BEFORE THE PUBLIC UTILITIES COMMISSION FILED OF THE STATE OF CALIFORNIA 10-03-14 04:59 PM
Order Instituting Rulemaking to Integrate and Refine Procurement Policies and Consider R.13-12-010 Long-Term Procurement Plans (Filed December 19, 2013)
PACIFIC GAS AND ELECTRIC COMPANY’S (U 39 E) PROPOSED 2014 BUNDLED PROCUREMENT PLAN
PUBLIC VERSION (Redacted: Cover Pleading, Attachment A and Attachment C)
CHARLES R. MIDDLEKAUFF MARK R. HUFFMAN PACIFIC GAS AND ELECTRIC COMPANY 77 Beale Street, B30A San Francisco, CA 94105 Telephone: (415) 973-6971 Facsimile: (415) 973-5520 E-mail: [email protected] Attorneys for PACIFIC GAS AND ELECTRIC COMPANY
Dated: October 3, 2014
TABLE OF CONTENTS Page
I. OVERVIEW OF THE PROPOSED 2014 BPP ...... 2 A. Structure and Organization of the BPP ...... 4 B. PG&E’s Alternative Scenario ...... 5 C. Procurement Limits ...... 10 D. Appendices Addressing Scheduling, Bidding, And CAISO Operating Orders ...... 11 E. Hedging Plan Changes ...... 12 F. Nuclear Fuel Plan Changes ...... 12 G. Scoping Memo Issues ...... 13 II. SECTION I – INTRODUCTION ...... 14 III. SECTION II – STATUTORY AND LOADING ORDER REQUIREMENTS ...... 14 IV. SECTION III – COMPLIANCE WITH THE COMMISSION’S PROCUREMENT STANDARDS OF CONDUCT ...... 15 V. SECTION IV – DESCRIPTION OF PG&E FILINGS MADE TO DEMONSTRATE COMPLIANCE AND COST RECOVERY ...... 16 VI. SECTION V – PRE-APPROVAL, APPROVAL, AND FILING REQUIREMENTS ...... 16 VII. SECTION VI – UPDATES TO THE BUNDLED PROCUREMENT PLAN VIA ADVICE LETTER...... 18 VIII. APPENDIX A – PROCUREMENT PRODUCTS ...... 18 IX. APPENDIX B – PROCUREMENT PROCESSES AND METHODS ...... 20 X. APPENDIX C – PROCUREMENT LIMITS AND RATABLE RATES ...... 22 A. Electric Capacity and Energy Limits ...... 22 B. Gas Limits ...... 24 C. GHG Limits ...... 24 XI. APPENDIX D – DESCRIPTION AND EVALUATION OF CPUC MANDATED AND PG&E ALTERNATIVE SCENARIOS ...... 25 A. CPUC Mandated Scenario ...... 25 B. PG&E Alternative Scenario ...... 26 1. CCA Load Assumptions ...... 26 2. Direct Access Load Assumptions ...... 26 3. Distributed Generation Load Assumptions ...... 27 4. Overlap Issues ...... 28
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TABLE OF CONTENTS (continued) Page
XII. APPENDIX E – ELECTRIC PORTFOLIO HEDGING PLAN...... 29 A. Tenor ...... 29 B. Hedging Targets and Limits...... 29 C. 32 D. Execution Strategy ...... 33 E. 33 F. Transition Plan ...... 33 G. Unusual Events, market Dislocations and Emergencies ...... 34 H. Liquidity Management Strategy ...... 35 I. Deletions from the 2010 BPP ...... 35 XIII. APPENDIX F – NUCLEAR FUEL PROCUREMENT PLAN ...... 36 A. Forward Contracting and Price Terms ...... 36 B. Nuclear Fuel Strategic Inventory ...... 36 C. Proposed Risk Management Measures ...... 37 XIV. APPENDIX G – GREENHOUSE GAS PROCUREMENT PLAN ...... 37 XV. APPENDIX H – CONVERGENCE BIDDING ...... 38 XVI. APPENDIX I – CONGESTION REVENUE RIGHTS ...... 39 XVII. APPENDIX J – BROKERAGES AND EXCHANGES ...... 39 XVIII. APPENDIX K – BIDDING AND SCHEDULING PROTOCOLS ...... 41 XIX. APPENDIX L – CAISO OPERATING ORDER PROTOCOLS ...... 42 XX. APPENDIX M – PROCUREMENT REVIEW GROUP, COST ALLOCATION MECHANISM GROUP, AND INDEPENDENT EVALUTOR ADMINISTRATION ...... 43 XXI. APPENDIX N – RISK MANAGEMENT POLICY AND TEVAR METHODOLOGY ...... 45 XXII. APPENDIX O – ACRONYM LIST AND GLOSSARY ...... 46 XXIII. CONCLUSION ...... 47 Attachment A - 2014 Bundled Procurement Plan (“BPP”) Sections, Corresponding 2010 BPP Sections, and Description of Changes Attachment B - Substantive Changes for Commission Approval Attachment C - PG&E’s Proposed 2014 Bundled Procurement Plan
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TABLE OF AUTHORITIES Page(s)
STATUTES Legislation
AB 57 ...... 14, 15
Dodd-Frank Wall Street Reform and Consumer Protection Act ...... 19, 20, 46
Public Utilities Code
Section 454.5...... 2, 11, 14 Section 454.5(g) ...... 2
CALIFORNIA PUBLIC UTILITIES COMMISSION
Decisions
D.03-12-062 ...... 21 D.04-12-048 ...... 17 D.06-11-048 ...... 19 D.07-12-052 ...... 17 D.10-12-034 ...... 38 D.11-10-002 ...... 11 D.12-01-033 ...... 1, 10, 12, 21, 22, 23 D.12-04-046 ...... 10, 25, 40 D.13-03-017 ...... 38 D.13-10-040 ...... 15 D.14-02-040 ...... 3, 6, 22 D.14-05-023 ...... 11, 14, 41
Resolutions
Resolution E-4135 ...... 17, 44, 45 Resolution E-4122 ...... 17 Resolution E-4660 ...... 38
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BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Integrate and Refine Procurement Policies and Consider R.13-12-010 Long-Term Procurement Plans (Filed December 19, 2013)
PACIFIC GAS AND ELECTRIC COMPANY’S PROPOSED 2014 BUNDLED PROCUREMENT PLAN (PUBLIC VERSION)
Pursuant to the Scoping Memo and Ruling of Assigned Commissioner and Administrative
Law Judge (“Scoping Memo”) issued in this proceeding on May 6, 2014, Pacific Gas and
Electric Company (“PG&E”) is submitting to the California Public Utilities Commission
(“CPUC” or “Commission”) for its review and approval PG&E’s proposed 2014 Bundled
Procurement Plan (“BPP”). This filing includes a cover pleading and three attachments. The cover pleading provides an overview of PG&E’s 2014 BPP and a description of each section in or appendix to the BPP. The cover pleading also provides an explanation of how the 2014 BPP differs from PG&E’s existing BPP which was approved by the Commission in Decision (“D.”)
12-01-033, including substantive changes that PG&E has made in the 2014 BPP. In this pleading, PG&E’s current, Commission-approved BPP is referred to as the “2010 BPP.”
Attachment A provides a table that lists all of the sections in or appendices to the 2014
BPP, identifies the corresponding section or appendix in the 2010 BPP, and provides a brief explanation of changes or modifications that have been made in each section or appendix.
Attachment A will allow parties to readily compare portions of the proposed 2014 BPP to
PG&E’s 2010 BPP. Attachment B includes a list of the substantive changes in the 2014 BPP for which PG&E is specifically requesting Commission approval. Finally, Attachment C is the proposed 2014 BPP. Because the 2014 BPP and this filing include market sensitive information
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under Public Utilities Code § 454.5(g), PG&E is submitting public and confidential versions of this filing and the 2014 BPP.
I. OVERVIEW OF THE PROPOSED 2014 BPP Under Public Utilities Code § 454.5, California’s investor-owned utilities (“IOUs”) are directed to submit procurement plans that, once approved by the Commission, establish the up-front standards for IOU procurement activities and cost recovery. Because each IOU’s procurement plan is for its bundled electric customers, it is typically referred to as a “Bundled
Procurement Plan” or “BPP.” PG&E’s 2014 BPP is intended to achieve PG&E’s goals to provide safe, reliable, affordable, and environmentally sensitive electric and gas service to its customers throughout northern and central California.
It has been four years since the IOUs last filed their BPPs, and while much of the energy industry in California has remained the same during that time, there have also been significant changes. Some aspects of PG&E’s 2014 BPP filing are similar or identical to PG&E’s existing
2010 BPP. For example, the list of approved procurement products and processes is relatively unchanged, as are specific procurement strategies, such as strategies related to convergence bidding. Other aspects of PG&E’s BPP have been updated to reflect the passage of time or
Commission decisions that have been issued during the last four years. For example, the discussion of PG&E’s compliance with the loading order adopted by the Commission as a part of the Energy Action Plan (“EAP”) has been updated to reflect significant developments in and
Commission decisions affecting PG&E’s Energy Efficiency (“EE”), Demand Response (“DR”), and Distributed Generation (“DG”) programs. In addition, over the last four years, there have been substantial developments in the procurement of renewable resources and the implementation by the California Air Resources Board (“CARB”) of California’s ground-breaking Cap and Trade Program.
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In addition to updates to reflect the passage of time, there are a number of important substantive changes in PG&E’s 2014 BPP. These changes reflect the rapid evolution of the electric industry in California and throughout the United States. This evolution is being hastened by technological developments, regulatory decisions and requirements, and legislative initiatives.
PG&E’s 2014 BPP reflects a number of these key changes which have occurred in the last four years and impact PG&E’s procurement activities. Below, PG&E highlights six key changes in its 2014 BPP, which include:
1. Significant structure and organization changes to the BPP to make it more streamlined, easy to use, and transparent;
2. The inclusion of PG&E’s Alternative Scenario for its bundled electric forecast for the years 2015-2024 to reflect updated forecasts of departing load consistent with the Commission’s direction in D.14-02-040;
3. The addition of electric energy, natural gas, and greenhouse gas (“GHG”) compliance instrument procurement limits;
4. New appendices which address PG&E’s scheduling and bidding practices in the California Independent System Operator (“CAISO”) markets and PG&E’s response to CAISO operating orders related to system reliability;
5. Changes to PG&E’s electric portfolio hedging plan (“Hedging Plan”) to reduce complexity, clarify compliance obligations, and address additional price exposure; and,
6. Changes to PG&E’s nuclear fuel procurement plan given the substantial changes in the worldwide nuclear fuel market.
In addition to discussing these six key changes, this Overview section also addresses the issues raised in the Scoping Memo related to the BPP. After the Overview section, the remainder of this cover pleading provides a detailed description of each section or appendix in the 2014 BPP, and describes changes or updates to the 2010 BPP that are reflected in PG&E’s proposed 2014 BPP.
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A. Structure and Organization of the BPP
PG&E’s 2014 BPP substantially restructures the 2010 BPP to make it more streamlined, easy to use, and transparent. The structure and organization of the 2010 BPP dates back to 2006 and the Commission’s 2006 Long-Term Procurement Plan (“LTPP”) proceeding. The 2010 BPP structure reflects an outline developed in the 2006 LTPP proceeding, which, eight years later, needs to be updated and refreshed. The 2010 BPP includes sections and discussions on certain topics that are redundant or, in other cases, spread over multiple sections of the 2010 BPP. For example, rules concerning the Procurement Review Group (“PRG”) and Independent Evaluators
(“IE”) are discussed in the body of the 2010 BPP and a separate appendix; these sections are redundant and have substantial overlap. Other topics appear in multiple places throughout the
2010 BPP. For example, there are numerous references in the body and appendices of the 2010
BPP describing how to update various portions of the 2010 BPP through an advice letter process.
