded costs by UOGs, 8
imports, and financial exposure in the confidential workpapers accompanying 9
SCE’s testimony. 10
ORA requested further data samplings on the specifics of 2016 Record 11
Period UOG MWh generation and resulting emissions, specifically from the 12
Mountainview Generating Station, SCE’s only UOG surpassing the 25,000 13
MTCO2e annual emissions threshold to qualify for compliance. As verified by 14
SCE, “SCE’s Utility-Owned-Generation (UOG) Direct Compliance costs and 15
GHG volume are entirely attributable to the Mountainview facility.”295 The 16
recorded 2016 Record Period UOG compliance cost is reported at 17
,296 while the forecasted 2016 Record Period compliance 18
cost for Mountainview UOG is estimated at 19
.297 These recorded emissions are similar to ARB reported emissions at 20
the Mountainview facility for the past two years, and seem to follow a recent trend 21
of declining emissions.298 SCE also provided Mountainview’s monthly generating 22
output,299 a sampling of the Mountainview generating units’ recorded emissions 23
294 Direct SCE 2016 ERRA Testimony Table I-1 Line 15. 295 SCE response to ORA Data Request 2, Question 6.e. 296 SCE response to ORA Data Request 2, Question 6.a., Attachment 6a, cells N14 and N21, respectively. 297 Inferred from Template D for the forecast of 2016 Record Period as filed in the 2018 Forecast of Operations Filing A. 17-05-006, Exhibit SCE-1, Table D-2. 298 ARB reported MTCO2e emissions for Mountainview as 2.40 million in 2014 and 2.27 million in 2015. 299 SCE response to ORA Data Request 2, Question 8.a.
195397070 8-13
for the months of January, March, June, August, and December as derived by the 1
SCE-developed software GHG Tracker.300 The emissions reported here correlate 2
with the GHG emissions costs reported in SCE’s testimony workpapers, and GHG 3
Tracker applies a fairly consistent emissions factor around 4
to the facility’s generation. Using Mountainview as an example, SCE has 5
provided raw facility-level data, as well as data confirming its intermediate 6
methodological steps, justifying its reported GHG emissions and costs to ORA’s 7
satisfaction. SCE also provided data underlying its reported emissions from 8
contracted resources.301 SCE’s recorded emissions, and the costs associated with 9
them, therefore appear reasonable. 10
2. SCE’s 2016 Record Period Compliance 11 Instrument Procurements Appear to Be 12 Reasonable and Not Detrimental to 13 Ratepayers 14
For the second year of the Cap-and-Trade program’s second compliance 15
period, SCE is required to surrender compliance instruments for 30% of its 2016 16
emissions, with the remaining 70% due after 2017. To account for its 2016 17
compliance obligation, SCE would require around 302 allowances and 18
offsets. As stated above, SCE procured GHG allowances in the 2016 19
Record Period, which will be sufficient for the 2016 obligation. In workpapers 20
provided with its supplemental testimony, SCE reports a recorded direct 2015 21
GHG volume of emissions in the 2016 Record Period.303 22
Fulfilling the remaining 70% obligation would then require using earlier 23
vintage allowances from SCE’s existing inventory in addition to the 24
300 SCE response to ORA Data Request 2, Question 8.b. 301 SCE response to ORA Data Request 2, Question 10. 302 SCE reports its total direct emissions for 2016 as in SCE response to ORA Data Request 2, question 6.a., Attachment 6a, cell N24. 30% of this number rounded up is . 303 SCE reports its total direct emissions for 2016 as in SCE response to ORA Data Request 2, question 6.a., Attachment 6a, cell N24.
195397070 8-14
compliance instrument procurements transacted in the 2016 Record Period. Given 1
the volume of GHG allowances that are usually traded, is a 2
amount of compliance instruments to acquire to fulfill the rest of 3
the 2016 compliance obligation, even if it were . 4
SCE procured allowances to meet its near-term obligation and 5
to meet the second compliance period obligation. However, 6
ORA’s review extends beyond whether or not a utility made purchases in 7
accordance with all applicable requirements, because the manner in which it chose 8
to meet its compliance obligation affects its revenue requirement and rates. For 9
GHG compliance, “GHG compliance instrument purchases record to SCE’s GHG 10
inventory account. The cost of these instruments is then averaged to yield an 11
overall average cost (i.e., $/mtCO2e) of all the instruments in inventory. As SCE 12
incurs GHG compliance obligations the cost of these obligations is recorded to 13
SCE’s ERRA account by applying the inventory weighted average price (in 14
$/mtCO2e) to the mtCO2e emitted using accrual accounting.”304 More expensive 15
transaction costs result in a higher WAC, and because a utility’s WAC price 16
affects the forecasted costs for which it will be requesting recovery, the utility’s 17
execution of a procurement strategy has an ongoing impact for ratepayers on its 18
current and future ERRA requests. Based on ORA’s review, SCE procured 19
sufficient allowances during the current record period. Given uncertainty in the 20
past year about the future of the Cap-and-Trade program, it is understandable why 21
SCE 22
23
As demonstrated in CARB’s most recent 24
Summary of Auction Settlement Prices and Results, allowance prices have 25
consistently risen since the November 2013 auction, from $11.48/MTCO2e at that 26
304 Direct SCE 2016 ERRA Testimony at pp. 124-125.
195397070 8-15
time to $13.80/MTCO2e in the May 2017 auction.305 Offsets, however, have 1
historically been priced significantly lower than allowances; 2
3
.306 SCE also reported that, as of February 4
2015, broker price quotes for 3-year invalidation risk offsets with a December 5
2015 delivery date are $10.25/MTCO2e.307 As of the writing of this testimony, 6
prices of both kinds of instruments have increased in response to the renewal of 7
the Cap-and-Trade program beyond 2020, but allowances still remain roughly 8
$3.00/MTCO2e more expensive than allowances.308 Furthermore, from 9
participation in multiple utilities’ PRG meetings and conversations with interested 10
parties, 11
12
13
IV. CONCLUSION 14
As stated by SCE in its testimony, “in this proceeding, SCE is not seeking 15
direct recovery of the full cost of GHG compliance transactions that were 16
undertaken during 2016 (pursuant to D.14-10-033). Rather, herein SCE is 17
providing information to facilitate review of SCE’s GHG-related costs that were 18
incurred during the Record Period and appropriately recorded to SCE’s ERRA 19
account.”309 The review ORA conducts for GHG compliance in ERRA 20
Compliance filings is not strictly a confirmation that an IOU procured one GHG 21
compliance instrument for every one MTCO2e of emissions in its accounts, 22
305 California Cap-and-Trade Program Summary of Joint Auction Settlement Prices and Results, May 2017 update, accessible via https://www.arb.ca.gov/cc/capandtrade/auction/auction.htm. 306 SCE A. 16-05-001 Chapter VII Template C-1, 2015 SCE WAC calculation. 307 SCE Response to A. 16-04-001 ORA Data Request 9, Question 6. 308 Californiacarbon.info quotes “Broker Spot” allowance prices at $15.12 as of July 24, 2017 and 3-year invalidation risk offsets at $12.13. 309 Direct SCE 2016 ERRA Testimony at p. 126.
195397070 8-16
because the defining feature of a Cap-and-Trade program is to allow entities 1
flexibility in determining how and when they will experience the cost of their 2
GHG emissions. 3
GHG cost recovery requested by SCE in ERRA is based on cost of regulatory 4
compliance according to Commission decisions and the ARB Cap-and-Trade 5
program rules, with inputs from emissions recorded in the Record Period and 6
procurements of compliance instruments as they impact the WAC of all 7
instruments in its inventory, past and present, as defined in D.14-10-033.310 As 8
such, cost recovery for GHG emissions compliance that is requested of ratepayers 9
is not directly proportional to instruments procured in a single record year. SCE 10
has the option not to purchase any compliance instruments for an entire Record 11
Period and could still meet its compliance obligation that year with previously 12
procured compliance instruments. It would nevertheless request cost recovery 13
from ratepayers due to the fact that it performed its GHG emissions compliance 14
obligation, and the WAC is meant to spread a utility’s compliance costs out over 15
time for the duration of the program. 16
SCE’s BPP recognizes the need for standards of review in ERRA that examine 17
more than just accounting when considering costs resulting from complex 18
decision-making processes. SCE’s monthly emissions compliance obligations, 19
and its annual cost of compliance, are the result of the emissions of resources in its 20
portfolio of contracts and UOG, as well as when and how SCE has chosen to 21
procure the instruments on behalf of those resources. Because of this, the 22
standard of review outlined in SCE’s BPP as covering the operation and 23
administration of its generation resources is the most appropriate for the purposes 24
of GHG emissions compliance in an ERRA Review proceeding. As established in 25
SCE’s BPP, this review consists of “a reasonableness review to determine if the 26
310 D.14-10-033 at pp. 22-23.
195397070 8-17
utility reasonably administered its QF and non-QF contracts, and if the operation 1
of its UOG, including maintenance outages, was reasonable.”311 And it is because 2
of this that ORA conducted a holistic review of SCE’s GHG emissions and cost 3
reporting, GHG emissions compliance instrument procurement, and GHG 4
emissions compliance strategy in general. 5
Overall, ORA does not object to SCE’s request that the Commission find its 6
GHG procurement activity for the 2016 Record Period reasonable and within its 7
procurement authority. ORA finds SCE’s GHG emissions compliance activity 8
and reporting deficient in only one noteworthy respect, and offers the following 9
recommendation: 10
11 12
13 14
15 16
17
311 SCE 2010 BPP at p. 81 (approved on October 11, 2012 in Resolution E-4542); and SCE 2014 BPP at p. 74 (approved on February 16, 2016 in Advice Letter 3349-E).