The 2014 BPP has been restructured and reorganized to reduce redundancies, make it easy to locate materials, and to be more transparent. With regard to reducing redundancies,
PG&E has reorganized the 2014 BPP to consolidate rules and discussions concerning specific topics in a single part of the BPP. For example, all of the rules regarding the PRG and IEs are now included in Appendix M. All of the sections in the 2010 BPP concerning updates through the advice letter process have been consolidated into a single discussion in Section VI of the
2014 BPP. The restructuring and consolidation of topics makes the 2014 BPP much easier to use; the Commission and parties will be able to go to a single section or appendix in the 2014
BPP to find information regarding a specific topic or issues, rather than having to look through the entire document for information.
In addition to eliminating redundancies, PG&E also restructured the 2014 BPP to make materials and information easier to find. For example, the approved products and procurement
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processes were embedded in a lengthy narrative discussion in the 2010 BPP. This information has now been put into two separate appendices – one for products (Appendix A) and the other for procurement processes (Appendix B) – so that they are easy to locate. PG&E has increased the number of appendices, and each appendix addresses a specific procurement-related issue or topic and so that it is easy for parties using the BPP to locate materials or information.
Finally, PG&E has restructured the BPP to increase its transparency. In the 2010 BPP, certain procurement-related topics were discussed without ready references to Commission decisions or rules. For example, PG&E’s 2010 BPP included a narrative of the procurement- related filings that PG&E was required to make, but did not identify the Commission decisions or rules requiring these filings. A table has been added to Section IV of the 2014 BPP that lists
PG&E’s procurement-related filing requirements and the corresponding Commission decisions or rules. Similarly, Appendix M includes a table of all of the PRG, Cost Allocation Mechanism
(“CAM”) Group, and IE requirements and corresponding Commission decisions. Appendix M replaces the narrative discussion in Appendix I of the 2010 BPP that did not include specific references to Commission decisions. The 2014 BPP will allow parties to review the procurement-related rules and requirements listed in the BPP, and to compare these rules and requirements to specific Commission decisions.
B. PG&E’s Alternative Scenario In the 2010 BPP, PG&E included 10-year energy and capacity forecasts based on
Commission-mandated assumptions and inputs. The 2014 BPP includes a similar forecast, referred to as the “CPUC Mandated Scenario,” that provides 10-year energy and capacity forecasts based on assumptions and inputs mandated by the Commission for the 2014 LTPP proceeding.
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However, there have been significant developments that have occurred since 2010 that are not completely reflected in the CPUC Mandated Scenario. To address these developments,
PG&E is also providing the PG&E Alternative Scenario in the 2014 BPP. The PG&E
Alternative Scenario differs from the CPUC Mandated Scenario in three key areas of the demand-side of the forecast: Community Choice Aggregation (“CCA”), Direct Access (“DA”), and DG. These differences are described below. There are no other substantive differences between the PG&E Alternative Scenario and the CPUC Mandated Scenario.
First, the PG&E Alternative Scenario reflects a higher amount of departing load for CCA.
In recent years, the number of customers served by CCA has increased and there are now two active CCA providers in PG&E’s service territory – Marin Clean Energy and Sonoma Clean
Power. PG&E believes that there is substantial uncertainty regarding the amount of load that will depart for these and other possible CCAs and that the CPUC Mandated Scenario underestimates the amount of CCA departing load. Thus the PG&E Alternative Scenario has an increased forecast of CCA load departures. This is consistent with the Commission’s recent direction in Decision 14-02-040 that PG&E estimate reasonable levels of expected CCA departing load.1
Second, the PG&E Alternative Scenario includes an updated forecast for DA load.
Direct Access is currently capped by California statute and cannot be expanded without additional legislation. Thus, PG&E is not forecasting substantial increases in DA. However,
PG&E has adjusted the DA load forecast in the PG&E Alternative Scenario as the DA load forecast in the CPUC Mandated Scenario is not based on the most recent DA load information.
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1 D.14-02-040 at pp. 16-17 and Ordering Paragraph (“OP”) 1.
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Third, the PG&E Alternative Scenario reflects increasing load departure attributable to
DG. As with CCA, there is substantial uncertainty regarding the levels of DG that will ultimately materialize. However, levels of DG, especially solar DG, are growing significantly in
PG&E’s service area and PG&E is currently forecasting substantial load reductions associated with the rapid expansion of DG. The PG&E Alternative Scenario reflects PG&E’s current forecast of anticipated DG growth over the next ten years.
PG&E believes that its alternative scenario provides a more accurate forecast of PG&E’s bundled procurement needs over the next ten years and thus is proposing that the Commission adopt the PG&E Alternative Scenario rather than the CPUC Mandated Scenario. In addition to the accuracy of the forecast, the PG&E Alternative Scenario raises a number of critical procurement and policy issues.
With regard to procurement issues, if the Commission adopts the PG&E Alternative
Scenario, PG&E’s forecasted bundled load will be substantially lower than the CPUC Mandated
Scenario. A substantially lower forecast for bundled load has a direct impact on PG&E’s procurement targets and limits. The consequential effect is that, to meet the needs of its bundled customers, PG&E would aim to procure less. In addition, a reduction in bundled load impacts the volume (annual gigawatt-hours (GWh)) of PG&E’s Renewable Portfolio Standard (“RPS”) requirements. Because a Load-Serving Entity’s (“LSE”) RPS requirements are based on a percentage of that LSE’s load, a reduction in PG&E’s forecasted bundled load reduces the volume of RPS-eligible energy that PG&E would aim to procure to meet its RPS requirements.
However, PG&E still expects to be fully compliant with California’s RPS requirements.
The PG&E Alternative Scenario also raises a number of key policy issues. These policy issues include: (1) which entities are responsible for long-term planning; (2) each LSE’s procurement obligations to meet reliability need; (3) each LSE’s procurement obligations to meet
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statutory and regulatory mandates; (4) cost allocation among LSEs; and (5) obligations to be the provider of last resort.
With respect to long-term planning, past and current practice is for the IOUs to be responsible for developing long-term resource and procurement plans to ensure reliable service and adequate supply in their respective service areas. Going forward, as PG&E’s bundled load decreases and the load of other LSEs in PG&E’s service territory substantially increases, the
Commission and policy makers will need to carefully consider how to ensure that other LSEs in
PG&E’s service territory are making adequate long-term plans and entering into long-term procurement obligations to ensure sufficient supply and reliability. Long-term planning can no longer be solely the responsibility of the IOUs, especially as the load served by other LSEs increases.
Concerning cost allocation, past and current practice has assigned to the IOUs procurement obligations to meet long-term system reliability, local reliability, and some policy mandates on behalf of all customers in the IOUs’ respective service territories. If the
Commission requires an LSE to procure resources to meet a need beyond the load it is contracted to supply—whether that need is for system reliability, local reliability, or some policy goal— there must be equitable cost allocation to all LSEs. For PG&E, this means that the costs associated with any obligation PG&E would have to procure for non-bundled customers must be equitably allocated to the LSEs serving these non-bundled customers.
In addition, the Commission and policy makers may need to re-examine what are the obligations to be a provider of last resort for California electric customers. The Commission and
California policy makers should consider how to ensure that all LSEs are prepared to reliably service their load on a long-term basis, and that there is appropriate compensation and cost recovery for entities that act as a provider of last resort. As the number of LSEs increase and the
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load served by non-IOU LSEs increases, re-examining issues concerning responsibilities and costs of being a provider of last resort is critical.
The Commission and policy makers also need to consider how responsibility for statutory and regulatory mandates will be applied going forward. Currently, many of the statutory and regulatory procurement-related mandates have been adopted for the IOUs only (or primarily), including programs such as the Renewable Auction Mechanism (“RAM”) and Feed-In Tariffs
(“FIT”) for small renewable and combined heat and power (“CHP”) projects. Many of these programs and mandates were adopted for the IOUs based on each IOU providing bundled electricity supply and electricity delivery to all but a small fraction of the total load in the IOU’s service territory. As LSEs other than the IOUs supply a greater percentage of the load under the
Commission’s jurisdiction, these types of programs and mandates will need to apply to all LSEs, not just the IOUs.
The Commission and policy makers should carefully consider how policies intended to facilitate CCA, DA, and DG growth impact the procurement responsibilities and requirements in
California. While the policy issues described above will not necessarily be addressed in Phase 2 of the 2014 LTPP proceeding, the PG&E Alternative Scenario vividly demonstrates the need to consider these issues expeditiously.
Finally, two additional issues related to PG&E’s Alternative Scenario merit discussion. First, PG&E’s Alternative Scenario is intended to be a long-term planning forecast and is not intended to be used as a shorter-term forecast for ratemaking or customer services in other proceedings or other similar uses. PG&E’s Alternative Scenario is intended to consider potential trends over the next decade, not more immediate ratemaking or customer service or program issues in other proceedings that will be based on shorter-term forecasts. Second,
PG&E’s Alternative Scenario is a forecast and it includes a number of assumptions regarding
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events which may or may not occur. For example, PG&E is assuming that certain entities which have announced plans to form a CCA actually go ahead and form the CCA and serve customers. In some cases, events such as new CCAs forming or DG growth may not occur, or may occur at a less rapid pace than forecasted in PG&E’s Alternative Scenario. If the
Commission adopts PG&E’s Alternative Case, PG&E intends to update its forecasts when it files advice letters to update the 2014 BPP procurement limits; these updated bundled load forecasts reflect updated circumstances, including events that actually occurred or did not occur.
C. Procurement Limits In D.12-01-033, the Commission expressed strong support for the use of procurement limits in the IOUs’ respective bundled procurement plans. As the Commission explained:
As a general matter, this approach is reasonable – the Commission sets an upper boundary, and the utilities can procure up to that level without coming back to the Commission. This makes it easier for the Commission to find that the resulting rates are just and reasonable, as there is effectively a cap on procurement amounts and associated costs.2
In response to this direction, PG&E included electric capacity limits in its 2010 BPP. The
Commission subsequently approved GHG procurement limits when it approved PG&E’s proposed GHG Procurement Plan in D.12-04-046. Consistent with the Commission’s direction,
PG&E has expanded the procurement limits in the 2014 BPP to include electric capacity, electric energy, GHG, and natural gas procurement limits. These limits are included in Appendix C of the 2014 BPP and will be based on the forecast approved by the Commission, as described above
(i.e., either the CPUC Mandated Scenario or the PG&E Alternative Scenario). The proposed
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2 D.12-01-033 at p. 7.
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limits establish PG&E’s procurement authority and ensure that procurement rates for PG&E’s bundled customers are just and reasonable.3
D. Appendices Addressing Scheduling, Bidding, And CAISO Operating Orders Since the IOUs resumed procurement responsibilities in 2003, the Commission has directed that the IOUs dispatch their resource portfolios in a least-cost manner. However, the
IOUs’ dispatch responsibilities changed significantly when the CAISO implemented its Market
Redesign and Technology Upgrade in April 2009.4 As the Commission recently explained,
“[t]he regulated utility is responsible for scheduling and bidding its generation to the CAISO, but once that is done, it is the CAISO’s responsibility to dispatch the generation.”5
The 2010 BPP provided an overview as to how PG&E dispatched its owned and contracted resources. The 2014 BPP significantly expands this discussion and makes it consistent with recent Commission decisions which explain that PG&E is responsible for scheduling and bidding, and that the CAISO performs the actual dispatch.6 In Appendix K,
PG&E provides a detailed discussion of its scheduling and bidding principles, processes, and protocols for PG&E-owned and contracted resources. Appendix K explains how PG&E develops its bids and schedules for the CAISO, including considerations such as incremental costs and opportunity costs.
Appendix L provides protocols for PG&E’s responses to specific CAISO Operating
Orders associated with maintaining system reliability. Under its tariff, the CAISO can issue operating orders to PG&E and other market participants to address system emergencies,
3 Id., Conclusions of Law (“COL”) 1-4 (procurement limits help ensure that rates are just and reasonable under Public Utilities Code section 454.5). 4 D.11-10-002, Finding of Fact (“FOF”) 1. 5 D.14-05-023, FOF 15. 6 Id.
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congestion, and overgeneration. These operating orders are generally the exception, rather than the norm, but it is likely that with increasing amounts of intermittent, inflexible renewable generation on the CAISO-controlled grid, situations involving system emergencies, congestion, and overgeneration may substantially increase in the future. Appendix L provides a description of how PG&E will respond to CAISO Operating Orders issued to address these operational situations.
E. Hedging Plan Changes
The Commission has approved utility hedging plans as a means of protecting customers from significant price spikes or swings in the market.7 In the 2014 BPP, PG&E has proposed a number of changes to its existing hedging plan to simplify PG&E’s hedging plan and address additional price exposure. The proposed changes will ultimately reduce the complexity of the hedging plan, clarify compliance obligations, and address additional price exposure. The specific changes to PG&E’s hedging plan are described in more detail in Section XII below.
F. Nuclear Fuel Plan Changes PG&E has revised procurement targets in its Nuclear Fuel Plan to reflect the fact that there have been substantial changes in the worldwide nuclear fuel market as a result of the
Fukushima Daiichi incident in Japan and subsequent changes in nuclear generation worldwide as a result of this incident. The proposed revisions to the Nuclear Fuel Procurement Plan will allow
PG&E
The Nuclear Fuel Plan runs through 2024 and ensures an adequate supply of fuel throughout the Diablo Canyon Power Plant (“DCPP”) license period.
7 D.12-01-033 at p. 25.
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G. Scoping Memo Issues
The Scoping Memo identified four issues related to the BPP that are within the scope of this proceeding: (1) procurement limits; (2) approved products; (3) procurement rules; and (4) compliance with state policies including the loading order.8 Each of these issues is addressed in the 2014 BPP. Procurement limits are addressed in Appendix C and approved products are addressed in Appendix A. Procurement rules are addressed in Sections I-VI and specific processes are addressed in Appendix B. In addition, PG&E’s 2014 BPP includes a number of appendices that address specific procurement strategies, such as CRRs (Appendix I), GHG procurement (Appendix G), and convergence bidding (Appendix H). Finally, the 2014 BPP provides PG&E’s integrated plan to comply with state policies, such as the loading order, by describing in detail PG&E’s programs to implement the loading order (Section II) and the application of the loading order in procurement (Appendix B). In addition, the 2014 BPP also addresses other state policies such as once-through cooling (Appendix B), procurement of renewable resources (Section II), and compliance with California’s rigorous GHG requirements
(Appendices B, C, and G).
One issue that was not identified for this phase of the 2014 LTPP proceeding was safety.
Establishing clear Commission rules and guidelines for how safety considerations should be integrated into the procurement process is important to provide clear, consistent direction to the
IOUs as to how they should incorporate safety into their BPPs. Consideration of procurement- related safety issues will require substantial time and resources from the Commission and parties to develop a comprehensive and clear approach to safety. Therefore, PG&E recommends that the Commission establish a third phase of the 2014 LTPP proceeding that is solely focused on
8 Scoping Memo at p. 11.
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how safety should be incorporated into the IOU procurement process, including consideration of how safety is used in the offer evaluation process and the assignment of responsibilities between generators and the IOUs for the safe operation of facilities. The Commission and parties would benefit from a third phase of this proceeding that is dedicated to safety issues.
II. SECTION I – INTRODUCTION Section I of the 2014 BPP provides an introduction and a summary of PG&E’s procurement goals, an overview of PG&E’s planning, procurement and scheduling/bidding activities, and an overview of the remainder of the 2014 BPP. PG&E changed the term
“dispatch” used in the 2010 BPP to “Scheduling/Bidding” to reflect the fact that the CAISO performs the actual dispatch of resources, and PG&E’s role is to schedule and bid into the
CAISO market.9 In addition, PG&E significantly expanded the discussion of its Scheduling and
Bidding practices by adding Appendix K to the 2014 BPP.
III. SECTION II – STATUTORY AND LOADING ORDER REQUIREMENTS
Section II of the 2014 BPP addresses statutory and loading order requirements and provides a summary of how PG&E complies with the requirements of Assembly Bill (“AB”) 57
(i.e., Public Utilities Code § 454.5) and the loading order adopted by the Commission as a part of the EAP. Sections II.B.1 through II.B.4 of the 2014 BPP update the descriptions of PG&E’s EE,
DR, RPS, and DG Programs that were included in the 2010 BPP. These updates reflect changes in Commission policies and Commission decisions that were issued after the 2010 BPP was approved. Section II.B.5 describes other generation resources available to PG&E after preferred resources are considered in procurement. Other generation resources were previously described in Section IV.F of the 2010 BPP. PG&E has shortened the discussion of other generation resources by deleting information that was duplicated in other parts of the BPP or was
9 D.14-05-023, FOF 15.
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unnecessary. PG&E has also added a discussion of energy storage to this section to reflect the
Commission’s recent energy storage decision (i.e., D.13-10-040).
In addition to these updates, PG&E deleted 2010 BPP Section IIA.1 which included a description of each of the departments in PG&E’s Energy Procurement organization. The
Energy Procurement organizational structure is not part of PG&E’s AB 57 procurement authority and thus including the organizational structure in the BPP is not necessary. Therefore, this section was largely deleted, except for Section II.A.1.f concerning compliance with Standard of
Conduct (“SOC”) 2. Compliance with SOC 2 is now addressed in Section III of the 2014 BPP.
IV. SECTION III – COMPLIANCE WITH THE COMMISSION’S PROCUREMENT STANDARDS OF CONDUCT Section III in the 2014 BPP addresses PG&E’s compliance with the Commission’s procurement-related SOCs. Table 3 in Section III of the 2014 BPP has been updated to reflect changed references to the location of applicable materials in the 2014 BPP. In addition, the summary of compliance for SOC 4 has been revised to indicate that the review of contract administration occurs in the annual Energy Resource Recovery Account (“ERRA”) Compliance
Review proceedings.
Section II.A.f.1 in the 2010 BPP, which addressed SOC 2, provided a link to a description of PG&E’s ethics training. This discussion has been shortened to remove the link, as the link may change with time. Instead, Section III of the 2014 BPP simply states that PG&E’s
Energy Procurement employees are required to execute an electronic certification that they are aware of the Code of Conduct, and that these employees are required to complete a training course on an annual basis.
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V. SECTION IV – DESCRIPTION OF PG&E FILINGS MADE TO DEMONSTRATE COMPLIANCE AND COST RECOVERY Section IV of the 2014 BPP describes the regulatory filings made by PG&E to demonstrate compliance with its Commission-approved BPP and the cost recovery that is authorized for generation resources procured in compliance with the BPP’s upfront standards.
Section IV is a significant improvement to the 2010 BPP, which contained a lengthy narrative describing monthly, quarterly and annual procurement-related filings. Section IV.A of the 2014 BPP consolidates the lengthy 2010 BPP narrative into a single table which describes
PG&E’s procurement-related filings and provides a citation to the Commission decision(s) or statutory authority which requires the filing. This table provides an efficient and transparent means of summarizing PG&E’s procurement-related filing and reporting requirements. PG&E added items to the table which had not been included in the 2010 BPP, such as the RPS Request for Offers Shortlist and Project Development Reports, the Annual RPS Plan, RAM and
Photovoltaic (“PV”) Program Reports, the Convergence Bidding Quarterly Report, and the
Energy Storage Plan biennial filing. In addition, PG&E updated certain descriptions. For example, PG&E updated the description of the Resource Adequacy (“RA”) Annual Report to include System, Local, and Flexible RA.
One item was deleted from the 2010 BPP discussion of filing requirements. The
2010 BPP included the LTPP proceeding as a PG&E filing. However, this is not a filing made by PG&E, but is instead a Rulemaking initiated by the Commission. Thus, PG&E deleted it from the 2014 BPP discussion of PG&E filing requirements.
VI. SECTION V – PRE-APPROVAL, APPROVAL, AND FILING REQUIREMENTS Section V of the 2014 BPP describes the pre-approval, approval, and filing requirements associated with PG&E’s procurement authority under the BPP.
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PG&E has updated this section of the BPP to reflect the pre-approval requirements established by the Commission when an IOU’s BPP includes procurement limits.10 The 2010
BPP provided that PG&E could execute contracts that are less than five years in duration without
Commission pre-approval, and that duration was determined either at the time the contracted resource begins delivery if delivery begins within one year of execution or at the time of contract execution if delivery occurs more than one year from execution. In D.07-12-052, the
Commission determined that the pre-approval requirements are different for IOUs with procurement limits. Because the 2014 BPP includes procurement limits for electric energy and capacity, natural gas, and GHG compliance instruments, PG&E has changed the pre-approval language in the 2014 BPP to be consistent with the Commission’s direction in D.07-12-052.
Section V of the 2014 BPP includes Table 5 which identifies different types of transactions and the corresponding filing requirement. This table is similar to the table in the
2010 BPP, but includes some updates and corrections to the appropriate venue for approval of certain transactions. Specifically, consistent with Commission decisions, non-RPS transactions with a contract duration of less than five years and Congestion Revenue Rights (“CRR”) transactions are approved through the Quarterly Compliance Report (“QCR”), not through the annual ERRA Compliance application as indicated in the 2010 BPP.11 Therefore, Table 5 in
Section V of the 2014 BPP has been changed to indicate that these transactions are approved through the QCR, rather than the annual ERRA Compliance application.
In addition, PG&E clarified in Items #2 and #3 of Table 5 that form contracts that are pre-approved by the Commission do not require approval, such as the form contracts approved
10 D.07-12-052 at p. 172 and OP 19. 11 D.07-12-052 at p. 185 (describing QCR); D.04-12-048 at pp. 107-108 (approval of contracts less than five years through compliance filing and five years or greater through an application); Resolutions E- 4135, OP 4 and E-4122, OP 4 (CRRs and Long-Term CRRs (“LT-CRRs”) are included in QCR).
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for the Feed-in Tariff Program and the RAM Program. PG&E also added Item #5 regarding the approval process for contracts arising from the Qualifying Facility and Combined Heat and
Power (“QF/CHP”) Settlement and Item #6 to indicate the approval process for amendments to existing QF contracts.
VII. SECTION VI – UPDATES TO THE BUNDLED PROCUREMENT PLAN VIA ADVICE LETTER Section VI of the 2014 BPP describes the process for updating PG&E’s BPP between
LTPP proceeding cycles. This section consolidates sections that were scattered throughout the
2010 BPP. Section VI also includes specific requirements for updates to PG&E’s Electric
Portfolio Hedging Plan, and provides that updates to PG&E’s electric energy, electric capacity, and natural gas limits are filed annually (or more frequently if necessary) in a Tier 1 advice letter and PG&E’s GHG compliance forecasts and purchase limits are filed as necessary in a Tier 2 advice letter.
In addition to consolidating sections from the 2010 BPP, PG&E deleted a paragraph from
Appendix L, Section D.9 of the 2010 BPP that allowed PG&E to file an advice letter to update the GHG Procurement plan to reflect changes in market conditions, PG&E’s electric portfolio, or
CARB regulations. This sentence was redundant and simply repeated the general authorization for PG&E to file advice letters to update its BPP during LTPP proceeding cycles.
VIII. APPENDIX A – PROCUREMENT PRODUCTS
Appendix A of the 2014 BPP addresses PG&E’s approved products. Most of the products identified in Appendix A have already been approved by the Commission. However,
PG&E is proposing some modifications and additions.
For electric products in Table A-1 of the 2014 BPP, PG&E has made minor updates and corrections in product descriptions. Changes were made to the descriptions of Item #7 (Financial
Call Option or Swaption), Item #8 (Financial Swap), Item #13 (Electricity Futures), Item #16 18
(Physical Call Options) and Item #24 (Non-Firm Transmission Rights Locational Swaps and
Futures). In addition, Item #10 (Reliability Demand Response Resource) was renamed and Item
#30 (Convergence Bids) was updated to reflect the fifteen minute market. These changes reflect more accurate product descriptions in accordance with recent industry developments and implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act. In addition, a new electric product was added to Table A-1 for Structured Transactions (Item #33).
While this is a new product for PG&E’s BPP, it was approved in D.07-12-052 for Southern
California Edison Company’s (“SCE”) 2006 BPP, and in SCE’s subsequent 2010 BPP.
Table A-2 lists PG&E’s GHG products. These products were previously included in the electric products table and the GHG Procurement Plan, but have now been moved to a separate table within Appendix A.