195397070
APPENDIX A
Witness Qualifications
195397070 A-1
QUALIFICATIONS AND PREPARED TESTIMONY 1
OF 2
RADU CIUPAGEA 3
Q.1 Please state your name and address. 4
A.1 My name is Radu Ciupagea. My business address is Electricity Planning 5
and Policy Branch, Office of Ratepayer Advocates, California Public 6
Utilities Commission, 505 Van Ness Avenue, 4th floor, San Francisco, 7
California. 8
Q.2 By whom are you employed and what is your job title? 9
A.2 I am employed by the California Public Utilities Commission as a Public 10
Utilities Regulatory Analyst in the Office of Ratepayer Advocates (ORA) 11
in the Electricity Planning and Policy Branch. 12
Q.3 Please describe your educational and professional experience. 13
A.3 I hold two Bachelor of Arts Degrees, in Economics and French, 14
respectively, from the University of California at Berkeley. 15
I have been employed by the California Public Utilities Commission since 16
February 1, 2011. Since joining the CPUC, I have worked on Demand 17
Response, low income energy efficiency, low-income subsidy programs, 18
Long-Term Procurement Plan, Joint Reliability Plan, Integrated Resource 19
Planning, and SCE Energy Resource Recovery Account. 20
Q.4 What is your area of responsibility in this proceeding? 21
A.4 I am responsible for Chapter 1 of ORA’s testimony. 22
Q.5 Does that complete your prepared testimony? 23
A.5 Yes, it does. 24
195397070 A-2
QUALIFICATIONS AND PREPARED TESTIMONY 1
OF 2
PATRICK CUNNINGHAM 3
Q.1 Please state your name and address. 4
A.1 My name is Patrick Thomas Cunningham. My business address is 505 Van 5
Ness Avenue, San Francisco, CA 94102. 6
Q.2 By whom are you employed and what is your job title? 7
A.2 I am employed by the California Public Utilities Commission as a Public 8
Utilities Regulatory Analyst in the Electricity Planning and Policy Branch 9
of the Office of Ratepayer Advocates (ORA). 10
Q.3 Will you please briefly state your educational background and 11 experience? 12
A.3 I hold a Master of Pacific and International Affairs degree from the 13
University of California San Diego, a Master of Arts degree in History 14
from the American Military University, and a Bachelor of Arts degree in 15
History from the University of California Santa Cruz. My most recent 16
degree allowed me to focus in the study of national energy procurement. I 17
joined ORA in May of 2016 and devoted my post-training work to the 18
study of ERRA cases and associated Commission decisions. I have 19
conducted analysis of least-cost dispatch and contract administration for 20
SDG&E’s 2015 ERRA. This year I am in review utility-owned hydro 21
administration for PG&E’s 2016 ERRA, contract administration for 22
SDG&E’s 2016 ERRA, and least-cost dispatch and contract administration 23
for SCE’s 2016 ERRA. I also coordinated and conducted analysis on 24
SDG&E’s 2018 ERRA Forecast. 25
Q.4 What testimony are you sponsoring in this proceeding? 26
A.4 I am responsible for Chapter II and VI, least-cost dispatch and contract 27
administration respectively. 28
Q.5 Does that complete your prepared testimony? 29
195397070 A-3
A.5 Yes, it does. 1
195397070 A-4
QUALIFICATIONS AND PREPARED TESTIMONY 1
OF 2
MICHAEL YEO 3
Q.1 Please state your name and business address. 4
A.1 My name is Michael Yeo. My business address is 505 Van Ness Avenue, 5
San Francisco, California. 6
Q.2 By whom are you employed and in what capacity? 7
A.2 I am employed by the California Public Utilities Commission as a Senior 8
Utilities Engineer in the Office of Ratepayer Advocates (ORA). 9
Q.3 Please describe your educational and professional experience. 10
A.3 I graduated from the University Of Toronto with a Bachelor of Applied 11
Science in Civil Engineering, and am a registered Professional Engineer. 12
Since joining the Commission in 1992, I have worked in various 13
assignments in ORA, Energy Division and the Consumer Protection and 14
Safety Division. Immediately prior to joining the Commission, I worked 15
for the California Department of Transportation. 16
Q.4 What is the scope of your responsibility in this proceeding? 17
A.4 I am responsible for Chapter 3, Utility-Owned Generation – Hydroelectric, 18
and Chapter 4, Utility-Owned Generation – Natural Gas. 19
Q.5 Does this complete your testimony at this time? 20
A.5 Yes, it does.21
195397070 A-5
QUALIFICATIONS AND PREPARED TESTIMONY 1
OF 2
BRIAN LUI 3
Q.1 Please state your name and business address. 4
A.1 My name is Brian Lui. My business address is 505 Van Ness Ave, San 5
Francisco, California, 94102. 6
Q.2 By whom are you employed and in what capacity? 7
A.2 I am employed by the California Public Utilities Commission as a Public 8
Utilities Financial Examiner III in the Office of Ratepayer Advocates 9
(ORA), Electricity Planning & Policy Branch. 10
Q.3 Please describe your educational and professional experience. 11
A.3 I received a Bachelor of Science Degree in Biochemistry from the 12
University of California, Riverside. I also possess a Master Degree in 13
Accounting from Golden Gate University in San Francisco. I joined the 14
Commission on January 7, 2014 in ORA’s Electricity Planning and Policy 15
Branch. In ORA, I am involved in the ERRA Forecast and ERRA 16
Compliance proceedings. Immediately prior to joining the Commission, I 17
worked for the California State Board of Equalization as a tax auditor. I 18
have over 5 years of experience working as an auditor in the public sector. 19
Q.4 What is the scope of your responsibility in this proceeding? 20
A.4 I am co-sponsoring ORA Chapter 7 (Compliance Audit of the Energy 21
Resource Recovery Account (ERRA) and other Balancing and 22
Memorandum Accounts). 23
Q.5 Does this complete your testimony at this time? 24
A.5 Yes, it does.25
195397070 A-6
QUALIFICATIONS AND PREPARED TESTIMONY 1
OF 2
GRANT NOVACK 3
Q.1 Please state your name and business address. 4
A.1 My name is Grant Novack. My business address is 505 Van Ness Ave, San 5
Francisco, California, 94102. 6
Q.2 By whom are you employed and in what capacity? 7
A.2 I am employed by the California Public Utilities Commission as a Public 8
Utilities Financial Examiner IV in the Office of Ratepayer Advocates 9
(ORA), Energy Cost of Service and Natural Gas Branch. 10
Q.3 Please describe your educational and professional experience. 11
A.3 I graduated from the University of Nevada, Las Vegas with a Bachelor of 12
Science Degree in Business Administration. I am a Certified Internal 13
Auditor. I joined the staff of the Commission in February 2003. I have 37 14
years auditing experience. 15
Q.4 What is the scope of your responsibility in this proceeding? 16
A.4 I am co-sponsoring Chapter 6 of ORA’s testimony on the Compliance 17
Audit of the Energy Resource Recovery Account (ERRA) and Other 18
Balancing and Memorandum Accounts. 19
Q.5 Does this complete your testimony at this time? 20
A.5 Yes, it does.21
195397070 A-7
QUALIFICATIONS AND PREPARED TESTIMONY 1
OF 2
THOMAS GARIFFO 3
Q.1 Please state your name, business address, and position. 4
A.1 My name is Thomas Gariffo and my business address is 505 Van Ness 5
Avenue, San Francisco, CA 94102. I am a Public Utilities Regulatory 6
Analyst in the Electricity Planning and Policy Branch of the Office of 7
Ratepayer Advocates. 8
Q.2 Please summarize your educational background. 9
A.2 I have a Master Degree in Public Policy with honors from the Luskin 10
School of Public Affairs at UCLA, where I focused primarily on fields 11
regarding environmental, energy, and technology policy. Prior to UCLA, I 12
received a Bachelor’s Degree in Political Science from UC Berkeley with a 13
focus on political communications and a Minor in Public Policy from the 14
Goldman School of Public Policy. 15
Q.3 Briefly describe you professional experience. 16
A.3 I have worked as an analyst for the Office of Ratepayer advocates for two 17
years on climate change programs such as the cap-and-trade program and 18
its relevant contributions to the ERRA proceedings, but also including the 19
Low Carbon Fuel Standards, transportation electrification and electric 20
vehicle initiatives, energy storage, research and development funding, and 21
renewable portfolio standards. Before that, I interned at the Luskin Center 22
for Innovation as research assistant to the director, researching electric 23
vehicle policies. 24
Q.4 What is the scope of your responsibility in this proceeding? 25
A.4 I am sponsoring Chapter 8. 26
Q.5 Does this complete your testimony at this time? 27
A.5 Yes, it does. 28
LIST OF ORA ATTACHMENTS
# Attachment Description
2.1
ORA-2014 through 2016 Price Forecast Analysis CONFIDENTIAL
(via email)
Workbook used to create Table 1 and analyze Price Forecast data. Built using data from SCE’s Section D workpapers from 2014-2016 Record Periods
2.2
ORA-2014 through 2016 DLAP Forecast Analysis CONFIDENTIAL
(via email)
Workbook used to create Table 2 and Figure 1 and analyze Load Forecast data. Built using data from SCE’s Section D workpapers and ORA analysis of Section D workpapers from 2014 and 2015 Record Periods
2.3ORA-Hydro Awards
CONFIDENTIAL
(via email)
Workbook used to create Figure 2 and analyze dispatch and bidding of dispatchable hydro resources. Built using SCE’s Section D Hydro Awards LMPs workbook
2.4ORA-CBPDA14
CONFIDENTIAL
(via email)
Workbook used to create Table 3 and analyze administration for the day-ahead 1-4pm CBP. Original workbook was given as a part of SCE’s testimony.
2.5ORA-CBPDO14
CONFIDENTIAL
(via email)
Workbook used to create Table 3 and analyze administration for the day-of 1-4pm CBP. Original workbook was given as a part of SCE’s testimony.
2.6ORA-CBPDO26
CONFIDENTIAL
(via email)
Workbook used to create Table 3 and analyze administration for the day-ahead 2-6pm CBP. Original workbook was given as a part of SCE’s testimony.
2.72017 Chapter II_Section H_DR-
SDPR CONFIDENTIAL
(via email)
Workbook from SCE testimony describing the Summer Discount Plan Residential demand response program
2.8
ORA Modified SCE Response to Data Request 21 Q1 Attachment
CONFIDENTIAL
(via email)
Workbook. ORA added two columns to this response which calculates the revenue lost due to incremental non-dispatch.
# Attachment Description
2.9ORA Report on SCE 2015 ERRA
CONFIDENTIAL
Two sections of ORA’s analysis of SCE’s 2015 ERRA A.16-04-001. The sections describe SCE’s demand response and commitment costs
2.10SCE Supplemental Direct Testimony 2015 ERRA
Selection from SCE’s supplemental testimony from A.16-04-001
2.11
SCE Chapter II_Section E_Commit Cost_ CONFIDENTIAL
(via email)
Workbook from SCE testimony describing commitment costs
2.12Data Request Responses
CONFIDENTIAL Various SCE responses to ORA data requests for A.16-04-001 and A.17-04-004
2.13Data Request 8 Q3 Attachment
CONFIDENTIAL
(via email)
Workbook. Attachment provided by SCE in their response to ORA data request 8, question 3.