For fuel products, PG&E has consolidated several products and made minor updates and corrections in product descriptions in Tables A-3 and A-4 of the 2014 BPP. First, Items #1 and #2 from Table II-2 of the 2010 BPP were consolidated into a single product which is now
Item #1 in Table A-3 in the 2014 BPP. Purchases and sales of natural gas continue to be approved products within the 2014 BPP; the distinction “spot” natural gas that was used in
Item #2 in the 2010 BPP is not necessary and is redundant. The description in Item #1 was also clarified.
Second, PG&E added distillate as a fuel product in Table A-3 of the 2014 BPP. PG&E’s
Humboldt Bay Generating Station primarily uses natural gas as a fuel source, but does use some distillate fuel for certain situations. Thus, PG&E added distillate fuel to the list of approved products. The recovery of distillate fuel costs for the Humboldt facility was approved in
D.06-11-048, OP 17.
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The last two changes to fuel products were to the descriptions of Item #1 and Item #2 in
Table A-4 of the 2014 BPP. Similar to the changes made to Items #7, #8, #13, #24 in Table A-1 in the 2014 BPP for electric products, the descriptions of these two fuel products were updated to reflect recent industry developments due to the implementation of the Dodd-Frank Act.
For credit products in Table A-5, PG&E clarified that Credit Intermediation Arrangement
(Item #3) may not be limited to just financial institutions as previously stated in 2010 BPP.
IX. APPENDIX B – PROCUREMENT PROCESSES AND METHODS
Appendix B of the 2014 BPP addresses PG&E’s approved procurement processes and methods. Section B of this Appendix has been restructured to separate market processes
(Section B.1), such as electronic solicitations and voice brokers, and Commission-mandated procurement programs (Section B.2), such as the RAM Program. Separating the procurement processes into market processes and Commission-mandated procurement programs provides greater clarity as to the source and requirements for a specific procurement process.
Section B.3 of the 2014 BPP describes the CARB auctions and allowance price containment reserve for GHG compliance instruments. This discussion was in Appendix L of the 2010 BPP (i.e., PG&E’s 2010 GHG Procurement Plan), but has been moved to Appendix B to consolidate the discussion of procurement processes and has been updated to reflect CARB’s implementation of the auction process.
Table B-1 includes the addition of a “Cashout” process (Item #15). Although cashout transactions are generally characterized as direct bilateral purchases or sales of natural gas,
PG&E added this item as a separate procurement process because the cashout process has important differences from most purchases or sales. Most importantly, a cashout is applied in accordance with a pipeline’s tariff, and the volumes and prices may not be known until after the fact, when the pipeline invoices PG&E. Although pipeline customers, including PG&E,
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typically try to avoid cashouts, they may be unavoidable in some circumstances due to the variable nature of gas demand for electric generation, among other factors. For example, if the
CAISO dispatches a unit late in the evening unexpectedly, PG&E has no opportunity to adjust gas supplies because gas nomination deadlines have passed. Under certain balancing or flow order conditions, this may result in a cashout. Cashouts include such mechanisms that may use a variety of names, including standby procurement charge and buy-back rate, depending on the pipeline.
PG&E also added Item #16 in Table B-1, which addresses the process for bilateral transactions for natural gas storage and pipeline capacity. This process was approved by the
Commission in D.03-12-062, COL 15, but had not been added to PG&E’s 2010 BPP.
Finally, PG&E is seeking clarification of Item #10 in Table B-1. Specifically, PG&E seeks clarification that the limitation stating that electronic solicitations are approved only for
“non-utility-owned resources” is not intended to bar transactions with PG&E California Gas
Transmission for natural gas storage products. The limitation on utility-owned resources (in
D.12-01-033, for example), clearly referred to “bids related to the development of utility-owned generation.”12 PG&E seeks clarification here to avoid a reading of this Item which might prevent the use of storage services provided by PG&E California Gas Transmission, for example. Bilateral transactions for storage products are allowed (Table B-1, Item #16), so a prohibition on electronic solicitations would be incongruous. Moreover, a transaction as simple and important to daily operations as a park or loan on a weekend, may be negotiated via electronic solicitation. PG&E seeks clarification that this process, which can be critical to managing daily gas balances, remains available to PG&E Electric Fuels.
12 D.12-01-033, p. 42 (emphasis added).
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Appendix B, Section D addresses Commission-adopted requirements for specific procurement processes. This section is a consolidation of several separate discussions in different portions of the 2010 BPP,13 and also includes several new requirements that have been adopted in recent Commission decisions, such as requirements related to upgraded and repowered plants participating in LTRFOs (Section D.3) and the determination of the term of a contract (Section D.6).
X. APPENDIX C – PROCUREMENT LIMITS AND RATABLE RATES
Appendix C of the 2014 BPP addresses PG&E’s procurement limits and ratable rates.
The Commission endorsed the use of procurement limits and ratable rates in D.12-01-033 and in
D.14-02-040. PG&E’s 2014 BPP includes electric capacity limits, and new limits for electric energy, natural gas, and GHG compliance instrument procurement. The limits are addressed in detail below.
A. Electric Capacity and Energy Limits
PG&E’s 2014 BPP includes three key changes related to electric procurement limits and ratable rates. First, PG&E made one modification to the methodology for electric capacity procurement limits in comparison to the 2010 BPP. For the purpose of calculation and compliance with electric capacity procurement limits, “planned preferred resources” was changed to also include procurement to comply with the Commission’s Energy Storage Program targets (see Footnote 4 in Section A.1 of Appendix C). This change was made because procurement for the Energy Storage Program is already factored into the calculation of the
13 Specifically, rules related to procurement of Once-Through Cooling resources that were located within Section II.A.7. of the 2010 BPP were moved to this Section D. Rules related to procurement of Utility- Owned Generation were moved into Section D from Section II.A.4.f. of the 2010 BPP. Rules related to procurement through Long-Term Request for Offers (“LTRFO”) were moved from Appendix I, Section C of the 2010 BPP. A discussion of the loading order applicability to procurement was moved into this appendix from Section II.A.8.c of the 2010 BPP. A discussion of the evaluation and selection of resources through an RFO was moved from Section II.A.8 of the 2010 BPP.
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electrical capacity procurement limits. Therefore, any procurement towards the Energy Storage
Program targets will not count against the electrical capacity procurement limits.
Second, PG&E has added new procurement limits and ratable rates for electric energy.
The calculation and compliance of PG&E’s electrical energy procurement limits and ratable rates follow the methodology employed by SCE for energy procurement limits and ratable rates included in SCE’s Commission-approved 2006 and 2010 BPPs, except for three modifications.
The first modification is that PG&E’s 2014 BPP includes just one overall net procurement limit for electric energy, rather than four separate limits (i.e., for on-peak purchases, on-peak sales, off-peak purchases and off-peak sales). One overall procurement limit for electric energy achieves the Commission’s objective of establishing procurement limits to assure just and reasonable rates14, but with the added benefit of being much simpler to manage.15 Another modification to SCE’s electrical energy procurement limit methodology is a clarification with respect to what transactions count against the electric energy procurement limits and ratable rates. This clarification concerns paired transactions, locational basis contracts, and CRRs and was made to accurately capture transactions and avoid double-counting certain transactions against the procurement limits. The last modification to SCE’s electric energy procurement limit methodology is a clarification indicating that the absolute notional volumes for all transactions will be used when counting against the procurement limits. This change was made in order to appropriately adapt the counting rules to the consolidated overall net procurement limit for electrical energy approach explained above.
14 D.12-01-033, COL 1-2. 15 The calculation of this procurement limit is detailed in Appendix C, Section A.2.
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Finally, in Appendix C PG&E included calculated electric capacity and energy procurement limits for both the PG&E Alternative Scenario and the CPUC Mandated Scenario.
The calculations of these two scenarios reflect the electric portfolios described in Appendix D.
B. Gas Limits PG&E’s 2014 BPP includes procurement limits and ratable rates for gas products in
Appendix C.16 The procurement limits, ratable rates, and calculation methodologies in PG&E’s
2014 BPP match those employed in SCE’s CPUC-approved 2006 and 2010 BPPs. The natural gas procurement limits in Appendix C replace the targets previously included in the 2010 BPP
Gas Supply Plan (“GSP”). The limit structure identifies limits on gas procurement activities, while reducing complexity relative to the targets and goals of PG&E’s 2010 GSP. PG&E’s natural gas limits include limits for gas supply (i.e., the natural gas commodity), pipeline capacity, and natural gas storage. These were the three elements of PG&E’s Commission- approved 2010 GSP. Similar to the electric procurement limits, PG&E calculated gas procurement limits for both PG&E’s Alternative Scenario and the CPUC Mandated Scenario described in Appendix D.
C. GHG Limits Finally, Appendix C includes updated Direct Compliance Instrument Purchase Limits for
2015 and 2016 based upon PG&E’s current GHG compliance instrument forecast. These GHG limits are the same for both the PG&E Alternative and CPUC Mandated Scenarios, since the same GHG-emitting resources existing within the electric portfolios of both scenarios.
Since the filing of the 2010 BPP, the uncertainty regarding the GHG Cap-and-Trade
Program has declined and the market for GHG products has developed substantially. Thus,
16 The Electric Portfolio Hedging Plan in Appendix E establishes further limits and strategies for the execution of financial gas transactions (hedges).
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PG&E has also included Financial Exposure Purchase Limits for 2015 and 2016 in its 2014 BPP.
Financial Exposure (calculated in accordance with the Commission’s approved methodology in
D.12-04-046) estimates PG&E’s indirect exposure to GHG costs embedded in the price of energy. PG&E will only use approved GHG Products provided in Appendix A to hedge GHG price risk that would be subject to these limits. Since the amount of energy to be purchased within the market varies between the PG&E Alternative and CPUC Mandated Scenarios, the
Financial Exposure Limits of the two scenarios are different. Therefore, calculations for both scenarios are provided.
XI. APPENDIX D – DESCRIPTION AND EVALUATION OF CPUC MANDATED AND PG&E ALTERNATIVE SCENARIOS Appendix D of the 2014 BPP provides a description and evaluation of two separate scenarios for bundled procurement needs between 2015 and 2024. The first scenario is the
CPUC Mandated Scenario, which includes load and resource assumptions mandated by the
Commission in the Scoping Memo. The second scenario, the PG&E Alternative Scenario, is based on the CPUC Mandated Scenario, but includes three demand-side modifications which impact the bundled load forecast. Both scenarios are described in more detail below.
A. CPUC Mandated Scenario Appendix D includes a description and evaluation of the CPUC Mandated Scenario, similar to the description and evaluation of the Commission-mandated case in the 2010 BPP.
The 2014 BPP incorporates the load and resource assumptions mandated by the Scoping Memo.
Tables D-1 and D-2 provide the energy and capacity balances under the CPUC Mandated
Scenario for the period 2015 to 2024.
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B. PG&E Alternative Scenario
The PG&E Alternative Scenario differs from the CPUC Mandated Scenario in three key areas. The three key areas all are on the demand-side of the forecast: CCA, DA, and DG. These differences are described below.
1. CCA Load Assumptions PG&E developed its estimate of CCA load loss for the PG&E Alternative Scenario based on an evaluation of current activity levels for existing CCAs, as well as activity levels for entities that have engaged in an extensive analysis of CCA. PG&E recognizes that there is substantial uncertainty about the amount of CCA that will materialize and, as discussed in Section I.B above, these forecasts may need to be adjusted as events do or do not occur. Notwithstanding this uncertainty, PG&E believes that its estimate of CCA load loss is more reasonable than the
CPUC Mandated Scenario estimate, given that the CPUC Mandated Scenario shows a level of load loss in 2024 for the combined categories of CCA and DA that is less than the current level of CCA and DA load. Specifically, the CPUC Mandated Scenario shows CCA and DA load combined in 2024 as 8,600 GWh per year, while existing DA load is about 9,600 GWh per year.
The CCA load loss in the CPUC Mandated Scenario is not realistic in light of the load served by existing CCAs, much less the expected activity of those communities engaged in evaluating
CCA. PG&E developed its CCA load forecast by estimating departing load based on the current load served by existing CCAs, combined with load that may be served by these entities, along with load that may be served by entities that are actively engaged in exploring CCA. PG&E’s estimates are described in more detail in Appendix D.