2.14ORA Least Cost Dispatch
Overview 062117 CONFIDENTIAL
Slides from an SCE presentation to ORA witnesses concerning LCD. Selection describes demand response resources and net benefits test
2.15
SCE Chapter II_Section E_SS and Market Awards_
CONFIDENTIAL
(via email)
Workbook from SCE testimony describing self-scheduling activity
5.1 Corrective Actions Palo Verde’s in-house Root Cause Evaluation (RCE) Report #16-14218-021 Revision 1 on the September 7, 2016 shutdown
6.1Data Request Responses
CONFIDENTIAL
SCE responses to ORA Data Requests 3, 7, 9, 12, and 18 which were cited in this testimony
6.2
Heber Geothermal Amendment 5
PPA amendment concerning Heber Geothermal. SCE provided this document in its response to MDR 1.3.3.2 (SCE confirmed on 9/11/2017 that the amendment is expired and not confidential)
6.3OASIS_Report_12152015_
Coachella_LMP CAISO-generated report on LMP prices at the Coachella PNode appropriate to Heber Geothermal
CHAPTER 2
ATTACHMENT 2.1
ORA-edited SCE Workbook Concerning 2014 through 2016 Price Forecast Analysis
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.2
ORA-edited SCE Workbook Concerning 2014 through 2016 DLAP Forecast Analysis
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.3
ORA-edited SCE Workbook Concerning Hydro Awards
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.4
CBPDA14
ORA-edited SCE Workbook Concerning Capacity Bidding Program Day-Ahead 1-4
Hour Dispatch
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.5
CBPDO14
ORA-edited SCE workbook concerning Capacity Bidding Program Day-Of 1-4 Hour
Dispatch
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.6
CBPDO26
ORA-edited SCE workbook concerning Capacity Bidding Program Day-Of 2-6 Hour
Dispatch
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.7
Workbook Concerning Summer Discount Program – Residential, Submitted by SCE
Along with A.17-04-004 Testimony
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.8
ORA-edited Version of SCE Response to ORA Data Request 21, Question 1 Workbook
Attachment
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.9
ORA Report on SCE 2015 ERRA Compliance A.16-04-001
(CONFIDENTIAL)
166892015
Docket Exhibit Number Commissioner Admin. Law Judge ORA Project Mgr.
: : : : :
A.16-04-001 ORA-1 Michel Florio Pat Tsen Radu Ciupagea
OFFICE OF RATEPAYER ADVOCATES CALIFORNIA PUBLIC UTILITIES COMMISSION
REPORT ON
SOUTHERN CALIFORNIA EDISON’S ENERGY
RESOURCE RECOVERY ACCOUNT
COMPLIANCE APPLICATION FOR RECORD
PERIOD 2015
San Francisco, California September 15, 2016
Attachment 2.9 Page 1
166892015 2-11
1 37 2
This information provides large-scale context for the efficacy of SCE’s load 3
bidding strategy. A high proportion of load cleared in the day-ahead market indicates that 4
SCE forecast and procured sufficient energy resources relative to consumer demand, and 5
then appropriately calculated the value of its resources and translated these values into 6
bids that would allow the resources to be economically dispatched. 7
C. Management of Thermal Resources 8
SCE is required to bid its utility-owned and contracted thermal resources at their 9
incremental (marginal) costs, recognizing all operating, regulatory, legal, environmental, 10
and financial obligations and constraints. ORA analyzed the following metrics in order to 11
assess whether SCE managed its thermal resources responsibly, consistent with least-cost 12
principles. 13
i. Commitment Cost Decisions 14
SCE is required to submit to CAISO its expected costs for starting up resources 15
and running them at their minimum load, also known as commitment costs.38 CAISO 16
logs this information into its Master File, which is the record of all dispatchable 17
resources’ operating parameters and costs, and is used to inform CAISO’s dispatch 18
decisions. Utilities can submit proxy bids, which are determined by CAISO and can vary 19
daily based on the cost of natural gas. Alternately, if SCE believes that the proxy bids set 20
by the CAISO do not adequately reflect the true costs of running a resource, like a 21
facility’s non-fuel related costs, SCE can use the registered cost option. The registered 22
cost option allows SCE to bid up to 1.5 times the proxy cost, but registered cost bids 23
cannot be updated for 30 days. 24
37 ORA Workpapers, Load Bid Calculations. 38 Commitment costs are different from incremental bid costs in that they reflect only the cost of starting up and running a resource at its minimum operational load and are for informational purposes. Incremental bids are submitted to the CAISO market for each resource, each hour of every day, and reflect the marginal cost of energy for that resource.
Attachment 2.9 Page 2
166892015 2-12
It is important for SCE to choose the correct cost option, allowing its dispatchable 1
resources to be bid as accurately as possible, and to fully capture the resource cost in the 2
bid price. This allows CAISO to optimize the dispatch of all available energy resources 3
based on the lowest possible cost, subject to other constraints. 4
At the end of 2014, CAISO updated its startup cost calculations to include major 5
maintenance adder costs, which were responsible for some of the variable non-fuel 6
related costs that would be captured in a registered cost bid. In 2015, in implementing 7
this change, CAISO issued the Commitment Cost Enhancement (CCE) initiative, which 8
mandated the use of proxy costs for all non-use limited dispatchable thermal resources.39 9
During the 2015 Record Period, SCE submitted registered costs for its use-limited 10
dispatchable thermal resources, and proxy costs for the remainder.40 Phase Two of the 11
CCE allowed market participants to submit proxy bids for multi-stage generators at up to 12
1.25 times the CAISO-calculated cost in order to capture the “transition” costs of moving 13
between configurations.41 14
Following CAISO’s Commitment Cost Enhancement initiative, 15
16
17 42 18
19 43 Cost impacts are calculated by comparing Bid Cost Recovery credits from 20
settlement invoices with the calculations from the corrected commitment costs.44 SCE 21
39 A.16-04-001, Testimony, Chapter II, Section F, Part 1, p. 22. 40 Id. 41 Id., p. 22-23. 42 Id., Chapter II Workpapers, “Section E_Commit Cost.” 43 Id. 44 SCE Response to Data Request 21, Question 1, Part a.
Attachment 2.9 Page 3
166892015 2-13
calculates these impacts for the year as a whole in the following year when preparing 1
ERRA testimony.45 2
SCE presented new information in its Record Period 2015 testimony regarding its 3
commitment cost bid errors for not only 2015, but for previous Record Periods as well. 4
While reviewing its Resource Data Template for the 2015 Record Period, SCE 5
discovered that the reason for the incorrect registered commitment cost elections was that 6
it had “misapplied the CAISO cost cap calculation formula when submitting Registered 7
[start-up and minimum load] cost values for its resources.”46 In its Supplemental Direct 8
Testimony, SCE reported that a subsequent investigation revealed that it had made the 9
same error in its commitment cost calculations for Record Periods 2012 through 2014 as 10
well.47 Additionally, SCE discovered 227 additional commitment cost calculation errors 11
committed in Record Period 2014.48 At the time SCE filed its Record Period 2012 and 12
2013 ERRA compliance testimony, it was not required for the utilities to provide 13
numerical data on their commitment cost elections, but the written testimony from these 14
two years does not mention any errors at all in the narrative.49 The combined cost impact 15
from incorrect commitment cost elections for 2012 through 2014 is 50 16
The information regarding the commitment cost calculation errors for Record 17
Periods 2012 through 2014 was presented to the Commission for the first time in the 18
Supplemental Testimony filed on June 29, 2016 and had not been reported in any 19
previous ERRA compliance filing.51 The Commission can only approve or disallow costs 20
based on the information available at the time of the ERRA filing. Because the reason for 21
45 SCE Response to Data Request 22, Question 7. 46 A.16-04-001, Testimony, Chapter II, Part E, p. 21. 47 Id., Supplemental Direct Testimony, Chapter IV, Part B, p. 18. 48 Id., Workpapers, “Section E_Commit Cost _SUPP_2012-14”. 49 A.14-04-006, A.13-04-001. 50 A.16-04-001, Supplemental Direct Testimony, Workpapers, “Section E_Commit Cost _SUPP_2012-14”. 51 SCE Response to Data Request 22, Question 3.
Attachment 2.9 Page 4
166892015 2-14
the commitment costs errors for 2012 through 2014 was only reported in the Record 1
Period 2015 filing, ORA had new reason to analyze the cost impacts incurred as a result 2
of these errors. Upon doing so, ORA found that the errors are unreasonable and the fact 3
that SCE did not notice or report them until 2016 demonstrates a lack of due diligence. 4
5
6
ii. Incremental Bid Cost Calculations 7
SCE calculates the incremental costs of its resources based on the variable costs 8
associated with increasing or decreasing units of energy. The components that go into 9
these incremental costs include incremental heat rates, variable operating and 10
maintenance costs, greenhouse gas (GHG) costs, CAISO grid maintenance charges, 11
natural gas prices, and any additional natural gas adders.52 12
13
14
15
16 53 17
At this time, SCE does not 18
know why these bids were submitted incorrectly, but notes that they are “exploring 19
potential remedies” to prevent this type of data discrepancy for future Record Periods.54 20
By comparison, in 2014, SCE submitted 21
22
23 55 The 2015 Record Period shows an improvement in both the number of bids 24
52 A.16-04-001, Testimony, Chapter II, Part E, Section 1, p. 19-20. 53 Id., p. 20. 54 Id. Chapter II Workpapers, “Section E_Inc Bid Cost Variance Methodology.” 55 A.15-04-002, Supplemental Testimony, Chapter III, Part A, p. 4.
Attachment 2.9 Page 5
166892015 2-15
with variances and in the overall cost impact of these variances. ORA does not 1
recommend a disallowance, but does recommend that SCE continue to monitor and 2
update its bidding system to prevent future errors. 3
iii. Bidding Activity 4
SCE bids all available resources into the market at their incremental cost and if the 5
LMP (the price of energy at the node where the resource is sited) is greater than or equal 6
to the bid price, CAISO will dispatch the resource. Although not reported in testimony, 7
SCE stated that it is “not aware of” any instances in which a resource was not bid into the 8
CAISO market when it was available.56 SCE is also not “aware of” occasions when 9
incremental energy was not awarded when the incremental bid cost at the awarded 10
MWh level was below the LMP.57 However, SCE’s incremental bid cost variance 11
workpapers included 59 occasions in which the LMP was greater than both the clean and 12
calculated bid, but the resources did not receive a market award.58 When ORA further 13
investigated these 59 occasions, SCE explained that on these occasions the resources had 14
been off-line and when factoring in start-up costs, it was not economic for CAISO to 15
dispatch the resource.59 16
The requirements described in D.15-05-007 state that the utility must report the 17
“[p]ercentage of times incremental energy was not awarded when incremental bid cost at 18
the awarded megawatt (“MW”) level was lower than the Locational Marginal Price 19
(“LMP”) at the applicable node.”60 ORA disagrees with SCE’s explanation that this 20
reporting only serves to indicate incorrect dispatch decisions61 as the Decision does not 21
make this distinction. ORA only received SCE’s explanation about the 59 22
56 SCE Response to Data Request 21, Question 2. 57 Id., Question 3. 58 A.16-04-001, Chapter II Workpapers, “Section D_Inc Bid Cost Variance Impact.” 59 SCE Response to Data Request 22, Question 4. 60 D.15-05-007, Appendix A, Item 3. 61 SCE Response to Data Request 22, Question 4.