2. Direct Access Load Assumptions PG&E has taken the current amount of load served under DA (approximately 9,600 GWh per year) and has kept it flat throughout the forecast period. While PG&E implicitly agrees with
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the CPUC Mandated Scenario that DA load will be limited to current legislative limits, PG&E believes that maintaining DA load at current levels (as opposed to reducing these loads over time, as is done in the CPUC Mandated Scenario) is a more realistic estimate of DA load.
3. Distributed Generation Load Assumptions PG&E forecasted PV adoptions by examining historical PV adoption rates, and adjusting growth projections based on anticipated policy developments. PG&E forecasted adoption of non-PV DG by the following technology categories: CHP, Fuel Cells, and Other. For traditional
CHP and “Other” technologies, PG&E’s forecast was developed using an historic 10-year average adoption rate. For fuel cell adoption, an exponential trend function, showing increasing rates of capacity addition, has been used.
By 2024, PG&E estimates that there will be approximately 12,100 GWh of generation from retail DG facilities, which equates to 13,300 GWh of avoided procurement at the point of generation (Table D-5, sum of lines 4 and 5). This compares to approximately 5,900 GWh of avoided procurement estimated in the CPUC Mandated Scenario (Table D-2, sum of lines 4 and
5). PG&E recognizes that there is substantial uncertainty as to the level of DG penetration that will occur. However, PG&E believes that its current forecast is more reasonable than the CPUC
Mandated Scenario.
The CPUC Mandated Scenario for DG relied on the mid-case scenario from the 2014
California Energy Demand forecast developed by the California Energy Commission (“CEC”).
A significant portion of the difference between CEC and PG&E forecasts is likely explained by different modeling approaches used by the CEC and by Bloomberg New Energy Finance
(“BNEF”), whose forecast informed PG&E’s projection. The CEC uses a modeling approach that is based on the United States Energy Information Administration’s National Energy
Modeling System model and the National Renewable Energy Laboratory’s SolarDS model. The
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CEC model predicts adoption based on consumer response to cost effectiveness as measured by a payback calculation.17 This approach was developed when most PV systems were owned by host customers, and is likely to under predict how cost effective PV is for consumers now that third-party owned (“TPO”) solar financing models are widely available. Under a third party ownership financing structure, cost effectiveness is more appropriately measured by comparing retail rates with prices that a third party solar provider can offer, given solar costs and profit margins.
BNEF uses an adoption model that measures cost effectiveness by comparing levelized bill savings against the levelized cost of solar. PG&E believes the approach used by Bloomberg better captures consumer decision-making under the current residential retail PV market environment in which third party financing models predominate. With TPO financing, the customer will have an economic incentive to install solar if bill savings are greater than the financing payment. Payback may not be the most applicable metric in this context.
Another difference between the PG&E Alternative and CPUC Mandated Scenario forecasts is that PG&E estimated an increase in installed MW associated with Zero Net Energy
(“ZNE”) policy, whereas the CEC did not. PG&E estimates that, starting in 2020, approximately
70 MW per year will be added as a result of California’s ZNE policy goals.
4. Overlap Issues
To address any overlap that may exist between its load forecasts, PG&E subtracted from the CCA load departures described above the DA load percentage across the service area, and the estimated amount of DG growth within these communities. This estimated DG growth was
17 California Energy Demand 2014-2024 Final Forecast Volume 1 Appendix B (January 2014), p. B-6.
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derived by applying the DG growth rates to the current proportion of DG penetration that is located within the various communities that have implemented or are actively exploring CCA.
XII. APPENDIX E – ELECTRIC PORTFOLIO HEDGING PLAN Appendix E includes PG&E’s Hedging Plan. PG&E has proposed a number of substantive changes to its Hedging Plan that will reduce complexity, clarify compliance obligations, and address additional price exposure. Changes to PG&E’s Hedging Plan are described in detail below.
A. Tenor In context of the Hedging Plan, tenor means the length of the delivery period to be hedged.
B. Hedging Targets and Limits
The hedging targets and limits in the 2014 BPP Hedging Plan are renamed and redefined from those in the 2010 BPP. The specific changes include the following:
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C.
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D. Execution Strategy
E.
F. Transition Plan The Transition Plan in the 2010 BPP was intended to guide the transition from the 2006
BPP Hedging Plan to the 2010 BPP Hedging Plan. The Transition Plan is updated to guide the
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transition from the 2010 BPP to this plan.
G. Unusual Events, market Dislocations and Emergencies
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H. Liquidity Management Strategy
I. Deletions from the 2010 BPP
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XIII. APPENDIX F – NUCLEAR FUEL PROCUREMENT PLAN Appendix F includes PG&E’s procurement plan for nuclear fuel used for DCPP. PG&E generally updated the tables and information in the plan to reflect the coverage of the plan from
2015 to 2024. In addition to these updates, PG&E made three substantive changes to the plan, which are described in detail below.
A. Forward Contracting and Price Terms
B. Nuclear Fuel Strategic Inventory
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C. Proposed Risk Management Measures
XIV. APPENDIX G – GREENHOUSE GAS PROCUREMENT PLAN
Appendix G of the 2014 BPP addresses PG&E’s GHG Procurement Plan. In the background section of Appendix G, PG&E included updates related to modifications of CARB’s
Cap-and-Trade regulation since the approval of the 2010 BPP. In particular, CARB expanded coverage of the Cap-and-Trade regulation in the second compliance period to cover suppliers of natural gas. Appendix G has been updated to indicate that the authority to procure for new natural gas-related obligations is being addressed in Commission Order Instituting Rulemaking
(“R.”) 14-03-003, and thus Appendix G only addresses those GHG compliance obligations related to PG&E’s electric procurement activities.
In addition, Appendix G was updated to reflect CARB’s approval on May 10, 2013 of the linkage with Quebec. Under this linkage, compliance instruments issued by CARB or Quebec are equally fungible and there is no way to identify what jurisdiction issued a particular
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compliance instrument. As such, PG&E modified the definition of allowances and offset credits to clarify that authorized compliance instruments are “accepted” by CARB rather than “created” or “issued” by CARB.
Finally, the GHG Procurement Plan in the 2010 BPP covered procurement for obligations related to GHG emissions from PG&E’s natural gas compressor stations.21 Subsequent to the approval of the 2010 BPP, authority to procure for GHG emissions related to PG&E’s natural gas compressor stations was approved in D.13-03-017 and thus this procurement obligation no longer needs to be covered in the BPP. As such, references to emissions from PG&E’s natural gas compressor stations have been deleted in the 2014 BPP.
XV. APPENDIX H – CONVERGENCE BIDDING
Appendix H of the 2014 BPP addresses Commission authorizations and requirements for
PG&E’s participation in the CAISO’s convergence bidding market. PG&E has not made any substantive changes to the convergence bidding appendix approved by the Commission in the
2010 BPP. PG&E has updated Appendix H to reflect market design changes implemented by
CAISO on May 1, 2014 (i.e., new ‘15 minute market’) and changes the reporting requirements.
Monthly reporting requirements expired one year after the start of CAISO convergence bidding markets; the quarterly reporting requirements started with the Q1 2012 report.22
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21 See e.g., 2010 BPP, Sheet Nos. 287-288. 22 See D.10-12-034, OP 7.
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XVI. APPENDIX I – CONGESTION REVENUE RIGHTS
Appendix I of the 2014 BPP addresses PG&E’s procurement of CRRs. PG&E made several substantive and non-substantive changes to the 2010 BPP in order to increase clarity and avoid repetition. First, the explanation of the analysis to identify candidate CRRs was updated and simplified. This analysis to determine the congestion cost and value of a CRR may be determined by transmission simulation studies, historical analyses, or a combination of both.
Second, PG&E eliminated the requirement to participate in CAISO auctions and the secondary market, making participation in both CRR-related procurement processes now optional.
Third, redundant language was eliminated. The CRR and LT-CRR sections were consolidated into one section. Duplicative language regarding the factors and measures which
PG&E will rely upon to make CRR selection was provided once (rather than twice as in the 2010
BPP) and is applicable to both the CAISO allocation and auction processes. For example, the
“Excess CRR” section in the 2010 BPP was removed since the authority to sell excess CRRs is covered in other areas of Appendix I: Auctions and Transactions in the Secondary Market.
Finally, PRG review of CRR procurement is now addressed in Appendix M and includes proposed changes to PRG review of CRRs. These changes are discussed in more detail in
Section XX below. Section K in Appendix F of the 2010 BPP, which addressed cost recovery for CRRs, was deleted from Appendix I in the 2014 BPP to avoid a duplicative discussion of cost recovery for authorized products. In the 2014 BPP, cost recovery is addressed in Section V.
XVII. APPENDIX J – BROKERAGES AND EXCHANGES Appendix J of the 2014 BPP addresses approved brokerages and exchanges. The list of approved brokers was updated to include the effective entity names for each broker (as of the filing date for this Pleading), to add one new broker, and to remove entities with which PG&E has ceased transacting. 39
In an effort to allow additional options for executing RPS-eligible transactions, PG&E requests to add the following broker to its existing list of Commission-approved brokerages the
Finerty Group, Inc. Authorizing this addition to PG&E’s list of approved brokerages does not obligate PG&E to use them. Instead, adding this broker will simply provide PG&E an option to do so. The decision to use this or any enabled brokerages in Appendix J will be made on a transaction-by-transaction basis. PG&E has routinely updated its list of brokerages and exchanges in order to add potential new counterparties for transactions that are consistent with
PG&E’s Conformed BPP. Further, should PG&E execute any RPS-eligible transaction through any brokerage on the list of approved brokers, PG&E will request Commission approval in accordance with the filing requirements provided in Section V of the 2014 BPP.
The following brokerage was deleted:
x Prebon was acquired by Tullett, which is already an approved broker list.
The following exchanges and futures commission markets were deleted:
x Green Exchange, LLC (“GreenX”), which was acquired by CME Group in 2012. CME Group also owns NYMEX, which is already listed as an approved exchange.
x Parity Energy, Inc., which ceased doing business on May 31, 2014.
There were three changes to Appendix J specific to GHG transactions. First, PG&E has clarified in footnote 1 that it only has authority to procure GHG products from brokerages though an RFO. Second, PG&E has noted in footnote 2 the requirements for requesting approval of new exchanges for GHG products as set forth by the Commission in D.12-04-046. Finally, to facilitate adherence to those requirements, PG&E has separately specified those exchanges that are authorized to transact GHG products.
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XVIII. APPENDIX K – BIDDING AND SCHEDULING PROTOCOLS
Appendix K of the 2014 BPP describes scheduling and bidding practices for the resources in PG&E’s bundled portfolio. PG&E changed the term “dispatch” used in the
2010 BPP to “Scheduling/Bidding” to reflect the fact that the CAISO performs the actual dispatch of resources, and PG&E’s role is to schedule and bid into the CAISO market.23 PG&E significantly expanded the discussion of its Scheduling and Bidding practices in this Appendix.
Appendix K provides an overview of the CAISO markets, describes the scheduling and bidding principles that PG&E utilizes to achieve least-cost dispatch (“LCD”), and describes the specific scheduling and bidding processes used by PG&E.
Section B of Appendix K provides an overview of the CAISO markets, including the day-ahead and real-time markets administered by the CAISO. These markets are fundamental to
PG&E’s scheduling and bidding practices, and the dispatch of PG&E’s owned and contracted resources.
Section C describes the principles that PG&E uses for bidding and scheduling. These principles, while similar to the principles described in the 2010 BPP with regard to dispatch, have been expanded to include greater detail regarding PG&E’s scheduling and bidding process.
Finally, Section D describes PG&E’s scheduling and bidding process, including how
PG&E develops the incremental costs for its bids into the CAISO markets, how GHG costs are factored into PG&E’s scheduling and bidding, and the use of opportunity costs for certain resources such as hydroelectric resources and dispatchable renewable resources. This section also describes self-scheduling, which PG&E is required to use as a result of constraints on
23 D.14-05-023, FOF 15 (“The energy regulated utility is responsible for scheduling and bidding its generation into the CAISO, but once that is done, it is the CAISO’s responsibility to dispatch the generation.”).