Attachment 2.9 Page 6
166892015 2-16
aforementioned occasions after substantial analysis and data discovery, but ORA does not 1
have the resources to verify all of SCE’s bidding activity to determine whether there are 2
any additional occasions in which SCE’s resources did not receive a market award 3
despite the bid cost being below the LMP. 4
SCE did not provide the necessary bidding activity data in its testimony, despite 5
the clear requirement in D.15-05-007 to do so.62 Additionally, SCE failed to perform the 6
necessary analyses on its own bidding and dispatch data to provide the full and correct 7
information when ORA requested the data. The purpose of the requirement to provide 8
this data in testimony is for the utilities to prove to the Commission that they managed 9
their resources according to least-cost principles. If the information and analysis is not 10
provided, it demonstrates a lack of due diligence and transparency. Additionally, because 11
SCE did not provide the required data and did not perform the necessary analysis, ORA 12
cannot determine whether there are additional omissions in SCE’s analysis and reporting. 13
ORA recommends: 14
● The Commission order SCE to improve its bidding activity 15 reporting in accordance with the D.15-05-007 and clearly 16 provide data for the number of times resources were not bid 17 into CAISO markets when available (even if it was zero 18 times) and the percentage of times incremental energy was 19 not awarded when the incremental bid cost was below the 20 LMP (even when 0% or if the added start-up and minimum 21 load costs make dispatch uneconomic). 22
iv. Self-Commitment 23
In the 2015 Record Period, 24
63 25
26
27
28
62 D.15-05-007, Appendix A, Item 3. 63 A.16-04-001, Testimony, Chapter II, Part E, Section 1, p. 20.
Attachment 2.9 Page 7
166892015 2-26
.97 Additionally, 1
were dispatched over the whole year.98 2
iii. Summary and Recommendations 3
SCE did not provide in its testimony or workpapers any information about DR 4
opportunity cost calculation, CAISO market integration, or instances when a DR trigger 5
was met but the resource was not dispatched, other than the trigger not being forecast. 6
Despite the clear requirement to do so in Decision D.15-05-007,99 all of these details 7
reported here came from a data request response. Going forward, SCE should provide 8
more information in its testimony and workpapers, adapted to explain its opportunity cost 9
calculations and bids as they are submitted to the CAISO market. 10
As mentioned earlier, ORA cannot assess SCE’s overall DR forecast accuracy 11
since it was only necessary to forecast trigger conditions for half of the Record Year. In 12
terms of use factor, or the percent dispatched of total number of hours as allotted in the 13
tariff, SCE’s performance is compared with the previous Record Period:100 14
DR Program Type 2015 Use Factor 2014 Use Factor
AMP –
AMP –
Day-Ahead CBP (1-4)
Day-Ahead CBP (2-6)
Day-Of CBP (1-4)
Day-Of CBP (2-6)
SDP-C
97 Id. “DR-CBPDO14_CONFIDENTIAL,” “DR-CBPDO26_CONFIDENTIAL.” 98 Id. “DR-SDPC_CONFIDENTIAL,” “DR-SDPR_CONFIDENTIAL.” 99 D.15-05-007, Appendix 2, Items 1 and 8. 100 A.15-04-001, ORA Testimony, Chapter II, p. 2-9,10. 101
Attachment 2.9 Page 8
166892015 2-27
SDP-R
Overall, SCE’s DR program management improved for most of its resources. There are 1
aspects to the CAISO market integration that yielded a better outcome for some types of 2
DR programs than others. Because this was a partial year, ORA cannot determine 3
whether, as a whole, SCE managed its DR resources according to least-cost principles. 4
However, SCE could significantly improve its reporting. ORA recommends: 5
● The Commission order SCE to report all of the Demand 6 Response metrics and data relevant to post-CAISO market 7 integration DR dispatch in its testimony and workpapers 8 according to D.15-05-007. 9
● The Commission order SCE to report any metrics, 10 calculations, evaluations of opportunity costs, bidding 11 activity, and processes associated with the CAISO market 12 integration process that are not delineated in D.15-05-007 but 13 that explain this process in a way that allows the Commission 14 to evaluate compliance with least-cost dispatch principles. 15
V. CONCLUSION 16
ORA finds that SCE managed most of its resources responsibly except its 17
commitment cost calculations, for which ORA recommends 18
Because the reason for the commitment costs errors for 2012 through 19
2014 was only reported in the Record Period 2015 filing, ORA had new reason to analyze 20
the cost impacts incurred as a result of these errors. Upon doing so, ORA found that the 21
errors are unreasonable and the fact that SCE did not notice or report them until 2016 22
demonstrates a lack of due diligence. ORA also recommends that SCE provide 23
substantially more information in its testimony and workpapers with respect to price and 24
load forecast; thermal bid cost calculation; hydro bidding, dispatch, and pumped storage 25
data; management of renewable resources; and DR following CAISO market integration. 26
Additionally, ORA recommends that SCE undergo independent reviews by a third party 27
of its price and load forecast models and its hydro forecast models, and for the plans of 28
these reviews to be in place by the time SCE files its next ERRA compliance application. 29
Attachment 2.9 Page 9
CHAPTER 2
ATTACHMENT 2.10
SCE Supplemental Direct Testimony for SCE 2015 ERRA A.16-04-001
Application No.: A.16-04-001 Exhibit No.: SCE-05 Witnesses: S. DiBernardo
M. Palanza E. Quach T. Ware T. Watson
(U 338-E)
Supplemental Direct Testimony of Southern California Edison Company
Before the
Public Utilities Commission of the State of California
Rosemead, California
June 29, 2016
Page 1
18
IV. 1
LEAST COST DISPATCH 2
A. Introduction 3
Decision (D.)15-05-007 included specific guidance on how SCE must demonstrate 4
compliance with the Commission’s Least-Cost Dispatch (LCD) requirements. This guidance 5
initially became effective for the 2014 Record Period through an Interim Ruling,16 and was 6
subsequently adopted by the Commission in D.15-05-007. One component of the demonstration 7
is exception rates and associated cost impacts for SCE-initiated CAISO Master File (Resource 8
Data Template, or RDT) changes regarding thermal resource startup (SU) and minimum load 9
(ML) costs. 10
B. Master File (RDT) Change Exceptions 11
As SCE stated in Exhibit SCE-01, Chapter II, while reviewing its RDT change history for 12
the 2015 Record Period, SCE discovered it had misapplied the CAISO cost cap calculation 13
formula when submitting Registered SU/ML cost values for several of its resources.17 Following 14
this discovery, SCE subsequently investigated previous years and determined that the issue also 15
occurred during the 2012-2014 Record Periods. 16
The CAISO Tariff allowed market participants to choose between two methodologies 17
(“Proxy” or “Registered”) to declare SU/ML costs. Proxy costs are automatically calculated 18
each day using an indexed natural gas price; Registered costs are fixed values set by the market 19
participant.18 Registered SU/ML costs are capped at 150% of the respective calculated Proxy 20
costs. In May 2012, SCE began inadvertently utilizing an incorrect (slightly lower) natural gas 21
transportation cost adder when calculating the cost cap for several of its resources, thus under-22
estimating the cap and in some cases artificially reducing the Registered SU/ML costs. The 23
16 Interim Ruling Providing Guidance for 2014 ERRA Compliance Proceedings, dated December 2,
2014. 17 See Table II-4 in A.16-04-001, Exhibit SCE-01C, p. 22. 18 See Exhibit SCE-01C, p. 21.
Page 2
CHAPTER 2
ATTACHMENT 2.11
Workbook Concerning Commitment Costs Submitted by SCE Along with A.17-04-004
Testimony
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.12
Various SCE Responses to ORA Data Requests for A.16-04-001 and A.17-04-004
(CONFIDENTIAL)
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-09
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/09/2017
Question 1.1.2.-1.1.2.2:
1.1.2. Are there any costs associated with purchasing too much or too little energy for load on the Day-ahead Market?
1.1.2.1. If so, please provide an estimation of costs for 2016 due to variances between awarded energy and delivered energy.
1.1.2.2. If so, please also state any payments to or refunds from CAISO resulting from such transactions.
Response to Question 1.1.2.-1.1.2.2:
CONFIDENTIALThis document contains confidential materials that are protected pursuant to California
Public Utilities Commission Decisions and Applicable Law- Public Disclosure Restricted -
Attachment 2.12 Page 1
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-09
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/09/2017
Question 1.1-1.1.1:
1. In regards to the workpaper “Ch. II_Section D_DLAP Highest 100 Value Days_CONFIDENTIAL.xlsx”
1.1. The tab, “100 Highest Energy Value Days” Column D shows a median and mean of
1.1.1. Did SCE change any policies or the Demand Bidding Strategy As described on page 17 of SCE Testimony. of procuring energy to serve customer load in order to
?
Response to Question 1.1-1.1.1:
CONFIDENTIALThis document contains confidential materials that are protected pursuant to California
Public Utilities Commission Decisions and Applicable Law- Public Disclosure Restricted -
Attachment 2.12 Page 2
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-05
To: ORAPrepared by: Jim Buerkle
Title: Director Dated: 05/22/2017
Question 1.1:
1. In regards to the El Segundo Cost Exceptions described on page 23 of the A.17-04-004 (“Application”).
1.1. Please describe how the incorrect startup cost parameter was calculated, and how the correct amount was calculated.
Response to Question 1.1:
There was no error in the startup cost calculation method, rather one component of the start-up cost calculation was not input into the bidding software that performs the calculation. So the startup calculation was using a $0 value for that cost component instead of the actual cost.
Attachment 2.12 Page 3
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-05
To: ORAPrepared by: Jim Buerkle
Title: Director Dated: 05/22/2017
Question 1.4:
1. In regards to the El Segundo Cost Exceptions described on page 23 of the A.17-04-004 (“Application”).
1.4. Please explain how SCE’s internal bid calculation systems generate bid prices for the CAISO market, including how the startup cost is a factor in routine bid calculations.
Response to Question 1.4:
CAISO’s market expects two different types of bid cost parameters for each resource: commitment costs (Start Up, Minimum Load, and Transition Costs) and marginal energy bid costs. Start Up bid costs are calculated using startup fuel, natural gas price, auxiliary load, electricity price index, greenhouse gas (GHG) price, and a Major Maintenance Adder. Minimum Load bid costs are calculated using fuel volume at minimum load, natural gas price, GHG price, Major Maintenance Adder, and variable operating and maintenance costs (VOM). Marginal energy bid costs are calculated using a formula based on the natural gas price, incremental heat rate, GHG price, and VOM. Start Up costs are not a factor in routine marginal energy bid calculations.
Attachment 2.12 Page 4
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-05
To: ORAPrepared by: Jim Buerkle
Title: Director Dated: 05/22/2017
Question 2.1:
2. In regards to cost variances due to systems malfunctions as described in page 20 of the Application and the Section E “Inc Bid Cost Variance Methodology” attachment.
2.1. Did SCE take any steps to investigate the cause of 1,080 instances of variance due to internal systems delaying the VOM cost adder data transfer process?
Response to Question 2.1:
The system error which resulted in these variances was not identified until months after the fact and did not reoccur so no root cause was determined. However, SCE's IT team routinely diagnoses the health of our systems and upgrades them to ensure maximum performance.
Attachment 2.12 Page 5
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-05
To: ORAPrepared by: Jim Buerkle
Title: Director Dated: 05/22/2017
Question 2.2:
2. In regards to cost variances due to systems malfunctions as described in page 20 of the Application and the Section E “Inc Bid Cost Variance Methodology” attachment.
2.2. If a costly variance occurs due to CAISO system errors, does CAISO have any procedures in place to refund SCE?
Response to Question 2.2:
SCE uses a process called “Shadow Settlement” to reproduce the charges assessed by the CAISO using internally available data sources to SCE. In the event of a variance between the shadow settlement and actual CAISO settlement, SCE researches the cause of the variance and will dispute the charge with the CAISO based on established protocols for the dispute process. The dispute case is reviewed by CAISO and can be denied or approved based on the reasoning provided for the dispute. In the case of a denial by CAISO where SCE believes the CAISO result is inappropriate, SCE can pursue the dispute further through a Go.
Attachment 2.12 Page 6
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 1 - 1.1:
1. In regards to the workpaper “Chapter II_Section E_Inc Bid Cost Variance_Confidential” Tab “Variance Descriptions”
1.1. What steps has SCE taken to reduce the “SCE user” causes for variance?
Response to Question 1 - 1.1:
To reduce the user errors associated with late updates of bid parameters (e.g. the errors on 9/1/16 and 11/14/16), SCE implemented measures focused on improving communication between groups and validation of data entry.The primary area of focus was the link between the group responsible for updating bid parameters and the group responsible for submitting bids. The handoff process was clarified, providing a better understanding of operating timelines, deadlines, and lead times. Communication was streamlined, with updates to bid parameters sent directly to the downstream bid submission group.To reduce user errors associated with data entry (e.g. the errors on 12/7/16 and 12/30/16), SCE is working to automate as many data entry processes as possible and institute more verification points for those processes that will continue to require manual entry.
Attachment 2.12 Page 7
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.1:
2.1. The Testimony describes that the startup (SU) cost error at El Segundo 5/6 and 7/8 was found in January 2017 by a routine data review. Please provide a description of the data review, including answers to the questions below:
Response to Question 2.1:
SCE’s tolling agreements include start-up charges and variable operating and maintenance (VOM) costs which may escalate each year. The routine review and update of these annual cost parameters is what led to the discovery of the El Segundo startup cost error.
Attachment 2.12 Page 8
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.1.1:
2.1.1. How often is the routine data review conducted?
Response to Question 2.1.1:
This particular review is conducted twice a year. Once in January or early February when the latest consumer price index (CPI) is released; and again in June using the latest CPI. Resources that have a calendar year contract term are updated in January; resources that have a contract term period that begins in June are updated in June.
Attachment 2.12 Page 9
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.1.2:
2.1.2. Is the data review conducted for all contracted resources at once, or staggered for resources across a timeframe?
Response to Question 2.1.2:
The review is staggered based on the contract term year as described above in 2.1.1.
Attachment 2.12 Page 10
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.1.3:
2.1.3. What data is checked by SCE during such a data review?
Response to Question 2.1.3:
The scope of this review are bid parameters that update annually, namely the startup charge and VOM. SCE also conducts monthly reviews of use limitations around number of starts and runtimes. Operating parameters such as ramp rate, heat rate, and ancillary service capability are reviewed on an ad-hoc basis since they only change when there is a physical change to the resource. CAISO tests are performed to validate and update those operational parameters.
Attachment 2.12 Page 11
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.1.4:
2.1.4. Is the data review designed to detect errors such as the SU cost error at El Segundo?
Response to Question 2.1.4:
The review is primarily designed to identify the correct bid parameters, but it will also detect incorrect values that have been in use.
Attachment 2.12 Page 12
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.1.5:
2.1.5. How did the data review detect the SU cost error?
Response to Question 2.1.5:
When the startup charge for El Segundo was updated, SCE discovered the prior year’s field had no startup cost value.
Attachment 2.12 Page 13
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.1.6:
2.1.6. How quickly was the SU cost error corrected following its discovery?
Response to Question 2.1.6:
The error was corrected immediately. SCE updated the startup cost value and used the correct value in the following day-ahead bids.
Attachment 2.12 Page 14
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.2:
2.2. Were there any standards or protocols in place that may have detected the SU cost error at the time of entry, between December 2016 and January 2017, or beyond January 2017 other than the routine data review conducted in January?
Response to Question 2.2:
There were no other standards or protocols in place at the time.
Attachment 2.12 Page 15
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.3:
2.3. Who is the developer/creator of and what is the name of the bidding software which performed the calculation as described in Data Request No. ORA-A.17-04-004 SCE005 Question 1.1?
Response to Question 2.3:
The bidding software is Power Cost Inc. (PCI).
Attachment 2.12 Page 16
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.4:
2.4. Was SCE personnel aware that the software would assume a $0 value if an input was not entered into the calculation?
Response to Question 2.4:
Yes.
Attachment 2.12 Page 17
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.4.1:
2.4.1. If so, is it common practice for SCE personnel to leave input blanks to intentionally enter a $0 value through routine bidding processes?
Response to Question 2.4.1:
It is not routine to leave an input field blank when the value should be $0. It is routine to enter $0 in order to minimize confusion.
Attachment 2.12 Page 18
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.4.2:
2.4.2. Would it be reasonable or preferable for the software to refuse the input of an empty entry, rather than assume a value of $0?
Response to Question 2.4.2:
Yes, a validation system that refuses an empty input field would help minimize this type of error.
Attachment 2.12 Page 19
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.5:
2.5. Does SCE have any other units at El Segundo, other than 5/6 and 7/8, for which they are the scheduling coordinator?
Response to Question 2.5:
No. SCE is only the scheduling coordinator for 5/6 and 7/8.
Attachment 2.12 Page 20
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.6:
2.6. Did any SCE or other personnel at El Segundo report that unit 5/6 and/or 7/8 was being dispatched by CAISO more than usual, or more relative to other units or powerhouses?
Response to Question 2.6:
The personnel at El Segundo send over a daily report which contains the start-up count and run hours from the previous day, as well as month to date and year to date. While the resource was being dispatched more by the CAISO than it had prior to the transition to SCE, we had no insight into the previous scheduling coordinators bidding practices. In addition, the Generator Resource Data Template (GRDT) provided by the resource owner prior to SCE becoming scheduling coordinator showed less operational flexibility to the market than what SCE had negotiated into the tolling contract and was reflected in the GRDT upon becoming scheduling coordinator. Other peaking units (such as SCE’s utility-owned peakers) also had a high frequency of dispatches during Q4.
Attachment 2.12 Page 21
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-10
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/13/2017
Question 2.6.1:
2.6.1. Are there any protocols in place for personnel at the plant to detect and report increased dispatches?
Response to Question 2.6.1:
Personnel at the plant report the number of start-ups and run hours daily but do not provide an opinion on the frequency of dispatch unless the contractual or air permit limitations are at risk of being violated.
Attachment 2.12 Page 22
Southern California EdisonApril 2016 ERRA Review A.16-04-001
DATA REQUEST SET A1604001 ORA-SCE-21
To: ORAPrepared by: Thomas Watson
Title: Principal Advisor Dated: 07/21/2016
Question 01:
1. Please explain the calculations provided in the workpaper titled, “SCE ERRA 2016 Chapter II_Section E_Commit Cost_CONFIDENTIAL.”
a. How are the cost impacts calculated?
b. What are the reasons that incorrect registered costs were submitted on each occasion that they were incorrect?
c. Please explain each occasion that an incorrect registered cost submission did not have a cost impact.
Response to Question 01:
Response to Question 1a:
As specified in D.15-05-007, cost impacts are based on an estimate of CAISO Bid Cost Recovery (“BCR”) gains or losses calculated by comparing BCR credits from settlements invoices with calculated BCR using correctly-calculated commitment costs. Response to Question 1b:
Please refer to Chapter IV, Section B of SCE’s Supplemental Direct Testimony in A.16-04-001, Exhibit SCE-05, dated June 29, 2016.
Response to Question 1c:
Incorrect commitment cost submissions were deemed impactful only when CAISO committed the respective unit and market revenues including BCR would have differed using the corrected costs. Incorrect submissions were deemed not impactful if the respective resource was not committed and thus BCR did not apply, or if it was committed and BCR did not apply using either the originally submitted or the corrected costs.
Attachment 2.12 Page 23
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-20
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 07/10/2017
Question 1:
1. Please provide a monthly and annual table summarizing the percentage of times incremental energy was not awarded when incremental bids at the awarded megawatt level was lower than the LMP at the applicable node. Please explain what caused the non-incremental award, to include CAISO decision to not award an appropriate bid, and refer to CIDI tickets (already included in Testimony as “SCE ERRA 2017 Chapter II_Section B_CAISO LCD CIDI tickets”) as needed. Please also include any other subsequent actions taken by the utility.
Response to Question 1:
Incremental bids are only one cost component that the CAISO’s model considers in making award decisions. The full cost of the energy dispatch includes both commitment costs (Startup, Minimum Load and Transition Costs) and incremental energy bids. SCE systems produce daily reports comparing total market revenue, inclusive of all awards for energy and ancillary services, netted against all of the costs to commit the resources and provide the awarded products (energy and ancillary services) over the course of a 24-hour period. When there is a significant gap between the expected and actual revenue—over a 24-hour period—SCE will ask for a CAISO review through the CIDI ticket process.