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certain resource types, such as run of river hydro, and for certain types of contracts that cannot be dispatched, such as pre-2010 QF contracts.
The demonstration of compliance with the Commission’s LCD requirements for a specific record year is addressed in PG&E’s ERRA Compliance application.
XIX. APPENDIX L – CAISO OPERATING ORDER PROTOCOLS Appendix L of the 2014 BPP describes PG&E’s actions when responding to CAISO system reliability needs, such as system emergencies, congestion, or overgeneration, and provides protocols for PG&E’s responses to specific CAISO Operating Orders associated with maintaining system reliability. Under its tariff, the CAISO can issue operating orders to PG&E and other scheduling coordinators to address system conditions. These operating orders are currently the exception, rather than the norm, but it is likely that with increasing amounts of intermittent, inflexible renewable generation on the CAISO-controlled grid, situations involving system emergencies, congestion, and overgeneration will increase in the future, and may increase substantially. The intent of providing this section is to provide transparency to the Commission and parties regarding PG&E’s existing protocols and preparedness when responding to CAISO system reliability events and CAISO operating orders.
Section B of Appendix L describes PG&E’s protocols for responding to CAISO declared system emergency events, including specific requirements for difference resource types.
Section C of Appendix L describes PG&E’s protocols for responding to CAISO declared physical congestion events, including a description of the various actions the CAISO can take to manage the event. Section C also describes specific requirements for different resource types, along with a description of the approach PG&E uses to manage situations when the distribution of the generation reduction among units is not specified by the CAISO.
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Finally, Section D of Appendix L describes PG&E’s protocols for responding to CAISO- declared overgeneration events, including a description of the various actions the CAISO can take to manage the event. This section describes how PG&E responds to such conditions during different timeframes and depending on the resource type. Section D also provides a description of the approach PG&E uses to manage situation when the distribution of generation reduction among the units is not specified by the CAISO.
XX. APPENDIX M – PROCUREMENT REVIEW GROUP, COST ALLOCATION MECHANISM GROUP, AND INDEPENDENT EVALUTOR ADMINISTRATION Appendix M of the 2014 BPP addresses the Commission requirements regarding the
PRG, CAM Group, and IE administration requirements. PG&E consolidated three similar sections from the 2010 BPP (Section II.A.9, II.A.10, and Appendix I) into a single appendix in the 2014 BPP.
There is one substantive clarification that has been included in Appendix M. In Table
M-1, Item #1, PG&E is requesting clarification that PRG review of each transaction greater than three months in duration executed according to a strategy previously reviewed by the PRG (but not part of a LTRFO) is not required prior to execution of the transaction. PG&E may review a procurement strategy with the PRG, such as a strategy for an RFO seeking products that are less than five years in duration. These types of RFOs are often based solely on price and winning offers are often executed within a short time after submission. In this situation, going back to the
PRG to review each transaction would take time, and potentially result in lost opportunities. If
PG&E has reviewed a procurement strategy with the PRG, then executes that strategy, it should not be required to bring each transaction back to the PRG for review prior to execution.
There are also several substantive changes that PG&E is proposing with regard to PRG review of CRR transactions. First, with respect to the annual CRR process, PG&E plans to continue to consult with its PRG prior to the start of the annual process. However, PG&E 43
proposes to change the PRG consultation to cover its CRR and LT-CRR position and overall procurement approach and strategy for the upcoming annual allocations and tiers. In Resolution
E-4135, the Commission directed PG&E “to provide the PRG participants, prior to the PRG meeting, a list of proposed annual and long term CRR nominations for allocation and auction…”24 PG&E has found this obligation impractical to implement. Similar to the time constraints applicable to the CAISO’s monthly CRR process, there is limited time to identify and finalize a list of proposed nominations in advance of the PRG meeting. Additionally, the CAISO provides critical information needed to determine nominations only days in advance of the nomination submission dates. For example, limits on the node-pairs that can be nominated in the long-term process are released only five business days before the long-term nominations are due. Therefore, PG&E proposes this requirement be changed to allow PG&E to consult with the
PRG prior to the start of the annual process regarding its CRR and LT-CRR position and approach for the upcoming process, and provide the PRG the full list of awarded CRRs and LT-
CRRs after the conclusion of the annual process.
Second, in an effort to standardize the CRR reporting requirements to the PRG, PG&E is proposing the notification timeframe for all awarded CRRs from annual and monthly processes as well as all transactions in the secondary market be five (5) business days. Five (5) business days matches the timeframe the Commission has allowed SCE for reporting transactions from the monthly process. Changing the reporting deadline to five business days for all CRR awards and transactions simplifies and makes more consistent BPP implementation and compliance.
Third, PG&E proposes to review its CRR position with the PRG at least once per year. This is a clarification of the requirement that “directs PG&E to review its CRR position
24 Resolution E-4135, p. 12
44
with the PRG in its periodic position update discussions…”25 As noted above, PG&E will provide the PRG with numerous reports throughout the year with information regarding CRRs.
In addition to changes regarding CRRs, PG&E also deleted the pro forma consulting services contract for IEs that was attached to the 2010 BPP as Attachment 1 to Appendix I.
Including a pro forma version of the consulting services agreement for IEs is not required by the
Commission.
XXI. APPENDIX N – RISK MANAGEMENT POLICY AND TEVAR METHODOLOGY Appendix N of the 2014 BPP addresses PG&E’s Risk Management Policy and TeVaR methodology. PG&E has updated this portion of the 2014 BPP in a number of areas. In
Section A.3, PG&E has provided further clarification of the definition of investment grade based on the ratings provided by Standard and Poor’s (“S&P”) and Moody’s. PG&E specifically clarified the external rating levels that are reflective of investment level credit rating, which are
BBB- by S&P or Baa3 by Moody’s. PG&E further clarified that it does not grant unsecured credit to counterparties that do not have an investment grade credit rating from the credit agencies or if PG&E’s internal evaluation does not support a credit rating equivalent of investment grade. Counterparties are instead requested to provide an appropriate amount of collateral for the transactions under consideration. In addition, counterparties which qualify for unsecured credit may still need to post additional collateral if the expected exposure is beyond the assigned credit limit.
In this same section, PG&E also clarified utilization of both its internal credit evaluation criteria and the external ratings to determine if a counterparty may qualify for unsecured credit with PG&E. The reason for this clarification is that not all counterparties have an external rating
25 Resolution E-4135, p. 12
45
and therefore internal credit evaluation by default is the only source for credit decision. In addition, credit ratings may not always reflect the latest financial disclosures or recent events. It is therefore important to highlight that credit decisions include both internal and external ratings, when available, for validation of overall assessment of creditworthiness.
PG&E has removed the specific dollar amounts associated with the various security requirements and instead retained the description for security amounts PG&E requires for the various financial and physical products. The reason for the removal of specific amounts is due to changes in security dollar amounts over time because of financial market conditions as well as market liquidity for a specific product.
PG&E has also clarified that it has incorporated collateral requirement for GHG products, both allowances and offset credits, in its bilateral agreements which were not in effect in 2010, but became effective starting in 2013. In addition, PG&E recognizes that for offset credits, there are additional invalidation risks that remain after receiving the offset credits. For this reason,
PG&E requires a different amount of collateral after the delivery to specifically address invalidation risk for offset credits.
In Section A.3, because PG&E utilizes financial products for its hedging program, it must comply with the The Dodd-Frank Wall Street Reform and Consumer Protection Act which was enacted in July 2010. The 2014 BPP was updated to reflect this compliance obligation.
Finally, Table E-1 in the 2010 BPP, containing long-term forecast TeVaR values, has been moved to Appendix D in the 2014 BPP to be presented consistently alongside other forecast values from the same set of simulations.
XXII. APPENDIX O – ACRONYM LIST AND GLOSSARY Appendix O is a list of acronyms and a glossary. PG&E has updated the acronym list and substantially reduced the glossary. The glossary in the 2010 BPP was 43 pages long and
46
included many terms which are either no longer applicable to PG&E’s procurement authority, or which are simply outdated. PG&E edited the glossary to delete terms which were irrelevant to the 2014 BPP.
XXIII. CONCLUSION As PG&E has demonstrated above, the proposed 2014 BPP is consistent with California statutes and Commission decisions, reasonable, and will result in affordable procurement-related costs for PG&E’s customers. PG&E respectfully requests that the Commission approve the proposed 2014 BPP, and, in addition, approve the specific substantive changes identified in
Attachment B.
Respectfully submitted,
CHARLES R. MIDDLEKAUFF MARK R. HUFFMAN
By: /s/ Charles R. Middlekauff CHARLES R. MIDDLEKAUFF
Pacific Gas and Electric Company 77 Beale Street, B30A San Francisco, CA 94105 Telephone: (415) 973-6971 Facsimile: (415) 973-5520 E-Mail: [email protected]
Attorneys for PACIFIC GAS AND ELECTRIC COMPANY Dated: October 3, 2014
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ATTACHMENT A
2014 Bundled Procurement Plan (“BPP”) Sections, Corresponding 2010 BPP Sections, and Description of Changes
(Public Version)
2014 BPP SECTIONS, CORRESPONDING 2010 BPP SECTIONS, AND DESCRIPTION OF CHANGES
Line No. 2014 BPP Section 2010 BPP Section Description of Changes 1 Section I – Introduction Section I – Introduction Updated to reflect 2014 Long-Term (Sheet No. 1)1 Procurement Plan Rulemaking. Discussion of process for updating the BPP moved to Section VI. 2 Section I.A – PG&E’s Section I.A – Overview of Updated to reflect PG&E’s Procurement Procurement Goals Procurement Activities Goals, including safety, reliability, Consistent with State Energy affordability and environmentally Action Plan sensitive electric service. (Sheet Nos. 1-4) 3 Section I.B – Overview of Section II.A.2 – Overview of Updated descriptions of overview of PG&E’s Planning, PG&E’s Procurement Process procurement process. Section II.A.2.c Procurement and (Sheet Nos. 15-17) of the 2010 BPP has been updated and Scheduling/Bidding moved into Appendix K. Activities 4 Section I.C – Overview of Section I.B – Overview of Updated and shortened overview of the PG&E’s Bundled PG&E’s Bundled Procurement 2014 BPP. Procurement Plan Plan (Sheet Nos. 5-10) 5 Section II.A – Compliance Section VI.A – Compliance with Updated the BPP reference column to with AB 57 AB 57 reflect sections in the 2014 BPP. (Sheet Nos. 90-91) 6 Section II.B – Compliance Sections II.A.8.c – Loading order Updated to reflect new, Commission- with the Loading Order Section IV approved programs to implement the loading order. (Sheet Nos. 48-49 and 67-85) 7 Section III – Compliance Sections II.A.1.f – Compliance Updated discussion of Standards of with Commission’s with Commission Standard of Conduct for procurement and Procurement Standards of Conduct #2 corresponding references in 2014 BPP. Conduct Section VI.B – Compliance with Commission’s Procurement Standards of Conduct (Sheet Nos. 13-15, 91-93) 8 Section IV.A – Monthly, Section VI.C – Description of Updated to reflect PG&E’s Quarterly and Annual Filings PG&E Filings Made to procurement-related reporting and Reports Demonstrate Compliance requirements and a new table was added to reflect these requirements. (Sheet Nos. 94-99) Section VI.C.5.b (regarding the ERRA Trigger) was moved to Section IV.B in the 2014 BPP and Section VI.C.5.c from the 2010 BPP was deleted.