Attachment 2.12 Page 24
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-21
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 07/31/2017
Question 01:
In regards to the workbook, “SCE ERRA 2017 Chapter II_Section E_Inc Bid Cost Variance_CONFIDENTIAL.xlsx”
1. The tab, “Hours LMP > Bid” lists, “2016 Count of Hours LMP > Incremental Energy Bid (No Award)”. The amount of Resource Hours listed in cell A4 appears to be the total for the “No_Inc_Awd” variable. Across all resources and hours for the Record Period, this binary variable appears to have a value of 1 when incremental dispatch is not awarded, but it also has a value of 1 when dispatch occurs when the LMP is below the P1 variable.
1.1. Please explain the purpose of the “Hours LMP > Bid” tab.
1.1.1. D.15-05-007 Appendix A Item 3e requires the reporting of instances when no energy was awarded when incremental bid costs were lower than the LMP. If tab “Hours LMP > Bid” does not demonstrate this showing, please state where in the ERRA application it is given.
1.1.1.1. Please also state where in the ERRA application the explanation and actions taken by SCE regarding non-award of incremental bids, required by the same decision, are located.
1.2. Please explain why the Resource Hours entry appears to include instances of dispatch when the LMP was below the P1 bid price.
1.3. Please state the reasons for why dispatch may occur when the LMP is below the lowest incremental economic bid.
Response to Question 01:
1.1 The purpose of the Hours LMP>Bid tab is to meet the requirements established in Appendix A: Joint Utilities Least Cost Dispatch Demonstration Proposal, Item 3e.
However, the calculations appear to be incorrect. The correct calculations are attached.
1.1.1 The calculations in Hours LMP>Bid tab appear to be incorrect. We have attached the
Attachment 2.12 Page 25
corrected calculations in the attached worksheet: Rev2_SCE ERRA 2017Chapter II_Section E_Inc Bid Cost Variance_CONFIDENTIAL wth fixed DA LMP for
MOSSLANDING 29JUN17.xlsx
1.1.1.1 Actions taken by SCE regarding questions over dispatch are located in “SCE ERRA 2017 Chapter II_Section B_CAISO LCD CIDI tickets”.
The award hours flagged in the corrected query are all acceptable because the award falls within the MW range for that price. For more description please refer to the response to question 2 below.
1.2 The calculation is incorrect, please refer to worksheet attached in 1.1.1.
1.3 Dispatches where LMP is below the bid price may occur if the CAISO awards Ancillary Services or if the resource is needed for system reliability (exceptional
dispatch). Ancillary services are co-optimized with energy, and the bid price and AS price are also be considered in the dispatch decision.
Attachment 2.12 Page 26
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-21
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 07/31/2017
Question 02:
2. Please explain how CAISO may award a MW quantity of energy that is different from the incremental MW bid quantities (for example, if a resource has a MW1 bid of 100MW, a MW2 bid of 200MW, but a market award of 150MW and a self-schedule award of 0MW).
Response to Question 02:
The quantities in the bid points reflect step changes in pricing and quantity. As long as the bid clears the segment (LMP is higher than bid price), the unit may be awarded anywhere between the lowest point of the bid segment up to the next highest bid segment.
Attachment 2.12 Page 27
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-21
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 07/31/2017
Question 03:
3. Were there any instances in the Record Period where there was no award for an incremental energy bid when the LMP was above the appropriate bid of a resource which was not due to CAISO dispatch decisions? If so, please describe what prevented incremental dispatch and any steps SCE took to address the problem.
Response to Question 03:
No, all available generation is bid into the CAISO market, so all dispatch decisions are made by CAISO. The only exceptions are due to unit outages and unit tests.
Attachment 2.12 Page 28
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-14
To: ORAPrepared by: Serge Handschin
Title: Manager-Project/Product 2 Dated: 06/26/2017
Question 01:
1. What constraints are there on Eastwood Power Station’s pump-back operation?
· Please include any typical hours or days, other than outages, when the station is unstaffed or operations are not possible.
· Please include any periods when pump-back was not possible, such as the afterbay water level conditions described on SCE’s response to Data Request 8, Question 1.3 attachment, tab “Eastwood,” cell H2.
Response to Question 01:
As noted, should equipment problems or scheduled maintenance prevent Eastwood from generating electricity in the conventional generating mode, then pump-back would also not be possible. Balsam Forebay receives water from Huntington Lake and from Pitman Creek. To generate electricity, water is routed from the Balsam Forebay to the Eastwood Power Station, and is discharged directly into Shaver Lake (i.e., there is no separate Eastwood Power Station "afterbay"). Water flow during pump-back is in the opposite direction. Insufficient water level in Shaver Lake (i.e., below 80,000 Acre-Feet), or having the Balsam Forebay in a full or near-full condition, prevents pump-back.
Pump-back was not possible from January 1 through January 16, 2016 due to Shaver Lake being below 80,000 Ac-Ft. On January 16 2016, Shaver Lake level became high enough for pump-back; however, pump-back was inoperable at that time due to equipment problems. These problems were corrected on February 16, 2016. However, shortly thereafter, Shaver Lake again dropped below 80,000 Ac-Ft, and pump-back was not possible until late-April when Shaver Lake next exceeded 80,000 Ac-Ft. From late-April until 2016 year-end, Shaver Lake level was sufficient for pump-back, and there were no Eastwood outages or extended pump-back equipment problems during that time, except for a scheduled outage November 28 through November 30.
Attachment 2.12 Page 29
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-14
To: ORAPrepared by: Serge Handschin
Title: Manager-Project/Product 2 Dated: 06/26/2017
Question 02:
2. The Testimony at page 55 (footnote 52), explains that it takes 1.33 MWh of electricity to pump 1.0 MWh worth of generation. Please explain any cost factors, such as startup or variable costs, which would also decrease the value of pump-back operations.
Response to Question 02:
There are no other economic factors considered for Eastwood pump-back operations.
Attachment 2.12 Page 30
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-14
To: ORAPrepared by: Leo Kim
Title: Manager-Project/Product 2 Dated: 06/26/2017
Question 08:
8. Please provide the opportunity cost value that was used as a part of SCE’s economic trigger condition for each month when the DR program was available for dispatch. Provide this information for each DR program which has a Section H worksheet. Please include this data in a separate worksheet or within an updated version of the Section H workpapers.
Response to Question 08:
CONFIDENTIALThis document contains confidential materials that are protected pursuant to California
Public Utilities Commission Decisions and Applicable Law- Public Disclosure Restricted -
Attachment 2.12 Page 31
CONFIDENTIAL This document contains confidential materials that are protected pursuant to California Public Utilities Commission Decisions and Applicable Law - Public Disclosure Restricted
Attachment 2.12 Page 32
CONFIDENTIAL This document contains confidential materials that are protected pursuant to California Public Utilities Commission Decisions and Applicable Law - Public Disclosure Restricted
Attachment 2.12 Page 33
CONFIDENTIAL This document contains confidential materials that are protected pursuant to California Public Utilities Commission Decisions and Applicable Law - Public Disclosure Restricted
Attachment 2.12 Page 34
CONFIDENTIAL This document contains confidential materials that are protected pursuant to California Public Utilities Commission Decisions and Applicable Law - Public Disclosure Restricted
Attachment 2.12 Page 35
CHAPTER 2
ATTACHMENT 2.13
Workbook Attachment for SCE’s Response to ORA Data Request 8, Question 3
(CONFIDENTIAL, Available Via Email)
CHAPTER 2
ATTACHMENT 2.14
SCE Presentation to ORA Concerning LCD
(CONFIDENTIAL)
CONFIDENTIAL. This document contains confidential materials that are protected pursuant to California Public Utilities Commission Decisions and Applicable Law ‐ Public Disclosure Restricted ‐
Least Cost DispatchORA Discussion
Thursday June 21, 2017
CONFIDENTIAL. This document contains confidential materials that are protected pursuant to California Public Utilities Commission Decisions and Applicable Law ‐ Public Disclosure Restricted ‐
Section H
8
CONFIDENTIAL. This document contains confidential materials that are protected pursuant to California Public Utilities Commission Decisions and Applicable Law ‐ Public Disclosure Restricted ‐
Section H | Net Benefits Test
8
CHAPTER 2
ATTACHMENT 2.15
Workbook Concerning Self-Scheduling Activity Submitted by SCE Along with
A.17-04-004 Testimony
(CONFIDENTIAL, Available Via Email)
CHAPTER 5
ATTACHMENT 5.1
Palo Verde’s in-house Root Cause Evaluation (RCE) Report #16-14218-021 Revision 1 on
the September 7, 2016 shutdown
Attachment 5.1 Corrective Actions
Attachment 5.1 Corrective Actions (continued)
Attachment 5.1 Corrective Actions (continued)
Attachment 5.1 Corrective Actions (continued)
Attachment 5.1 Corrective Actions (continued)
CHAPTER 6
ATTACHMENT 6.1
Selected SCE Responses to ORA Data Requests for A.17-04-004
(CONFIDENTIAL)
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-09
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 06/09/2017
Question 3.1:
3. In regards to Lines 2-7 Table VII-41 on page 116 of the Application.
3.1. Did any notional value changes occur for the six contracts between expiring terms and auto-renewal?
Response to Question 3.1:
No, there was no notional value changes for the six contracts between expiring terms and auto-renewal.
Attachment 6.1 Page 1
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-07
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 05/26/2017
Question 3.1:
3. In regards to the Contract Amendment Administration of Geysers Power Company on page 162 and 163 of the Application.
3.1. Did this Letter Agreement create a notional value change for the PPA involved?
Response to Question 3.1:
3.1. No, this Letter Agreement did not create a notional value change to the PPA.
Attachment 6.1 Page 2
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-09
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 06/09/2017
Question 3.2.-3.2.1.:
3. In regards to Lines 2-7 Table VII-41 on page 116 of the Application.
3.2. Was it possible for SCE to renegotiate terms of the six contracts between expiration and renewal?
3.2.1. If so, did SCE attempt to do so?
Response to Question 3.2.-3.2.1.:
3.2. - No. In accordance with Decision 16-07-008, the Commission required that all longer term contracts be converted to month-to-month contracts. The terms are not negotiable. The Tariff dictates all terms for gas transportation contracts. Please see explanation in Table VII-41 of the Testimony.
3.2.1 - N/A, please see answer to 3.2.
Attachment 6.1 Page 3
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-18
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 07/07/2017
Question 02:
2. During the 2016 record period, SCE amended agreements in order to extend the termination date to facilitate the transition into a new form of contract. Please provide the name and contract ID of the contract(s) which replaced the contracts below and cite the page number in SCE’s testimony where those new contract(s) are introduced. If a contract was not replaced with a new one, or was merged into another agreement, please clarify.
· Altagas Pomona Energy Letter Agreement and Amendment 5,· AES Tehachapi Wind LLC 85-A Amendments 7 and 8· AES Tehachapi Wind LLC 85-B Amendments 7 and 8· Difwind Farms Limited V Amendment 3· Difwind Partners Trust Amendments 5 and 6· Section 16-29 Power Purchase Contract Trust Amendment 6 & 7· Section 22 Power Contract Trust Amendment 3 and 4· Westwind Trust Amendment 4 and 5· Painted Hills Wind Developers Amendment 6· The Bank of New York Mellon Trust Company Letter Agreement· Oak Creek Energy Trust Amendment 3· Energy Development & Construction Corp Amendment 2 and 3
2.1. A majority of the amendments listed in question 2 experienced a reduction of short-run avoided cost (SRAC) cost of energy. Please define SRAC. In your description, please include a description of the relation of SRAC to the total cost of energy SCE pays the counterparty.
Response to Question 02:
2. Altagas Pomona Energy Letter Agreement and Amendment 5 – SCE and AltaGas Pomona Energy, Inc. executed Amendment No. 5 on January 26, 2016 to extend the termination date of the contract beyond January 2, 2016 to the earlier of (i) CAISO commercial operation date, with thirty days’ notice, or (ii) June 30, 2016, allowing AltaGas Pomona Energy, Inc. time to become a CAISO independent market participant. Additionally, the amendment clarifies that if a Generator Interconnection Agreement is executed and becomes effective, it replaces the Interconnection Facilities Agreement (IFA) as the operative interconnection agreement. On April 22, 2016, AltaGas Ponoma provided written notice to SCE on the termination of the PPA
Attachment 6.1 Page 4
effective May 31 , 2016 as AltaGas achieved commercial operation with the CAISO on June 1, 2016.
AES Tehachapi Wind LLC 85-A Amendments 7 and 8 – SCE and AES Tehachapi Wind LLC 85-A executed Amendment No. 7 on January 13, 2016 and Amendment No. 8 on April 14, 2016 to extend the contract term to provide AES Tehachapi Wind LLC 85-A with additional time to finalize their Small Generation Interconnection Agreement (SGIA). On April 30, 2016 the contract extension terminated early due to completion of replacement interconnection agreement.
AES Tehachapi Wind LLC 85-B Amendments 7 and 8 – SCE and AES Tehachapi Wind LLC 85-B executed Amendment No. 7 on January 13, 2016 and Amendment No. 8 on April 14, 2016 to extend the contract term to provide AES Tehachapi Wind LLC 85-B with additional time to finalize their Small Generation Interconnection Agreement (SGIA). On April 30, 2016 the contract extension terminated early due to completion of replacement interconnection agreement.
Difwind Farms Limited V Amendment 3 – This contract was extended per Amendment No. 3 to no later than May 31, 2017 in order to grant the project owner additional time to complete CAISO’s New Resource Implementation process, which is required in order for a project to become a merchant resource in the CAISO market. However, on March 22, 2017 the project underwent a change in ownership, and its new owner, Terra-Gen, LLC has since chosen to seek a new QF Standard Offer Contract (SOC) with SCE, and is in the process of preparing documentation for submittal to SCE. As a result, SCE and Terra-Gen, LLC executed Amendment No. 4 on May 31, 2017 to extend the contract term to no later than November 30, 2017 to effectively work through the CAISO processes and get a new interconnection agreement in place. Amendment No. 4 will be represented in SCE's 2017 ERRA Review of Operations filing.
Difwind Partners Trust Amendments 5 and 6 – SCE and Difwind Partners Trust executed Amendment No. 5 on January 12, 2016 and Amendment No. 6 on March 2, 2016 to extend the contract term end date to provide Difwind Partners Trust with additional time to obtain their Generation Interconnection Agreement (GIA). On March 10, 2016 the contract for Difwind Partners Trust expired and was not merged or replaced with a different contract.
Section 16-29 Power Purchase Contract Trust Amendment 6 & 7 – SCE and Section 16-29 Power Contract Trust executed Amendment No. 6 on January 8, 2016 and March 2, 2016 to extend the contract term to provide Section 16-29 Power Purchase Contract Trust with additional time to obtain their Generation Interconnection Agreement (GIA). On March 10, 2016 the contract for Section 16-29 Power Purchase Contract Trust expired and was not replaced or merged with a different contract.
Section 22 Power Contract Trust Amendment 3 and 4 – SCE and Section 22 Power Contract Trust executed Amendment No. 3 on January 8, 2016 and January 21, 2016 to extend the contract term to provide Section 22 Power Contract Trust additional time to obtain their Generation Interconnection Agreement (GIA). On January 29, 2016 the contract for Section 22
Attachment 6.1 Page 5
Power Contract Trust expired and was not replaced or merged with a different contract.
Westwind Trust Amendment 4 and 5 - SCE and Westwind Trust executed Amendment No. 4 on June 23, 2016 to extend the termination date to coincide with the transition to a new QF SOC contract for Smoke Tree Wind, LLC (ID 6496). The termination extension stated that the termination date shall not go beyond December 31, 2016. However this contract was terminated before it came online, resulting in amendment 5 executed on December 19, 2016 to extend the term again to April 30, 2017 allowing the project additional time to execute a Small Generation Interconnection Agreement (SGIA).
Painted Hills Wind Developers Amendment 6 - SCE and Painted Hills Wind Developers executed Amendment No. 6 on January 5, 2016 to extend the termination date from November 30, 2015 to March 31, 2016, while Painted Hills Wind Developers prepared the facility for transition. However, midway through the counterparty changed their mind and subsequently did not follow through on the requirements, as a result the contract ended March 31, 2016.
The Bank of New York Mellon Trust Company Letter Agreement – A Letter Agreement was executed on December 21, 2016, to extend the contract termination date day-for-day, from December 22, 2016, until an amendment to the PPA was executed; provided, the day-for-day extension did not exceed January 6, 2017. Subsequently, Amendment No. 5 was executed on January 5, 2017, which extended the term of the PPA through August, 31, 2017, to allow time for a new Interconnection Facilities Agreement to be finalized. Amendment No. 6 was executed on March 29, 2017, to further extend the term of the PPA through September 30, 2017, to allow time for a new Interconnection Facilities Agreement to be finalized. These amendments will be cited in SCE’s 2017 ERRA Review of Operations.
Oak Creek Energy Trust Amendment 3 – Contract was extended per Amendment No. 3 to grant the project additional time to put in place a new Small Generator Interconnection Agreement (SGIA) with SCE’s Transmission and Distribution group, which went in to effect on February 1, 2017. The PPA with SCE terminated January 31, 2017, per Amendment No. 3, and no replacement contract was put in place.
Energy Development & Construction Corp Amendment 2 and 3 – Energy Development & Construction Corp. successfully executed a power purchase agreement with another counterparty; therefore, the PPA between SCE and Energy Development & Construction Corp expired on June 30, 2017.
2.1. The Short-Run Avoided Cost is a pricing methodology established in D.07-09-040 and modified in D.10-12-035. Included for your reference is the most recent SRAC posting (srac_price_update.xlsx). The posting contains the primary components (fuel price, fuel transport, heat rate, VOM, and TOD) of the formula. CAISO energy is tied to delivered fuel price and heat rate with natural weather and market variances tied to hour of delivery. SRAC has historically been at or near the CAISO SP15 market price, thus any amendment with pricing discounted to SRAC represents a savings to SCE’s customers. Also included for reference are the historical SRAC prices (SRAC_hist.pdf).
Attachment 6.1 Page 6
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-18
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 07/07/2017
Question 04:
4. In reference to the Regulus Solar 5th Amendment on page 163, please describe any material
and non-material costs of reducing the Performance Assurance amount. Please include any change in exposure to risk which SCE or the counterparty may be exposed to as compared to pre-amendment conditions.
Response to Question 04:
SCE's customers are not exposed to any new costs as a result of Amendment No. 5 to the Regulus Solar, LLC contract. The reduction of the Performance Assurance amount is not expected to increase SCE's exposure to a risk of default by Regulus Solar, LLC, as the contract price is significantly higher than current market prices for renewable energy, thus disincentivizing Regulus Solar, LLC from seeking to take any actions that could jeopardize their contract with SCE.
Attachment 6.1 Page 7
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-18
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 07/07/2017
Question 05:
5. In reference to the Voyager Wind I 1st Amendment on page 179, please state which party
sought to defer the COD and for what purpose.
5.1. Also please state if SCE must make any adjustments to meet its renewable portfolio standard position as a result of this PPA’s delay.
Response to Question 05:
5.
Attachment 6.1 Page 8
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-18
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 07/07/2017
Question 06:
6. Please provide the calculation method(s) SCE typically uses to derive the notional value change of a modified contract.
Response to Question 06:
The calculation method varies depending on the nature of the modification, however, the general premise considers the net of total benefits and totals costs of the contract before and after a change in price, term or other economic condition under the contract. In addition, please see SCE's ERRA Review of Operations, 2016 Chapter VII Workpapers provides the specific calculation made for each contract modification.
Attachment 6.1 Page 9
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-18
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 07/07/2017
Question 07:
7. Please provide the calculation method(s) SCE typically uses to derive the net present value change of a modified contract.
Response to Question 07:
Net present value (NPV) is obtained by applying a discount rate to the notional values (as discussed in Question No. 6.) and discounting those values to an effective date when the transaction or valuation occurred. In addition, please see SCE's ERRA Review of Operations, 2016 Chapter VII Workpapers.
Attachment 6.1 Page 10
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-12
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 06/19/2017
Question 02:
2. If the list provided in Question 1 does not include the amendments to PURPA and CHP contract amendments, as listed on Table VII-50 of the Testimony, please state why.
· In particular, contract ID 2050, 4025, 6044, and 6053 experienced changes in contracted energy price, but the Testimony does not report any change in notional value of those contracts. If these contracts are not mentioned in Question 1, please address why in your response to Question 2.
Response to Question 02:
Contract IDs 2050, 4025, 6044, and 6053 are contracts that were each temporarily extended (less than six months) for purposes detailed in SCE’s testimony (Chapter 7, D.2.e). While the temporary extensions of these contracts are a benefit to customers through a negotiated reduction in price, the short-term nature of these extensions provide a negligible notational change.