1 Sheet No. references are to the most current version of the 2010 BPP, which is dated April 11, 2014.
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Line No. 2014 BPP Section 2010 BPP Section Description of Changes 9 Section IV.B – Section VI.C.5.b – ERRA Trigger Updated description of the ERRA Additional Reporting Trigger Application. (Sheet Nos. 97-98) Requirements – ERRA Trigger 10 Section IV.C – Description Section VI.D – Description of Updated description to reflect changes of Cost Recovery for BPP Costs Recovered Through ERRA since 2010 BPP, including deleting Procurement reference to the WaveConnect program (Sheet Nos. 99-100) which no longer exists. 11 Section V – Pre-Approval, Section VI.E – Pre-Approval, Updated the filing requirements for Approval and Filing Approval and Filing certain types of transactions and added Requirements Requirements additional filing requirements for existing QF contract amendments and (Sheet Nos. 100-102) contracts under the QF/CHP Settlement. 12 Section VI – Updates to Section I – Introduction Updated to consolidate discussions of Bundled Procurement Plan BPP updating requirements that were (Sheet No. 1) Via Advice Letter described in various sections of the 2010 Section II.A.6 – Electrical BPP. Capacity Procurement Limits and Ratable Rates (Sheet No. 44) Appendix B, Section E – Hedging Plan Updates Via Advice Letter (Sheet No. 133) Appendix D, Section B.3.c. – Updates to the Gas Supply Plan (Sheet Nos. 151-152) Appendix H, Section G – Future Convergence Bidding Strategies (Sheet No. 171) Appendix L, Section D.9 – Updates Via Advice Letter (Sheet No. 307) 13 Appendix A, Section A – Section II.A.3.a – Updated to reflect corrections and Electric Products Electric Products modifications in the product descriptions, and moved to new (Sheet Nos. 18-22) Appendix A. Added a new product “Structured Transaction.” 14 Appendix A, Section B – Section II.A.3.a – Moved the GHG products from the Greenhouse Gas Products Electric Products Electric Product section in the 2010 BPP into a separate table in the 2014 BPP. (Sheet Nos. 18-22) Appendix L.D.2 –Greenhouse Gas-Related Products (Sheet No. 289)
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Line No. 2014 BPP Section 2010 BPP Section Description of Changes 15 Appendix A, Section C – Section II.A.3.b – Gas Products Updated and clarified descriptions; Fuel Products merged two products from the 2010 (Sheet Nos. 22-24) BPP. Added distillate product, which is used for backup and startup fuel at one facility and was approved by the Commission in D.06-11-048. 16 Appendix A, Section D – Section II.A.3.c – Credit Products Updated to reflect minor updates and Credit Products corrections in the product descriptions. (Sheet Nos. 24-25) 17 Appendix B, Section A – New Section – Not Applicable New Appendix added to 2014 BPP. Introduction 18 Appendix B, Section B – Section II.A.4 – Overview of Market and Commission-mandated Overview of Procurement Energy Products Market processes separated into two Processes (Sheet Nos. 26-33) subsections. Added a subsection regarding GHG compliance instrument Appendix L, Section A.2 – GHG procurement. Procurement Plan (Sheet Nos. 282-284) 19 Appendix B, Section C -- Section II.A.5 – PG&E’s Updated process descriptions and added Approved Procurement Procurement Methods and new transaction process for Cashout and Processes And Practices Practices Bilateral Transactions for Natural Gas Storage and Pipeline Capacity. (Sheet Nos. 33-35) 20 Appendix B, Section D – Section II.A.7 – Contracting Updated to consolidate discussions of Commission Adopted Rules for Once-Through Cooling certain procurement processes that were Limitations for Specific Units in various sections of the 2010 BPP, and Procurement Processes incorporate requirements from D.14-02- (Sheet Nos. 44-46) 040. Section II.A.5.f – Solicitations and Request for Offers (Sheet 31) Section II.A.8.c – Loading Order (Sheet Nos. 48-49) Appendix I, Section C – Request for Offer Process (Sheet Nos. 180-181) Section II.A.8 – The Application of Least-Cost Best-Fit and the Loading Order in PG&E’s Procurement Processes (Sheet Nos. 46-48) 21 Appendix C, Section A – Section II.A.6 – Electrical Updated electric capacity limits, added Electric Limits Capacity Procurement Limits and as new electric energy limits, and Ratable Rates provided procurement limit calculations for a PG&E Alternative Scenario as well (Sheet Nos. 41-44) as for the CPUC Mandated Scenario. Appendix A – Table PGE-3 and PGE-4 (Sheet Nos. 106-107)
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Line No. 2014 BPP Section 2010 BPP Section Description of Changes 22 Appendix C, Section B – Gas Appendix D – Electric Portfolio Updated to replace the Gas Supply Plan Limits Gas Supply Plan in the 2010 BPP and includes procurement limits for natural gas (Sheets 147-152) supply, pipeline capacity and storage. Provided procurement limit calculations for a PG&E Alternative Scenario as well as the CPUC Mandated Scenario. 23 Appendix C, Section C – Appendix L.D.4.i – Maximum Moved from the GHG Plan into this Greenhouse Gas Limits Volume Limits appendix to allow all procurement limits to be covered in one area of the BPP. Appendix L.D.4.j – Financially Updated to reflect the new plan duration Hedging Greenhouse Gas and market changes, and provided Compliance Instrument Price Financial Exposure Purchase Limit Risk calculations (in accordance with the (Sheet Nos. 300-305) methodology approved in D.12-04-046) for a PG&E Alternative Scenario as well Section V.C. – Greenhouse Gas as the CPUC Mandated Scenario. Emission Evaluation Direct Compliance Obligation Purchase (Sheet No. 89) Limits were also provided, but the calculation did not differ between the two scenarios. 24 Appendix D, Section A – Section III – Description of Updated to describe Appendix D (i.e., Introduction Commission-mandated case CPUC Mandated Scenario and the PG&E Alternative Scenario). (Sheet No. 61) 25 Appendix D, Sections B.1 Sections III.A and III.B – Load Updated to reflect the CPUC Mandated and B.2 – CPUC Mandated Forecast and Existing and Scenario load and resource assumptions Scenario Load Forecast and Planned Resources for for the 2014 LTPP. Existing and Planned Commission-mandated Case Resources Appendix A – Energy and Capacity Tables (Sheet Nos. 61-67, 104-105) 26 Appendix D, Section B.3 – Section V – Evaluation of Updated to reflect the evaluation for CPUC Mandated Scenario Commission-mandated Case CPUC Mandated Scenario. Evaluation of Revenue (Sheet Nos. 86-89) Requirements, Rates and Risk 27 Appendix D, Section C – Adds the PG&E Alternative Scenario. PG&E Alternative Scenario 28 Appendix E, Section A – Introduction No substantive changes. Introduction (Sheet No. 109) 29 Appendix E, Section B – Section A – Scope of the Hedging Updated text in the beginning of this Hedging Plan Structure Plan section (i.e., Section A.1 regarding GHG has been moved to Section B.1.c (Sheet Nos. 109-111) and updated in reference to PG&E’s GHG Plan) and the remaining subsections have only minor, non- substantive changes.
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Line No. 2014 BPP Section 2010 BPP Section Description of Changes 30 Appendix E, Section C.1 – Section B.1 – Tenor Tenor (Sheet No. 112) 31 Appendix E, Section C.2 – Section B.2 – Operating Targets Hedging Targets and Limits (Sheet Nos. 112-117)
32 Appendix E, Section C.2 – Hedging Targets and Limits (Sheet Nos. 117-119) 33 Appendix E, Section C.3.a – Section B.3.a – Product Mix Product Mix Targets Targets (Sheet Nos. 120-122) 34 Appendix E, Section C.3.b –
(Sheet Nos. 122-123) 35 Appendix E, Section C.4 – Section B.4 – Execution Strategy Execution Strategy (Sheet Nos. 124-125)
36 Appendix E, Section C.5 –
(Sheet Nos. 125-126) 37 Appendix E, Section D.1 – Section C.1 – Transition Plan Transition Plan (Sheet Nos. 126-127)
38 Appendix E, Section D.2 – Section C.2 – Unusual Events, Unusual Events, Market Market Dislocations, and Dislocations, and Emergencies Emergencies (Sheet Nos. 127-129)
39 Appendix E, Section E – Section D – Liquidity Liquidity Management Management Strategy Strategy (Sheet Nos. 129-133)
40 Appendix F, Section A.1 – Appendix C, Section A.1 ‒ Updated to reflect new information The Nuclear Fuel Cycle The Nuclear Fuel Cycle about the number of suppliers and customers for various portions of the (Sheet Nos. 135-136) nuclear fuel cycle. 41 Appendix F, Section A.2 – Appendix C, Section A.2 – Diablo Canyon Power Plant Diablo Canyon Power Plant Operations Plan Operations Plan (Sheet Nos. 136-137)
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Line No. 2014 BPP Section 2010 BPP Section Description of Changes 42 Appendix F, Section B – Appendix C, Section B– PG&E’s Nuclear Fuel PG&E’s Nuclear Fuel Procurement Plan Procurement Plan
(Sheet Nos. 137-138) 43 Appendix F, Section B.1 – Appendix C, Section B.1 – Forward Contracting and Forward Contracting and Price Terms Price Terms
(Sheet Nos. 138-140) 44 Appendix F, Section B.2 ‒ Appendix C, Section B.2 ‒ Nuclear Fuel Strategic Nuclear Fuel Strategic Inventory Inventory (“SI”) Management Management (Sheet Nos. 140-141) 45 Appendix F, Section B.3 ‒ Appendix C, Section B.3 ‒ Proposed Risk Management Proposed Risk Management Measures Measures
(Sheet Nos. 141-142) 46 Appendix F, Section B.4 ‒ Appendix C, Section B.4 ‒ Risk Nuclear Liability and Issues Regarding Nuclear Fuel Insurance Issues Regarding Contracts Nuclear Fuel Contract (Sheet Nos. 142-144) 47 Appendix F, Section B.5 ‒ Appendix C, Section B.5 – Updated to incorporate title change and Capped Liability Under Suppliers Seeking to refine discussion. Some Contracts Contractually Cap Liability (Sheet No. 144) 48 Appendix F, Section C.1 ‒ Appendix C, Section C.1 ‒ Regulatory and Political Regulatory and Political Outlook Outlook Not Specific to Not Specific to PG&E PG&E (Sheet Nos. 144-145) 49 Appendix F, Section C.2 ‒ Appendix C, Section C.2 ‒ No substantive changes. Transactions Outside the Transactions Outside the Scope Scope of the Plan of the Plan (Sheet No. 145) 50 Appendix F, Section D – Appendix C, Section D – Summary of Proposal and Summary of Proposal and Conclusion Conclusion
(Sheet Nos. 145-146) 51 Appendix G –GHG Appendix L – GHG Procurement Updated to reflect the following: (1) the Procurement Plan Plan plan only covers compliance obligations related to PG&E’s electric procurement (Sheet Nos. 279-309) and (2) minor edits for the passage of time.
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Line No. 2014 BPP Section 2010 BPP Section Description of Changes 52 Appendix H – Convergence Appendix G – Convergence Updated to reflect market design Bidding Bidding changes and reporting requirement updates. (Sheet Nos. 166-171) 53 Appendix I, Section A – Appendix F, Section A – No substantive changes. Introduction Introduction (Sheet Nos. 157-158) 54 Appendix I, Section B – Appendix F, Section B – No substantive changes. Congestion Revenue Rights Congestion Revenue Rights and and Long-Term Congestion Long-Term Congestion Revenue Revenue Rights Procurement Rights Procurement Objectives Objectives (Sheet No. 158) 55 Appendix I, Section C – Appendix F, Sections C and D Updated and reorganized (i.e., Sections Congestion Revenue Rights C and D from Appendix F in the 2010 (Sheet Nos. 158-160) Procurement BPP have been merged into a single section in the 2014 BPP, and Section D.3 from Appendix F is now in Section D of the 2014 BPP. 56 Appendix I, Section D – Appendix F, Section E – Volume No substantive changes. Volume Limits Limits (Sheet Nos. 160-161) 57 Appendix I, Section E – Appendix F, Section F – Updated and reorganized (i.e., Sections Selection Criteria for Valuation and Risk Analysis F, G, and a portion of H from Appendix Congestion Revenue Rights (Sheet No. 161-162) F in the 2010 BPP have been merged in Allocations and Auction into a single section in the 2014.BPP in Appendix F, Section G – Processes order to avoid redundancy so that there Nomination Criteria in is just one overall explanation of the Congestion Revenue Rights selection criteria for CRRs in allocation Allocation Process and auction processes.. (Sheet Nos. 162-163) Appendix F, Section H – Congestion Revenue Rights Auction Participation (Sheet Nos. 163-165) 58 Appendix I, Section F – Appendix F, Section H – Updated to reflect that participation in Congestion Revenue Rights Congestion Revenue Rights CRR auctions will be optional, as Auction Participation Auction Participation opposed to mandatory. This section F (Sheet Nos. 163-165) (of Appendix I) also clarifies actions PG&E may take to sell excess CRRs Appendix F, Section J – Excess within the auction process. Congestion Revenue Rights (Sheet No. 165) 59 Appendix I, Section G – Appendix F, Section H – Updated to reflect that participation in Transactions in Secondary Congestion Revenue Rights secondary markets will be optional, as Congestion Revenue Right Auction Participation opposed to mandatory. This section G Market (Sheet Nos. 163-165) (of Appendix I) also clarifies actions PG&E may take to sell excess CRRs Appendix F, Section J – Excess within the secondary markets.. Congestion Revenue Rights (Sheet No. 165)
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Line No. 2014 BPP Section 2010 BPP Section Description of Changes 60 Appendix J – Brokerages and Appendix H – Brokerages and Updated to reflect the following: (1) the Exchanges Exchanges deletion and name change of several (Sheet Nos. 173-173-A) brokerages; (2) the name change of several exchanges; (3) specifically identifying those exchanges approved for GHG products, and (4) the addition of a new broker: Finerty Group, Inc. 61 Appendix K – Section I.B.1 New Appendix added that incorporates Bidding and Scheduling and updates information regarding (Sheet No. 6) scheduling and bidding of PG&E’s Section II.A.2.c – Dispatch owned and contracted resources. (Sheet Nos. 16-17) Section II.A.5.a – Daily and Hour-Ahead Planning and CAISO’s Real-Time Market (Sheet Nos. 38-40) 62 Appendix L – CAISO New Section – Not Applicable New Appendix added, which was not Operating Order Protocols included in the 2010 BPP, that describes PG&E’s actions when responding to CAISO system reliability needs. 63 Appendix M, Section A – Section II.A.9 – PG&E’s Use of Updated to reflect expanded discussion Procurement Review Group the Procurement Review Group on the regular PRG and the CAM and Cost Allocation Process Group. Two tables were added to Mechanism Group reflect Commission requirements (Sheet Nos. 49-52) associated with consulting and reporting Appendix I, Section A – to the PRG and CAM Group. Procurement Review Group Clarification requested to PRG review (Sheet Nos. 175-177) of transaction three months or greater (Table M-1, Item #1) and modifications to PRG review of CRRs and LT-CRRs. 64 Appendix M, Section B – Section II.A.9 – PG&E’s Use of Updated to include Table M-3 which Independent Evaluators the Independent Evaluators outlines the procurement activities requiring an independent evaluator and (Sheet No. 52) the associated directive. Appendix I, Section B – Independent Evaluators (Sheet Nos. 177-180, 182-222) 65 Appendix N, Section A.1 – Section II.B.1 – Portfolio Risk Updated bundled system average rate Portfolio Risk Assessment Assessment and Customer Risk and associated Customer Risk Tolerance and Customer Risk Tolerance consistent with the 10 percent risk Tolerance tolerance factor for 2014 (see (Sheet Nos. 52-55) description of risk assessment and Customer Risk Tolerance). 66 Appendix N, Section A.2 – Section II.B.2 – PG&E’s Current Updated the refine the discussion, but Current Risk Management Risk Management Practices are no substantive changes were made. Practices (Sheet Nos. 55-56)
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Line No. 2014 BPP Section 2010 BPP Section Description of Changes 67 Appendix N, Section A.3 – Section II.B.3 – PG&E’s Credit Updated to refine the discussion and Credit and Collateral and Collateral Requirements categories of transactions were modified Requirements to reflect the passage of time. (Sheet Nos. 57-60) 68 Appendix N, Section B – Appendix E – PG&E’s TeVaR Updated by moving Table E-1 in TeVaR Methodology Methodology Appendix E of the 2010 BPP to Appendix D in the 2014 BPP. (Sheet Nos. 154-155) 69 Appendix O – Acronym List Appendices J and K Updated to reflect acronyms and and Glossary relevant terms used in the 2014 BPP. (Sheet Nos. 223-277)
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ATTACHMENT B
Substantive Changes for Commission Approval
Substantive Changes for Commission Approval
In its cover pleading, PG&E provides an overview of the 2014 BPP and described in detail changes between the 2010 BPP and the 2014 BPP. Many of the changes were updates to reflect the passage of time or events which have occurred since the 2010 BPP was approved. Other changes were substantive changes to PG&E’s current procurement authority. In the table below,
PG&E identifies the substantive changes to its procurement authority that were included in the
2014 BPP for which PG&E is requesting Commission approval. PG&E is requesting approval of the entire 2014 BPP, but is providing this table of substantive changes so that the Commission and parties can identify substantive changes for which Commission approval is requested.
Topic and Section of 2014 BPP Summary of Substantive Change and request for Approval
Appendix A, Table A-1, Item #33 – Structured Approve adding Structured Transactions product (this Transactions product has already been approved for SCE).
Appendix B, Table B-1, Item #10 Approve clarification that limitation on electronic solicitations for utility-owned resources does not apply to natural gas storage provided by PG&E California Gas Transmission.
Appendix B, Table B-1, Item #15 – Cashout Approve the addition of a new procurement process for gas pipeline imbalances referred to as a “cashout”
Appendix C, Procurement Limit Approve the proposed procurement limits for electric capacity and energy, natural gas (including natural gas supply, transportation and storage), and GHG compliance instruments
Appendix D, PG&E Alternative Scenario Approve PG&E’s Alternative Scenario and the corresponding capacity and energy balance tables as well as the corresponding procurement limits
Appendix E, Electric Portfolio Hedging Plan Approved PG&E’s revised Electric Portfolio Hedging Plan
Appendix F, Nuclear Fuel Procurement Plan Approve PG&E’s revised Nuclear Fuel Procurement Plan
B-1
Topic and Section of 2014 BPP Summary of Substantive Change and request for Approval
Appendix G, Greenhouse Gas Procurement Plan Approve PG&E’s revised Greenhouse Gas Procurement Plan, which covers PG&E’s obligations related to electric procurement (not its obligations as a natural gas supplier)
Appendix I, Congestion Revenue Rights Approve PG&E’s revised CRR procurement
Appendix J, Brokers Approve the addition of a new broker -- Finerty Group, Inc.
Appendix K, Scheduling and Bidding Protocols Approve new Appendix K
Appendix L, CAISO Operating Order Protocols Approve new Appendix L
Appendix M, PRG consultation regarding Approve the clarification proposed in Table M-1, Item transactions that are three months or more in #1 regarding PRG review of transactions three months duration or greater in duration
Appendix M, PRG review of CRRs Approve the modified language in Table M-1, Item #9 and Table M-2, Item #12 regarding review of CRR and LTCRR transactions with the PRG
Appendix N, Risk Management Policy Approve PG&E’s revisions and clarifications to its Risk Management Policy
B-2
ATTACHMENT C
PG&E’s Proposed 2014 Bundled Procurement Plan
(Public Version)
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Introduction 7KLV$SSHQGL[GHVFULEHV3DFLILF*DVDQG(OHFWULF&RPSDQ\¶V ³3* (´ KHGJLQJ SODQ ³+HGJLQJ3ODQ´ IRULWVHOHFWULFSRUWIROLR7KH+HGJLQJ3ODQJXLGHV3* (¶V PDQDJHPHQWRIWKHFRPPRGLW\SULFHULVNLQWKHSRUWIROLR,QDGGLWLRQWKH+HGJLQJ3ODQ VHUYHVDVDIUDPHZRUNIRU&DOLIRUQLD3XEOLF8WLOLWLHV&RPPLVVLRQ ³&38&´RU ³&RPPLVVLRQ´ FRPSOLDQFHUHYLHZWKURXJKWKHTXDUWHUO\FRPSOLDQFHUHSRUWVDQGDQQXDO (QHUJ\5HVRXUFH5HFRYHU\$FFRXQW ³(55$´ SURFHHGLQJV B. Hedging Plan Structure 7KH+HGJLQJ3ODQLQFOXGHVWKHIROORZLQJFRPSRQHQWV x 3ODQWHQRU x +HGJLQJWDUJHWVDQGOLPLWV x 3URGXFWPL[VWUDWHJ\ x ([HFXWLRQVWUDWHJ\ x &RQGLWLRQVZKHQLWLVDFFHSWDEOHWRRSHUDWHRXWVLGHWKHKHGJLQJSODQDQG x /LTXLGLW\PDQDJHPHQWVWUDWHJ\ 7KHUHPDLQGHURIWKLVVHFWLRQGHVFULEHVLPSRUWDQWSODQQLQJDVSHFWVWKDWDUHQRWSDUW RIWKH+HGJLQJ3ODQ 1. Physical Supply Managed Separately From the Hedging Plan a. 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Greenhouse Gas 3* (¶VREMHFWLYHVIRUPDQDJLQJWKHHOHFWULFSRUWIROLR¶VH[SRVXUHWRSK\VLFDO JUHHQKRXVHJDV ³*+*´ FRPSOLDQFHLQVWUXPHQWVXSSO\ULVNVDUHGLIIHUHQWIURP3* (¶V REMHFWLYHVIRUPDQDJLQJWKHHOHFWULFSRUWIROLR¶VH[SRVXUHWRILQDQFLDOULVNVDVVRFLDWHGZLWK *+*FRVWV7KHUHIRUH3* (PDQDJHVWKHHOHFWULFSRUWIROLR¶VSK\VLFDO*+*FRPSOLDQFH LQVWUXPHQWVXSSO\VHSDUDWHO\IURPWKHHOHFWULFSRUWIROLR¶VH[SRVXUHWRILQDQFLDOULVNV,Q PDQDJLQJWKHHOHFWULFSRUWIROLR¶VILQDQFLDOULVNVDVVRFLDWHGZLWK*+*FRVWV3* (¶V REMHFWLYHVDUHWRUHGXFHH[SRVXUHRIWKHHOHFWULFSRUWIROLRWR*+*FRPSOLDQFHLQVWUXPHQW SULFHYRODWLOLW\WRUHGXFH7H9D5DQGWRVWDELOL]HHOHFWULFUDWHVIRUFXVWRPHUV C. Hedging Plan 1. Tenor ,QWKHFRQWH[WRIWKH+HGJLQJ3ODQWHQRUPHDQVWKHOHQJWKRIWKHGHOLYHU\SHULRGWR EHKHGJHG 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 106 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 2. 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Liquidity Mitigation Strategies 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 120 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ $33(1',;) 18&/($5)8(/352&85(0(173/$1 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 121 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ A. Background on Nuclear Fuel Procurement 1. 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Diablo Canyon Power Plant Operations Plan 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 123 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 124 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 7$%/() 3$&,),&*$6$1'(/(&75,&&203$1< '&33(67,0$7('18&/($5)8(/6833/<5(48,5(0(176 BBBBBBBBBBBBBBB B. PG&E’s Nuclear Fuel Procurement Plan 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 125 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 1. Forward Contracting and Price Terms 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 126 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 127 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 2. Nuclear Fuel Strategic Inventory Management 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 128 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 3. Proposed Risk Management Measures 4. Nuclear Liability and Insurance Issues Regarding Nuclear Fuel Contracts 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 129 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 130 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 5. Capped Liability Under Some Contracts C. Issues Affecting the Plan 1. Regulatory and Political Outlook Not Specific to PG&E 'HFLVLRQ1R ,VVXHGE\ 'DWH)LOHG October 3, 2014 6WHYHQ0DOQLJKW(IIHFWLYH 6HQLRU9LFH3UHVLGHQW 5HVROXWLRQ1R 5HJXODWRU\$IIDLUV &DO38&6KHHW1R 131 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 3DFLILF*DVDQG(OHFWULF&RPSDQ\ 6DQ)UDQFLVFR&DOLIRUQLD %XQGOHG3URFXUHPHQW3ODQ 2. Transactions Outside the Scope of the Plan D. 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