Attachment 6.1 Page 11
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-12
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 06/19/2017
Question 04:
4. Did SCE have any instances of over or under-collection of payments with any counterparties in 2016? If so, please state the amounts over or under-collected, describe how the over or under-collection occurred, and state if the situation is resolved or outstanding.
Response to Question 04:
On occasion, SCE does have differences of opinion on interpretation of contract terms with counterparties. This, in turn, might result in an under-payment or over-payment depending on the point of view. If the amount is substantial enough to warrant Dispute of the payment, the contracts allow a period of time for the counterparty to take action. See Disputes Chapter VII, sections D (1)(k), D(2)(j), and D(3)(j). If SCE discovers an over-payment has occurred, SCE will claw-back within the next payment cycle. Other than the Disputes discussed in the testimony, there were no outstanding issues during the Record Period.
Attachment 6.1 Page 12
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-07
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 05/26/2017
Question 3.1:
3. In regards to the Contract Amendment Administration of Geysers Power Company on page 162 and 163 of the Application.
3.1.
Response to Question 3.1:
3.1.
Attachment 6.1 Page 13
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-07
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 05/26/2017
Question 3.6.1:
3. In regards to the Contract Amendment Administration of Geysers Power Company on page 162 and 163 of the Application.
3.6.
3.6.1.
Response to Question 3.6.1:
3.6.1.
Attachment 6.1 Page 14
Southern California EdisonApril 2017 ERRA Review A.17-04-004
DATA REQUEST SET A1704004 ORA-SCE-07
To: ORAPrepared by: Ezana Emmanuel
Title: Project Manager Dated: 05/26/2017
Question 3.6.2:
3. In regards to the Contract Amendment Administration of Geysers Power Company on page 162 and 163 of the Application.
3.6.
3.6.2.
Response to Question 3.6.2:
3.6.2.
Attachment 6.1 Page 15
CHAPTER 6
ATTACHMENT 6.2
PPA Amendment Concerning Heber Geothermal
Southern California Edison Confidential Information
RAP ID# 3001, Heber Geothermal Company LLC
The contents of this document are subject to restrictions on disclosure as set forth in the Agreement.
Amendment No. 5 to the Agreement.
AMENDMENT NO. 5
to the POWER PURCHASE AND SALES AGREEMENT
between SOUTHERN CALIFORNIA EDISON COMPANY
and HEBER GEOTHERMAL COMPANY LLC
(RAP ID# 3001)
This Amendment No. 5 (“Amendment No. 5”) to the Agreement (as that term is defined below) is executed on the date(s) indicated on the signature pages hereof, is effective as of December 15, 2015(the “Effective Date”) and is entered into by and between Southern California Edison Company, a California corporation (“SCE”), and Heber Geothermal Company LLC, a Delaware limited liability company (“Seller”). SCE and Seller are hereinafter sometimes referred to individually as a “Party” and jointly as the “Parties”. Capitalized terms used and not otherwise defined in this Amendment No. 5 shall have the meanings ascribed to such terms in the Agreement.
RECITALS The Parties enter into this Amendment No. 5 with reference to the following facts:
A. SCE and Seller’s predecessor in interest have entered into that certain Power Purchase and Sales Agreement, dated August 26, 1983, as amended by that certain Amendment No. 1 dated December 11, 1984, that certain Settlement Agreement and Amendment No. 2 dated on or about August 7, 1995, that certain Amendment No. 3 dated May 1, 2008, and that certain Amendment No. 4 dated June 1, 2012 (as amended, the “Contract”); which Contract was amended by that certain Agreement Addressing Renewable Energy Pricing and Payment Issues, dated June 19, 2001, that certain Amendment No. 1 to the Agreement Addressing Renewable Energy Pricing and Payment Issues dated November 30, 2001, and that certain Agreement No. 2 Addressing Renewable Energy Pricing Issues dated May 10, 2006 (together with the Contract, the “Agreement”).
B. On December 14, 2015, Seller provided SCE notice of the expiration of the Contract Term effective at 11:59 P.M. Pacific Time on December 15, 2015. SCE disagreed and on December 15, 2015, SCE provided Seller notice of the expiration of the Contract Term effective at 11:59 P.M. Pacific Time on December 14, 2015.
C. Because Seller delivered Capacity and Net Energy to SCE on December 15, 2015, the Parties have agreed to amend the Agreement to extend the Contract Term, to adjust the
Southern California Edison Confidential Information
RAP ID# 3001, Heber Geothermal Company LLC
The contents of this document are subject to restrictions on disclosure as set forth in the Agreement.
Amendment No. 5 to the Agreement.
energy and capacity price formulas for deliveries during the Extension Period (defined below), on the terms and subject to the conditions set forth below.
AGREEMENT
In consideration of the promises, mutual covenants and agreements hereinafter set forth, and for other good and valuable consideration, as set forth herein, the Parties agree to amend the Agreement as follows: 1. Section 3.8 is deleted and replaced with the following:
“3.8 Contract Term: The term of this Agreement shall commence on the Date of Firm Operation and end at 11:59 P.M. Pacific Time on December 15, 2015.”.
2. Section 14.2 is amended to add the following new section at the end thereof:
“(g) Notwithstanding the foregoing, effective for deliveries made beginning at 12:00 A.M. Pacific Time on December 15, 2015 through the remainder of the Contract Term (the “Extension Period”), the Monthly Energy Payment formula set forth in Section 14.2 shall be deleted and replaced with the following:
Extension Period Payment = A x B
Where:
A = the energy scheduled during the applicable settlement interval of the Extension Period (kWh); and
B = ninety-seven and seven tenths percent (97.7%) of the hourly Day-Ahead Locational Marginal Price at COACHELV_2_N101 for the applicable settlement interval of the Extension Period, as published by the CAISO on January 4, 2016 ($/kWh).
The Extension Period Payment shall be calculated for all settlement intervals during the Extension Period.”.
3. Section 15.2.2 is amended to add the following new Section 15.2.2.4 at the end thereof:
“15.2.2.4 Notwithstanding the foregoing, effective for deliveries made during the Extension Period, SCE shall not be obligated to make any payment pursuant to this Section 15.2.2.”.
4. MISCELLANEOUS
(a) Reservation of Rights. Each of the Parties expressly reserves all of its respective rights and remedies under the Agreement.
Southern California Edison Confidential Information
RAP ID# 3001, Heber Geothermal Company LLC
The contents of this document are subject to restrictions on disclosure as set forth in the Agreement.
Amendment No. 5 to the Agreement.
(a) Legal Effect. Except as expressly modified as set forth herein, the Agreement remains unchanged and, as so modified, the Agreement shall remain in full force and effect. Each of the Parties hereby represents and warrants that the representations contained in the Agreement are true on and as of the date of hereof as if made by the Party on and as of said date.
(b) Governing Law. THIS AMENDMENT NO. 5 AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. TO THE EXTENT ENFORCEABLE AT SUCH TIME, EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AMENDMENT NO. 5.
(c) Successors and Assigns. This Amendment No. 5 shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and assigns.
(d) Authorized Signatures; Notices. Each Party represents and warrants that the person who signs below on behalf of that Party has authority to execute this Amendment No. 5 on behalf of such Party and to bind such Party to this Amendment No. 5. Any written notice required to be given under the terms of this Amendment No. 5 shall be given in accordance with the terms of the Agreement.
(e) Further Agreements. This Amendment No. 5 shall not be amended, changed, modified, abrogated or superseded by a subsequent agreement unless such subsequent agreement is in the form of a written instrument signed by the Parties.
(f) Counterparts; Electronic Signatures. This Amendment No. 5 may be executed in one or more counterparts, each of which will be deemed to be an original of this Amendment No. 5 and all of which, when taken together, will be deemed to constitute one and the same agreement. The exchange of copies of this Amendment No. 5 and of signature pages by facsimile transmission, Portable Document Format (i.e., PDF), or by other electronic means shall constitute effective execution and delivery of this Amendment No. 5 as to the Parties and may be used in lieu of the original Amendment No. 5 for all purposes.
[Remainder of Page Intentionally Left Blank.]
CHAPTER 6
ATTACHMENT 6.3
CAISO-Generated Data Pertaining to the Price Node for Heber Geothermal
Generated using OASIS
http://oasis.caiso.com/mrioasis/logon.do
OPR_DT OPR_HR NODE_ID_XML MARKET_RUN_IDLMP_TYPE GRP_TYPE POS MW GROUP12/15/2015 13 COACHELV_2_N101 DAM LMP ALL 1 16.2835 112/15/2015 14 COACHELV_2_N101 DAM LMP ALL 1 16.79641 112/15/2015 19 COACHELV_2_N101 DAM LMP ALL 1 45.92661 112/15/2015 23 COACHELV_2_N101 DAM LMP ALL 1 29.86395 112/15/2015 10 COACHELV_2_N101 DAM LMP ALL 1 20.72879 112/15/2015 16 COACHELV_2_N101 DAM LMP ALL 1 23.87438 112/15/2015 4 COACHELV_2_N101 DAM LMP ALL 1 22.13197 112/15/2015 6 COACHELV_2_N101 DAM LMP ALL 1 29.64196 112/15/2015 7 COACHELV_2_N101 DAM LMP ALL 1 38.02776 112/15/2015 20 COACHELV_2_N101 DAM LMP ALL 1 40.31258 112/15/2015 8 COACHELV_2_N101 DAM LMP ALL 1 37.49812 112/15/2015 17 COACHELV_2_N101 DAM LMP ALL 1 32.89707 112/15/2015 21 COACHELV_2_N101 DAM LMP ALL 1 35.32448 112/15/2015 11 COACHELV_2_N101 DAM LMP ALL 1 16.60772 112/15/2015 1 COACHELV_2_N101 DAM LMP ALL 1 23.73809 112/15/2015 5 COACHELV_2_N101 DAM LMP ALL 1 23.68978 112/15/2015 18 COACHELV_2_N101 DAM LMP ALL 1 44.79315 112/15/2015 22 COACHELV_2_N101 DAM LMP ALL 1 32.54006 112/15/2015 24 COACHELV_2_N101 DAM LMP ALL 1 26.8157 112/15/2015 2 COACHELV_2_N101 DAM LMP ALL 1 22.1234 112/15/2015 9 COACHELV_2_N101 DAM LMP ALL 1 24.75181 112/15/2015 12 COACHELV_2_N101 DAM LMP ALL 1 17.34342 112/15/2015 15 COACHELV_2_N101 DAM LMP ALL 1 19.37321 112/15/2015 3 COACHELV_2_N101 DAM LMP ALL 1 21.43722 1
